Canada Gazette, Part I, Volume 154, Number 51: Clean Fuel Regulations

December 19, 2020

Statutory authorities
Canadian Environmental Protection Act, 1999
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 gases (GHGs) are primary contributors to climate change. The largest sources of GHG emissions in Canada are from the extraction, processing and combustion of fossil fuels. In order to exceed Canada’s current GHG emission reduction target under the Paris Agreement, and achieve the goal of net-zero emissions by 2050, a number of GHG emission reduction measures have been implemented. While these actions are bringing Canada closer to meeting its climate goals, further action is required.

Description: The proposed Clean Fuel Regulations (the proposed Regulations) would require liquid fossil fuel primary suppliers (i.e. producers and importers) to reduce the carbon intensity (CI) of the liquid fossil fuels they produce in and import into Canada from 2016 CI levels by 2.4 gCO2e/MJ in 2022, increasing to 12 gCO2e/MJ in 2030. The proposed Regulations would also establish a credit market whereby the annual CI reduction requirement could be met via three main categories of credit-creating actions: (1) actions that reduce the CI of the fossil fuel throughout its lifecycle, (2) supplying low-carbon fuels, and (3) specified end-use fuel switching in transportation. Parties that are not fossil fuel primary suppliers would be able to participate in the credit market as voluntary credit creators by completing certain actions (e.g. low-carbon fuel producers and importers). In addition, the proposed Regulations would retain the minimum volumetric requirements (at least 5% low CI fuel content in gasoline and 2% low CI fuel content in diesel fuel and light fuel oil) currently set out in the federal Renewable Fuels Regulations (RFR). The RFR would be repealed.

Regulatory development: The annual CI reduction requirements have been informed by extensive consultation with industry stakeholders and associations (including the oil and gas sector, low-carbon energy sectors, and industry sectors that use liquid fuels), environmental non-governmental organizations (ENGOs), representatives from provincial and territorial governments, associations representing Indigenous Peoples, administrators of similar regulations in other jurisdictions, and academics. ENGOs and stakeholders in the low carbon energy sectors support the proposed Regulations while some provincial governments and some stakeholders in the oil and gas sector have raised concerns about the costs of compliance. Since the proposed Regulations were first proposed in a discussion paper in February 2017, the Department has made a number of changes to the design of the proposed Regulations in response to feedback received.

The proposed Regulations are intended to be a flexible, performance-based policy tool that reduces the CI of liquid fossil fuels supplied in Canada. Therefore, the proposed Regulations incorporate, but also improve upon the federal RFR. The proposed Regulations would also be complementary to carbon pricing as they would provide an additional incentive to reduce GHG emissions by reducing the CI of liquid fuels, which are primarily used in the transportation sector, a major source of GHG emissions in Canada.

Cost-benefit statement: Between 2021 and 2040, the cumulative GHG emission reductions attributable to the proposed Regulations are estimated to range from 173 to 254 megatonnes of carbon dioxide equivalent (Mt CO2e), with a central estimate of approximately 221 Mt. To achieve these GHG emission reductions, the modelling conducted for this analysis estimates that the proposed Regulations could result in societal costs that range from $14.1 to $26.7 billion, with a central estimate of $20.6 billion. Therefore, the GHG emission reductions would be achieved at an estimated societal cost per tonne between $64 to $128, with a central estimate of $94. To evaluate the results, a break-even analysis was conducted that compares the societal cost per tonne of the proposed Regulations to the Departmental value of the social cost of carbon (SCC) published in 2016, and to more recently published estimates of the SCC value found in the academic literature. Given that the updated estimates of the SCC exceed the estimated societal cost per tonne of the proposed Regulations, the Department concludes that it is plausible that the monetized benefits of the proposed Regulations would exceed its costs.

The proposed Regulations would increase production costs for primary suppliers, which would increase prices for liquid fuel consumers (i.e. households and industry users). In addition, credit revenues would decrease the costs of production for low-carbon energy suppliers, which would make low carbon energy sources (e.g. biofuel and electricity) relatively less expensive in comparison. These price effects would lead to decreased end-use demand for fossil fuels and increased end-use demand for lower carbon energy sources, thereby reducing national GHG emissions. To evaluate to the direct impact of the proposed Regulations as well as the effect of relative price changes on Canadian economic activity and GHG emissions, a macroeconomic analysis was completed. When these effects are taken into account, it is estimated that the proposed Regulations would result in an overall GDP decrease of up to $6.4 billion (or up to 0.2% of total GDP) while reducing up to 20.6 Mt of GHG emissions in 2030, using an upper bound scenario where all credits are sold at the marginal cost per credit.

The proposed Regulations would work in combination with other federal, provincial, and territorial climate change policies to create an incentive for firms to invest in innovative technologies and fuels by setting long-term, predictable and stringent targets. The broad range of compliance strategies allowed under the proposed Regulations would also allow fossil fuel suppliers the flexibility to choose the lowest-cost compliance actions available. If the proposed Regulations induce more long-term innovation and economies of scale than projected in the estimates presented in this analysis, then the proposed Regulations could result in lower costs and greater benefits, particularly over a longer time frame.

One-for-one rule: The proposed Regulations would result in annualized net administrative cost increases of about $350,100 for fossil fuel producers and importers. Annualized administrative cost savings for renewable fuel producers and importers are estimated at $55,200. Overall, the total net annualized administrative cost increases are estimated at $294,900 for all stakeholders. The proposed Regulations would be considered an “IN” under the Government of Canada’s one-for-one rule.

Small business lens: The small business lens does not apply to the proposed Regulations as no mandatory participants are considered small businesses.

Issues

Greenhouse gases (GHGs) are primary contributors to climate change. The largest sources of GHG emissions in Canada are from the extraction, processing and combustion of fossil fuels. GHG emissions from the oil and gas and transportation sectors account for 26% and 25% of total GHG emissions in Canada respectively.footnote 1 In order to exceed Canada’s current GHG emission reduction target to reduce emissions by 30% below 2005 levels by 2030 under the Paris Agreement, and achieve the goal of net-zero emissions by 2050, a number of GHG emission reduction measures have been implemented.footnote 2 However, further action is required to meet Canada’s GHG emission reduction targets. In particular, without additional action, it is expected that emissions from Canada’s transportation and oil and gas sectors would continue to increase year-over-year.

Background

Global warming is projected to lead to changes in average climate conditions and extreme weather events. The impacts of climate change are expected to worsen as the global average surface temperature becomes warmer. Climate change impacts are of major concern for society: changes in temperature and precipitation can impact natural habitats, agriculture and food supplies, and rising sea levels can threaten coastal communities.footnote 3

The Government of Canada has committed to taking action on climate change. At the United Nations Framework Convention on Climate Change (UNFCCC) conference in December 2015, the international community, including Canada, adopted the Paris Agreement, an accord intended to reduce global GHG emissions to limit the rise in global average temperature to less than 2°C above pre-industrial levels and to aim to limit the temperature increase to 1.5°C. As part of its Intended Nationally Determined Contribution (INDC) commitment under the Paris Agreement, Canada pledged to reduce national GHG emissions by 30% below 2005 levels by 2030.footnote 4

On December 9, 2016, Prime Minister Trudeau, along with most first ministers of Canada, agreed to the Pan-Canadian Framework on Clean Growth and Climate Change (PCF). The PCF was developed to establish a path forward to meet Canada’s commitments under the Paris Agreement.footnote 5 November 25, 2016, as part of the PCF, the Government of Canada announced its plan to develop a Clean Fuel Standard (CFS) to reduce Canada’s GHGs by 30 Mt annually by 2030 on a lifecycle basis for fuels used in Canada.footnote 6 Since announcing the policy in late 2016, the Department of the Environment and Climate Change Canada (the Department) has engaged broadly with stakeholders on the design of the CFS and a number of formal consultation documents were released including

On December 13, 2019, the Minister of the Environment and Climate Change (the Minister) received a mandate letter from Prime Minister Trudeau to implement a whole-of-government plan for climate action, a cleaner environment and a sustainable economy. This included implementing the PCF, while strengthening existing and introducing new GHG reducing measures to exceed Canada’s current 2030 emission reduction goal and begin work so that Canada can achieve the goal of net-zero emissions by 2050.

Petroleum fuels and petroleum alternatives produce different quantities of GHG emissions when the full lifecycle of the fuel is considered, depending on the process used to produce the fuel, the actual composition of the fuel, and the way the fuel is used. The lifecycle of fuel accounts for all emissions connected to the extraction, production, transportation and combustion of a given fuel. Lifecycle-based fuel standards (such as the CFS) are based on lifecycle analysis (LCA) and require lifecycle carbon intensity (CI) calculations, based on the quantity of CO2 equivalent emissions per unit of energy produced (i.e. gCO2e/MJ) to assess the different GHG reduction values of fuels.

Generally speaking, CI standards or requirements are designed by assessing the CI values for each fuel using an LCA approach and comparing them to a required CI value that declines each year. Low carbon fuels that have CI values below the required CI value can generate credits, while fuels with CI values above the required CI value generate deficits. Credits and deficits are denominated in metric tonnes of lifecycle GHG emissions. Providers of fuels (the regulated parties) must demonstrate that the total mix of fuels they supply for use in the regulated jurisdiction (national or regional) meets the CI standards for each compliance period (usually a year). Regulated entities meet their compliance obligation by ensuring that the number of credits it earns or otherwise acquires from another party is equal to, or greater than, the deficits it has incurred.

British Columbia and California have implemented standards to lower the CI of fuels (called low-carbon fuel standards or clean fuel standards). Under these standards, requirements are set to reduce the lifecycle GHG emissions intensity of the fuels supplied in a given year by a certain percentage relative to a stipulated baseline year (e.g. 10% by 2020 from a 2010 baseline CI level).footnote 8 The sections below describe relevant fuel CI requirements that currently exist in Canada, the United States, and the European Union (EU).

Renewable fuel requirements — Canada

The federal Renewable Fuels Regulations (RFR) were established in August 2010. They require petroleum fuel producers and importers to have an average renewable content of at least 5% based on their volume of gasoline, and an average renewable content of at least 2% based on their volume of diesel fuel and heating distillate oil.footnote 9 The purpose of the RFR is to reduce overall GHG emissions from gasoline and diesel fuel, which is primarily used in transportation. There are exemptions for specialty fuels (e.g. those used in aircraft, competition vehicles, military combat equipment), for fuel used in northern regions, for export, for space heating purposes, and for the province of Newfoundland and Labrador. Unlike the proposed Regulations, the RFR does not require reductions in GHG emissions on a lifecycle basis, nor do they contain safeguards to ensure that biofuel production does not adversely affect biodiversity (direct land use change).

Five provinces (British Columbia, Alberta, Saskatchewan, Manitoba, and Ontario) already have renewable fuel requirements equal to or higher than the current federal requirements set in the RFR. Most of these provinces, along with Quebec, have established renewable fuel industries. Some jurisdictions (e.g. Alberta, Ontario) also require that the renewable fuels utilized meet a specific GHG performance standard.

Renewable fuel requirements — United States

Established in December 2005, the United States Renewable Fuel Standard (U.S. RFS) requires increasing annual volumes of renewable fuels to be blended into fossil fuels.footnote 10 The U.S. RFS differentiates renewable fuels based on their lifecycle GHG emission reductions, including emissions from indirect land use change. The indirect land use change impacts of biofuels relate to the consequence of releasing more carbon emissions due to land use changes induced by the expansion of croplands for biofuel production in response to the increased demand for biofuels. The annual volumetric requirements are set out for four categories of renewable fuels. The categories are designed to increase the use of renewable fuels with lower GHG lifecycle carbon intensities. Each category must meet a certain GHG reduction threshold (20% for conventional or first-generation renewable fuels, 50% for advanced biofuels, 50% for biomass-based diesel, and 60% for cellulosic biofuel). Fuels with a higher GHG reduction threshold (e.g. cellulosic ethanol) can also be used to help meet the volumetric requirements. In addition to the annual volumetric requirements for a lower GHG reduction threshold (e.g. conventional renewable fuels), the U.S. RFS requires the creation of credits, representing volumes of renewable fuels, and has a credit trading system. Currently, the RFS requires conventional renewable fuel to comprise 11% of transportation fuel, 3% of advanced biofuel, 2% of biomass-based diesel and less than 1% of cellulosic biofuel.footnote 11

Seven states also have renewable fuel requirements: Louisiana, Minnesota, Missouri, Montana, Oregon, Pennsylvania, and Washington.

Fuel CI requirements — British Columbia, California, Oregon and the EU

In January 2010, British Columbia’s Renewable and Low Carbon Fuel Requirements Regulation (RLCFRR) came into effect. Under the RLCFRR, the RLCFRR requires reductions in the lifecycle CI of transportation fuels supplied in a given year. In addition, at least 5% of gasoline and 4% of diesel by volume must contain renewable fuel.footnote 12 Initially, fuel suppliers were required to progressively decrease the average CI of their fuels to achieve a 9% reduction in 2020 from a 2010 CI baseline.footnote 13 In December 2018, British Columbia’s Ministry of Energy, Mines and Petroleum Resources (the Ministry) announced in their CleanBC Plan an increase of the CI target to 20% by 2030 relative to 2010 CI levels.footnote 14 In July 2020, these amendments to the RLCFRR came into effect.footnote 13 To date, British Columbia is the only province with a low carbon fuel standard.

The RLCFRR applies to all fuels used for transportation in British Columbia with the exception of fuel used by aircraft or for military operations. British Columbia’s requirement does not differentiate between crude oil types. Fuel suppliers can comply with the RLCFRR by reducing the overall CI of the fuels they supply, acquiring credits from other fuel suppliers, or by entering into an agreement with the province. Under these agreements, fuel suppliers are able to generate credits based on actions (projects) that reduce GHG emissions through using low-carbon fuels sooner than would have otherwise occurred without the agreed-upon action. Examples of projects supported under credit creating agreements include installing and operating new pumps that supply finished gasoline with at least 15% ethanol or finished diesel with at least 10% biodiesel or 50% hydrogenation-derived renewable diesel.

Adopted in April 2010, California’s Low Carbon Fuel Standard initially required fuel suppliers to reduce the CI of transportation fuels by 10% by 2020, from a 2010 baseline.footnote 15 California’s Low Carbon Fuel Standard was readopted in November 2015 to correct for legal deficiencies found in the initial fuel standard while also increasing the stringency of the CI reduction requirement to help meet its original target.footnote 16 In July 2020, the California Air Resource Board approved amendments to the regulation, which require fuel suppliers to reduce the CI of transportation fuels they supply by at least 20% by 2030, from a 2010 baseline. It also added new crediting opportunities to promote zero emission vehicle adoption, alternative jet fuel, carbon capture and sequestration, and advanced technologies to achieve deep decarbonization in the transportation sector.

Oregon’s Clean Fuels Program took effect in 2016 and requires a reduction in the annual average CI of Oregon’s transportation fuels (gasoline and diesel) by 10% from the 2015 level by 2025.footnote 17 It prescribes declining maximum CI limits, for each year.

The EU also has a similar policy in place. Established in April 2009, the Fuel Quality Directive requires fuel suppliers to reduce lifecycle GHG emissions from fuels by 10% by 2020.footnote 18 The Fuel Quality Directive works in tandem with the EU Renewable Energy Directive, which stipulates that the share of biofuels in the transportation sector should be 10% (by energy content) for each member country by 2020.footnote 19

Objective

The proposed Regulations intend to reduce GHG emissions by reducing the lifecycle CI of liquid fossil fuels used in Canada. To achieve this, the proposed Regulations would incentivize low carbon fuel uptake, end-use fuel switching in transportation, and process improvements in the oil and gas sector. The proposed Regulations aim to reduce the CI of liquid fossil fuels by 12 grams of carbon dioxide equivalent per megajoule (gCO2e/MJ) by 2030, which represents a decrease of approximately 13% in CI below 2016 levels. The proposed Regulations would work in conjunction with other federal, provincial and territorial policies to help exceed Canada’s current 2030 GHG emission reduction target under the Paris Agreement, and put Canada on a path towards the goal of net-zero emissions by 2050. In doing so, the proposed Regulations would encourage innovation and growth by increasing incentives for the development and adoption of clean fuels and energy efficient technologies and processes.

Description

Subsection 139(1) of the Canadian Environmental Protection Act, 1999 (CEPA) states that no person shall produce, import or sell a fuel that does not meet the prescribed requirements. The proposed Regulations, which would be made under subsection 140(1) and, for the compliance credits regime, under section 326 of the CEPA, would implement this prohibition.

Under the proposed Regulations, producers and importers of liquid fossil fuels, called primary suppliers, would have to reduce the lifecycle CI of the liquid fossil fuels they produce or import in Canada. Most primary suppliers are corporations that own refineries and upgraders. The proposed Regulations would establish annual lifecycle CI limits per type of liquid fossil fuel, expressed in grams of carbon dioxide equivalent per megajoule (gCO2e/MJ). The liquid fossil fuels that would be subject to the annual CI reduction requirement are gasoline, diesel, kerosene and light and heavy fuel oils. This obligation would be placed on primary suppliers who domestically produce or import at least 400 cubic metres (m3) of liquid fossil fuel for use in Canada. Non-fossil fuels would not have a CI reduction requirement.

The annual lifecycle CI reductions requirements for liquid fossil fuels would come into force in December 2022 starting at a 2.4 gCO2e/MJ reduction in CI and increasing to 12 gCO2e/MJ by 2030 at a rate of 1.2 gCO2e/MJ per year. Reduction requirements for the years after 2030 would be held constant at 12 gCO2e/MJ, subject to a review of the regulations and future amendments.

A primary supplier’s annual reduction requirement would be expressed in tonnes of carbon dioxide equivalent (tCO2e) and would be calculated on a company-wide basis, summing up the reduction requirements per liquid fossil fuel type for each of a company’s production facilities and for their total imports, based on the energy content of fossil fuels. The proposed Regulations would also incorporate the minimum volumetric requirements that are currently set out in the federal RFR, requiring a minimum 5% low-carbon-intensity fuel content in gasoline and 2% low-carbon-intensity fuel content in diesel fuel and light fuel oil.

The proposed Regulations would set out the baseline CI values for each fossil fuel type (e.g. gasoline or heavy fuel oil) produced in and imported for use in Canada. These values are Canadian average lifecycle CI values, calculated from the Department’s Fuel Lifecycle Assessment Model. This means that every type of fossil fuel is assigned the same national average value. GHG emissions from all stages in a fuel’s lifecycle are included in the determination of the baseline CI values. The proposed Regulations would also set out the annual CI limits for each fossil fuel type. The annual CI reduction requirements (e.g. 12 gCO2e/MJ in 2030) that primary suppliers would have to meet for the fuels they supply to Canada is the difference between the baseline CI value and the CI limit for that fossil fuel type. All fossil fuel types have the same annual CI reduction requirement. The proposed Regulations would not differentiate fossil fuels based on crude oil type, or whether the crude oil is produced domestically or imported into Canada.

The proposed Regulations would include a limited number of exemptions from the annual compliance obligation. Reduction requirements would not apply to aviation fuel, fossil fuel exported from Canada, fossil fuel used in scientific research, and fossil fuel sold or delivered for use in competition vehicles. In addition, certain volumes would be excluded from the primary supplier’s pool. These include liquid fossil fuels sold or delivered for a use other than combustion, produced in a facility for use in that facility (other than in mobile equipment), sold or delivered for use in a marine vessel with an international port destination, and sold or delivered for non-industrial use in remote communities. Remote community is defined as a geographic area that is not serviced by an electrical distribution network that is under the jurisdiction of the North American Electric Reliability Corporation or by a natural gas distribution system.

The proposed Regulations would establish a credit market, where each credit would represent a lifecycle emission reduction of one tonne of CO2e. For each compliance period (typically a calendar year), a primary supplier would demonstrate compliance with their reduction requirement by creating credits or acquiring credits from other creators, and then using the required number of credits for compliance. Once a credit is used for compliance it is cancelled and can no longer be used.

To meet the minimum volumetric requirements incorporated from the RFR, each primary supplier would be required to demonstrate for each compliance period that, of the total number of compliance credits it retires for compliance, a minimum (equivalent to 5% of its gasoline pool and 2% of its diesel and light fuel oil pool) is from low-CI fuels. These compliance credits are part of the total credits used to meet reduction requirements, but the same compliance credit cannot be used to meet the 2% and 5% requirements respectively. Primary suppliers who have surplus compliance units under the RFR would be able to convert these units into credits under the proposed Regulations after the end of the final compliance period of the RFR.

Parties that are not fossil fuel primary suppliers would be able to participate in the credit market as voluntary credit creators. In addition to the primary suppliers that would be subject to the CI reduction requirements in the proposed Regulations, other possible credit creators would include low carbon fuel producers and importers (e.g. a biofuel producer), electric vehicle charging site hosts, network operators, fuelling station owners or operators, as well as parties upstream or downstream of a refinery (e.g. an oil sands operator).

Credits may be created by primary suppliers or voluntary credit creators who take one of the following actions:

Primary suppliers would also be able to use compliance credits created following credit creation rules related to reducing the CI of gaseous or solid fuels for up to 10% of their liquid class reduction requirement. The crediting opportunities for gaseous and solid fuels would include projects that reduce emissions in the lifecycle of solid and gaseous fuels, and the production or importation of low CI gaseous fuels including renewable natural gas, biogas, hydrogen and renewable propane.

Compliance Category 1 recognizes actions that reduce a fossil fuel’s CI through GHG emission reduction projects to create credits. Credits can be created as of the date of registration of the final Regulations. Projects can include an aggregation of reductions from multiple sources or facilities, and no minimum emissions reduction threshold is set. The number of credits created would be determined by a quantification method, which specifies the eligibility criteria for the project as well as the approach for quantification. Quantification methods would be maintained outside of the proposed Regulations and developed by a team of technical experts, including departmental representatives, and reviewed by a broader consultative committee that includes stakeholders in industry, academia, and other technical experts.

The Department would develop quantification methods for various project types, starting with the following list:

This work would take into consideration existing emission reduction accounting methodologies or offset protocols in other jurisdictions. The Department would develop a generic quantification method for projects for which there is no applicable quantification method. Projects such as energy efficiency, cogeneration, electrification and methane reductions could be recognized under the generic quantification method provided they meet the eligibility criteria.

To be able to create credits under the proposed Regulations, a project would have to generate emission reductions that are real and incremental (i.e. additional) to a defined base case. The base case would be defined in the quantification method for each project type. The generic quantification method will predefine the base case for some foreseen project types or provide guidance on how to determine the baseline for other project types. A primary supplier may use credits created under the generic quantification method in order to satisfy up to 10% of its total liquid reduction requirement annually.

For all quantification methods other than the generic method, additionality would be assessed during the development of the quantification method at the project type level and would take into account many factors, including whether an action is required by another Canadian law or regulation, technological and financial barriers, and the market penetration rate of the technology or practice. Quantification methods would be periodically reviewed for additionality and maintained, modified or withdrawn as business as usual activities evolve. For the generic quantification method, separate and more streamlined additionality criteria would be developed and assessed at the project level.

Eligible projects must be conducted in Canada. They must also reduce the CI of a fossil fuel at any point along its lifecycle, achieve incremental GHG emission reductions, and must have begun to reduce, sequester, or use CO2e emissions on or after July 1, 2017. Project proponents would first apply to the Department to have a project recognized for credit creation and would submit a validation report. Each year, they would report information specified in the appropriate quantification method that is accompanied by a third-party verification report and a verification opinion. Credits would be created for 10 years for emission reduction projects, except for carbon capture and storage projects, which would create credits annually for a minimum of 20 years. In addition, projects may be renewed a single time for an additional 5 years after the initial crediting period, provided an applicable quantification method still exists at the time of renewal.

Compliance Category 2 encompasses credits that would be created under the proposed Regulations for low CI fuels produced or imported in Canada. Low CI fuels are fuels, other than the fossil fuels subject to the CI reduction requirements, that have a CI equal to or less than 90% of the credit reference CI value for the fuel. Most low CI fuels available on the market are forms of biofuels, such as ethanol. Other low CI fuels include synthetic fuels, such as those made from the CO2 captured from the atmosphere as a result of direct air capture or syngas generated from any biomass resource that could also be employed to make new low CI fuel products under a circular economy approach.

All low CI fuels supplied to the Canadian market, including fuels used to comply with existing federal and provincial renewable fuel regulatory requirements and British Columbia’s RLCFRR, would be able to create credits under the proposed Regulations. Credits may be created for liquid and gaseous low CI fuels as of the date of registration of the final Regulations. Credits for low CI fuels would be created based on the amount of low-carbon fuel they supply to the Canadian market annually (in MJ), the difference between the lifecycle CI of the low CI fuel, and the credit reference CI value for the fuel. In order to create credits, a low CI fuel producer or foreign supplier would be required to obtain an approved CI value for each low CI fuel that they produce or import. The proposed Regulations would require the use of either the Fuel Lifecycle Assessment (LCA) Model to calculate facility-specific CI values using facility-specific data, or the use of disaggregated default values available in the proposed Regulations.

A Fuel LCA Model is being developed by the Department to support the development and implementation of the proposed Regulations. Fuel producers and foreign suppliers would be able to use the model to determine facility-specific CI values once they have 24 months of operating data. They could use a provisional CI value using the model with only 3 months of data, until 24 months of data is available. Facilities with less than 3 months of operating data for a low CI fuel would need to use prescribed disaggregated default values. Fuel producers would be required to submit an application to the Minister for approval of each fuel’s CI, as well as submit an annual CI report that demonstrates that the CI has not increased above 0.5 gCO2e/MJ of the approved CI. The approved CI values would no longer be valid if there are changes at the facility and the approved CI is no longer representative of the production processes for the low CI fuel, or if changes occur that increase the CI of the fuel by more than 0.5 gCO2e/MJ above. A minimum threshold of an improvement of 1.0 gCO2e/MJ or 5% difference between the approved value and the proposed new value, whichever is greater, would be required in order to submit a request for a new CI value.

As noted above, the proposed Regulations would allow the creation of credits from the production of low CI fuels produced from biomass-based feedstocks. To prevent adverse impacts on land use and biodiversity stemming from the increased harvest and cultivation of these feedstocks, the proposed Regulations would establish land-use and biodiversity (LUB) criteria. Only biofuels made from biomass feedstock that adhere to the LUB criteria would be eligible for compliance credit creation. These criteria apply to feedstock regardless of geographic origin. The criteria do not apply to feedstock that is not biomass (e.g. fuel made from direct air capture) or that is designated “low-concern biomass feedstock” (e.g. municipal solid waste).

The LUB criteria are separated into requirements specifically for forest feedstock, those specific for agricultural feedstock, and those that apply to all feedstock. These criteria also impose requirements for supply chain declarations (used to trace eligible material from the feedstock harvester to the biofuel producer) and material balancing (used to permit physical mixing of eligible and non-eligible feedstock). The onus for demonstrating criteria adherence rests with the biofuel producers, but compliance with the criteria would need to be demonstrated at the producer level or through an approved certification scheme.

Compliance Category 3, specified end-use fuel switching in transportation, enables credit creation for changing or retrofitting a fossil fuel combustion device to be powered by another fuel or energy source, such as electric vehicles (EVs). This does not directly reduce the CI of fossil fuels but reduces GHG emissions by displacing gasoline or diesel used in transportation by fuels or energies with lower CIs. Credits would be created by the owners or operators of a fuelling facility that supplies fuels for transportation uses (natural gas, renewable natural gas [RNG], hydrogen, propane, renewable propane), by the producers and importers of low CI fuels (RNG, hydrogen and renewable propane) used for transportation purposes, by the owners or operators of hydrogen fuelling stations for dispensing hydrogen to hydrogen fuel cell vehicles, by charging network operators for residential and public charging of EVs, and by charging site hosts for private or commercial charging of EVs. Credit for residential charging of electric vehicles would be phased out by the end of 2035 for charging stations installed by the end of 2030. Any residential charging station installed after the end of 2030 would not be eligible for credits after 2030. The proposed Regulations would require charging network operators to reinvest 100% of the proceeds from the sale of credits created by residential and public EV charging. The revenue would have to be reinvested into two available categories of actions: either reducing the cost of EV ownership through financial incentives to purchase or operate an EV, or expanding charging infrastructure in residential or public locations, including EV charging stations and electricity distribution infrastructure that supports EV charging.

A primary supplier may also use the compliance fund mechanism by contributing to an eligible “registered” funding program in order to satisfy up to 10% of its annual reduction requirement. The credit price under this mechanism would be set in the proposed Regulations at $350 in 2022 (consumer price index [CPI] adjusted) per compliance credit. The credits created by these investments cannot be traded and would expire if not used for that compliance period. Primary suppliers may create credits by contributing to a registered funding program between January 1 and June 30, as well as between November 1 and November 30 following the end of a compliance period.

Funds or programs within a fund that reduce CO2e emissions may be eligible to become a registered fund. The fund or program must operate in Canada, provide funding for projects or activities that support the deployment or commercialization of technologies or processes that reduce CO2e emissions, and provide publicly available annual audited reports. Any contributions to the fund must be used for projects or activities that reduce emissions within a five-year period from the time the contribution is made.

For primary suppliers unable to satisfy their reduction requirement by June 30 following the end of a given compliance period, a market-clearing mechanism that facilitates credit acquisition by primary suppliers would also be available. The proposed Regulations would set a maximum price for credits acquired, purchased or transferred in the credit clearance mechanism (CCM) at $300 in 2022 (CPI adjusted) per compliance credit. If there are not sufficient credits available in the CCM for all primary suppliers to satisfy their outstanding reduction requirement, each primary supplier would be eligible to acquire a prorated amount of the available credits. If the CCM is depleted of all pledged credits, primary suppliers with a shortfall must contribute to a registered funding program, up to the maximum of 10% of their CI reduction requirement. After satisfying those obligations, a primary supplier can carry forward up to 10% of its CI reduction requirement into a future compliance period, with a maximum deferral of two years. An interest of 20% is applied annually to any deferred amount.

The proposed Regulations would require the reporting of all credit trades, and all parties would be required to register and keep records. Annual compliance reporting to the Minister would be required for all primary suppliers and credit creators. The proposed Regulations would include validation and verification requirements. Most significantly, regulated parties would be required to obtain from an independent, accredited third-party verification body a report stating whether the information submitted is complete, compliant with the requirements, and credits and obligations are accurate and without material error. The Quality Assurance System would include requirements for most submitted applications and reports to be validated or verified by a third party, with accompanying validation or verification reports.

The Department is planning to publish the final version of the Regulations in late 2021. Once that happens, credit creators would be able to register and start to create credits. The final compliance period for the RFR would be 2022, with the final reporting and true-up period for the RFR occurring in 2023. The RFR would then be repealed on January 1, 2024.

Regulatory development

Consultation

Since the Government of Canada’s 2016 announcement of its commitment to develop a CFS, the Department has actively engaged with stakeholders from across the country on the design of the regulations. Since 2017, the Department has held extensive consultation sessions on the development of the proposed Regulations, including group meetings, technical webinars and bilateral meetings. Stakeholders in these sessions included industry (fossil fuel producers and suppliers, low carbon fuel producers and suppliers, emission-intensive and trade-exposed (EITE) sectors, and other various industry groups), provinces and territories, Indigenous Peoples, environmental non-governmental organizations (ENGOs), administrators of similar programs in other jurisdictions (e.g. the California Air Resources Board) and academics. The Department has conducted hundreds of hours of bilateral meetings with individual stakeholders upon request in addition to participating in and chairing formal committees, as described below.

Publications

In February 2017, a discussion paper was published to gain initial views from stakeholders, provinces, and territories to inform the development of a regulatory framework in advance of developing specific regulations. The discussion paper laid out different approaches adopted by other jurisdictions, and posed technical questions related to the potential applicability of various elements within existing regulatory regimes at the time. The comment period closed on April 25, 2017, and the Department received over 125 comments from stakeholders. Following this, a Regulatory Framework was published in December 2017, outlining key design elements. Though no comments were formally requested, 47 comments were received and reviewed by the Department in early 2018.

In December 2018, a Regulatory Design Paper was published on the CFS website and in the Canada Gazette, Part I. The Regulatory Design Paper built on the two previous consultation documents and outlined the main design elements and approach for the proposed CFS Regulations for liquid fuels. Comments on the design paper closed on February 1, 2019, and over 100 comments from stakeholders, provinces, and territories and stakeholders were received. These comments informed the development of the proposed Regulations. Shortly after, a Cost-Benefit Analysis (CBA) Framework was published in February 2019, outlining the methodology for the CBA, which is part of this Regulatory Impact Analysis Statement (RIAS). Following the release of the framework, extensive stakeholder consultation took place through committees, working groups and submissions on the Regulatory Design Paper, informing the regulatory development of the proposed Regulations.

In June 2019, the Proposed Regulatory Approach was published, building on the Regulatory Design Paper (2018), the Regulatory Framework (2017) and on the extensive stakeholder engagement on the previous publications (such as the discussion paper). The Proposed Regulatory Approach provided the full set of requirements and credit creation opportunities for liquid fuels. It was open for public comment until August 26, 2019, and the Department received 95 submissions with comments on the Proposed Regulatory Approach.

All publications mentioned above are accessible at the Government of Canada’s Clean Fuel Standard webpage.

Committees and working groups

The Department chaired several committees, which provided a forum for active engagement with stakeholders. These committees included a multi-stakeholder committee, a technical working group, and a task group specifically examining impacts to EITE sectors. Provinces and territories have also been heavily engaged in the consultations on the proposed Regulations and were participants on various committees, including a Federal-Provincial-Territorial Working Group. Engagement via these committees helped inform the more detailed aspects of the design of the proposed Regulations for the liquid fuel class, and will continue to operate through the development of the gaseous and solid fuel class regulations.

Established in January 2018, the Multi-Stakeholder Consultative Committee (MSCC) met periodically both via webinar and in-person to provide a forum for the Department to update interested parties on progress and to provide an opportunity for advice and input to be offered on the proposed Regulations. This Committee has a pan-Canadian representation from key industry associations, academia, ENGOs, provincial and territorial governments and other federal departments. Four meetings were held in 2018, with approximate attendance of up to 250 participants out of 700 invitees. In 2019, two meetings were held in July to present the Proposed Regulatory Approach, with an estimated 300 participants in attendance. One meeting of the MSCC was held in July 2020 to summarize proposed changes since 2019.

Established in January 2018, the Technical Working Group (TWG) consists of a smaller group of regulated parties and other key partners, such as representatives of the biofuel industry, provincial and territorial governments, and the electricity sector. Progress and feedback received from the TWG are reported back to the MSCC. In addition to the core TWG members, specific sectoral and technical experts have been invited to provide input on specific issues as they emerged. The TWG has approximately 60 members. Nine meetings (in-person and/or teleconferences) were held in 2018, five in 2019 and seven in 2020.

Established in January 2019, the EITE Task Group undertakes additional focused consultations regarding the proposed Regulations. The task group is a forum for the Department to listen to and understand concerns brought forward by EITE sectors and to explore credit creation opportunities for EITEs under the proposed Regulations. There are approximately 40 members, composed of one representative from each industry association participating in the Clean Fuel Standard TWG, as well as company TWG members not otherwise represented. Industry associations who are not members of the TWG but who are EITE sectors were invited. In total, five meetings were held in 2019 and representatives were invited to attend the June 2020 TWG sessions.

Two Federal-Provincial-Territorial Working Groups were established as a forum for the Department to engage provincial and territorial counterparts on the development of the proposed Regulations. The first group is at the working-level and the second one is an Assistant Deputy Minister committee. Attendees included representatives from each province and territory. Five meetings were held in 2017, five meetings were held in 2018, three meetings were held in 2019 and two in 2020.

In addition to the specific committees mentioned above, the Department has conducted many ongoing bilateral meetings with interested parties and stakeholders since 2017. The proposed Regulations have also been raised within other forums, including the Multi-Stakeholder Committee on GHG Regulatory Measures and Programs and the Joint Working Group on the Future Vision for Canada’s Oil and Gas Industry. Overall, the Department has conducted hundreds of hours of bilateral meetings with provinces, territories, and individual stakeholders, in addition to participating and chairing formal committees.

Updates and engagement process since the 2019 Proposed Regulatory Approach

Since the Proposed Regulatory Approach was published in June 2019, the onset of the COVID-19 pandemic and further analysis of stakeholder feedback led to some updates to the design of the proposed Regulations. A key change relates to the CI stringency of the proposed Regulations. In June 2020, the Minister announced to the TWG that the stringency of the proposed Regulations would be changed in order to help mitigate the impacts of the COVID-19 pandemic on industry stakeholders and at the same time ensure that the proposed Regulations remain on track to deliver significant GHG emission reductions by 2030. The first three years of the proposed Regulations would see a reduction in stringency while the 2030 stringency has been increased from 10 gCO2e/MJ to 12 gCO2e/MJ. Other updates included more details on quantification methods, LUB criteria, the compliance fund mechanism and CCM, and a review process of the proposed Regulations. Material from these sessions is available upon request.

To inform these changes, two consultation sessions took place in June 2020 with the Federal-Provincial-Territorial Working Groups. Five consultation sessions were held in June 2020 with the TWG, and representatives from the Federal-Provincial-Territorial Working Groups and the EITE Task Group were invited to participate. These sessions included a focused session on updates to the CBA framework since February 2019. Following the June consultations, a session was held with the MSCC in July 2020 to present the proposed updates to the regulatory design. Bilateral meetings were also held throughout the summer of 2020 with stakeholders to further discuss their feedback on the updated regulatory design. Additionally, information sessions regarding LUB criteria, took place in July and August 2020 with Provincial and Territorial counterparts, as well as TWG members.

Engagement process for the development of the Lifecycle Analysis Model

To inform the development of the LCA Model which is required to support the implementation of the proposed Regulations, stakeholders have been engaged on this component since 2019. At the very initial stages of development of the Fuel LCA Model, stakeholders were engaged in reviewing the fossil fuel baseline values by participating in the CFS TWG and providing comments over the summer of 2019. Following this process, a critical review was carried out by a committee of technical and LCA experts that reviewed and commented on the methods and data used in the LCA of fossil fuel pathways to ensure conformity with lifecycle assessment requirements and guidelines set out in the ISO 14 040/44 standards by the International Standards Organization. Based on the critical review and stakeholders’ comments, the fossil fuel baseline values were updated.

An update on the Fuel LCA Model was provided during the summer of 2020 to the TWG, MSCC, EITE representatives and Federal-Provincial-Territorial Working Groups in a series of webinars and bilateral meetings. In winter 2021, TWG members will have the opportunity to review the methodological approach used to develop the default low carbon fuel CI values and provide comments. Comments from stakeholders would be considered in updates to the methodology and for the low carbon fuel CI values throughout the summer of 2021.

Prior to the public launch of the Fuel LCA Model, the Department will form a Steering Technical Advisory Committee (STAC) with membership from industry, academia, the Government of Canada, and ENGOs that have expertise in life cycle assessment, GHG quantification, and/or GHG credit trading schemes. The role of the STAC is to provide ongoing technical support and feedback with respect to the development, update, and maintenance of the Fuel LCA Model. In addition, a provincial and territorial committee will be formed to act as a forum for discussion regarding how the proposed Regulations would interact with existing provincial and territorial policies and programs, and to identify any additional needs provinces and territories may have in relation to the Fuel LCA Model.

CEPA National Advisory Committee consultations

In accordance with subsection 140(4) of the Canadian Environmental Protection Act, 1999 the Department offered to consult on the proposed Regulations with representatives from provincial, territorial and Indigenous governments through the CEPA National Advisory Committee.

Summary of key concerns

Stakeholders expressed a diverse range of views on the proposed Regulations, including concerns and recommendations on the various design elements outlined in the Proposed Regulatory Approach, preceding publications and the June 2020 consultations. A summary of the key issues is provided below.

Trajectory of the annual carbon intensity reduction requirement

A number of primary suppliers consulted were concerned that the annual CI reduction requirement in the 2019 Proposed Regulatory Approach was too high for the initial compliance year 2022, while others noted that the stringency overall was too high. Some argued that there was not enough lead-in time for new technologies and investments. In addition, primary suppliers expressed concerns about the potential for an insufficient supply of global biofuels, which would increase the risk of a shortfall of credits in the market. Primary suppliers and EITE stakeholders also recommended that the CI requirements be lowered for the first compliance year, compliance flexibilities (such as an earlier credit creation period, increased or unlimited cross-class credits trading) be expanded, and for a generic method for facility improvements to be established. These concerns have been reiterated during the ongoing COVID-19 pandemic period, as the oil and gas sector continues to face financial and liquidity challenges due to low oil prices.

Low carbon fuel producers (i.e. credit creators) and ENGOs recommended that the stringency of the annual CI reduction requirement should be increased, or extended beyond 2030 to provide a long-term signal for clean fuel investments. In general, stakeholders recommended that a safeguard mechanism be in place to address unprecedented events, such as a public health pandemic, to temporarily suspend or scale back requirements under the proposed Regulations.

The design of the proposed Regulations takes into account the cost impacts for regulated parties to comply with its requirements. To assist with the oil and gas industry’s recovery from the economic and financial impacts associated with the COVID-19 pandemic, changes were made to the CI reduction requirements outlined in the 2019 Proposed Regulatory Approach and the proposed design that was consulted on in June 2020. For example, the CI trajectory starts later and at a lower level. The CI reduction requirements would come into force on December 1, 2022, instead of on June 1, 2022. The Department also decreased the CI reduction requirement in 2022 from 3.6 gCO2e/MJ to 2.4 gCO2e/MJ. These adjustments are intended to give primary suppliers additional time to make investments to meet their CI reduction requirements. To ensure CI reduction requirements remain on track to deliver significant GHG emission reductions by 2030, the Department has increased the CI stringency in 2030 from 10 gCO2e/MJ to 12 gCO2e/MJ. This decision was taken after a careful review of the state of the oil and gas sector and expected emissions reductions outcomes from the proposed Regulations.

In addition, the proposed Regulations allow early credit creation for actions as of registration of the final Regulations. Based on the stringency in the CI trajectory for primary suppliers, an increasing number of oil and gas corporations are expanding, or are considering expansion into low-carbon fuels to comply with the proposed Regulations.

Compliance Category 1: Greenhouse gas reductions along the lifecycle of fossil fuels to reduce carbon intensity

Several primary suppliers raised concerns regarding the potential for limited credit creation opportunities to comply with the proposed Regulations. As such, they requested greater flexibility to meet their CI reduction requirements (see trajectory and market design comments above). However, ENGOs, low carbon fuel suppliers, and end-use fuel switching credit creators have recommended that credits created from Compliance Category 1 be limited to a certain percentage of the annual obligation in order to ensure market signals are created to incentivize investment in low-carbon fuels. Regarding the quantification methods for credit creation presented in the June 2020 consultations, primary suppliers recommended the inclusion of an energy efficiency quantification method. During these consultations, a technology penetration rate of 5% was first considered as one of the criteria used to assess additionality. In other words, if a certain project type has a technology penetration rate higher than 5%, a technological or financial barrier would need to be identified in order to meet the criteria for additionality. Some provinces and EITEs also raised concerns on the additionality assessment and its 5% penetration rate requirement, noting the assessment is not aligned with other compliance categories and that the penetration rate is too low. Primary suppliers also expressed concern that the five-year crediting period that was initially proposed for eligible projects other than carbon, capture and storage is too short and has the risk to restrict credit creation opportunities. Lastly, primary suppliers recommended that it be possible to create credits retroactively, as of July 1, 2017.

The Department has carefully reviewed all comments received on reducing GHG emissions and meeting CI reduction requirements. In response to primary suppliers’ concerns regarding there being too few credit creation opportunities, the Department is undertaking the development of a generic quantification method in order to incent early investments and innovative technologies. Furthermore, the decrease in the 2022 CI reduction requirement and roll over of compliance units from the RFR would result in no additional action being required on behalf of primary suppliers in the first year of the proposed Regulations coming into force. The CI reduction requirement trajectory would then increase slowly and linearly year-over-year to allow lead time for investments, and the trajectory would be revised in 2030 to reflect the declining CI of fuels. Moreover, the first review of the proposed Regulations would allow the Department to take stock of the current state of fossil fuels and their CIs.

Concerning stakeholders’ recommendation to put a limit on credits created from Compliance Category 1, the Department found that placing a credit limit on this category for projects that are undergoing an additionality assessment at the project type level would go against the principal goals of the proposed Regulations, which is to reduce the lifecycle CI of fossil fuels and achieve incremental reductions. It would also reduce the compliance flexibility of the proposed Regulations and would decrease the availability of credits in the market. However, placing a credit limit of 10% while developing separate and more streamlined additionality criteria at the project level for the generic quantification method would provide compliance flexibility while mitigating risks associated with the additionality assessment. Given that all other quantification methods would undergo the additionality assessment at the project type level, there is no credit limit on all other project types.

Concerning the quantification methods, the Department is now developing a generic quantification method. Projects such as energy efficiency, cogeneration, electriciation and methane reductions could be recognized under the generic quantification method (QM) provided they meet the eligibility criteria. Existing quantification methods would be eliminated as incremental technological innovation becomes business as usual and new quantification methods would be added as clean technology advances. Regarding the penetration rate of 5%, one of the criteria used to assess additionality in all quantification methods other than the generic quantification method, the Department has added an additional flexibility: the penetration rate must be less than 5% or no more than five facilities, which is appropriate. As long as one of these criteria is fulfilled, then no further assessment of additionality is needed, reducing burden. This added flexibility recognizes that in some sectors with few facilities, the 5% may be more easily exceeded and provides another option of no more than five facilities as an alternative threshold. On the crediting period, the Department changed the time period to 20 years with one renewal period of 5 years for carbon capture and storage projects and 10 years with one renewal period of 5 years for other projects to better align with existing provincial and federal regulations (such as the Alberta Emission Offset System) and carbon credit systems.

Compliance Category 2: Supplying low-carbon fuels

A number of low carbon fuel producers and ENGOs emphasized the need to have a strong demand signal for low carbon fuel investment, with concerns that the inclusion of compliance flexibility mechanisms (such as the compliance fund mechanism) and the adoption of Compliance Category 1 would impede this signal. Limiting compliance through Compliance Category 1, increasing the stringency of the CI target, or including a safety net that would review the level of compliance through this category in 2025 was recommended to support a market signal for low-carbon fuels. The Department expects that the stringency of the proposed Regulations in 2030 is high enough that there would be sufficient demand for biofuels (more detailed analysis on this is provided in the section on Benefits and costs).

Feedstock availability concerns were raised regarding the supply for low-carbon fuels, as well as concerns on indirect land-use change and implications to biodiversity. On feedstock availability, some primary suppliers and low carbon fuel producers highlighted a risk for low feedstock supply, in particular for advanced biofuels, and its implications for credit creation. They voiced concerns that existing technologies for advanced biofuels are not currently commercially viable and therefore could not significantly contribute to reducing liquid fossil fuel CIs. Some stakeholders also suggested the use of mass balance to align with other jurisdictions that have implemented regulatory requirements for credit creation.

The Department has reviewed all comments received relating to low-carbon fuels and feedstock and has considered their implications for the design of the proposed Regulations. The Department expects that there would be sufficient supply of low-carbon fuels to enable compliance with the proposed Regulations in 2030 (see section on Compliance Category 2: Supplying low-carbon fuels for more detail).

Land-use and biodiversity criteria

As a signatory to the international Convention on Biological Diversity, Canada is committed to responsible stewardship of its biological resources and to the United Nations 2030 Agenda for Sustainable Development. To prevent negative land use and biodiversity impacts from increased harvesting of feedstock for biofuel production, the Department released the proposed Land Use and Biodiversity (LUB) criteria for the proposed Regulations in April 2019. Only feedstocks that adhere to the LUB criteria would be able to create credits under the proposed Regulations.

Comments on the first iteration of the LUB criteria largely centred on preventing land-use change in areas with high carbon stock, how crops associated with high indirect land-use change (ILUC) would be treated, and how sustainable management of forest harvesting would be ensured. Some credit creators requested the inclusion of quantified CI factors to incorporate indirect land use change. A second draft of the criteria was published in August 2019.

The Department proposed several changes to the LUB criteria to the TWG in June 2020. Those proposed changes sought to strengthen some aspects of the LUB criteria, and to ensure the criteria are measurable and verifiable. The changes also added a list of feedstock types exempt from the LUB criteria, modified the material balance approach, and revised the definitions of forest, grassland, and wetland.

The proposed Regulations include additional changes made following the June 2020 consultation sessions with stakeholders. The June proposal prohibited credit creation for feedstocks harvested in any protected areas designated by international organizations. The proposed Regulations respond to recommendations from provinces and territories by limiting this restriction to protected areas designated by international organizations if they have been ratified by the national and sub-national jurisdictions in which the feedstock was harvested.

Other comments related to the risk of fraud related to the list of feedstocks not subject to the LUB criteria, citing experience in the EU where some feedstocks have been falsely claimed to be waste (which is not subject to the EU’s equivalent of the proposed LUB criteria). Some stakeholders requested that criteria be revisited that prevent credit creation for feedstocks harvested within 30 meters of a water body (i.e. in riparian zones). Many suggested that adherence to existing provincial riparian zone regulations should satisfy the LUB riparian criterion. On crop expansion requirements that prevent credit creation for feedstocks harvested in forests, wetlands and grasslands since 2008, the Department received comments noting that there is insufficient GIS data for the proposed 2008 baseline. Finally, several stakeholders recommended that the proposed Regulations recognize that adherence to provincial requirements for agriculture and forestry practices should satisfy all of the proposed Regulation’s LUB criteria, and aggregate compliance was also requested as an option for credit creators to come into compliance with the LUB criteria.

Following extensive discussions and analysis after the June 2020 consultation sessions, the Department made changes to its proposed LUB criteria requirements. The proposed Regulations provide that any land designated by an international agreement as protected must also be recognized by the jurisdiction to be considered ineligible land for the CFS feedstock harvesting. To address the risk of fraud, the proposed Regulations do not include the “waste multiplier” that is in the EU system to create additional incentives for the use of waste feedstock. For riparian zones, the proposed Regulations recognize national and regional riparian regulations that protect against adverse LUB impacts, include a grandfathering clause to allow credit creation for feedstocks harvested in any riparian zones that were harvested prior to 2020, and allow feedstocks from harvesting in forest riparian zones if the forest harvester has management practices in place to protect the riparian zones and related water bodies. For crop expansion requirements, the Department changed the baseline from January 2008 to January 2020 to better align with the first official signal of the proposed Regulations. As a response to concerns regarding burden and duplication created by the LUB criteria with provincial regulations, the proposed Regulations enable recognition of national or sub-national regulatory frameworks that align with the LUB criteria on a criterion by criterion basis.

Consultations with provinces and territories during the summer of 2020 led to refinement of the indicators that could be used to prove compliance with the LUB criteria in the event of an audit, and to the development of the information requirements for using an aggregate compliance approach in which all suppliers in a jurisdiction that has rules aligned with the LUB criteria would be deemed eligible.

Compliance Category 3: Specified end-use switching in transportation

Electric vehicle (EV) manufacturers, original equipment manufacturers (OEMs), and electricity utilities generally recommended that they would each be best suited as default credit creators for residential EV charging; however, charging network operators supported utilities as the default credit creator. Utilities highlighted that they are in a better position to understand the sources of electricity being supplied to the grid and the associated CIs. Utilities also believe they are best suited to promote EVs and to invest in infrastructure to support electrification while mitigating costs to the electrical grid and all end users of electricity. Alternatively, primary suppliers generally supported OEMs as default credit creators for EV charging under Compliance Category 3. That being said, OEMs expressed concerns that opportunities to create credits would not be significant, sustained, secure or predictable.

Overall, the majority of stakeholders are supportive of requirements that, in order to be eligible to create credits, home charging data must be accurately measured and of requirements to reinvest the credit revenue resulting from home charging data. Stakeholders were opposed to phasing out credit creation for residential EV charging, noting that would be premature to do so before adoption of EVs becomes common practice in the Canadian market. However, primary suppliers recommended that if they are a charging network operator and create credits for residential or public EV charging to satisfy a portion of their CI reduction requirement, there should be no reinvestment requirement associated with a credit that has not been sold. A few stakeholders recommended eliminating revenue reinvestment requirements altogether, and others suggested expanding the scope of reinvestment requirements to other activities such as education and awareness of EVs. Additionally, some stakeholders recommended expanding end-use fuel switching beyond transportation.

In June 2020, the Department presented a revised proposal for EV credit creation to stakeholders, which included a proposal to phase out residential EV charging credits from 100% in 2026 to 0% in 2030. The Department has reviewed the comments received and assessed the proposed June 2020 approach to end-use fuel switching in transportation. The proposed Regulations were updated to reflect comments received. The default credit creator for residential EV charging would be charging network operators for homes equipped with network-connected charging stations. Credit for residential charging of electric vehicles would be phased out by the end of 2035 for charging stations installed by the end of 2030. Any residential charging station installed after the end of 2030 would not be eligible for credits after 2030. In the proposed Regulations, parties that have the legal right to ownership of the data regarding the amount of electricity that is supplied to EVs and the time it is supplied through network-connected charging stations can create credits. Charging network operators would be required to reinvest 100% of the revenues generated from the sale of credits from residential and public EV charging in financial incentives for EV owners or buyers and expanding charging infrastructure in residential or public locations. There would not be revenue reinvestment requirements for primary suppliers that use their own credits to satisfy a portion of their reduction requirements.

Based on the Departmental analysis, EVs are expected to create the majority of end-use fuel switching credits, where the market can provide significant opportunities for credit creation. At this time, the Department is not considering extending end-fuel switching beyond transportation.

Many stakeholders expressed the desire for additional clarity around how energy efficiency ratio (EER) values were determined. EER values were developed to be representative of the types of vehicles in use in Canada, leading to credit creation based on a comparison to the vehicles being displaced. The EER values would be reviewed over time and may be updated as the energy efficiency of various technologies change over time, and as other more specific fuel and vehicle applications are introduced to the market.

Credit market design

Primary suppliers raised concerns over the credit market design, and the potential for credit shortages. As a way to address shortages in credit supply, primary suppliers recommended greater flexibility, including unlimited exchange of credits between different fuel classes, no restriction on credit banking and unrestricted use of the compliance fund mechanism. On the other hand, some credit creators raised concerns that a surplus of credits or compliance flexibilities would limit the demand for low-carbon fuels, affecting investments in this sector.

To reduce the risk of a credit shortage, the 2022 CI reduction requirement was lowered in comparison to what had been outlined in the June 2019 Proposed Regulatory Approach. A slow, linear increase of the CI trajectory over time is expected to allow sufficient lead time for investments. In addition, the proposed Regulations impose limits on the proposed flexible compliance options. These include a 10% limit of payment into the compliance fund mechanism, a 10% limit on the trading credits across fuel classes, and a 10% limit on carrying forward a credit obligation. These limits help ensure that a market signal supports investments in low-carbon fuels.

A number of stakeholders requested regular departmental reports on the proposed Regulations using aggregated indicators, such as credit totals, trades and average credit price. The Department plans to release reports using aggregated indicators.

Compliance flexibilities / market stability mechanisms

Credit Clearance Mechanism

Primary suppliers and some provinces raised concern that the price cap of the Credit Clearance Mechanism was too high, while low-carbon fuel suppliers, end-use fuel switching credit creators, and ENGOs noted the price cap was too low. Both stakeholder groups expressed concern that the price ceiling would affect market signals for investments in their respective sectors.

The Credit Clearance Mechanism serves to provide some price certainty to both primary suppliers and credit creators. The Department reviewed existing credit clearing mechanisms in other jurisdictions in the context of a Canadian market. The Department set a credit clearance ceiling price based on a review of credit costs expected in the credit market and the price cap of similar credit clearance mechanisms in California and Oregon.

Compliance fund mechanism

Primary suppliers and some provinces raised concerns that the price ceiling of the compliance fund mechanism is too high, while credit creators and ENGOs noted that the price ceiling is too low. Both stakeholder groups noted that the price ceiling would affect market signals for investments in their respective sectors. In addition, several provincial stakeholders recommended that revenues generated from the compliance fund mechanism be invested in relevant GHG emission reduction programs at the provincial and territorial level.

The compliance fund mechanism ceiling price represents an upper bound of credit costs expected in the credit market. It is expected that many compliance actions would be undertaken at lower cost.

Revenues from the compliance fund mechanism would be disbursed to applicable provincial and territorial programs that meet the criteria set out in the proposed Regulations.

Exemptions

Several stakeholders recommended that certain sectors be exempted from the proposed Regulations, including rail, marine and aviation. Stakeholders noted that these sectors represent a small portion of domestic consumption of fossil fuels, are subject to international standards, and cost-effective emission reduction pathways are largely non-existent. Alternatively, some stakeholders recommended credit creation under the proposed Regulations for domestic aviation fuel. There was a consensus among stakeholders for continued discussions on the proposed Regulations, the Output-Based Pricing System Regulations and international regimes, such as the International Civil Aviation Organization’s Carbon Offsetting and Reduction Scheme for International Aviation.

The International Maritime Organization adopted an interim strategy for GHG emissions in 2018, which will be reviewed in 2023. The Department supports the International Maritime Organization as the appropriate forum to address international maritime shipping emissions, and the work it has undertaken to address these emissions. Therefore, liquid fuels for international marine use would not be subject to the proposed Regulations. The International Civil Aviation Organization’s Carbon Offsetting and Reduction Scheme for International Aviation is mitigating GHG emissions from international aviation. The Government of Canada supports the International Civil Aviation Organization as the appropriate forum to address international aviation emissions, and the work it has undertaken to address these emissions. Therefore, jet fuel that is used for international flights would not be subject to the proposed Regulations. The treatment of domestic aviation fuels and credit creation for low CI aviation fuels is still under consideration, and is being examined in conjunction with carbon pollution pricing policies. However, aviation gasoline – the fuel that is used in smaller, piston engine aircrafts (e.g. a Cessna) – would not be subject to the proposed Regulations. According to the Department’s GHG inventory and projections from the Departmental Reference Case, the volume of aviation gasoline used in Canada is low (unlike jet fuel, for example) and its contribution to Canada’s overall annual GHG emissions is low. In addition, aviation gasoline certification bodies have not yet focused on suitable low CI gasolines for aviation use. Instead, they remain focused on finding unleaded aviation gasoline alternatives.

Regional implications

The Department received a number of comments from provinces and primary suppliers on regional implications under the proposed Regulations. Some concerns related to the limited access to biofuels and biogas in certain parts of Canada, with a particular emphasis on the challenges facing Newfoundland and Labrador relating to accessing these fuels. Recommendations were put forward to allow for regional exemptions (e.g. to exempt heating oil or not to apply a volumetric mandate), some of which are consistent with the RFR to address a combination of logistical issues, technical feasibility and cost concerns. The mining industry echoed some of the northern geographical implications, highlighting cost implications and competitiveness concerns from the proposed Regulations on their use of liquid fuels for on-site fleets or electricity generation.

The Department has carefully reviewed the regional implications of the proposed Regulations, and has considered the concerns raised by stakeholders during the drafting of the proposed Regulations. The proposed Regulations offer various flexible compliance options that do not require blending, and provide compliance options such as process improvements and buying of credits. Remote communities are exempted from the proposed Regulations, many of which are in northern jurisdictions. In addition, fuels produced in or imported into Newfoundland and Labrador are exempted from the volumetric mandate incorporated from the RFR, as there are limitations on low carbon fuel capacity. However, fuels produced in or imported to Newfoundland and Labrador would still be subject to the CI reduction requirements given that there are multiple ways to comply with the proposed Regulations (such as actions along the lifecycle) without having to blend low-carbon fuels. The proposed Regulations would apply to industrial use of fuel in remote communities, consistent with the federal carbon pollution pricing backstop system under the Greenhouse Gas Pollution Pricing Act.

Impact on industry and consumers

Several industry, provincial, and territorial stakeholders raised concerns over competitiveness and cumulative cost impacts on EITE sectors. Stakeholders are concerned Canadian EITEs would be disadvantaged compared to international competitors not subject to similar regulations. On cumulative impacts, concerns relate to increased costs for fossil fuel use, particularly for natural gas. EITE stakeholders recommended specific EITE protection mechanisms to minimize costs, carbon leakage and competitiveness impacts, such as credits to EITEs, decreased stringency in the liquid class for primary suppliers, or to not move ahead with regulating the gaseous and solid classes. During the consultation process, stakeholders requested to see in-depth analysis of the cumulative impacts of the proposed Regulations, along with other climate change regulations on EITE sectors. Primary suppliers also raised concerns over the impact of the proposed Regulations on consumers with respect to increased fuel prices for transportation and space heating.

The Department has completed an economic analysis within the RIAS which illustrates the economic impacts of the proposed Regulations across economic sectors and regions of Canada (more detail on this is provided in the section on benefits and costs). As EITE facilities are not primary suppliers, they are not directly regulated by the proposed Regulations and are therefore not eligible to create credits to mitigate against the increased costs. Under the proposed Regulations, some opportunities exist for the EITE sector to create credits, such as carbon capture and storage at a fertilizer plant or for a pulp and paper facility to use biogas from wastewater. The Department has also set a trajectory for the annual CI reduction requirement in the liquid class regulations that increases gradually until 2030, allowing for the banking of credits and lead time for investments to be made on clean technologies. The gradual phase-in approach of the proposed Regulations would present primary suppliers with the flexibility to choose the lowest cost compliance actions available.

Administrative burden

Many stakeholders raised concern with the potential for administrative burden and suggested reporting, validation, and verification requirements under the proposed Regulations be aligned with existing federal and provincial requirements, where possible.

The Department is developing a Credit and Tracking Solution (CATS) to facilitate and track registration, reporting, credit creation, credit transactions, and compliance of regulated parties who would participate in the proposed Regulations. This system is being developed on the same platform as the CATS for the Output-Based Pricing Regulations, allowing for some efficiencies related to system planning and implementation. The design of the online platform incorporates a robust Quality Assurance System of third party validation and verification to ensure the integrity of credits in the credit market.

Some stakeholders commented on the CI validity, recommending a longer lifespan of operational data to provide market certainty. Comments were raised as a response to the proposed 12-month operating data requirements in the Proposed Regulatory Approach. The Department has reconsidered its original approach on the CI validity period, and have proposed changes to address stakeholders’ comments. The proposed Regulation has a longer lifespan, requiring a 24-month operational period to obtain a final CI value. In addition, there is a shorter provisional qualification of 3 months for a temporary CI value.

Modern treaty obligations and Indigenous engagement and consultation

As required by the Cabinet Directive on the Federal Approach to Modern Treaty Implementation, an assessment of modern treaty implications was conducted on the proposal. The assessment did not identify any modern treaty implications or obligations since the proposal is outside of the subject matter scope covered in modern treaties.

Indigenous governments and groups were invited to participate in the extensive engagement process held with stakeholders throughout the development of the proposed Regulations. Overall, 15 Indigenous organizations were invited to participate in the MSCC meetings. During one of these meetings, a general question regarding credit creation opportunities was posed and answered. Additionally, one Indigenous organization joined the Technical Working Group and has had bilateral conversations with the Department on the CFS, including on the Fuel LCA Model. The Department will inform Indigenous groups of the opportunity to comment further upon publication of the proposed Regulations in the Canada Gazette, Part I.

Instrument choice

Development of the PCF involved the identification of a wide range of policy options for reducing GHG emissions, including the proposed Regulations to reduce the CI of fuels. The process for evaluating the instrument choice focused on options for how to reduce the CI of fuels. Consideration was given to four options: increase the stringency of carbon pricing, increase the stringency of the renewable fuels requirements under the RFR, propose a CI standard covering liquid, gaseous and solid fuels concurrently, or implement a phased CI standard approach first beginning with a CI standard for liquid fuels and with CI standards for gaseous and solid fuels to follow.

Market-based approach — Increasing the carbon price

Under the Greenhouse Gas Pollution Pricing Act, the federal carbon pollution pricing backstop system (the federal backstop system) implements a regulatory charge on fossil fuels as well as a regulated trading system for industry. The federal backstop system only applies in provinces and territories that request it or that do not implement a carbon pollution pricing system aligned with the stringency requirements set out in the federal benchmark. The fuel charge, which is generally payable by fuel producers or distributors, began at $20 per tonne of CO2e in 2019, and increases by $10 per year to $50 per tonne of CO2e in 2022. Carbon pricing sends an economic signal to emitters and offers them the flexibility to choose to make investments or make changes to their behaviour to lower their GHG emissions, or to continue to emit the same amount of GHGs and pay a fee for the pollution produced. There will be a review of the overall approach to carbon pricing by early 2022 and the design of the federal backstop system may be adjusted in response to this review.

The proposed Regulations would act as a complement to carbon pricing. Carbon pricing sends a broad signal across the economy to spur the lowest-cost GHG emission reductions wherever they may be found. At relatively low prices, the GHG emission reductions are likely to come from incremental changes such as energy efficiency improvements. However, the proposed Regulations would also send a targeted incentive to deliver transformational changes along the lifecycle of fossil fuels. The proposed Regulations would enable longer-term, higher-cost capital investments in measures needed to transition to a low-carbon economy, such as carbon capture and storage.

These policies would help individuals and businesses overcome barriers to behavioural change, thus achieving greater GHG emission reductions. While carbon pricing creates an incentive for individuals and businesses to reduce GHG emissions at a relatively low cost, without readily available and reasonably priced low-carbon goods and services, individual and collective behaviours may be slow to change. The proposed Regulations would increase the availability and use of lower-carbon fuels and alternative transportation technologies, supporting carbon pricing by providing individuals and businesses with a range of choices to lower their carbon footprint.

The proposed Regulations and carbon pricing would send mutually reinforcing price signals to individuals and businesses to induce action to reduce GHG emissions. In some cases, this mutually enforced market signal may even help to reduce costs for businesses. For example, some facilities would be covered under both the Output-Based Pricing System (OBPS) and the proposed Regulations (e.g. a refinery). If these facilities take actions to reduce emissions (e.g. by installing carbon capture and storage), they would pay less (or even create surplus credits) under the OBPS, and could also create credits under the proposed Regulations. This policy combination would create a stronger incentive to reduce GHG emissions than either policy on its own.

The way in which the proposed Regulations would lead to price impacts would be different from carbon pricing. Despite targeting higher-cost actions, the effects of the proposed Regulations on fuel prices would not necessarily be greater. Carbon pricing places a direct price on the carbon content of fuel (the amount of carbon emitted when the fuel is burned). By contrast, the proposed Regulations would affect fuel prices indirectly, by requiring fuel suppliers to support actions that reduce the carbon intensity of the fuel. The increased costs associated with the proposed Regulations would be the cost of these abatement actions, which would only need to be undertaken to the extent needed to reduce the CI to the required level, and need not apply to the entire quantity of fuel supplied.

Regulatory approach — Increasing the renewable fuel mandate, with CI reduction requirements

The RFR requires fuel producers and importers to have an average annual renewable fuel content of at least 5% based on the volume of gasoline and 2% based on diesel fuel and heating distillate oil that they produce or import respectively. The RFR require a renewable blend content but do not specify a CI requirement, which can vary depending on the feedstock utilized. Technical and economic blending barriers limit blending as a sole instrument in achieving reductions that would be enough to bring Canada closer to meeting its commitments under the Paris Agreement. The Department considered increasing the volumetric requirements under the RFR and adding CI reduction requirements for the renewable fuels. This approach was rejected on the basis that it was less flexible for regulated parties as it would not allow for low CI fuels that are not renewable (e.g. fuels produced from direct air capture and carbon recycling), nor other CI reduction methods (such as GHG emission reduction projects along the lifecycle of fuels, or end-use fuel switching).

Federal regulatory approach — CI standards for liquid fuels

The proposed Regulations would create clear and consistent CI reduction targets across Canada that would create incentives for emission reductions along the fossil fuel lifecycle by imposing stringent targets. The proposed Regulations would also complement the pan-Canadian approach to pricing carbon pollution by focusing on reducing the CI across the lifecycle of fossil fuels, thus driving additional GHG emission reductions from the oil and gas and transportation sectors. The design of the proposed Regulations includes elements of a market-based approach via the credit market, allowing regulated parties to buy and sell credits to facilitate compliance. This approach provides obligated parties with a feasible and flexible method to choose a CI reduction pathway that is suited for their circumstances and encourages new low-carbon technologies.

In June 2019, the Department published a Proposed Regulatory Approach for the CFS, which proposed a CI reduction requirement of 3.6 gCO2e/MJ in 2022 that would increase linearly to 10 gCO2e/MJ in 2030.footnote 20 However, since then the Department found that a higher stringency in the first few years of the proposed Regulations could make it difficult for stakeholders to comply given the COVID-19 pandemic and upon further analysis of stakeholder feedback. In order to help mitigate potential impacts from the COVID-19 pandemic, the first three years of the proposed Regulations would see a reduction in stringency in comparison to what was originally proposed in the June 2019 Proposed Regulatory Approach. However, in order to ensure that the proposed Regulations continue to deliver significant emissions reductions, the proposed 2030 stringency was increased from 10 gCO2e/MJ to 12 gCO2e/MJ.

Regulatory analysis

Under the proposed Regulations, primary suppliers (the regulated entities) would have an annual carbon intensity (CI) reduction requirement for the amount of liquid fossil fuel supplied domestically (gasoline, diesel, kerosene, and light and heavy fuel oils). The annual CI reduction requirement would become more stringent from 2022 to 2030, starting at 2.4 grams of carbon dioxide equivalent per megajoule (gCO2e/MJ) in 2022 and reaching 12 gCO2e/MJ in 2030 (see Table 1). A primary supplier’s annual reduction requirement would be expressed in lifecycle tonnes of carbon dioxide equivalent (tCO2e) and would be calculated on a company-wide basis, summing up the reduction requirements per liquid fossil fuel type for each production facility and for their total imports.

There are 39 companies that refine, upgrade or import liquid fossil fuels that would be regulated parties under the proposed Regulations. Of these, 12 companies own refineries and upgraders, 7 of which who also import. Roughly 95% of oil upgrading capacity is located in Alberta and the remaining 5% is located in Saskatchewan. About 34% of oil refining capacity is located in British Columbia, Alberta, Saskatchewan and Manitoba, while 43% is in Ontario and Quebec and about 23% in the Atlantic Provinces.footnote 21

The proposed Regulations would establish a credit market, where credits would represent a lifecycle emission reduction of one tonne of CO2e. For each compliance period, a primary supplier would demonstrate compliance by retiring the required amount of credits. Parties that are not primary suppliers would be able to participate in the credit market as credit creators (non-mandatory participants). Credit creators would include low-carbon fuel producers/importers (e.g. biofuel producers), electric vehicle charging site hosts, network operators, fueling station owners or operators, as well as parties upstream or downstream of a refinery such as an oil sands operator.

The proposed Regulations would have the following three main categories of credit-creating actions: (1) actions that reduce the CI of the fossil fuel throughout its lifecycle; (2) supplying low-carbon fuels; and (3) end-use fuel switching in transportation. A liquid class credit reference CI value would be used to calculate the amount of compliance credits created for low-carbon fuels and some end-use fuel switching.footnote 22 These are shown in Table 1 between 2021 and 2030. Interim fossil fuel CI values were used for this analysis and will be updated in the analysis presented alongside the final Regulations, when published in the Canada Gazette, Part II.footnote 23

Table 1: Annual liquid lifecycle CI reduction requirements for primary suppliers
  2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
CI reduction requirement
(gCO2e/MJ)
n/a 2.4 3.6 4.8 6.0 7.2 8.4 9.6 10.8 12.0
Liquid class credit reference CI value
(gCO2e/MJ)
90.4 90.4 89.2 88.0 86.9 85.7 84.5 83.4 82.2 81.0

Primary suppliers would be able to comply via the three main categories of credit creation. However, they may also comply by acquiring compliance credits from other credit creators, or by contributing to a compliance fund mechanism for up to 10% of their annual reduction requirement. The credit price under the fund would be set in the proposed Regulations at $350 in 2022 per compliance credit (CPI adjusted). Compliance credits created from certain activities that reduce emissions throughout the lifecycle of gaseous and solid fuels may also be used for up to 10% of the annual reduction requirement. A diagram of how the credit market would work is shown in Table 2 below (for illustrative purposes only).

Table 2: Illustrative diagram of credit market actions by participant

Participant

Action

Credit Calculation

Result

Primary suppliers
(Refinery / upgrader / importer)

Supply liquid fossil fuels (e.g. gasoline)

Annual CI reduction requirement

(gCO2e/MJ)

X

Fossil fuel supplied (MJ)

÷

1 000 000 (g/t)

Emissions (tCO2e)

=

Compliance deficits

Primary suppliers / companies upstream or downstream of a refinery

Reduce the carbon intensity of fossil fuel throughout lifecycle (e.g. process improvements)

Credit calculation is project-type specific based on GHG emissions reduced

Avoided emissions (tCO2e)

=

Compliance credits

Low-carbon fuel suppliers

(Producer / importer)

Supply low-carbon fuels (e.g. ethanol)

[Liquid class credit reference carbon intensity

-

Specific lifecycle carbon intensity value]

(gCO2e/MJ)

X

Energy supplied (MJ)

÷

1 000 000 (g/t)

Avoided emissions (tCO2e)

=

Compliance credits

Charging site hosts / network operators / fueling station operators or owners / low-carbon fuel suppliers

End-use fuel switching in transportation (e.g. electric vehicles, natural gas vehicles, hydrogen fuel cell vehicles)

[Energy Efficiency Ratio

X

Liquid class credit reference carbon intensity

-

Specific lifecycle carbon intensity value]

(gCO2e/MJ)

X

Energy supplied (MJ)

÷

1,000,000 (g/t)

Avoided emissions (tCO2e)

=

Compliance credits

Costs and benefits

It is estimated that credit creation from actions that are expected to occur in the baseline, such as credits from low-carbon fuels supplied for federal and provincial blending mandates, plus banked credits from previous years would be sufficient to fulfill the regulatory requirements for the first few years that the proposed Regulations are in force (2021 to 2025), as shown in Figure 1. By 2026, credits from incremental actions would be required, and it is estimated that 2027 is the last year in which banked credits would be used and the first year in which the fund would be accessed. In 2028, it is estimated that credits from emerging technologies would be required to fulfill the annual CI reduction requirement. The fund and emerging technology pathways represent the highest cost compliance options that are available when cheaper options have all been exhausted. Emerging technologies make up the difference between the amount of credits required and credits from known pathways. For this analysis, these actions are assumed to cost the same as the fund. The proposed Regulations reach full stringency in 2030 and credits created reach a peak of 28.2 million. Total credits created remain relatively constant at 2030 levels from 2031 to 2040.

Figure 1: Estimated credits required, created and banked, 2021–2040 (millions)

Figure 1: Estimated credits required, created and banked, 2021–2040 (millions) - description below

Figure 1 - Text version

Figure 1 illustrates a line graph, with the y-axis representing millions of credits, and the x-axis representing the year. The numbers in the y-axis range from zero to 30.0 million, in 5.0 million increments. The years on the x-axis range from 2021 to 2040. There are three lines on the graph; the first is a line representing the credits required. This line starts at zero in 2021 and has a positive slope until 2030, and, after 2030, this line flattens with slight fluctuations (positive and negative) over the following 10 years. The next line illustrates total credits created and banked. This line starts at 0.8 million credits in 2021, and has a positive slope from 2021 to 2024, a negative slope from 2024 to 2025, then a positive slope from 2025–2030. This is to illustrate that credits created plus banked credits in the initial years of the proposed Regulations are higher than the credits required. This line reaches a peak in 2030 and the line flattens between 2030 and 2040. The final line illustrates banked credits on their own to illustrate how much they contribute to the credit requirement. This line starts at zero in 2021, and has a positive slope until 2024 where it reaches a peak of 9.7 million credits. From 2024 to 2027, the slope of the line is negative as the stringency of the proposed Regulations increases over time and there is a drawdown of the credit bank until it goes down to zero in 2027 and stays at zero between 2027 and 2040. The numerical values presented in the image follow:

Year Credits created and banked (millions) Credits required (millions) Banked credits (millions)
2021 0.8 n/a n/a
2022 12.6 3.8 0.8
2023 19.3 9.6 8.8
2024 20.2 12.6 9.7
2025 18.3 15.6 7.6
2026 19.1 18.5 2.7
2027 21.1 21.1 0.6
2028 23.6 23.6 0
2029 25.9 25.9 0
2030 28.2 28.2 0
2031 28.1 28.1 0
2032 28.0 28.0 0
2033 28.0 28.0 0
2034 27.9 27.9 0
2035 27.9 27.9 0
2036 28.0 28.0 0
2037 28.0 28.0 0
2038 28.1 28.1 0
2039 28.2 28.1 0
2040 28.7 28.2 0

The most significant costs would be incurred in 2025, as firms start to draw down their bank of credits and have to make significant capital investments in order to comply with increasingly more stringent CI reduction requirements. Incremental GHG emission reductions are expected to begin in 2026 as incremental projects come online. In 2030, when the proposed Regulations reach full stringency, there would be GHG emission reductions of about 17.5 megatonnes of carbon dioxide equivalent (Mt CO2e). After 2030, it is estimated that GHG emission reductions would decline slightly to about 16.0 Mt in 2040. The compliance costs for the proposed Regulations are also estimated to gradually decline after 2030. This is because credits from actions expected to occur in the baseline rise over time as the CI requirement stays constant at 12 gCO2e/MJ, resulting in non-incremental baseline credits crowding out credits from incremental actions. The CI reduction requirements after 2030 will be subject to a review of the proposed Regulations and potential future amendments.

Figure 2: Incremental GHG emission reductions by year
Figure 2: Incremental GHG emission reductions by year - description below
Figure 2 - Text version

Figure 2 illustrates a bar graph, with the y-axis representing incremental GHG emission reductions ranging from 0 to 20.0 Mt CO2e, and the x-axis represents the year from 2021 to 2040. GHG emission reductions are at zero between 2021 and 2025 inclusive. There is a bar in 2026 with incremental GHG emission reductions estimated at 5.6 Mt. Between 2026 and 2030, the value of the bar gradually increases year over year to 17.5 Mt in 2030. From 2031 to 2033, the bars decrease year over year to 16.1 Mt in 2033. From 2033 to 2040, estimates fluctuate between 15.9 and 16.4 Mt. The numerical values presented in the image follow:

Year GHG emission reductions (Mt CO2e)
2021 0
2022 0
2023 0
2024 0
2025 0
2026 5.6
2027 8.5
2028 11.6
2029 14.5
2030 17.5
2031 17.0
2032 16.5
2033 16.1
2034 16.1
2035 16.2
2036 16.3
2037 16.3
2038 16.4
2039 15.9
2040 16.0
Figure 3: Present value net costs by year

Figure 3: Present value net costs by year - description below

Figure 3 - Text version

Figure 3 is a bar graph that illustrates the present value net costs to society per year. The y-axis represents present value net costs of the proposed Regulations in millions of dollars ranging from $0 to $6,000 million, and the x-axis represents the year, ranging from 2021 to 2040. There are no bars between 2021 to 2024 inclusive since the present value net costs are so small within this period, ranging from $6.9 million in 2021 to $5.5 million in 2024; these estimates are representative of industry and government administrative costs carried due to the proposed Regulations. In 2025, there is a large bar with net costs estimated at approximately $5,440 million dollars, which mostly represents capital costs carried. Net costs presented in the bars between 2026 and 2040 mostly reflect ongoing operating costs and savings. In the 2026 bar, net costs are estimated at approximately $1,021 million. From 2026 to 2030, the bars gradually increase year over year to about $1,513 million in 2030. From 2031 to 2040, the bars steadily decrease year over year to about $771.6 million in 2040. The numerical values presented in the image follow:

Year Present value net costs (millions of dollars)
2021 6.9
2022 5.4
2023 6.0
2024 5.5
2025 5,439.5
2026 1,021.1
2027 1,035.4
2028 910.0
2029 1,216.1
2030 1,513.4
2031 1,326.1
2032 1,147.0
2033 993.8
2034 954.9
2035 918.3
2036 884.1
2037 851.6
2038 820.3
2039 795.7
2040 771.6

Between 2021 and 2040, the cumulative GHG emission reductions attributable to the proposed Regulations are estimated to range from 173 to 254 Mt, with a central estimate of approximately 221 Mt. To achieve these GHG emission reductions, it is estimated that the proposed Regulations could result in societal costs that range from $14.1 to $26.7 billion, with a central estimate of $20.6 billion. Therefore, the GHG emission reductions would be achieved at an estimated societal cost per tonne between approximately $64 and $128, with a central estimate of $94.

To evaluate the results, a break-even analysis was conducted that compares the societal cost per tonne of the proposed Regulations to the departmental value of the social cost of carbon (SCC) published in 2016 (estimated at $50/tCO2), to more recently published estimates of the SCC value found in the academic literature, including recent updates to two of the main models relied on to develop ECCC’s 2016 estimated SCC. These recent estimates of SCC range between $135 and $440/tCO2. As a result, the Department concludes that, given the higher range of more recent SCC estimates, it is likely that the monetized benefits of the proposed Regulations would exceed its costs once the Department updates its SCC estimate.

The proposed Regulations would increase production costs for primary suppliers, which would increase prices for households and industrial users. Credit creation would also generate revenue for low-carbon energy suppliers, which would make low-carbon energy sources such as electricity relatively less expensive in comparison. This would lead to decreased end-use demand for fossil fuels and increased end-use demand for lower-carbon energy sources, thereby reducing national GHG emissions.

To evaluate the direct impact of the proposed Regulations as well as the effect of relative price changes on Canadian economic activity and GHG emissions, a macroeconomic analysis was completed. When price effects are taken into account, it is estimated that the proposed Regulations would result in up to 20.6 Mt of GHG emission reductions, with a slight decrease in GDP of up to 0.2% in 2030, using an upper bound scenario where all credits are sold at the marginal cost per credit.

Analytical framework

TBS guidance: The impacts of the proposed Regulations have been assessed in accordance with the Treasury Board Secretariat (TBS) Canadian Cost-Benefit Analysis Guide.footnote 24 Impacts have been identified, quantified and monetized where possible, and compared incrementally to a non-regulatory scenario.

Key impacts: The logic model in Figure 4 illustrates the incremental impacts of the proposed Regulations that the Department is able to quantify and monetize in this analysis. Compliance actions under the proposed Regulations would result in incremental domestic GHG emission reductions, net capital and operating costs for industry, as well as administrative costs for both industry and government. Compliance costs are also expected to have an impact on the demand for energy and therefore on economic output and emissions. Other impacts are assessed qualitatively.

The proposed Regulations would work in combination with other federal, provincial, and territorial climate change policies to create an incentive for firms to invest in innovative technologies and fuels by setting long-term, predictable and stringent targets. The broad range of compliance strategies allowed under the proposed Regulations would also allow fossil fuel suppliers the flexibility to choose the lowest-cost compliance actions available. If the proposed Regulations induce more long-term innovation and economies of scale than projected in the estimates presented in this analysis, then the proposed Regulations could result in lower costs and greater reductions, particularly over a longer time frame.

Figure 4: Logic model for the analysis of the proposed Regulations

Figure 4: Logic model for the analysis of the proposed Regulations

Baseline scenario: The baseline scenario assumes a status quo in which the proposed Regulations are not implemented. The baseline scenario is based on the most recent GHG emissions inventory and projections from the 2019 Departmental Reference Case. It includes the federal carbon pollution pricing backstop system (the federal backstop system), provincial carbon pricing policies, as well as the future impact of relevant policies and measures taken, or announced in detail by the federal, provincial and territorial governments as of September 2019.footnote 25 Therefore, the baseline scenario does not account for impacts associated with the COVID-19 pandemic. However, the extent to which COVID-19 may influence the results are qualitatively described. Independent industry and consumer actions to reduce GHG emissions have also been considered as part of the baseline scenario, to the extent possible (e.g. trends in electric vehicle uptake, trends in process improvements). An updated baseline scenario will be used when the final Regulations are published in the Canada Gazette, Part II.

Regulatory scenario: The analysis compares the expected impacts of the proposed Regulations (the regulatory scenario) to a scenario that assumes the proposed Regulations are not implemented (the baseline scenario). Societal costs are directly incurred as a result of the creation of compliance credits, not as a result of acquiring compliance credits in trade. Therefore, compliance credit purchases are a transfer payment between parties since a payment from one party to another is not considered a cost to society as a whole. Moreover, it is expected that some credit-creating activities taken under the proposed Regulations would be attributable (or partially attributable) to other federal and provincial policies or industry action that would have occurred in the absence of the proposed Regulations. Given this, it is expected that not all of these activities, and thus not all the costs and emission reductions associated with these activities, would be attributable to the proposed Regulations. All benefits and costs presented would be incremental to the baseline scenario, unless otherwise specified.

The regulatory scenario assessed in this analysis is of the proposed regulatory design that was presented to stakeholders in the June 2020 consultations. The Department has since updated the design of the proposed Regulations based on stakeholder feedback. Important changes that would affect the results of this analysis include the delay of the phase out on residential electric vehicle charging credits, which now starts in 2031 instead of 2027, and the coming-into-force date of the reduction requirements, which is now December 1, 2022, instead of June 1, 2022. The last compliance period for the Renewable Fuels Regulations (RFR) would be 2022, the final reporting and true-up period would be in 2023, and the RFR would be repealed in 2024. However, the June 2020 consultations had a final compliance period for the RFR in 2021, final reporting and true-up period in 2022, and repeal in 2023. Consequently, the one-time rollover of credits from the RFR would occur in 2023 instead of 2022. These changes could not be incorporated into this analysis in time for the Canada Gazette, Part I, publication. As a result, credit estimates for end-use fuel switching would be underestimated, banked credits would be underestimated, incremental actions may start later than estimated, capital expenditures would not be required as early as estimated, and incremental costs and GHG reductions would be overestimated. However, these changes are not expected to significantly change the results or the conclusions of the analysis (see section on uncertainty of impact estimates for more detail). These design changes will be incorporated into the analysis presented alongside the final Regulations, when published in the Canada Gazette, Part II.

Time frame of analysis: The time frame considered for this analysis is 2021 to 2040. Based on the design that was presented in the June 2020 consultations, the proposed Regulations are assumed registered in late 2021 and the first compliance year requiring reductions in the CI of liquid fossil fuels would be 2022, six months after the registration of the proposed Regulations. The annual CI reduction requirement would become more stringent between 2022 and 2030, starting at 2.4 gCO2e/MJ in 2022, reaching 12 gCO2e/MJ by 2030. A 2021 to 2040 time frame was considered sufficient for estimating most of the impacts, since GHG emission reductions are not expected to occur until 2026 and most of the costs are not expected to occur until 2025. Reductions and costs are also expected to decrease annually beyond 2030 as the annual CI reduction requirement stays constant at 12 gCO2e/MJ and non-incremental credits from actions expected to occur in the baseline rise over time, crowding out credits from incremental actions. The CI reduction requirements after 2030 will be subject to a review of the proposed Regulations and potential future amendments. Finally, forecasts of oil and natural gas prices and production are taken from the Canada Energy Regulator, which are available up to 2040.footnote 26

Monetary costs: All monetary results are shown in 2019 Canadian dollars, inflating non-2019 values (using GDP Deflator data), and converting non-Canadian prices (2019 exchange rates).footnote 27 When shown as present values, future year impacts have been discounted at 3% per year as per TBS guidance, and shown as present value in 2020.

Break-even analysis (BEA): The net results of the proposed Regulations are presented in terms of monetized impacts (costs and savings) and quantified GHG emission reductions, summarized as a societal cost per tonne attributable to the proposed Regulations. This result also represents an approximation of the carbon value that would allow the proposed Regulations to break even to ensure that benefits are at least equal to costs. To determine the plausibility of the break-even value associated with the proposed Regulations, the societal cost per tonne of the proposed Regulations is compared to the Department’s central SCC value published in 2016, and more recently published SCC estimates from the literature.footnote 28 This is because the recent academic literature shows that the SCC values currently used by the Department are lower than more recent estimates. For the break-even value to be plausible, it should fall within the range of these updated SCC values.

Lifecycle analysis versus national inventory accounting

The proposed Regulations would require CI reductions along the lifecycle of fuels. A lifecycle approach considers the GHG emissions involved in multiple stages of the fuel’s production process, from feedstock extraction or cultivation to fuel combustion. The lifecycle carbon intensity of fuels includes GHG emissions that occur over multiple years and in multiple sectors such as the emissions associated with the use of electricity inputs, fuel inputs, material and chemical inputs, transportation and land use change. This is fundamentally different from a national GHG inventory approach that quantifies GHG emissions from different industrial or economic sectors on an annual basis.

A national inventory approach accounts for emissions from imported finished fuels; however, it would only account for the portion of those lifecycle emissions occurring within Canada’s boundaries. This includes mainly the emissions from transporting, refining and processing the fuel, as well as its combustion in Canada. Lifecycle analysis (LCA) considers emissions from imported fuels that occur in other jurisdictions where it is produced. National inventory accounting is a standardized approach used by participating countries in the United Nations Framework Convention on Climate Change (UNFCCC). Using it enables comparisons between countries and provides a framework for the global accounting of emissions. The LCA approach is not concerned with national boundaries and seeks to quantify all emissions from the extraction or cultivation of the feedstock to the combustion of fuels. Compliance credits under compliance categories 1 and 3 would be created under the proposed Regulations using the LCA approach. Therefore, the number of compliance credits created for most credit-creating pathways would be estimated using LCA CI values. For Compliance Category 1, the number of credits created would be determined by a quantification method (QM) for each project type that is consistent with International Standard ISO 14064-2 entitled Specification with Guidance at the Project Level for Quantification, Monitoring and Reporting of Greenhouse Gas Emission Reductions or Removal Enhancements and published by the International Organization for Standardization.

The Department used the national inventory accounting approach in order to estimate incremental GHG emissions reductions, which is consistent with the Departmental reference case and international reporting requirements. Canada’s GHG inventory is developed, compiled, and reported annually by the Department, and is prepared in accordance with the UNFCCC reporting guidelines. Canada’s emissions projections in the Departmental Reference Case are based on end-use combustion emission intensities and include only domestic emissions. All emissions and removals attributed to direct land use change are excluded from the national emissions total.footnote 29

Pathway modelling and analysis

The proposed Regulations give primary suppliers flexibility in terms of how to comply. Given this, it is not possible to forecast and monetize all possible compliance pathways that may exist now and in the future. To assess the impacts of the proposed Regulations, a representative set of pathways for creating compliance credits were identified for each of the three categories of compliance credit-creation (actions that reduce the CI of the fossil fuel throughout its lifecycle; supplying low-carbon fuels; and end-use fuel switching in transportation).

To the extent possible, the representative credit-creating pathways used for analysis have considered what has occurred in other jurisdictions with similar policies (such as California’s Low Carbon Fuel Standard), as well as pathways that are technologically ready or commercially available today. The analysis attempts to identify the technical or economic barriers to achieving reductions under each credit-creating pathway in order to establish an upper bound estimate on the number of compliance credits that could be created for each pathway by 2030.

Some of the credits that would be created under the proposed Regulations would not be directly attributable to the proposed Regulations. These would count towards compliance but are not considered incremental in the analysis. Therefore, each potential pathway has been assessed in terms of compliance credits created, and incremental emission reductions and compliance costs through a partial equilibrium (or static) analysis. This analysis assumes that the demand for energy remains constant, and does not include energy price impacts on GDP and GHG emissions.

It is assumed that firms would choose the least-cost available credit-creating pathways in order to comply with the proposed Regulations and pathways are ranked in the order of estimated cost per credit. Low-cost pathways may be chosen in part because of other policies (e.g. existing fuel blending requirements), or existing trends (e.g. electric vehicle uptake), or because of industry innovations that may develop in the absence of the proposed Regulations (e.g. process improvements). As such, emission reductions and costs from these pathways would be considered as part of the baseline scenario and would not be attributed to the proposed Regulations (non-incremental). Therefore, estimates of total pathway compliance credits may under or overestimate the incremental impacts of the proposed Regulations. The analysis considers both estimates of compliance credits created and the likelihood of the attribution of their emission reductions and costs to the proposed Regulations. The representative compliance pathways and their likelihood of attribution to the proposed Regulations are presented in Table 3.

Table 3: Representative pathways and attribution to the proposed Regulations
Representative Compliance Pathway Attribution
Emerging technologies (e.g. co-processing) Incremental
Compliance fund Not quantified
Blending ethanol in the gasoline pool Incremental
Blending biodiesel/HDRD in the diesel and light fuel oil pools Incremental
Carbon capture and storage (CCS) Incremental
Refinery process improvements Incremental
Flaring or conserving methane emissions Some incremental
Existing projects announced after July 2017 and before the end of 2021 Non-incremental
End-use fuel switching to electric and natural gas/propane vehicles Non-incremental
Low-carbon fuels from existing blending mandates Non-incremental
Macroeconomic modelling

The proposed Regulations would increase production costs for primary suppliers, which would increase prices for households and industrial users. Conversely, credit creation would also generate revenue for low-carbon energy suppliers, which would make low carbon energy sources (e.g. electricity) relatively less expensive in comparison. This would lead to decreased end-use demand for fossil fuels and increased end-use demand for lower carbon energy sources. To evaluate the impact of price effects that the proposed Regulations could be expected to have on Canadian economic activity and GHG emissions, a macroeconomic analysis (or dynamic analysis) was completed using EC-PRO, the Department’s computable general equilibrium (CGE) model, and is presented as part of the distributional analysis of regulatory impacts.

Impacts from compliance categories

The proposed Regulations would have three main categories of credit-creating actions: (1) actions that reduce the CI of the fossil fuel throughout its lifecycle; (2) supplying low-carbon fuels; and (3) end-use fuel switching in transportation. The credit-creating actions have been assessed using representative pathways. Primary suppliers would also be able to comply by contributing to a compliance fund mechanism for up to 10% of their annual reduction requirement. The credit price under the fund would be set in the proposed Regulations at $350 (in 2022 nominal dollars) per compliance credit (CPI adjusted). The estimated impacts of these categories of credit-creating actions and the fund are described below.

Compliance credits created for some actions related to gaseous and solid fuels may be used for up to 10% of a primary supplier’s annual reduction requirement for liquid fuels each year. However, credits created for actions related to gaseous and solid fuels are not estimated in this analysis. If primary suppliers use gaseous and solid credits for compliance it is expected that they would only do so if they are less expensive to create than liquid credits.

Compliance Category 1: Actions that reduce the carbon intensity of the fossil fuel throughout its lifecycle

Parties may be able to take actions along the lifecycle of fossil fuels that reduce the CI of the fuel. These actions could be taken by primary suppliers (e.g. refinery/upgrader) and by credit creators upstream or downstream of a primary supplier (e.g. crude/oil sands producer), with the exception of carbon capture and use/storage, where the action can be taken by industrial facilities in addition to oil and gas facilities only for the GHG emissions associated with fuel combustion.

For Compliance Category 1, the number of credits created would be determined by a quantification method (QM), which specifies the eligibility criteria for the project as well as the approach for quantification. The Department would maintain a list of eligible quantification methodologies outside of the proposed Regulations. Projects would have to generate emission reductions that are real and incremental to a defined baseline (i.e. additional) to be able to create compliance credits. For all quantification methods other than the generic quantification method, this additionality would be assessed during the development of the quantification methodology. For the generic quantification method, additionality would be assessed at the project level. All quantification methodologies would be reviewed periodically for additionality, and maintained, modified or withdrawn accordingly.

The estimated compliance credits, costs, and reductions for representative credit-creating pathways in this category are presented below. Representative pathways for this category of credits include refinery process improvements, methane conservation at facilities covered by the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds: (Upstream Oil and Gas Sector) (the Methane Regulations), methane flaring at small facilities not covered by the Methane Regulations, carbon capture and storage and enhanced oil recovery.

Refinery process improvements

Refiners could implement process improvements at facilities to reduce the lifecycle CI of fuels. Based on a 2013 report by the California Air Resources Board (CARB), it is expected refiners could conduct the following project types to reduce their emissions shown in Table 4.footnote 30

Table 4: Possible refinery process improvement projects
Equipment type Project type
Boilers Projects associated with cogeneration, steam and combined cycle plants
Electrical equipment Projects dealing with electric motors powering air compressors, heating ventilation and air conditioning (HVAC) equipment, refrigeration equipment, pumps, fans, and other types of equipment
Stationary combustion Projects with stationary gas turbines
Steam equipment Projects dealing with steam motors powering air compressors, fans, or pumps
Thermal equipment Projects dealing with furnaces and heat exchangers
Other equipment Projects that did not fall into another category including refinery-wide projects and flare system projects

Credit-creation: Given a lack of detailed facility-level information, the degree to which these projects would be applicable in a Canadian context is unknown. This analysis therefore assumes that the technical potential and the costs for process improvements at Canadian refineries are the same as refineries in California. The cost and reduction estimates from the CARB report were obtained from industry reported information from refineries in California, and are not based on detailed engineering and cost analysis. The Department is undertaking the development of a generic quantification method for projects for which there is no applicable quantification method. For this quantification method, separate and more streamlined additionality criteria would be developed and assessed at the project level. Under the proposed Regulations, refinery process improvement projects that meet the additionality criteria would be eligible to create compliance credits in accordance with this quantification method. For the purpose of this analysis, any projects that cost below $50/tonne (in nominal 2022 dollars) based on the 2013 CARB report are not expected to meet the additionality criteria, and therefore are not expected to create compliance credits.footnote 31

It is estimated that credits from refinery process improvements would not be needed for compliance until 2026 since it is likely that there will be a sufficient quantity of credits from baseline activities and banked credits for meeting the annual CI reduction requirements between 2021 and 2025. As such, it is estimated that this pathway would create about 0.6 million compliance credits per year on average between 2026 and 2040.

Attribution: Since this pathway overlaps with carbon pricing, any projects that cost below $50/tonne are not expected to meet the additionality criteria, and therefore would not create compliance credits. Projects above $50/tonne are expected to be attributable to the proposed Regulations and would create compliance credits.

Incremental impacts: It is estimated that credits from this pathway are not needed until 2026; therefore it is assumed that capital costs are incurred in 2025. GHG reductions, and operating costs and cost savings would be incurred in 2026. Refinery process improvement projects are presented in Table 5 along with their associated capital costs, operating costs and cost savings, and GHG reduction estimates.

Table 5: Compliance costs (in millions) and reductions (Mt) by project typefootnote 32

Note: Values presented are undiscounted.

Project Type Capital Cost Annual Operating Cost Annual Operating Savings Annual Reductions
Boilers Optimize equipment operation/install additional units 110 0.5 (2.4) <0.1
Other equipment Install new equipment, renewable energy project, updated system 760 <0.1 (1.4) 0.6

Cumulative GHG emission reductions between 2021 and 2040 are estimated at 8.9 Mt. Over the time frame of analysis, this pathway would also result in total capital costs to industry of $751 million, total operating costs of $6 million, and total operating savings of $39 million. Therefore, it is estimated that this pathway would result in a total compliance cost to industry of about $717 million between 2021 and 2040.

Methane conservation at facilities covered under the Methane Regulations

In the baseline scenario, it is assumed that the federal Methane Regulations are in place nationally since equivalency agreements with provinces were being finalized at the time of this analysis and were not incorporated into Reference Case 2019. This will be updated in the analysis presented alongside the final Regulations, when published in the Canada Gazette, Part II. Under the Methane Regulations, facilities that are covered by the venting requirements would be subject to a venting limit and be required to conserve their gas or destroy their gas by flaring instead.footnote 33 However, under the proposed Regulations, facilities that would have flared under the Methane Regulations may now choose to conserve their gas. It is assumed that a facility would have flared if its gas production minus on-site fuel use is smaller than 750 000 m3 per year or if the facility is already selling less than 20 000 m3 of gas per year.

Credit creation: Under the proposed Regulations, methane reduction projects that meet the eligibility and additionality criteria of the generic quantification method would create compliance credits. The eligibility criteria for methane reduction projects are under development. For the purpose of this analysis, it is assumed that the incremental difference between flaring and conserving would count for credit under the proposed Regulations. Under this assumption, it is estimated that the maximum potential for compliance credits by 2030 is about 1.0 million per year from facilities in Alberta and Saskatchewan, assuming that all facilities that would have flared under the Methane Regulations choose this as a credit-creating pathway.

Attribution: Methane emissions are not covered by the Federal Backstop System, which applies in part in Saskatchewan, and they are not covered under Saskatchewan’s Management and Reduction of Greenhouse Gases (Standards and Compliance) Regulations.footnote 34 Thus, reductions incremental to the Methane Regulations in Saskatchewan could be attributed to the proposed Regulations. In Alberta, actions to reduce methane emissions can be used to comply with Alberta’s Technology Innovation and Emissions Reduction Regulation (TIER). It is expected that, on average, actions to conserve methane in Alberta would be less than $50/tonne and would likely be attributed to TIER. Therefore, it is assumed that actions in Alberta to reduce methane emissions through conserving gas are not attributed to the proposed Regulations.

Credits from baseline methane conservation in Alberta are estimated to start in 2022 in order to comply with TIER. Credits from incremental methane conservation in Saskatchewan are estimated to start in 2026 and 2027 since credits from baseline activities and banked credits would no longer be sufficient for meeting the annual CI reduction requirement. Therefore, credits for methane conservation are estimated at 0.2 million in 2022, increasing to 1.0 million in 2030, and decreasing to 0.8 million in 2040. Methane conservation in Saskatchewan heavy oil is estimated to be one of the highest cost pathways therefore, as non-incremental baseline credits from end-use fuel switching rise over time, high cost, incremental methane conservation credits are displaced.

Incremental impacts: Given the above, capital costs, operating costs, and GHG reductions are estimated to start in 2026 and 2027. Cumulative reductions for methane conservation between 2021 and 2040 are estimated at 11.7 Mt CO2e (about 0.8 Mt in 2030). The proposed Regulations would also result in some conserved gas, estimated at 173 petajoules (PJ). A reference price for natural gas, which adjusts the market price to account for transportation costs, was used to estimate society’s willingness to pay for this conserved gas. Alberta Energy Regulator estimates of the Alberta Reference Price were used, and these prices were then applied to the estimated quantity of methane that would be conserved.footnote 35 The value of conserved gas is estimated to be $898 million over the time frame of the analysis.

It is estimated that about 7,300 facilities would be affected between 2026 and 2040, including new facilities estimated to come online. Therefore, capital costs would be incurred each year by all affected facilities to conserve gas by installing a vapour recovery unit, which is estimated to average about $180,000 per facility.footnote 36 Some facilities in Saskatchewan are also expected to incur capital costs related to pipeline infrastructure, assumed at $600,000.footnote 37 The annual operating cost per facility is estimated at $9,000 per facility. Over the time frame of analysis, total capital costs for this pathway are estimated at $1,600 million and total operating costs are estimated at $105 million. Overall, it is estimated that this pathway would result in a total compliance cost to industry of about $1,705 million between 2021 and 2040.footnote 38

Methane flaring at small facilities not covered under the Methane Regulations

In the baseline scenario, it is assumed that the federal Methane Regulations are in place nationally. Some small facilities are not covered under the Methane Regulations and are not required to reduce vented gas in the baseline scenario. In the regulatory scenario, it is expected that these small facilities could choose to flare or conserve their gas under the proposed Regulations. The incremental difference between venting and flaring/conserving methane emissions could count for credit as part of the proposed Regulations.

Credit-creation: It is assumed that the incremental difference between venting and flaring at small facilities would count for credit under the proposed Regulations. It is estimated that credits from this pathway would not be needed for compliance until 2026 since credits from baseline activities and banked credits would no longer be sufficient for meeting the annual CI reduction requirement. As such, credits for methane flaring are estimated at 1.2 million in 2026, increasing to 1.3 million in 2030, and increasing further to 1.7 million in 2040 as new facilities come online. These estimates represent the maximum potential for compliance credits from small facilities in Alberta and Saskatchewan, assuming that all facilities choose this as a credit-creating pathway.

Attribution: Methane emissions are not covered by the Federal Backstop System, which applies in part in Saskatchewan, and they are not covered under Saskatchewan’s Management and Reduction of Greenhouse Gases (Standards and Compliance) Regulations. Thus, flaring at small facilities in Saskatchewan could be attributed to the proposed Regulations. Flaring at small facilities in Alberta would also be attributed to the proposed Regulations because they are not covered under the Methane Regulations and cannot be used to comply with TIER.

Incremental impacts: Capital costs, operating costs, and GHG reductions are estimated to start in 2026. Cumulative reductions between 2021 and 2040 from this pathway are estimated at 21.8 Mt CO2e and it is estimated that about 29 100 facilities would be affected between 2026 and 2040. This includes existing and new facilities estimated to come online. Therefore, capital costs would be incurred each year by affected facilities in order to install a flare or incinerator to destroy the gas, estimated at $75,000 on average per facility.footnote 39 Annual operating costs associated with ongoing operation and management are estimated at $300 per facility to flare.footnote 36 Over the time frame of analysis, total capital costs for this pathway are estimated at $1,606 million and total operating costs are estimated at $40 million. Overall, it is estimated that this pathway would result in a total compliance cost to industry of about $1,646 million between 2021 and 2040.

Carbon capture and storage and enhanced oil recovery

Carbon capture and storage (CCS) captures CO2 emissions from industrial facilities before they are released into the atmosphere. Once captured, the CO2 is compressed and transported to a storage site, where it is injected underground in geological formations. The CO2 captured can also be used for other purposes, often referred to as carbon capture, utilization and storage (CCUS). For example, CO2 can be used as an additive to improve the integrity of products such as cement. A common subset of CCUS is enhanced oil recovery (EOR), which is a process that injects CO2 underground into mature oil fields to increase the amount of oil that can be recovered from an oil reservoir while storing CO2 underground.

Two quantification methodologies are under development under the proposed Regulations for CCS and EOR projects. Credits could also be created for CCS and EOR projects that capture combustion emissions from industrial facilities in addition to oil and gas facilities. To mitigate credit liability, a percentage of credits would be held back to cover risks of potential future leaks. The proposed Regulations would apply a 0.5% discount factor for CCS credits that would never be returned to the project proponent.

Credit-creation: It is expected that about 1.3 million credits per year would be created from CCS/EOR projects that were announced after July 2017 but would be created after registration of the final Regulations. These actions would create early credits in the initial years of the proposed Regulations.

There is a significant amount of uncertainty in the estimation of future CCS/EOR projects. CCS projects tend to have high capital costs that often vary by project, and are dependent on the depth of storage, storage site, and the method and materials required to capture and store carbon. According to the Global CCS Institute, the cost per tonne of CO2 avoided in Canada could range from $40 to $260 depending on the sector. Costs of CCS can be reduced if there is opportunity for EOR; however, there also tends to be some technical uncertainty when implementing projects (e.g. issues with the amine solution at the Boundary Dam facility for the first few years of development).footnote 40

It is assumed that 3 million credits per year from additional CCS projects could come online before 2030. This is based on 2017 data from the Greenhouse Gas Reporting Program on facilities located near potential storage sites in the Alberta Industrial Heartland.footnote 41 Technically, while there is potential to exceed this estimate, high upfront costs and technical uncertainties could limit the development of new CCS/EOR projects, at least during the initial years of implementation of the proposed Regulations. It is reasonable to expect that there would be some increased CCS/EOR capacity in the long-term as the proposed Regulations ramp up in stringency and demand for credits increase.

It is estimated that incremental credits from CCS/EOR projects would start in 2026 since baseline and banked credits would no longer be sufficient to fulfill the annual CI reduction requirement. As such, it is estimated that these projects would create about 1.3 million credits in 2022, rising to 4.3 million in 2030, and are assumed to remain constant at 2030 levels between 2031 and 2040.

Attribution: Any CCS/EOR projects announced after July 2017 but before the final proposed Regulations are registered in 2021 are not considered incremental as they are expected to be attributable to federal and provincial subsidy programs. Since CCS/EOR projects tend to have high, upfront capital cost barriers and technical uncertainty, CCS/EOR projects are unlikely to occur without regulatory incentives. Credits from the proposed Regulations are expected to provide enough of an incentive such that CCS/EOR projects announced after the coming into force date of the proposed Regulations would be considered attributable to the proposed Regulations.

Incremental impacts: Cumulative reductions between 2021 and 2040 are estimated at 45 Mt. The estimated capital cost of CCS/EOR is about $1,250 million on average per Mt of annual CO2 sequestered capacity. This estimate is based on data from large-scale CCS/EOR projects that have been completed in Canada and the U.S.footnote 42 These projects were the first few of their kind in the U.S. and Canada, and it is expected that future projects could have lower costs as the technology matures.footnote 40 However, declining technology costs have not been modelled given that there is uncertainty as to how much technology costs may decline over time. It is assumed that the operating costs for a given year are 4% of the capital costs (about $50 million annually per tonne of CO2 sequestered).footnote 43 There could be substantial cost savings from projects that use EOR. However, due to a lack of data on the potential for oil recovery from such projects, the cost savings have not been modelled. Total capital costs for this pathway are estimated at $3,239 million and total operating costs are estimated at $1,547 million over the time frame of analysis. Overall, it is estimated that this pathway would result in a total compliance cost to industry of about $4,786 million between 2021 and 2040.

Compliance Category 2: Supplying low-carbon fuels

Low-carbon fuel producers and importers (the default credit creators) would create credits by supplying low-carbon fuels for use in Canada. Based on similar policies in other jurisdictions (e.g. British Columbia, California), the most-likely representative pathways under this category would be to increase the supply of the following low-carbon fuels: ethanol in gasoline, biodiesel in diesel and light fuel oil (LFO), hydrogenation-derived renewable diesel (HDRD) in diesel and LFO.footnote 44, footnote 45

Technical and economic blending barriers

The United States Environmental Protection Agency (EPA) has registered ethanol blends of up to 15% (E15) as a fuel for use in model year 2001 and later for new cars, light-duty trucks, and medium-duty passenger vehicles. Therefore, it is expected that the future vehicle fleet in Canada could handle E15 by 2030 as a pathway under the proposed Regulations.footnote 46

For biodiesel, the majority of North American engine manufacturers endorse up to a 5% biodiesel in diesel blend (B5). The Engine Manufacturers Association issued a technical statement indicating biodiesel use up to B5 should not cause engine or fuel systems problems.footnote 47 As biodiesel is more widely tested and used, manufacturers would be in a better position to support the use of higher blends. Warranty coverage of B20 and higher is offered by select manufacturers under specific conditions. However, similar to the use of regular diesel, some manufacturers may limit the scope of their warranties by stating that failures from the use of any fuel cannot be attributed to a factory defect. Therefore, the cost of repair under these circumstances (if any) would not be covered by certain warranties. As a result, it is expected that the future vehicle fleet in Canada could handle biodiesel blends of up to 5% by 2030.footnote 48

HDRD is a drop-in fuel, with properties indistinguishable from those of petroleum diesel. It has been successfully tested up to a 50% blend at various climate conditions in existing diesel-fuelled engines.footnote 49 However, HDRD currently competes with biodiesel for feedstock and is more costly to produce than biodiesel and petroleum diesel.footnote 50 Domestic HDRD consumption in 2017 was 250 million litres. HDRD is not produced domestically and global production in 2017 of HDRD was only about 4 billion litres per year.footnote 51, footnote 52 Given this, it may be more reasonable to expect HDRD blends closer to about 6% (or about 1.3 billion litres of additional HDRD) by 2030. This would require the construction of roughly three new HDRD facilities by 2030, either in Canada or globally.

Domestic production versus imports of low-carbon fuels

The proposed Regulations are expected to provide market signals that would increase the demand for low-carbon fuels in Canada. Additional volumes are expected to be met with a combination of increased domestic production and imports. The proposed Regulations do not differentiate between domestic and imported low-carbon fuels in how credits are created. The proposed Regulations would require the use of the Fuel Life Cycle Assessment Tool to calculate facility-specific CI values, and the same requirements would apply to imported low-carbon fuels. Therefore, the lower the CI value a low-carbon fuel has on a lifecycle basis, the more credits the low-carbon fuel producer or importer would obtain. Existing producers and importers of low-carbon fuel in Canada are expected to benefit from the demand created by the proposed Regulations.

Between 2013 and 2017, domestic production of ethanol has been approximately 1.8 billion litres per year, while domestic consumption in the same period has been between 2.8 to 3.0 billion litres per year. The difference has been met by American ethanol imports.footnote 53 The United States has a projected surplus for ethanol in 2030, estimated at 6 billion litres.footnote 54 Midwestern states have enacted regulations to promote ethanol production as an indirect measure to support local farming.footnote 55 Currently, Brazil is the largest importer of ethanol from the United States, followed by Canada. Given these factors, it is possible that Canada could import additional volumes of ethanol needed (about 2.8 billion litres) to achieve E15 under the proposed Regulations.

Approximately 1 billion litres of additional biodiesel would be required to achieve a 5% blend rate in 2030. Domestic biodiesel demand in 2017 was approximately 550 million litres. Canada currently produces enough biodiesel domestically to meet this demand at about 600 million litres. However, Canadian producers exported 300 million litres to the United States in order to take advantage of tax incentives available there for low-carbon fuels. The remaining domestic demand for biodiesel was imported.footnote 51 Importing the required quantities is possible; however, if this pathway is taken, regulated parties may have to pay a higher price for biodiesel. In addition, given the current lack of domestic HDRD production in Canada, it is reasonable to expect that additional volumes of HDRD would be imported, at least in the initial years of the proposed Regulations.

Given the availability of imports and the capital cost barriers involved with a rapid scale up in domestic supply, the analysis assumes for simplicity that additional volumes of ethanol, biodiesel and HDRD supply would be met by imports. Nonetheless, it is reasonable to expect that there would be some increased domestic production in the long-term as the proposed Regulations ramp up in stringency and demand for low-carbon fuels increase. This would provide a stronger and more reliable signal to investors with regard to de-risking capital investments. In addition, if the CI value of domestically produced low-carbon fuels are lower than imported low-carbon fuels, this would provide an additional incentive for domestic production.

Credits created from supplying low-carbon fuels

Credits would be given to low carbon fuel producers and importers for the amount of low-carbon fuel supplied in Canada and would be issued using an LCA approach. The same volume of renewable fuel used to meet federal and provincial volumetric blending requirements and low carbon fuel standards may be used to create credits under the proposed Regulations.

The regulatory scenario assumes that by 2030, the ethanol content in gasoline increases to 15%, and biodiesel and HDRD content in diesel and LFO increases to 5% and 6% respectively on a volumetric basis, up from baseline levels. Credits are estimated by multiplying the amount of energy supplied under the regulatory scenario by the difference between the liquid class credit reference values (shown in Table 1 above) and the carbon intensity of the low-carbon fuel. For the purpose of this analysis, interim national average LCA CI values are used in the calculation of credits and are estimated at 49 gCO2e/MJ for ethanol, 26 gCO2e/MJ for biodiesel and 29 gCO2e/MJ for HDRD.footnote 56 These LCA CI values were determined based on Canadian data and other lifecycle assessment tools, and were compared to fuel pathways submitted to British Columbia and California.

Table 6 shows the amount of fossil and low-carbon fuels supplied in Canada in the regulatory scenario between 2021 and 2030. In 2022, it is estimated that there would be 130 PJ of low-carbon fuel supplied in Canada. In 2026, credits from baseline activities and banked credits would no longer be sufficient to fulfill the annual CI reduction requirement. Therefore, it is estimated that biodiesel blending in diesel and LFO would increase above baseline levels in 2026 (at 142 PJ) while ethanol blending in gasoline and HDRD blending in diesel and LFO would increase above baseline levels in 2027 (at 180 PJ). Blend levels are assumed to increase linearly to the assumed blend rates in 2030 (at 293 PJ). The annual supply of low-carbon fuels remains relatively constant at 2030 levels between 2031 and 2040.

Table 6: Fossil and low-carbon fuels supplied in the regulatory scenario (PJ)

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

  2021–2025 2026–2029 2030 2031-2040 Total
Gasoline 6 597 4 821 1 129 11 029 23 577
Diesel 5 858 4 494 1 071 10 850 22 273
LFO 304 214 49 458 1025
Ethanol 418 439 152 1 489 2 498
Biodiesel 119 178 64 643 1 004
HDRD 119 177 76 764 1 136

The proposed Regulations would provide incentive for low carbon fuel suppliers to obtain more credits by reducing the CI of the low-carbon fuels they supply. The reduction of the CI values of low-carbon fuels in California’s LCFS system has been demonstrated since the program began in 2011. This is partly due to lowering of the CI of the electricity grid in California, improved agricultural practices, increased efficiency in production, as well as the use of lower CI feedstocks.footnote 57 However, there is uncertainty as to how much the CI values of these fuels might decline over time. Therefore, it is assumed that the lifecycle CIs of low carbon fuels remain constant over time. Uncertainty around how CI values may change over time is addressed in the uncertainty of impact estimates section.

Table 7 shows the total number of credits estimated for supplying low-carbon fuels by fuel type between 2021 and 2030. Primary suppliers who have surplus compliance units under the RFR would be able to convert these units into credits under the proposed Regulations. Therefore, there would be a one-time rollover of credits from the RFR in 2022 estimated at 1.4 million based on departmental data from the RFR (as presented to stakeholders in the June 2020 consultations). In 2022, credits from low-carbon fuel blending are estimated at 6.4 million, increasing to 6.5 million in 2026, to 8.1 million in 2027, and 12.4 million in 2030. Between 2031 and 2040, annual credits for supplying low-carbon fuels remain relatively constant at 2030 levels.

Table 7: Credits from low-carbon fuels by fuel type (millions)

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

  2021–2025 2026–2029 2030 2031–2040 Total
Ethanol 13.6 15.2 4.9 47.6 81.3
Biodiesel 6.2 10.4 3.6 36.0 56.3
HDRD 5.8 9.7 4.0 39.8 59.2
Total 25.6 35.4 12.4 123.4 196.8
Attribution of supplying low-carbon fuels to the proposed Regulations

In the baseline scenario, the federal RFR requires petroleum producers and importers to have an annual average of 5% renewable fuel content in gasoline (met with ethanol) and 2% renewable fuel content in diesel fuel and heating distillate oil (met with biodiesel and HDRD) based on volume. Some provinces blend at higher rates due to their own renewable fuel requirements and low carbon fuel standards, which have increased the national average blend rate up in recent years beyond the levels required under federal regulatory requirements. The same volume of renewable fuel used to meet these federal and provincial regulations may be used to create a credit under the proposed Regulations. Given that these actions would have occurred in the absence of the proposed Regulations, they would not result in incremental costs or GHG emissions reductions.

In the absence of the proposed Regulations, the likelihood of increased blending above existing federal and provincial blend requirements and policies is low, since it is generally more expensive to blend low-carbon fuel with fossil fuel. Given this, the increased use of low-carbon fuels above baseline levels is expected to be attributable to the proposed Regulations. Therefore, costs and associated emission reduction benefits that are expected to occur above baseline levels would be attributable to the proposed Regulations.

GHG benefits of blending low-carbon fuels

Blending higher levels of low-carbon fuel with fossil fuel is expected to result in increased domestic GHG emissions reductions. To estimate emissions reductions, it is assumed that the fuel used in Canada remains constant on an energy basis between the baseline and regulatory scenarios. For example, the regulatory scenario assumes an additional 152 PJ of ethanol in 2030 compared to the baseline scenario. As a result, the regulatory scenario also assumes that the energy demand for gasoline is reduced by 152 PJ compared to the baseline scenario. Therefore, the incremental amount of fossil fuel displaced is equal to the amount of incremental low-carbon fuel supplied on an energy basis.

Table 8 shows the estimated incremental amount of low carbon fuel supplied domestically due to the proposed Regulations. In the regulatory scenario, it is expected that low-carbon fuel blending would increase above baseline levels by 2026 given that credits from baseline activities and banked credits would no longer be sufficient to fulfill the annual CI reduction requirement. Incremental blending is assumed to increase linearly from 2026 to 2030, reaching the assumed blend rate in 2030. Between 2031 and 2040, annual incremental low-carbon fuel supplied remains relatively constant at 2030 levels.

Table 8: Incremental low-carbon fuel supplied by fuel type (PJ)

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

  2021–2025 2026–2029 2030 2031–2040 Total
Ethanol 0 101 67 648 816
Biodiesel 0 74 37 367 478
HDRD 0 73 49 488 610
Total 0 247 152 1 504 1 904

Incremental domestic emissions reductions were quantified by subtracting the estimated emissions in the baseline scenario from emissions in the regulatory scenario. Emissions for each scenario were calculated by multiplying end-use combustion emission intensities by the amount of fuel supplied domestically in each scenario. This is equivalent to multiplying the incremental low-carbon fuel supplied by the difference between the emission intensity for fossil fuels and the emission intensity for low-CI fuels. The weighted national average emission intensities used for each fuel are presented in Table 9 (from the Departmental Reference Case). For more information on the difference between lifecycle carbon intensities and combustion emission intensities, please refer to the section above on lifecycle analysis versus national inventory accounting.

Table 9: Combustion emission intensity values by fuel type (in gCO2e/MJ)
Fuel type Emission intensity value
Gasoline 71.67
Diesel 71.73
LFO 71.16
Ethanol 2.40
Biodiesel/HDRD 5.92

It is estimated that the incremental GHG emissions reductions are about 128 Mt over the time frame of analysis from blending low-carbon fuels with fossil fuels. GHG emission reductions are shown in Table 10, by blend pathway.

Table 10: Total GHG emissions reductions by blend pathway (in Mt CO2e)

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

Blend pathway 2021–2025 2026–2029 2030 2031–2040 Total
Ethanol in gasoline 0 7.0 4.6 44.9 56.5
Biodiesel and HDRD in diesel 0 9.2 5.4 53.9 68.5
Biodiesel and HDRD in LFO 0 0.5 0.3 2.5 3.2
Total 0 16.7 10.3 101.3 128.2
Costs of blending low-carbon fuels

To meet increased low-carbon fuel demand due to the proposed Regulations, terminals would have to store fossil fuels with higher volumes of low-carbon fuel. It is expected that they would incur capital and operating costs to install or upgrade infrastructure (such as the installation of additional storage or shipping capacity). There are approximately 87 primary terminals in Canada, about 43 have blending capacity and about 44 are without blending capacity.footnote 58 Based on stakeholder consultations, costs to upgrade facilities with E15 blending capacity are estimated at $2 million per site and costs to upgrade facilities without blending capacity would cost around $10 million per site.

For biodiesel, it is estimated that approximately 25 primary terminal sites would need additional/new biodiesel blending capacity. About half of the biodiesel sites would be required to re-utilize tanks and equipment at an average cost of about $5.5 million per site, and the other half would be required to build a new tank for an additional $2 million per site ($7.5 million). In addition, it is estimated that approximately five primary terminal sites would require tankage and piping work for HDRD receipt and blending at about $5 million per site.footnote 59 It is assumed that it takes two years to build out terminal infrastructure.footnote 60 Therefore, capital costs for terminals are incurred in 2025 and 2026. It is estimated that total capital costs for terminals would be about $644 million over the time frame of analysis.

Retail and cardlock fuelling stations would have to provide blended fuel to end users. It is assumed that fuelling stations are currently equipped to handle up to 5% biodiesel. For ethanol, it is assumed that any new retail gas stations built after 2016 would be E15 compatible. As of 2015, there were about 11 900 retail gas stations in Canada.footnote 61 To blend up to E15, existing retail gas stations would need to either repurpose existing tanks and add a dispenser (low cost), or install a new tank and dispenser (high cost). The number of facilities that would need to repurpose or install new tanks and dispensers is unknown. Therefore, an average capital cost was used and estimated at $79,100 per retail station.footnote 62 It is assumed that it takes two years to build blending infrastructure at retail gas stations.footnote 60 Therefore, capital costs to retail gas stations are incurred in 2025. Total capital costs for retailers are estimated to be about $800 million over the time frame of analysis.

To blend higher levels of low-carbon fuel with fossil fuel, refiners and terminals would also incur net incremental operating costs for supplying low-carbon fuels, estimated at $9,922 million between 2021 and 2040. Net incremental operating costs to supply low-carbon fuels were calculated by subtracting the incremental fossil fuel production cost savings by the incremental low-carbon fuel costs. To obtain incremental fossil fuel production cost savings, wholesale fossil fuel prices were applied to the incremental amount of fossil fuel displaced. To obtain incremental low-carbon fuel costs, wholesale low-carbon fuel prices and ongoing transportation costs were applied to the incremental amount of low-carbon fuel supplied.

To calculate wholesale prices, data from the Kent Group on average fossil fuel price margins by province between 2015 and 2019 were used to determine the differential between wholesale fuel prices and retail fuel prices.footnote 63 The Canadian average differential between wholesale and retail fuel prices is estimated at 43% for the gasoline pool and 38% for diesel pool. These wholesale price differentials were then applied to retail fossil fuel price forecasts from the Departmental Reference Case in order to estimate wholesale gasoline and diesel price forecasts.

To calculate ethanol and biodiesel prices, energy-equivalent price differentials between low-carbon fuels and fossil fuels were calculated using data from the U.S. Department of Agriculture on average gasoline, diesel, ethanol, and biodiesel prices from 2015 to 2019.footnote 64 The estimated price differential is 24% between ethanol and gasoline, and 17% for biodiesel and diesel. These differentials were applied to the wholesale price forecasts for gasoline and diesel in order to obtain ethanol and biodiesel price forecasts. For HDRD, no price indices exist. As a result, a literature review was conducted to determine representative volumetric HDRD prices.footnote 65 Due to price uncertainty, an average of a high and low estimate of HDRD was calculated, and an average energy-equivalent price differential was estimated between biodiesel and HDRD of 20%.footnote 66

In addition, ethanol and biodiesel are primarily transported by other means than fossil fuel pipelines because of operational challenges such as their ability to pick up water, degrade jet fuel quality, affect materials used in transportation and storage systems and because the existing pipeline infrastructure does not always line up with where biofuels are produced or available. It is therefore expected that there would be incremental ongoing transportation costs to deliver ethanol and biodiesel by rail or other modes of transportation.footnote 67 Therefore, it is assumed that refiners and terminals would incur ongoing transportation costs of about $0.05 per litre of incremental ethanol and biodiesel demanded.footnote 68

In total, capital costs are estimated at $1.5 billion and operating costs are estimated at $9.9 billion over the time frame of the analysis. Overall, supplying low-carbon fuels under the proposed Regulations is estimated to result in a total compliance cost of $11.4 billion between 2021 and 2040.

Potential impacts from indirect land use change

Direct land-use change (DLUC) happens when a particular parcel of land is converted to grow crops for biofuel production. Indirect land-use change (ILUC) occurs when crops grown for biofuels displace traditional food and animal feed crops, leading to production of that displaced food crop elsewhere (i.e. other land is converted to grow the food crop). If new agricultural land expands into areas with high carbon stock such as forests, wetlands and peat land this leads to additional GHG emissions. If it occurs in a highly biodiverse land, it could result in biodiversity loss.

The proposed Regulations are designed to prevent these impacts in two ways. The Fuel LCA Model would account for GHG impacts of DLUC in the CI of low carbon intensity fuels, and the proposed Regulations would include criteria to prevent adverse land-use and biodiversity impacts related to biofuel feedstock cultivation and harvesting. These land use and biodiversity (LUB) criteria apply to feedstock regardless of geographic origin, but feedstock are exempt if they are not biomass (e.g. fuel made from direct-air-capture CO2) or if they have been deemed by the Department as “low-concern biomass feedstock” (e.g. municipal solid waste). Only biofuels made from feedstock that adhere to the LUB criteria are eligible for credits under the proposed Regulations

Other potential impacts of blending low-carbon fuels

Ethanol has a higher-octane value than gasoline, so refiners could choose to avoid processing higher-octane gasoline and produce lower-octane gasoline instead if they choose to blend more ethanol. Given this, there may be some potential for refiner cost savings.

Alternatively, if refiners choose to keep producing higher-octane gasoline, the blended fuel would have an overall higher-octane value in the regulatory scenario. Standards for Original Equipment Manufacturers have been implemented to provide high compression engines in cars to the North American market, which require fuel with higher-octane values. Mid-level ethanol blends (E15 to E25) coupled with high compression engines could lead to some efficiency improvements that may be sufficient to offset the lower energy content of ethanol. If this is the case, there could be some potential for more emissions reductions and some mitigation of costs to consumers.footnote 69, footnote 70

Higher blends of biodiesel in diesel could improve fuel lubricity and raises the cetane number of the fuel. Diesel engines depend on the lubricity of the fuel to keep moving parts from wearing prematurely. Given this, it is possible that as refiners blend more biodiesel, they could choose to lower the lubricity of petroleum diesel to save on costs.footnote 71

Furthermore, increased blending of low-carbon fuels in fossil fuels is expected to result in changes to air quality. For more information on how the proposed Regulations are expected to impact air quality, please refer to the impacts on air quality section below.

Compliance Category 3: End-use fuel switching in transportation

End-use fuel switching occurs when an end user of fuel changes or retrofits a combustion device, for example an engine, to be powered by another fuel or energy source such as electricity or hydrogen in transportation. End-use fuel switching does not directly reduce the CI of the fossil fuel but reduces GHG emissions by displacing the fossil fuel with a fuel or energy carrier that has a lower CI.

The proposed Regulations would allow credit creation for some end-use fuel switching in the transportation sector. All low-carbon energy volumes supplied for transportation would be eligible to create credits, except for rail vehicles. These low-carbon energy sources would include hydrogen in fuel cell vehicles, electricity in electric vehicles, natural gas and renewable natural gas (including compressed and liquefied) or hydrogen (including compressed and liquefied) in natural gas vehicles, and propane and renewable propane in propane vehicles.

End-use fuel switching to electric vehicles and to natural gas/propane vehicles in transportation are the two representative pathways that have been modelled for Compliance Category 3. This is because there is little to no uptake of other end-use fuel switching pathways in Canada (such as renewable natural gas and hydrogen). These are still emerging technologies and there is not enough information on them to estimate their likely uptake in Canada by 2030. However, the proposed Regulations would provide an incentive for these kinds of technologies.

End-use fuel switching to electric vehicles (EVs)

For homes equipped with charging stations connected to a network, the charging network operator would be the default credit creators. Charging network operators would also be the default credit creators for public charging. Private or commercial charging would create credits for site hosts by default.

Credit-creation: Credits would be created in accordance with the following formula based on the energy efficiency ratio of the vehicle class (Ree), the liquid class credit reference CI value (CIref) [see Table 1 above], the lifecycle emissions of the electricity used to propel the EVs, the quantity of electrical energy of a given CI supplied to the EVs (Q) and the energy density of electricity (D).

Credits = [(Ree × CIref) – CIe] × Q × D × 10-6

Energy demand forecasts for EVs were obtained from the Departmental Reference Case. Electricity that is supplied by a charging station that is installed in a residence no later than December 31, 2030, would be eligible of creating full credits until December 31, 2035. After this time, no residential charging would be eligible for credit creation. Any new residential charging stations installed after December 31, 2030, would not be eligible for credit creation. However, the regulatory scenario assessed in this analysis is of the proposed regulatory design that was presented to stakeholders in the June 2020 consultations where credits created from residential EV charging would be phased out linearly by 25% starting in 2027, reaching zero in 2030. As such, credit estimates from residential EV charging would be underestimated in this analysis. Given this, it is assumed that 28% of light-duty EV energy demand from the Reference Case is from public charging, the remaining 72% of demand is from home charging. The proposed Regulations also require that all EV charging data be collected by a charging station that measures and communicates charging data to a charging network operator. Thus, it is assumed that 7.5% of light-duty EV energy demand is from residential charging stations capable of collecting and communicating charging data to a charging network operator. It is also assumed that this value would grow by about 2.5% each year based on consultations with stakeholders.footnote 72 As a result, these factors were also applied to Reference Case energy demand estimates for light-duty vehicle (LDV) EV charging. Table 11 presents EV energy demand estimates over the time frame of analysis. EV energy demand in 2022 is estimated at 6 PJ, increasing to 11 PJ in 2030, and to 24 PJ by 2040.

Table 11: EV energy demand estimates by vehicle category (PJ)

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

  2021–2025 2026–2029 2030 2031–2040 Total
LDV-LDT 5 9 2 50 66
HDV 4 10 4 81 99
Buses 23 19 5 51 97
Total 31 38 11 182 261

Credits for end-use fuel switching to EVs are calculated using constant 2016 lifecycle CI electricity values by province. The electricity CI values vary depending on the mix of the electricity grid in each province. For example, provinces that rely more on natural gas powered electricity would have a higher CI value than provinces that rely more on hydroelectric power. The Canadian average electricity CI value is 180.4 tonnes per gigawatt hour (t/GWh). An energy efficiency ratio (EER) of 4.1 was used for light-duty vehicles (LDV) and trucks (LDT), and an EER of 5.0 for buses and heavy-duty vehicles. Given this, Table 12 shows EV credit estimates over the time frame of analysis.

Table 12: EV credit estimates by vehicle category (millions)

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

  2021–2025 2026–2029 2030 2031–2040 Total
LDV-LDT 1.4 2.7 0.7 14.7 19.5
HDV 1.5 4.0 1.6 30.8 37.9
Buses 7.6 7.2 1.8 18.7 35.3
Total 10.4 14.0 4.0 64.2 92.6

Given the relative infancy of EVs compared to their internal combustion engine (ICE) counterparts, some projections of future EV uptake vary substantially from what is estimated above. Barriers to wide-scale EV adoption include costs, technical limitations, infrastructure, and market dynamics and technological constraints include range limitation and charging times. Moreover, infrastructure requirements for EVs are complex when compared to fossil fuel-related infrastructure already in place. While consumer attitudes towards EVs are evolving and Government incentive programs have helped increase adoption rates, the current default market preference remains for ICE vehicles. Factors pushing towards increased EV adoption include increasing market familiarity with the technology, improvements in battery range and charging times, expanding infrastructure, and decreasing costs. Given the wide variability among forecasts, a sensitivity analysis on the number of credits created for end-use fuel switching is presented in the Uncertainty of impact estimates section.

Attribution and incremental impacts: It is expected that the EV market would continue to expand in the baseline scenario in the absence of the proposed Regulations, with corresponding increases in electricity consumption as a substitute to gasoline and diesel. Other policies, such as the federal Zero Emission Vehicle mandate, would also create incentives for EV uptake and infrastructure to be built.

Primary suppliers would have the option to acquire credits by trade from charging network operators and site hosts, therefore acting as a subsidy. This subsidy on its own would not likely be sufficient to incentivize investment that supports measurable incremental EV uptake. However, it would provide another incentive that could work in conjunction with other federal and provincial EV policies to boost market signals for increasing EV deployment. This analysis does not take that impact into account.

End-use fuel switching to natural gas and propane vehicles

For compressed and liquefied natural gas and propane, including the fossil portion of any blend with a renewable fuel component, the fuelling facility owner or operator would be the default credit creator for fuelling for transportation purposes. The credits would be created in the liquid class as this represents a displacement of liquid transportation fuel.

Credit-creation: Credits would be created in accordance with the following formula based on the liquid class credit reference CI value (CIref) [see Table 1 above], the lifecycle carbon intensity (CI), the volume (Q) and the energy density (D) of compressed natural gas (CNG), liquefied natural gas (LNG) or liquefied petroleum gas (LPG) supplied.

Credits = [CIref – CILNG,CNG,LPG] × Q × D × 10-6

Energy demand from natural gas and propane powered vehicles is estimated at 7 PJ in 2022, increasing to 15 PJ in 2030, and to 29 PJ by 2040. For the purpose of this analysis, credits for end-use fuel switching to natural gas/propane in transportation are calculated using constant lifecycle CI values of 65 gCO2e/MJ for CNG, 65 gCO2e/MJ for LNG, and 75 gCO2e/MJ for LPG. It is assumed that 50% of the natural gas demand is CNG and 50% is LNG. These CI values are the 2016 average Canadian CI values for compressed natural gas and propane calculated as part of the development of the Fuel LCA Model.footnote 73 No EER values are mentioned in the formula as the EER values are close to one for these pathways. Using energy demand forecasts from the Departmental Reference Case, it is estimated that 0.1 million credits would be created in 2022, increasing to 0.2 million in 2030, and to 0.3 million credits by 2040.

Attribution and incremental impacts: This pathway on its own would not likely be sufficient to incentivize investment that supports measurable incremental natural gas/propane uptake in transportation. As with EVs, however, this pathway would provide another incentive that could work in conjunction with other federal and provincial policies to boost market signals for increasing deployment of natural gas and propane vehicles. This analysis does not take that impact into account.

Impacts from the Compliance Fund

The proposed Regulations would establish a Compliance Fund as a flexibility mechanism. Primary suppliers would be able to contribute to this compliance fund mechanism for up to 10% of their annual reduction requirement. The credit price under the fund would be set in the proposed Regulations at $350 in 2022 nominal dollars per compliance credit (CPI adjusted), which corresponds to $330 in 2019 dollars. Any contributions to the fund must be used for projects or activities that reduce emissions within a five-year period from the time the contribution is made. This analysis treats the fund contributions as if they are transfer payments. Thus, impacts from the fund are presented as equal and offsetting costs to industry (payments) and benefits to society (assets for investments to reduce GHG emissions).

It is estimated that the fund would be used initially in 2027 for about 9% of the credit requirement, equivalent to about 1.8 million credits. Between 2028 and 2036, it is estimated that the fund would be used up to the full 10% limit at 2.8 million credits in 2030. In 2033, it is estimated that use of the fund would decline as credits from end-use fuel switching increase over time and the credit requirement of 12 gCO2e/MJ stays constant. By 2038, it is estimated that the fund would no longer be required to fulfill the credit requirement. Estimates of fund assets and payments over the time frame of analysis are presented in Table 13.

Table 13: Estimates of fund assets and payments (millions of dollars)

Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.

  2021–2025 2026–2029 2030 2031–2040 Total
Fund assets 0 1,753 693 3,025 5,470
Fund payments 0 1,753 693 3,025 5,470

Quantification of eventual GHG reductions from the fund is not possible at this time and is beyond the scope of this analysis. This is because the specific projects that would receive support in the future from the fund are unknown at this time. Without information on project parameters, it is not possible to estimate incremental GHG emission reductions. However, given that the fund would be required to deliver real, short-term, traceable reductions, it is expected to contribute to the objective of the proposed Regulations to achieve up to 23 Mt of GHG reductions.

Emerging technology pathways

Emerging technologies are technologies that are at a lower technological readiness level, or those that are at a high technological or commercial readiness level but have low adoption rates due to various reasons such as cost, asymmetric information, or lack of incentive. It is expected that the proposed Regulations would provide a sufficient incentive to increase the adoption of emerging technologies to reduce GHG emissions. Examples of emerging technologies that could receive credits under the proposed Regulations include co-processing biocrude, hydrogen in fuel cell vehicles, renewable natural gas in natural gas vehicles; renewable electricity at fossil fuel facilities, emerging low-CI fuels, and direct air capture. However, because emerging technologies have low adoption rates there is not a lot of data available on costs. Given this, it is assumed that emerging technology credits make up the difference between the amount of credits required and credits created from mature technologies plus the fund.footnote 74 Credits for emerging technologies are assumed to be incremental and cost the same as the fund ($330 per credit in 2019 dollars).

By 2028, it is assumed that banked credits, credits from mature technologies, and fund contributions would no longer be sufficient to fulfill the credit requirement. Thus, 0.7 million credits from emerging technologies would be required. Credits from emerging technologies are estimated to gradually increase to a maximum in 2030 at 1.6 million, and then gradually decrease each year after until 2033 when they are no longer needed due to a crowding out effect from increasing baseline credits created from end-use fuel switching and a constant annual CI reduction requirement. As a result, the associated incremental costs and GHG reductions follow the same trend. Incremental impacts from emerging technologies are presented in Table 14 between 2021 and 2040.

Table 14: Incremental costs and GHG reductions from emerging technologies

Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.

  2021–2025 2026–2029 2030 2031–2040 Total
Costs (millions of dollars) 0 457 392 363 1,213
GHG reductions (Mt CO2e) 0 1.8 1.6 1.5 4.9

The CI reduction requirements after 2030 will be subject to a review of the proposed Regulations and potential future amendments.

Impacts on air quality

Some of the representative pathways are expected to result in changes to the levels of air pollutants, which would therefore result in changes to air quality. Air pollutants are substances that affect human health and the environment (such as ground level ozone, particulate matter, and acid rain).footnote 75 Air pollutants can be grouped into four different categories: criteria air contaminants and related pollutants (e.g. ozone, particulate matter, sulphur oxides, nitrogen oxides, volatile organic compounds, etc.), persistent organic pollutants (e.g. dioxins and furans), heavy metals (e.g. mercury), and toxics (e.g. benzene). These air pollutants are all different. They differ in their chemical composition, reaction properties, emission sources, how long they last in the environment before breaking down, their ability to move long or short distances, and their eventual impacts.footnote 76

The likely impact on air pollutant emissions from Compliance Category 1 is unknown, and has not been assessed. However, these impacts are likely to be minimal. Air pollutant emissions from gasoline vehicles and engines are already regulated to a significant extent under existing regulations such as the Regulations Amending the Sulphur in Gasoline Regulations, which limit the sulphur content of gasoline.footnote 77 Refining sector emissions are also regulated through the Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector).footnote 78 In addition, given the flexibility of the proposed Regulations in regard to the choice of compliance pathway, it is unknown where, and by how much, air pollutant emissions would change.

The impact of the proposed Regulations on air quality due to blending low-carbon fuels is also expected to be minimal. A previous risk assessment conducted by Health Canada on the health risks and benefits associated with the use of ethanol-blended gasoline compared to unblended gasoline indicated that increasing the use of E10 fuel in Canada would result in a possibly negligible decrease in the number of adverse health effect incidents.footnote 79 This decrease would result from a reduction in ambient air concentrations of select pollutants resulting from E10 fuel use. In general, there were no substantial differences in predicted health effects between the conventional gasoline baseline and E10 fuel scenarios. No further study was conducted to evaluate ethanol blends up to E15.

In addition, previous analyses by Health Canada indicated that the use of B5 or B20 nationally is expected to result in minimal air quality and health benefits/risks, and these are likely to diminish over time.footnote 80 Although substantial modelling and data limitations remain, the current available evidence suggests that the incremental health impacts associated with the widespread use of low-level biodiesel blends in Canada, as compared to the use of diesel, are expected to be minimal. Currently, there is limited information regarding the air quality impacts associated with increased HDRD blending in diesel.

Summary of credits created

Early credit creation starts at the end of 2021 when the Department is targeting completion of the final Regulations and publication in the Canada Gazette, Part II, subject to Governor in Council approval. Early action credits are created for baseline actions (e.g. low-carbon fuels supplied for federal/provincial blending mandates, end-use fuel switching) for up to six months before the coming into force date in 2022 of the proposed Regulations. Credit creation from baseline pathways plus banked credits from previous years are sufficient to fulfill the credit requirement and result in an accumulation of banked credits for the first few years that the proposed Regulations are in force (2021–2025). Credit estimates between 2021 and 2025 are presented in Table 15.

Table 15: Credit estimates between 2021 and 2025 (millions)

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

  2021 2022 2023 2024 2025
Baseline credits 0.8 11.7 10.4 10.5 10.7
Banked credits 0 0.8 8.8 9.7 7.6
Incremental credits 0 0 0 0 0
Fund 0 0 0 0 0
Credits created and banked 0.8 12.6 19.2 20.2 18.3
Credits required (0) (3.8) (9.6) (12.6) (15.6)
Net credits 0.8 8.8 9.7 7.6 2.7

In 2026, credits from baseline pathways and banked credits are estimated to no longer be sufficient to fulfill the credit requirement. As a result, it is estimated that incremental actions (e.g. CCS, blending low-carbon fuels) would be required starting in 2026. It is estimated that 2027 is the last year in which banked credits are used and the first year in which the fund is accessed. In 2028, it is estimated that credits from emerging technologies would be required to fulfill the credit requirement. By 2030, the proposed Regulations reach full stringency at 12 gCO2e/MJ and blending of low-carbon fuels would be used to the assumed blend rates (15% for ethanol, 5% for biodiesel and 6% for HDRD). The fund would also be accessed to the regulatory limit of 10% and emerging technology credits would be needed to meet the credit requirement. Credit estimates between 2026 and 2030 are presented in Table 16.

Table 16: Credit estimates between 2026 and 2030 (millions)

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

  2026 2027 2028 2029 2030
Baseline credits 10.9 11.0 11.2 11.3 11.4
Banked credits 2.7 0.6 0 0 0
Incremental credits 5.5 7.7 10.0 12.0 14.0
Fund 0 1.8 2.4 2.6 2.8
Credits created and banked 19.1 21.1 23.6 25.9 28.2
Credits required (18.5) (21.1) (23.6) (25.9) (28.2)
Net credits 0.6 0 0 0 0

The estimated trend in total credits created between 2031 and 2040 remains relatively flat after 2030. However, as the credit requirement remains constant at 12 gCO2e/MJ, credits from end-use fuel switching are estimated to increase over time, crowding out incremental credits and the fund. As a result, incremental credits decrease from 14.0 million in 2030 to 12.5 million in 2040 and the fund decreases from 2.8 million in 2030 to zero in 2040. Credit estimates by compliance category between 2021 and 2040 are presented in Figure 5.

Figure 5: Credit estimates by compliance category, 2021–2040 (millions)

Note: Credit estimates for supplying low-carbon fuels peak in 2022 due to the one-time roll-over of credits from the RFR, estimated at 1.4 million (as presented to stakeholders in the June 2020 consultations).

Credit estimates by compliance category, 2021–2040 (millions) - description below

Figure 5 - Text version

Figure 5 is a line graph that illustrates credit estimates by compliance category. The y-axis represents millions of credits, ranging from zero to 14.0 million. The x-axis represents the year, ranging from 2021 to 2040. There are four lines in this graph. The first line illustrates credits created from actions along the lifecycle. This line starts at about 0.1 million in 2021 and remains constant at about 1.5 million between 2022 and 2025. Credits represented in this line increase sharply in 2026 to 6.6 million credits as credits from incremental actions are required. Between 2027 and 2038, credits gradually increase year over year to about 7.8 million in 2038. In 2039 and 2040, credits decrease to 7.4 million as higher cost pathways for actions along the lifecycle are displaced by increasing baseline credits from end-use fuel switching. The second line illustrates credits created from supplying low-carbon fuels. This line starts at 0.5 million in 2021 and jumps to 7.8 million in 2022 due to baseline credits from the provincial and federal blending mandates and a one-time rollover of credits from the RFR. From 2022 to 2024, the slope of the line is negative. From 2025 to 2030, the line has a positive slope where it reaches its highest point in the graph at 12.4 million credits in 2030 and remains relatively flat thereafter between 2031 and 2040. The third line illustrates credits created from end-use fuel switching, which has a positive slope that starts at about 0.2 million credits in 2021 and gradually increases year over year to about 8.9 million credits in 2040. The fourth line starts at zero and has a horizontal slope between 2021 and 2026, it then has a positive slope until 2030 when it reaches a peak at about 4.4 million credits. From 2030 to 2038, the line has a negative slope as fund and emerging technology credits are displaced by increasing baseline credits from end-use fuel switching. In 2038, credits from the fund and emerging technologies are at zero and they remain at this level with a horizontal slope from 2038 to 2040. The numerical values presented in the image follow:

Year Actions along the lifecycle
(millions)
Supplying low-carbon fuels
(millions)
End-use fuel switching
(millions)
Fund + Emerging Technologies
(millions)
2021 0.1 0.5 0.2 0
2022 1.5 7.8 2.4 0
2023 1.5 6.3 2.6 0
2024 1.5 6.2 2.8 0
2025 1.5 6.2 3.0 0
2026 6.6 6.5 3.3 0
2027 7.0 8.1 3.5 1.8
2028 7.1 9.7 3.8 3.0
2029 7.1 11.1 4.0 3.7
2030 7.2 12.4 4.2 4.4
2031 7.3 12.4 4.6 3.9
2032 7.4 12.3 5.0 3.3
2033 7.5 12.3 5.4 2.7
2034 7.6 12.3 5.9 2.1
2035 7.7 12.3 6.4 1.5
2036 7.7 12.3 6.9 1.0
2037 7.8 12.3 7.4 0.5
2038 7.8 12.3 7.9 0
2039 7.4 12.4 8.4 0
2040 7.4 12.4 8.9 0

Summary of benefits

The proposed Regulations would reduce GHG emissions that would otherwise be emitted into the atmosphere. It is estimated that the proposed Regulations would result in 221 Mt of cumulative GHG emission reductions that are attributable and measurable over the time frame of this analysis, as shown in Table 17 below.

End-use fuel switching could work in combination with other policies to further incentivize EV uptake but is not likely to result in measurable reductions attributable to the proposed Regulations alone. In addition, by law, the fund would be required to invest in GHG emission reductions. However, there is uncertainty as to the timing, magnitude and incrementality of the reductions attributable to the fund. There is also uncertainty regarding the potential for actions taken throughout the fuel lifecycle and from potential emerging technologies. Uncertainty regarding the impacts of attribution assumptions have been assessed in a sensitivity analysis (see section on Uuncertainty of impact estimates).

It is estimated that the proposed Regulations would not result in incremental GHG emission reductions until 2026 since industry compliance is expected to be achieved by using credits from actions that would have occurred in the baseline between 2021 and 2025 (see section above on summary of credits created). Incremental GHG emission reductions peak in 2030 at about 17.5 Mt and are estimated to gradually decline each year after as the CI reduction requirements remain constant after 2030 and credits from end-use fuel switching uptake crowd out the need to use credits from incremental pathways. The CI reduction requirements after 2030 are subject to a review of the proposed Regulations and potential future amendments.

Table 17: Incremental GHG emission reductions by compliance category (Mt CO2e)

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

  2021–2025 2026–2029 2030 2031–2040 Total
Actions along the lifecycle 0 21.8 5.7 60.0 87.4
Supplying low-carbon fuels 0 16.7 10.3 101.3 128.2
Emerging technologies 0 1.8 1.6 1.5 4.9
Total GHG reductions 0 40.3 17.5 162.8 220.6

As noted in the analysis of the methane conservation pathway (Compliance Category 1), it is estimated that there would be conservation of approximately 173 PJ of natural gas over the time frame of analysis due to methane conservation actions attributable to the proposed Regulations, valued at $898 million. The proposed Regulations are also expected to generate fund assets to government estimated at $5,470 million between 2021 and 2040. Table 18 presents benefits from conserved gas and the fund over the time frame of analysis.

Table 18: Benefits from conserved gas and fund contributions
  2021–2025 2026–2029 2030 2031–2040 Total
Conserved gas (PJ) 0 38 12 124 173
Value of conserved gas (millions $) 0 126 37 735 898
Fund assets (millions $) 0 1,753 693 3,025 5,470

Methane conservation actions and the fund are representative pathways used for modelling purposes. In reality, stakeholders may not necessarily choose these pathways in order to comply. As such, it is possible that these benefits are not realized. If the fund is selected, it would create assets that would be used to invest in projects that further reduce GHG emissions. The specific projects that would receive support in the future from the fund are unknown at this time. Without information on project parameters, it is not possible to estimate GHG emission reductions. Therefore, quantification of GHG emission reductions from the fund is beyond the scope of this analysis. However, given that the fund would be required to deliver real, short-term, traceable reductions, it is expected to contribute to the objective of the proposed Regulations to achieve up to 23 Mt of GHG reductions.

Summary of industry compliance costs

It is expected that credits would be created under the proposed Regulations for activities that would have otherwise occurred in the baseline scenario. As such, not all of the costs would be attributable to the proposed Regulations. Incremental compliance costs are estimated at $26.9 billion and compliance cost savings are estimated at $39.2 million. Net compliance costs attributable to the proposed Regulations are estimated at $26.9 billion over the period of analysis and are presented in Table 19.

Table 19: Net compliance costs (millions of dollars)

Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.

  2021–2025 2026–2029 2030 2031–2040 Total
Compliance costs 5,435 6,055 2,242 13,211 26,943
Compliance cost savings 0 12 3 24 39
Net compliance costs 5,435 6,043 2,240 13,187 26,904

The proposed Regulations result in incremental compliance costs in 2024 because most of the compliance pathways require upfront capital investments and lead time for projects to become operational. Early action credits and a low stringency in the early years of the proposed Regulations allow time for a buildup of banked credits from baseline activities (such as credits from low-carbon fuels supplied under the RFR). This accumulation of banked credits in the early years is expected to provide firms with enough lead time to make capital investments in projects required by 2030, when the proposed Regulations reach full stringency. As a result, operating costs are not incurred until 2026 since industry compliance is expected to be achieved by using banked credits from baseline actions between 2021 and 2025 (see section above on summary credits created). Net operating costs increase gradually from 2026 to 2029, reaching their peak in 2030 (at $2,096 million). Net operating costs gradually decline between 2031 and 2040 due to more credits from baseline end-use fuel switching uptake that reduces the need to use credits from incremental pathways. Estimates of net compliance costs by compliance category are shown in Table 20.

Table 20: Net compliance costs by compliance category (millions of dollars)

Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.

  2021–2025 2026–2029 2030 2031–2040 Total
Actions along the lifecycle 3,990 2,357 265 2,243 8,855
Supplying low-carbon fuels 1,445 1,476 889 7,556 11,366
Emerging technologies 0 457 392 363 1,213
Fund payments 0 1,753 693 3,025 5,470
Net compliance costs 5,435 6,043 2,240 13,187 26,904

Industry and government administrative costs to ensure compliance

The proposed Regulations would require primary suppliers to keep records and submit reports (including a registration report, a compliance report, a refinery and upgrader report, and verification reports). They would also incur costs to submit information on credit creation activities and third-party verification of reports. In addition, primary suppliers and renewable fuel producers and importers who were previously regulated under the Renewable Fuels Regulations (RFR) would benefit from some administrative cost savings due to the repeal of the RFR. As a result, net administrative costs to primary suppliers are estimated at $8.2 million over the time frame of analysis. Administrative cost savings to primary suppliers and renewable fuel producers and importers are estimated at $5.4 million from 2021 to 2040. As a result, there would be total net administrative costs to industry estimated at $2.8 million between 2021 and 2040.footnote 81

The Department would incur opportunity costs to enforce and administer the proposed Regulations. With respect to enforcement costs, it is expected that there would be costs required for the hire and training of new enforcement officers, training for current enforcement officers, costs for equipment, and costs for inspections. In total, enforcement costs are estimated at $9.7 million between 2021 and 2040.

Program implementation opportunity costs include the hiring and training of new full-time employees, training and equipment, policy analysis, data collection and analysis, verification and validation of third-party verifiers, compliance promotion, as well as reporting and information management. The Department would also incur administrative costs related to the design and development of a credit transaction system, the Fuel Lifecycle Assessment Model, and the electronic reporting system. Resources would also be required in order to operate the credit transaction system, verify compliance pathways, as well as to update these tools and systems. In total, program costs for the proposed Regulations are expected to be about $75.0 million between 2021 and 2040.

Table 21: Administrative costs for industry and Government (millions of dollars)

Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.

  2021–2025 2026–2029 2030 2031–2040 Total
Industry administrative costs 2.7 1.7 0.4 3.4 8.2
Industry administrative cost savings (1.2) (1.3) (0.3) (2.6) (5.4)
Government administrative costs 27.3 17.9 4.1 35.4 84.7
Net administrative costs 28.7 18.3 4.2 36.2 87.5

Total net industry administrative costs are estimated at $2.8 million between 2021 and 2040, and total government administrative costs to implement and enforce the proposed Regulations are estimated at $84.7 million over the time frame of analysis. Total administrative costs to industry and government necessary to ensure compliance with the proposed Regulations are estimated to be $87.5 million between 2021 and 2040.

Break-even analysis of central case results

Between 2021 and 2040, the proposed Regulations are estimated to result in GHG emission reductions of 221 Mt at a cumulative cost of $27.0 billion to industry and government and a cost of $20.6 billion to society over the time frame of analysis. Table 22 presents a summary of central case impacts.

Table 22: Central case impacts (millions of dollars)

Note: Figures may not add up to totals due to rounding. Monetized values are discounted to the present value using a 3% discount rate.

  2021–2025 2026–2029 2030 2031–2040 Total
Credit creation costs 5,435 4,303 1,549 10,186 21,473
Fund payment costs 0 1,753 693 3,025 5,470
Administrative costs 30 20 5 39 93
Value of conserved gas benefits (0) (126) (37) (735) (898)
Credit creation cost savings (0) (12) (3) (24) (39)
Fund asset benefits (0) (1,753) (693) (3,025) (5,470)
Administrative cost savings (1) (1) (0) (3) (6)
Net costs 5,463 4,183 1,513 9,463 20,623
GHG emission reductions (Mt) 0 40 18 163 221

To obtain the cost per tonne estimate of the proposed Regulations, costs to industry and government are divided by the amount of the GHG emissions reduced between 2021 and 2040. To obtain the net cost per tonne estimate of the proposed Regulations, costs to industry and government less benefits to society are divided by the amount of the GHG emissions reduced between 2021 and 2040. In this analysis, only the monetized costs are discounted. The GHG emission reductions are left undiscounted. The analysis was done this way to show what the costs of the proposed Regulations would be to achieve the estimated amount of GHG emission reductions in their physical form. Therefore, the anticipated GHG emission reductions would be achieved at an estimated cost per tonne of $123 and a net cost per tonne of $94 (see Table 23).

Table 23: Central case cost-effectiveness analysis (2021–2040)

Note: Figures may not add up to totals due to rounding. Monetized values are discounted to the present value using a 3% discount rate. GHG emission reductions are undiscounted.

  2021–2025 2026–2029 2030 2031–2040 Total
Cost (millions $) 5,436 6,044 2,240 13,187 26,907
Net cost (millions $) 5,463 4,183 1,513 9,463 20,623
GHG reductions (Mt CO2e) 0 40 18 163 221
Cost per tonne ($/tCO2e) 123
Net cost per tonne ($/tCO2e) 94

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/or benefits associated with changes in CO2 emissions.footnote 82 The SCC is a monetary measure of the global damage expected from an additional tonne of CO2 emissions for a given year. The central estimate is currently $50/tCO2 (in 2019 dollars).footnote 83

Generally speaking, for regulations that result in CO2 emissions or reductions, the SCC is used to measure the quantifiable costs of emitting one tonne of CO2 for a given year. To calculate the social benefits from CO2 emission reductions, the annual tonnes of CO2e emissions reduced are multiplied by the SCC for each year in question. These monetized benefits are then discounted to present value, using a 3% discount rate, and are summed over the time frame considered for analysis. Since 2016, all federal regulatory analysis involving GHG emissions has relied on SCC values published by the Department. 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.

Recent academic literature published by the authors of the DICE model and the PAGE model indicate 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, the SCC estimate in the updated version of the DICE model has more than doubled compared to the iteration on which the Department’s current SCC estimate is based. This change is largely due to updates to global population estimates, data revisions to economic activity estimates, and incorporating new research on the carbon cycle.footnote 84 In addition, revisions to the PAGE model, which include climate science updates, economic updates, and novel developments such as incorporating the impact of non-linear Arctic feedbacks on the global climate system and economy, have also resulted in significant increases to its estimate of the SCC.footnote 85

As a result, the current SCC values used for Canadian regulatory analysis likely underestimate climate change damages to society, and the social benefits of reducing GHG emissions. Therefore, updating the SCC based on the latest climatological and economic evidence would likely result in a higher SCC estimate. The Department is updating its SCC estimate, but results are not yet available.

Given the likelihood that an updated departmental SCC estimate would be considerably higher than its current value, an interim approach is being used for this analysis where the updated SCC estimates from the above literature are considered alongside the Department’s current SCC value. This is being done to illustrate a range of plausible values if the Department were to update its SCC estimate based on new versions of the models currently used.

As there is inherent uncertainty concerning avoided climate change damages, a break-even analysis (BEA) has also been conducted to establish a range of benefits that would be needed to offset the monetized costs of the proposed Regulations. This approach is simple and transparent, provides a risk tolerance perspective, and maintains a link between previous and future climate change analyses.

Break-even analysis (BEA) is a technique used to assess how valuable a non-monetized effect would have to be in order to meet or exceed net costs. It is most effective when analysts are particularly uncertain about one key parameter — in this case, the dollar value of social benefits from GHG 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).

For the proposed Regulations, the break-even value was determined by calculating the net cost per tonne of GHG emission reductions. This value is estimated at approximately $94, as illustrated in Table 23 above. To validate the break-even value, the net cost per tonne of the proposed Regulations was compared to the Department’s central SCC value for the year 2020 and to more recently published SCC estimates in the academic literature from the DICE and PAGE models. Consistent with methodologies used by other jurisdictions, to validate the break-even value, it should fall within a plausible range of similar values.footnote 86 In this instance, the break-even value was compared to a range of SCC values reported in Table 24.

Table 24: Central case break-even analysis using the net cost per tonne of $94

Note: The Department’s central SCC estimate and the updated DICE SCC estimate are discounted to present value, using a real 3% discount rate. The Department’s central SCC estimate is reported in 2019 Canadian dollars using the Canadian GDP Deflator. The DICE and PAGE central estimates are reported in 2019 Canadian dollars using the U.S. GDP Deflator and market exchange rates. The updated PAGE SCC estimate is discounted using equity weighting and pure time preference.footnote 87

Publication SCC Estimate CBA result
The Department’s central SCC estimate for 2020 (2016 Technical Update [PDF] ) $50/tCO2 Net cost
Updated DICE SCC estimate for 2020 (2017 Publication) $135/tCO2 Net benefit
Updated PAGE SCC central estimate for 2020 (2019 Publication [PDF] ) $440/tCO2 Net benefit

As illustrated in Table 24, the break-even analysis suggests that with the updated SCC estimates, it is plausible that the proposed Regulations would yield a net benefit result.

Uncertainty of impact estimates

The results of this analysis are based on key parameter estimates, which may be higher or lower than indicated by the projections and assumptions relied on to develop the analysis. For example, the modelling relies on assumptions about the proportion of category 1, 2 and 3 credits that would be created and at what cost. These assumptions account for the costs of known, mature technologies as well as assumptions about emerging technologies. It relies on projections of energy demand and prices. Furthermore, it follows TBS guidance on federal cost-benefit analyses of regulations, which requires the use of a 3% discount rate when a regulation has health or environmental impacts.

Given this uncertainty, sensitivity analyses were conducted to assess the impact of changes to these parameters on the expected impacts of the proposed Regulations, where possible between 2021 and 2040.

Credit creation: The estimated number of credits created for each compliance pathway may be higher or lower than estimated in the central analysis, and consequently the estimated incremental costs and reductions (impacts are shown in tables 25 and 26 below). Feedback from stakeholders was solicited by the Department, which yielded a range of results. Additionally, it is expected that changes in energy demand and future technological advances could result in significantly higher than estimated credits. To estimate the effect of different credit estimates on the final results, sensitivity analyses were conducted for seven scenarios:

It is possible that a scenario could arise in which credits from emerging technologies are not realized. This could happen if technological advancements or adoption rates of emerging technologies (such as co-processing) are lower than anticipated. If this is the case, it is expected that emerging technology pathways could be replaced by credits from cross-class trading (available for up to 10% of the annual CI reduction requirement in a given year) and stakeholders would still be able to comply. Stakeholders would also have the ability to carry forward up to 10% of their annual CI reduction requirement in a given year in the event that they are not able to acquire or create enough credits.

Price forecasts: The analysis would be sensitive to the assumptions and forecasts for energy prices over the relevant time period. To address this, the analysis has presented high and low scenarios for the price differential between low-carbon fuels and fossil fuels. In the low scenario, price differentials are 50% lower than the central case at 12% for ethanol and gasoline, 8% for biodiesel and diesel, and 11% for HDRD and biodiesel. In the high scenario, price differentials are 50% higher than the central case at 36% for ethanol and gasoline, 25% for biodiesel and diesel, and 28% for HDRD and biodiesel. It is estimated that the proposed Regulations would result in a net cost per tonne of $75 for the low scenario (lower than the central case) and $111 for the high scenario (higher than the central case).

Discount rate: TBS recommends a 7% discount rate for cost-benefit analyses in most cases; however, for health and environmental analyses or when a regulation has impacts occurring over a long time horizon, a lower discount rate (3%) is considered more appropriate. A sensitivity analysis was done to compare the central case (3%) to the higher discount rate (7%). It is estimated that this scenario would result in a net cost per tonne of $64 (lower than the central case).

Table 25: Sensitivity analysis of cost-effectiveness result (2021–2040)

Note: Values discounted to present value using a 3% discount rate, except in the case in which a 7% rate is used.

Variable(s) Sensitivity Case Net Costs
(Millions)
GHG Reductions
(Mt)
Net Cost
per Tonne
($/tCO2e)
Central case (from Table 23) N/A 20,623 221 94
Credits from actions along the lifecycle Fewer 26,728 208 128
More 21,115 227 93
Credits from supplying low-carbon fuels Fewer 24,018 191 126
More 19,554 200 98
Credits from end-use fuel switching Fewer 26,601 254 105
More 16,357 173 95
Fund Not used 26,093 244 107
Price differential: low-carbon fuel versus fossil fuel Lower 16,668 221 75
Higher 24,506 221 111
Discount rate 7% 14,059 221 64

To validate the break-even value, the net cost per tonne of the proposed Regulations was compared to the Department’s central SCC value for the year 2020 ($50/tCO2) and more recently published SCC estimates in the academic literature from the DICE and PAGE models ($135/tCO2 and $440/tCO2, respectively). For the break-even value to be plausible, it should fall within the range of SCC values reported in Table 26.

Table 26: Sensitivity analysis of break-even plausibility (2021–2040)
Variable(s) Sensitivity Case Net Cost
per Tonne
($/tCO2e)
Break-even Result
Department ($50/tCO2) DICE
($135/tCO2)
PAGE
($440/tCO2)
Central case (from Table 23)   94 Net cost Net benefit Net benefit
Credits from actions along the lifecycle Fewer 128 Net cost Net benefit Net benefit
More 93 Net cost Net benefit Net benefit
Credits from supplying low-carbon fuels Fewer 126 Net cost Net benefit Net benefit
More 98 Net cost Net benefit Net benefit
Credits from end-use fuel switching Fewer 105 Net cost Net benefit Net benefit
More 95 Net cost Net benefit Net benefit
Fund Not used 107 Net cost Net benefit Net benefit
Price differential: low-carbon fuel versus fossil fuel Low 75 Net cost Net benefit Net benefit
High 111 Net cost Net benefit Net benefit
Discount rate 7% 64 Net cost Net benefit Net benefit

Over the time frame of analysis, it is estimated that the proposed Regulations would result in a societal cost per tonne that ranges between $64 and $128, with a central estimate of $94. For all of the sensitivity scenarios, it is plausible that the proposed Regulations would still yield a net benefit result.

Potential implications from changes to the proposed June 2020 regulatory design

The regulatory scenario assessed in both the central case and the sensitivity analysis is of the proposed regulatory design that was presented to stakeholders in the June 2020 consultations. The Department has updated the design of the proposed Regulations since then based on stakeholder feedback and additional analysis. Important changes that would affect the results of this analysis include the delay of the phase out on residential EV charging credits for end-use fuel switching, which now starts in 2031 instead of 2027, and the coming-into-force date of the proposed Regulations, which is now December 1, 2022, instead of June 1, 2022. The last compliance period for the RFR would be 2022, the final reporting and true-up period would be in 2023, and the RFR would be repealed in 2024. However, the June 2020 consultations had a last compliance period for the RFR in 2021, final reporting and true-up period in 2022, and repeal in 2023. Consequently, the one-time rollover of credits from RFR would occur in 2023 instead of 2022. These changes could not be incorporated into the analysis in time for the Canada Gazette, Part I publication. However, these design changes will be incorporated into the analysis presented alongside the final Regulations, when published in the Canada Gazette, Part II.

The delay in the phase-out of residential EV charging credits would lead to a higher number of credits created from end-use fuel switching over the time frame of analysis. Since end-use fuel switching credits are considered non-incremental, cumulative baseline credits would increase, crowding out higher cost, incremental actions. As a result, the cumulative incremental cost and GHG emission reductions estimated between 2021 and 2040 would decrease.

The delay in the coming into force would reduce the credits required in 2022. However, all credits created from baseline pathways between the time the final Regulations are expected to be registered in 2021 and their coming into force in late 2022 would be banked. The additional six months would provide primary suppliers with more lead time to develop and establish incremental credit pathways, which would decrease cumulative incremental costs and GHG emission reductions slightly.

Furthermore, the delay in the one-time rollover of credits would result in an additional year of RFR credit creation. In conjunction with the change in the coming into force date, this would provide additional baseline credits, which would allow primary suppliers somewhat more lead time to develop and establish incremental credit pathways. However, the delay in the one-time rollover of credits is not expected to change the baseline credits or credits required significantly, and would have an insignificant impact on the cumulative costs and GHG emission reductions.

Overall, some incremental actions and capital expenditures may not be required as early as estimated in the analysis due to these design changes. It is expected that these impacts would be delayed by about a year. The cumulative and 2030 cost and GHG emission reduction estimates may decrease slightly but are not expected to substantially change the results.

Potential implications due to the COVID-19 pandemic

The baseline scenario does not account for impacts associated with the COVID-19 pandemic given that it was developed before updated forecasts were available. Impacts from COVID-19 are expected to influence the results presented in this analysis and will be captured in the baseline scenario presented in the analysis published alongside the final Regulations, once published in the Canada Gazette, Part II. For now, this section describes qualitatively some of the likely effects that COVID-19 may have on the results.

Primary suppliers, low-carbon fuel suppliers, and other sectors of the economy have faced significant declines in product demand due to social distancing guidelines and lockdown measures used to limit the spread of COVID-19. The oil and gas sector has been particularly affected by a world oil price crash that resulted from both reduced demand stemming from the pandemic and global oversupplies of oil.footnote 88

According to the International Energy Agency, social distancing guidelines and lockdown measures have also resulted in supply chain disruption and delays in project construction for renewable sectors. Restrictions on business activities and travel have reduced energy demand in transportation and industry, decreasing the consumption of low carbon intense energy. Emerging macroeconomic challenges may lead to the cancellation or suspension of investment decisions for projects under development, even if they are at an advanced stage.footnote 89

As a result, primary suppliers and other voluntary parties may have less ability to invest in credit-creating actions in the first few years of implementation of the proposed Regulations. It is expected, therefore, that short-term estimates of credits required, credits created, and incremental benefits and costs may be lower than estimated in this analysis. To mitigate potential investment barriers due to COVID-19, the proposed Regulations are less stringent in the early years and firms should be able to comply without having to make incremental investments.

In its July 2020 Monetary Policy Report, the Bank of Canada forecasts a sharp rebound in economic activity in the reopening phase of the recovery from the COVID-19 pandemic, followed by a more prolonged recuperation phase over the medium term in a slow return to pre-pandemic levels of economic activity in Canada.footnote 90 It is difficult to predict the future trajectory of the COVID-19 pandemic or its long-term impact on consumer and business behaviour on energy demand. However, it may be reasonable to expect that firms would have less difficulty raising capital for investments as the proposed Regulations become more stringent in the long run. As such, it is expected that long-term estimates of credits required, credits created, and the incremental benefits and costs should be relatively the same as presented in this analysis.

Distributional analysis of regulatory impacts

Between 2021 and 2040, the cumulative domestic GHG emission reductions attributable to the proposed Regulations are estimated to be approximately 221 Mt CO2e (about 17.5 Mt in 2030) at a net societal cost of about $20.6 billion. This analysis presents the benefits and costs to Canadian society as whole. The proposed Regulations are also expected to increase fuel prices, so a fuel price analysis was conducted and is presented below. In addition, the direct impacts of the proposed Regulations and effects from relative changes in energy prices are not uniformly distributed across society so the analysis has considered a range of distributional impacts, including the overall GDP and GHG impact, impacts on provinces and territories, impacts on sectors, as well as household and gender-based analysis plus (GBA+) impacts. Furthermore, distributional impacts are presented using 2030 as a representative year given that 2030 is the year in which the proposed Regulations would reach full stringency.

Fuel price analysis

The proposed Regulations are expected to increase production costs for primary suppliers, which would increase liquid fuel prices for households and freight transportation since they are the main consumers of liquid fuels. Table 27 presents the share of liquid energy demand by broad sector category projected in 2030. The majority of gasoline and LFO demand is consumed by households and the majority of diesel and HFO demand is consumed by freight transportation and industry.

Table 27: Share of liquid energy demand by sector category in 2030
Sector category Share of liquid energy demand (%)
Households 41
Freight transportation 40
Industry 11
Commercial 8
Electric utility generation <1

Price impacts in the earlier years of the proposed Regulations are expected to be minimal given the initial stringency in 2022 (at 2.4 gCO2e/MJ) that would be met with credits created from actions expected to occur in the baseline scenario (such as credits from end-use fuel switching and existing blending requirements), which would be banked in the initial years. As the stringency increases gradually over time to 12 gCO2e/MJ in 2030, incremental price impacts would likely increase year by year as firms begin to invest in incremental credit creating projects.

Three scenarios of potential incremental price impacts in 2030 on liquid fossil fuels are presented in Table 28, assuming that demand for energy remains constant (a partial-equilibrium analysis). One scenario represents a low-likelihood situation in which all credits are self-created and used by primary suppliers to meet their CI reduction requirement, and therefore credits would not go to the credit market for sale. To estimate this, the average cost to create a credit was used and is estimated at about $110 per credit in 2030. The average cost to create a credit was estimated by taking the credit creation cost for each pathway in 2030 and then multiplying that by the number of credits created for each pathway. Another scenario represents a low-likelihood situation in which all credits are created by voluntary parties and are sold into the credit market at market value. To estimate this, the marginal cost to create a credit was used and is estimated at $330 per credit in 2030.

These scenarios represent lower and upper bound estimates of the cost per credit (none or all of the credits are sold on the market). A more likely situation would be where some credits are sold in the credit market at market value and some are created and used by primary suppliers to meet their own annual reduction requirement. For example, it is expected that most credits from actions along the lifecycle would be self-created by primary suppliers and would not be sold on the credit market at market value, while most end-use fuel switching credits would be created by voluntary parties and would go to market at market value. Credits from supplying low-carbon fuels are expected to be created via a combination of both voluntary parties and primary suppliers. These credits may not go to market if there is a contract in place between the voluntary parties producing low-carbon fuels and the primary suppliers.

With this in mind, a couple of simple scenarios are considered to establish a narrower range of estimates for the likely cost per credit. This suggests that the average cost would be within this range and a value of $215 is used to determine a central estimate of likely fuel cost increases attributable to the proposed Regulations.

Table 28: Estimated range in incremental fuel price impacts in 2030 (cents per litre)

Note: this analysis does not account for increased low-carbon fuel use in the fuel pools.

Fuel Pool No credits go to market (All credits are self-created) Some credits go to market (Some credits are self-created) All credits go to market (No credits are self-created)
Gasoline pool 4 7 11
Diesel pool 4 9 13
LFO pool 5 9 14
HFO pool 5 10 15

The degree to which production cost increases results in price increases to consumers depends on several market factors, including distribution constraints, market share competition, refinery capacity and production, and fuel demand. Of the various factors contributing towards the fuel prices, the crude oil price has the highest variability. The Energy Information Administration estimates the single largest influence behind changing gasoline prices is the crude oil market, which is subject to speculation, price shocks, supply disruptions, and general uncertainty.footnote 91 For example, average gasoline prices in Canada from 2010 to 2019 have ranged from approximately 90 to 140 cents a litre.footnote 92 Gasoline prices experience volatility often related to fluctuations in the crude oil market, but gasoline is subject to its own supply and demand pressures. Cyclical trends such as seasonal changes in refining costs, production adjustments, and changes in demand contribute to gasoline price movements over a typical year.footnote 91 Therefore, while the proposed Regulations may increase fuel prices, their anticipated impact on fuel prices is within the range of regular fuel price fluctuations.

EC-PRO modelling

A macroeconomic analysis of impacts on GDP and GHG emissions, impacts on provinces and territories, and impacts on sectors was modelled using EC-PRO, the Department’s computable general equilibrium (CGE) model of climate change policies. EC-PRO captures differences between provinces and territories and forecasts national impacts. EC-PRO simulates the response to the proposed Regulations in Canada’s main economic sectors in each jurisdiction, and models the interactions between sectors, including interprovincial trade. It captures characteristics of provincial production and consumption patterns through a detailed supply-use table and links provinces and territories by means of bilateral trade. Each province and territory is explicitly represented as a region. The rest of the world is represented as import and export flows to Canadian provinces and territories, which are assumed to be price-takers in international markets. The model incorporates information on energy use and combustion emissions from the Departmental Reference Case.

Impacts on GDP and GHG emissions

The proposed Regulations would increase production costs for primary suppliers. Subject to the market considerations outlined above, it is likely that at least some of these costs would be passed on in the form of increased prices for liquid fuel consumers (i.e. households and industrial users). Credit creation would also generate revenue for low-carbon energy suppliers, which would make low carbon energy sources (e.g. electricity) relatively less expensive in comparison. On balance, these price effects are expected to lead to decreased end-use demand for fossil fuels and increased end-use demand for lower carbon energy sources. To evaluate the direct impact of the proposed Regulations as well as the effect of relative price changes on Canadian economic activity and GHG emissions, a macroeconomic analysis was completed using the EC-PRO model. As EC-PRO is a general equilibrium model, it captures direct and indirect impacts to all components of GDP. Modelling suggests that the proposed Regulations would lead to a decrease in overall GDP of up to $6.4 billion (or up to 0.2% of total GDP) and GHG emission reductions of up to 20.6 Mt in 2030, assuming that all credits are sold in the credit market and are sold at the marginal cost per credit.

The proposed Regulations would work in combination with other federal, provincial, and territorial climate change policies to create an incentive for firms to invest in innovative technologies and fuels by setting long-term, predictable and stringent targets. The broad range of compliance strategies allowed under the proposed Regulations would also allow fossil fuel suppliers the flexibility to choose the lowest-cost compliance actions available. If the proposed Regulations induce more long-term innovation and economies of scale than currently estimated, then the proposed Regulations could result in lower costs and greater reductions, particularly over a longer time frame.

GDP impacts by province and territory

The costs associated with the proposed Regulations would vary by region. Table 29 shows the breakdown of estimated GDP impacts due to the proposed Regulations across Canada using EC-Pro.

Table 29: Distribution of estimated GDP impacts across regions in 2030
Province/Territory Millions of Dollars Percentage Change (%)
British Columbia (171) <(0.1)
Alberta (171) <(0.1)
Saskatchewan (17) <(0.1)
Manitoba (361) (0.4)
Ontario (3,710) (0.4)
Quebec (1,273) (0.2)
New Brunswick (208) (0.5)
Nova Scotia (229) (0.5)
Prince Edward Island (35) (0.4)
Newfoundland and Labrador (243) (0.7)
Yukon (3) <(0.1)
Northwest Territories 17 0.6
Nunavut 31 0.9

It is estimated that the proposed Regulations would have a negligible GDP impact on British Columbia due to revenues generated from baseline blending credits attributed to the existing Renewable and Low Carbon Fuel Requirements Regulation and baseline end-use fuel switching credits in the province. Alberta and Saskatchewan are also estimated to have negligible GDP impacts since upstream oil sectors are largely located in these provinces and there are more opportunities to generate credit revenue from actions along the lifecycle of fuels such as CCS and flaring/conserving methane relative to other provinces.

Ontario and Quebec would have the largest absolute decrease in GDP given that they are the largest provinces by population and their aggregate fuel consumption is higher than in other provinces. However, relative to the size of their GDP, it is estimated that provinces in Atlantic Canada would be more negatively affected by the proposed Regulations. This is largely because the Atlantic Provinces use more LFO for home heating than other provinces. However, the Government is considering measures to accelerate the transition away from LFO in the Atlantic Provinces in order to reduce this impact. In addition, Atlantic Canada is estimated to have fewer opportunities to create credits from actions along the lifecycle of fuels (for example credit creating opportunities from CCS are unavailable due to inadequate geological storage). Furthermore, baseline EV and low-carbon fuel uptake in Atlantic Canada is low in comparison to other provinces. This lack of baseline credits affects Newfoundland and Labrador in particular given that the province does not have a blending requirement in place and it was exempt under the federal RFR.

Quebec is less affected by the proposed Regulations in comparison to most provinces since baseline EV credits are higher compared to the national average. This is because Quebec has provincial EV policies in place and its electricity grid is the least carbon intensive in Canada. Ontario and Manitoba exhibit comparable estimated GDP impacts in scale. While fuel consumption per unit of GDP is projected to be higher in Manitoba than in Ontario, credits from EV uptake in Manitoba are higher due to the low carbon intensity of its electricity grid. As such, Manitoba has a similar decrease in GDP to Ontario. For all three regions, credit creation from actions along the lifecycle of fuels is limited, with the supply of low-carbon fuels and baseline EV uptake creating the majority of credits.

Liquid fuels supplied to non-industrial remote communities are exempt under the proposed Regulations. As a result, the model assumes that liquid fuels supplied to the territories would not be covered under the proposed Regulations, but the territories would still have the ability to generate revenue from the creation of credits. In the model, credits are created in the territories via endogenous fuel switching to lower carbon energy sources. This results in a positive impact on GDP. In reality, the magnitude of the positive impact on GDP in the territories may not be as high as estimated here, given that this analysis does not capture costs related to liquid fuel supplied to industrial users located in remote communities.

Impacts by sector

It is expected that the proposed Regulations would increase production costs for primary suppliers (mostly oil refineries and upgraders). In turn, the resulting higher liquid fossil fuel prices would increase costs for sectors that use these fuels in their production processes, which would result in changes to output. Table 30 presents the estimated percentage change in output by sector in 2030, assuming that all credits go to market and sell at the marginal cost per credit. Change in output reflects the increase or decrease in the output of finished products within a particular sector. In EC-PRO, sectors adapt to changing prices in order to maximize profit, and each sector is modelled as one representative firm per province or territory. Therefore, the results do not reflect the impacts on individual facilities. Based on these assumptions, it is estimated that the proposed Regulations would have a negative impact on output for all sectors except for electricity generation. Uncertainty exists surrounding the extent to which fuel consumers would be able to fuel switch away from liquid fuels and make efficiency improvements to mitigate cost impacts and resulting output reductions.

Table 30: Cost as a percentage change in output by sector in 2030
Sector Change in Output (%)
Electricity generation 0.2
Cement and other non-metallic minerals <(0.1)
Services (0.1)
Manufacturing and construction (0.1)
Airline transportation (0.1)
Mining (including coal) (0.1)
Oil sands upgraders (0.1)
Oil and gas pipelines (0.1)
Primary metals (including iron and steel, aluminum, and other) (0.1)
Chemicals (including fertilizers) (0.1)
Conventional oil extraction (0.1)
Agriculture, forestry and lumber (0.2)
Natural gas extraction, processing and distribution (0.3)
Pulp and paper (0.3)
Primary oil sands and oil sands mining (0.6)
Freight transportation (ground) (1.2)
Oil refineries (1.5)
In-situ oil sands (1.6)

This modelling estimates that the proposed Regulations would decrease output for in-situ oil sands (1.6%), oil refineries (1.5%), and freight transport (1.2%) the most. Oil refineries are primary suppliers under the proposed Regulations and the majority of the liquid fossil fuels they produce are supplied for domestic use. Therefore, the majority of their output is directly subject to the CI reduction requirements under the proposed Regulations. A combination of low-carbon fuel uptake and price impacts on fuel cause a decrease in output for refineries. Since refined fossil fuel output decreases, the demand for bitumen also decreases. Freight output also decreases because liquid fuels represent a relatively large portion of the freight costs. Increased freight production costs are passed onto service users which results in decreased demand.

Oil sands upgraders are also primary suppliers under the proposed Regulations; however, it is estimated that the decrease in product output for upgraders is minimal (0.1%). This is because most of the synthetic crude produced by upgraders is exported, and as such, is not covered by the proposed Regulations. In addition, it is estimated that upgraders, and to varying degrees oil extraction sectors, would have more revenue-generating opportunities from the creation of credits for actions such as CCS and process improvements, in order to meet their annual CI reduction requirements.

Most of the other sectors presented in Table 30 are end users of liquid fossil fuels and/or freight transportation service users and are not subject to the requirements under the proposed Regulations. The magnitude of the estimated impact on these sectors is dependent on how much liquid fuel and freight transportation they consume, as well as the degree to which increased fuel costs are likely to lead to reduced demand for their products. As a result, it is estimated that these sectors would have negligible to more moderate decreases in product output ranging from less than 0.1% in the cement and other non-metallic minerals sector to 0.6% in the primary oil sands and oil sands mining sector.

Electricity generation has a positive output effect (0.2%) because the proposed Regulations would create an incentive to switch from fossil fuels to electricity since it is generally less carbon intensive, depending on the region. The agriculture, forestry and lumber sector is estimated to have a negative output effect (0.2%) because low-carbon fuels used for blending are assumed to be imported. To the extent that the low-carbon fuels used for compliance with the proposed Regulations are produced domestically, the impact on output would be lower or even positive.

Competitiveness impacts
Primary suppliers

Refineries, upgraders, and importers that supply liquid fossil fuels (primary suppliers) would incur compliance costs in order to comply with the proposed Regulations. Fossil fuel importers and producers are subjected to the same annual CI reduction requirement. Therefore, in the near term, refineries and importers would have the scope to increase product prices in order to mitigate increased production costs rather than to absorb them through lower profit margins. This would allow them to maintain competitiveness in the short run. However, over time, increases in liquid fuel prices would be expected to change consumption behaviour in Canada, reducing the overall demand for liquid fossil fuels and their inputs (e.g. bitumen).

Upgraders would have limited flexibility to increase product prices to consumers in order to mitigate compliance costs. Prices for inputs (e.g. heavy oil and bitumen) are based on North American heavy oil benchmarks, leaving little scope for upgraders to influence the prices. However, upgraders primarily export the synthetic crude that they produce, so the impact on the sector is expected to be minimal given that exports are not covered under the proposed Regulations. In addition, most of the companies that own upgraders also own refineries. These companies may be at more of an advantage under the proposed Regulations than refining companies that do not own any upstream operations given that they would have more credit creating opportunities for actions along the lifecycle of fuels.

Compliance costs associated with the proposed Regulations would likely be greater for firms with less ability to create compliance credits rather than acquiring them from third parties. These are likely to be firms with constrained access to capital, such as primary suppliers with lower levels of production, or limited access to credit creation opportunities. For these firms, additional compliance costs could affect their economic viability if there is insufficient time remaining in the life of a facility to recover the compliance costs. In certain cases, facilities may need to alter operations due to the proposed Regulations.

It is possible, but unlikely, that firms may choose to increase exports of fossil fuels in order to avoid domestic CI reduction requirements under the proposed Regulations. It is unlikely because all regulated fossil fuels under the proposed Regulations are assigned the same liquid credit reference CI value, so there is no advantage to adjusting the mix of fuels sold domestically or exported based on differences in CI values. Furthermore, international demand for fossil fuel is exogenous and the proposed Regulations would not spur an increase in demand for Canadian fossil fuel outside of Canada.

In response to potential financial and competitiveness impacts, several flexibilities have been included in the proposed Regulations. For example, the broad range of compliance strategies provided for under the proposed Regulations would allow primary suppliers to choose the lowest cost compliance actions available. In addition, the long-term nature of the proposed Regulations and the gradual increase in the annual CI reduction requirement between 2022 and 2030 would allow time for investments to take place and would give investors the certainty needed to make longer-term investments in clean technologies, production facilities, and infrastructure.

Freight transportation sector

The freight transportation sector is an end user of liquid fossil fuels, and would incur increased costs due to the proposed Regulations as a result of liquid fuel price increases. As this sector is not trade-exposed and does not compete directly in international markets, it is expected that the freight transportation sector would offset any increased costs due to the proposed Regulations by increasing freight transport service prices. As a result, sectors that use freight transportation services, such as mining for example, would incur increased costs from the proposed Regulations. However, it is possible that some firms in the freight transportation sector may not be able to fully pass on increased costs and may need to absorb some of these costs, depending on market share competition in the regions in which they operate. As a result, additional compliance costs may require those firms to alter operations due to the proposed Regulations.

Liquid fossil fuel end users and freight transportation service users

Some sectors that are liquid fossil fuel end users or are freight transportation service users, such as mining and iron and steel, would experience increased costs as a result of the proposed Regulations. However, the output effects by sector are estimated to be low, even when using a low-likelihood scenario where all credits go to market at the marginal cost per credit (see Table 30). Therefore, it is unlikely that these increased costs would cause industry to move production to jurisdictions with lower carbon-related costs. Consequently, it is considered unlikely that the proposed Regulations would result in a phenomenon known as “carbon leakage,” in which domestic production is displaced to a foreign location, with domestic GHG emissions “leaking” out of Canada to other jurisdictions.

Household and gender-based analysis plus (GBA+) impacts

The proposed Regulations are estimated to increase the price of liquid fuels and a large portion of liquid fuels are consumed by households. The proposed Regulations would increase transportation fuel and home heating expenses for households and it is estimated that increased household costs for liquid fuels could range from $1.2 to $3.7 billion, with a central estimate of $2.4 billion. Assuming 2.5 people per household on average in Canada and applying that to the 2030 population projection of 42.1 million, it is estimated that the proposed Regulations would result in an average cost per household of $69 to $208 in 2030, with a central estimate of $136.footnote 93 However, these impacts would not be distributed equally across households. The average cost per household would depend on how much or what type of liquid fuel a household consumes.

It is expected that increases in transportation fuel and home heating expenses would disproportionately impact lower and middle-income households, those living in single detached households or those without control over the energy efficiency of their dwellings that use heating oil, as well as households currently experiencing energy poverty or those likely to experience energy poverty in the future.footnote 94 Moreover, according to Statistics Canada, single mothers are more likely to live in lower-income households, and may be more vulnerable to energy poverty and adverse impacts from increases to transportation and home heating prices.footnote 95

Seniors living on fixed incomes may also face higher transportation and heating costs resulting from the proposed Regulations. This may be most acute for seniors living in the Atlantic provinces, where they account for a higher share of the total population compared to other Canadian provinces and are also more likely to experience some of the highest energy expenditures in Canada proportional to income.footnote 96, footnote 97 It is possible that there could be other socio-economic groups that may have disproportionately lower income, may be at an increased vulnerability to energy poverty, or may be adversely affected by the proposed Regulations. However, these groups may not be fully captured in this analysis due to lack of data availability, scarcity of research, or under-representation in available studies (such as the LGBTQ2+ community).

Household transportation

Households use liquid fuels primarily for passenger transportation, through personal vehicle ownership and public transportation. This would result in higher refuelling costs for owners of personal vehicles, and added costs to public transportation agencies, potentially resulting in higher fares. Using the increased gasoline price estimates from Table 28, it is estimated that increased costs could range from $57 to $156 per vehicle in 2030 for households that use gasoline-powered internal combustion engine vehicles, with a central estimate of $100 per vehicle.footnote 98 However, the overall impact on households would vary based on factors such as vehicle fuel type, geography, distances travelled by households and vehicle efficiency.

Low-income households may be disproportionately affected by the proposed Regulations as they may incur higher transportation costs relative to their income.footnote 99, footnote 100 Moreover, low-income households tend to have a lower ability to absorb higher fuel costs compared to high-income households. In addition, low-income households that rely on personal vehicle transportation may also have limited ability to switch to newer, cleaner or more fuel-efficient vehicles. For example, EVs (such as plug-in EVs, plug-in hybrid EVs, and hybrid EVs) are relatively newer technologies that tend to have greater upfront costs compared to internal combustion engine vehicles. Therefore, low-income households may continue to purchase cheaper automobile options (i.e. those with combustion engines) despite increased gasoline prices, though they may choose not to drive as much.footnote 100

The proposed Regulations would also affect households differently depending on geography and region. For instance, rural households are more likely to have higher rates of vehicle ownership, but they are also more likely to have less access to public transportation.footnote 101 For this reason, they may have limited opportunity to reduce their fuel consumption in response to higher gasoline prices. Similarly, Canadian households in the Atlantic Provinces spend a higher proportional amount of their expenditures on private transportation compared to all other provinces while also having some of the lowest average levels of disposable income.footnote 102, footnote 102 Therefore, the impact of increased gasoline prices may have a larger impact on households in the Atlantic Provinces compared to other areas.

The proposed Regulations would increase the price of diesel fuel. Municipalities that rely on diesel-powered buses as part of their public transportation fleets may respond to this fuel price increase by raising transit fares. This would disproportionately impact lower-income households; a group more likely to use mass transit on a regular basis, and also more sensitive to transit fare increases.footnote 103, footnote 104 However, impacts could be mitigated through discounted transit fares offered to lower-income households. An increase in fuel costs could also result in encouraging increased transit ridership, potentially generating additional revenue to offset the rising costs.footnote 105

If electric bus uptake is higher than estimated in this analysis, this could also reduce the impact of fuel prices on transit authorities. As transit authorities shift towards replacing diesel powered fleets with electric buses, fuel consumption would decrease, and a variation in fuel price would have a smaller impact on operating expenditures. Furthermore, transit authorities could create credits under the proposed Regulations by implementing electric bus fleets. As a result, cost impacts on transit authorities could be mitigated through sale of credits.

Household heating

The proposed Regulations would also have regional impacts that would be felt beyond the national average. Homes that use LFO powered furnaces may incur higher costs compared to homes that use other forms of energy, such as natural gas. Using the increased LFO price estimates from Table 28, it is estimated that households that use LFO for home heating could experience an increase in heating costs of about $66 to $232 in 2030, with a central estimate of $149.footnote 106 This represents a 3% to 11% increase in LFO heating costs, with a central estimate of 7%.footnote 107 That said, the impact on households that primarily use LFO for home heating would vary depending on various factors such as size or type of dwelling, region, or home heating efficiency. For example, those living in rural areas would be more likely to experience negative welfare impacts from increases in heating costs, particularly as they tend to live in larger dwellings compared to urban areas.footnote 108

In contrast to other provinces in Canada, fuel oil expenditures as a share of total energy expenditures are much higher in the Atlantic Provinces. This is in part due to fuel oil being a more commonly used energy source for home heating.footnote 109 For example, fuel oil is used by 78% of households in Prince Edward Island and 48% of households in Nova Scotia, and while electricity is the main home heating source in Newfoundland and Labrador and New Brunswick, fuel oil is used to a greater extent in these provinces than in the rest of Canada.footnote 110 Overall, for households in the Atlantic Provinces that rely on home heating oil, it is estimated that heating costs would range from about $95 to $334 in 2030, with a central estimate of $214.footnote 111

Low-income households that primarily use LFO for home heating could be particularly affected since they may not have the resources to absorb higher home heating costs. In addition, these households may not have the ability to switch to cheaper forms of home heating due to location, type of residence, or high capital costs to install a new furnace/upgrade to a higher efficiency furnace. This may be particularly the case for Indigenous, visible minority, and recent immigrant households as they have a higher tendency to be disproportionally lower income than other Canadian households and may live in older and less-energy efficient dwellings as well as dwellings more in need of repair.footnote 112 Furthermore, recent immigrant households tend to have higher home occupancy rates due to larger family sizes, which may necessitate larger dwellings.footnote 112, footnote 113 As such, with larger dwellings, these households would require higher energy expenditures to maintain the same level of comfort in the event that home heating prices rise.

Households that own their home may have a greater ability to switch to cheaper forms of home heating than those that rent. This is because homeowners typically have more power to make energy efficiency improvements to their home compared to renters. For instance, landlords may be less inclined to pay higher upfront capital costs to install more energy efficient furnaces as tenants are often responsible for paying their own utility bill.footnote 114 Moreover, as low-income households tend to have the least access to home ownership, live in older and less-energy efficient dwellings, and live in smaller dwellings that require more energy per floor area, they may be disproportionately impacted by increased fuel costs for home heating.footnote 115, footnote 116

Impacts on remote communities

The proposed Regulations would exempt liquid fossil fuels supplied to non-industrial remote communities in order to minimize the potential for disproportionate impacts to occur.

Employment impacts

It is estimated that the proposed Regulations could create job opportunities in sectors that may benefit from generating credit revenue (e.g. clean technology), and lost job opportunities in other sectors that are primary suppliers or that use liquid fuels (e.g. oil and gas). A full employment analysis has not been conducted because GBA+ impacts would depend on the actual compliance strategies chosen and would depend on the characteristics of the specific populations employed at firms or facilities that may be affected. For example, it is assumed in the analysis that increased demand for low-carbon fuels would be met by imports. However, if low-carbon fuels are supplied domestically, this could result in positive employment impacts in low-carbon fuel sectors. Young and middle-aged men would be at the greatest advantage to benefit from employment opportunities within these sectors.footnote 117, footnote 118

Job opportunities in the oil and gas, or freight transport sectors are expected to be negatively impacted given that the proposed Regulations would increase production costs for these sectors and would decrease demand for fossil fuel products. Canada’s oil refining sector as an example, employs a high proportion of middle-aged men compared to the average working-age population, this group may face an increased risk of job scarcity due to the proposed Regulations.footnote 119 When searching for new employment, older workers in Canada (especially those aged between 55 and 64) face unique barriers including ageism; lack of education and access to training; difficulty finding and applying to jobs; health issues, work-life balance issues, and lack of workplace accommodations.footnote 120, footnote 121, footnote 122 Facilities within rural communities may also be adversely impacted. Rural facilities often contribute to rural economies by providing high-paying salaries, municipal tax proceeds, and infrastructure investments. As such, reductions in industrial activity, salaries, and jobs could potentially negatively affect economic activity and population retention in rural communities.

Environmental impacts

A consequence of climate change is the increased frequency, intensity and/or duration of extreme weather events, which increases risks for vulnerable populations such as children, seniors, low-income earners and the homeless, as well as communities in areas exposed to natural hazards. These impacts include increased demands on health care services, disruption of social networks, damage to, or unavailability of, housing, shelter and other physical infrastructure (e.g. hospitals, grocery stores, telecommunications).footnote 123 Incremental damages incurred as a result of an increase in GHG emissions are considered to be distributed globally. There are two unique aspects to climate change: (1) it involves a global externality, where emissions anywhere in the world contribute to global damages; and (2) the only way to effectively address climate change is through global action. The proposed Regulations, in combination with actions in the PCF, would help to minimize the impacts of climate change globally. These measures could also minimize the impacts of climate change on potentially vulnerable groups in Canada, and contribute to a resilient Canadian economy.

Small business lens

Analysis under the small business lens concluded that the proposed Regulations would not directly impact Canadian small businesses. No mandatory regulated parties are considered small businesses. Furthermore, as required by CEPA, primary suppliers that produce or import less than 400 m3 of liquid fossil fuel per year would not be subject to the requirements of the proposed Regulations. However, it is possible that some of the businesses that choose to opt in to this regulatory regime by becoming voluntary participants may be considered small businesses. The costs incurred by voluntary participants due to the proposed Regulations do not represent compulsory regulatory costs for small businesses, as these facilities have the discretion to choose to participate. It is likely that any small business that voluntarily participates in the proposed Regulations would do so in order to generate revenue through the sale of credits that would be greater than any costs incurred. Thus, the proposed Regulations are expected to benefit any small businesses that choose to opt in.

One-for-one rule

The one-for-one rule applies since there is a net incremental increase in administrative burden on business. The proposed Regulations would result in a new regulatory title and would be considered an “IN” under the Government of Canada’s one-for-one rule, meaning that the proposed Regulations would increase administrative burden costs on businesses. However, as the proposed Regulations would also incorporate the renewable fuel content requirements set out under the federal RFR, this new regulatory title would be offset by the proposed repeal (an “OUT”) of the existing federal RFR. This would result in a net neutral impact on regulatory titles as per the Government of Canada’s one-for-one rule.footnote 124

Under the proposed Regulations, only primary suppliers would be subject to administrative requirements. While other parties, such as renewable fuel producers and importers, can voluntarily create credits, and would incur administrative requirements if they choose to participate in the credit market, it is expected that they would do so only where the benefit is greater than the cost of participating. Therefore, the one-for-one rule analysis only accounts for the administrative requirements that would be imposed on primary suppliers. As per the Treasury Board of Canada Secretariat (TBS) guidance, if a regulatory change provides more than one option for compliance or reporting for a single regulatory requirement, the rule applies only to the option that imposes the lowest administrative costs.footnote 125 Given this, it is assumed that primary suppliers would choose to purchase credits.

The administrative costs that would result from implementation of the proposed Regulations are primarily tied to the ongoing record-keeping requirements, reporting, submitting information on credit creation activities, and third party auditing of reports. The proposed Regulations would require primary suppliers to submit annual reports including a compliance report, a fossil fuel production report, and validation and verification reports. This is estimated to range from an average of 8 to 90 hours per company per year, depending on the type of report. For legal contracting, it is estimated that it would take about 4 hours on average at a frequency of 8 times per company per year. Primary suppliers would also be required to submit a one-time registration report to the Department to register as a participant under the proposed Regulations. In addition, management, scientists, engineers, analysts, accountants, lawyers and auditors would be required to learn about the proposed Regulations. It is assumed that it would take about 6 hours per company to register and between an average of 8 to 90 hours per company to learn about the proposed Regulations.

The proposed Regulations would also incorporate the existing volumetric content requirements that are in the federal RFR, which currently require an average 5% renewable fuel content in gasoline and 2% renewable fuel content in diesel fuel and heating distillate oil. Incorporating RFR requirements into the proposed Regulations and repealing the RFR itself would not impose new administrative burden on businesses (i.e. the existing RFR requirements would be carried over to the proposed Regulations without change), but this would decrease administrative burden.

The last compliance period for the RFR would be 2022. The final reporting and true-up period would be in 2023, and the RFR would be repealed in 2024. As of 2023, RFR stakeholders (e.g. fossil fuel and renewable fuel producers and importers) would no longer be required to keep records and submit compliance unit account books. In addition, they would no longer be required to keep records or submit reports for Schedule 4 (Annual Report from a Primary Supplier), Schedule 5 (Annual Report from a Participant), and Schedule 7 (Annual Report from a Renewable Fuel Producer or Importer), or complete Schedule 3 (Auditor’s Report) auditing as of 2024. The one-for-one rule analysis presented here is based on the proposed regulatory design that was presented to stakeholders in the June 2020 consultations, which had a last compliance period for the RFR in 2021, final reporting and true-up period in 2022, and repeal in 2023. This change could not be incorporated into this analysis in time for the Canada Gazette, Part I publication. Therefore, administrative costs and cost savings presented in this analysis would be slightly overestimated but the results are not expected to be significantly different. This design change will be incorporated into the one-for-one rule analysis presented alongside the final Regulations, when published in the Canada Gazette, Part II.

The proposed Regulations would regulate a total of 39 primary suppliers, 21 out of 39 are already regulated under the RFR. Administrative costs would be borne by all 39 primary suppliers regulated under the proposed Regulations. The RFR regulates a total of 58 stakeholders, 27 out of 58 were primary suppliers and 31 out of 58 were renewable fuel suppliers. All 58 stakeholders under the RFR would incur administrative cost savings (including the 21 primary suppliers that would now be regulated under the proposed Regulations).

The total net present value administrative costs for all 45 primary suppliers (18 that would be newly regulated under the proposed Regulations and 27 that were previously regulated under the RFR) over a 10-year time frame (2021 to 2031) are estimated at $2,459,000, or $55,000 per company, though the cost per company would be lower or negative for the 27 primary suppliers that were previously regulated under the RFR and higher for the 18 primary suppliers that were not. The present value of the administrative cost savings for all 31 renewable fuel suppliers no longer regulated under the RFR are estimated at $388,000 or $13,000 per company over the 10-year time frame. Therefore, the total net present value of the administrative cost increases are estimated at $2,071,000 for all 76 stakeholders (31 renewable fuel producers and 45 primary suppliers), or $27,000 per company, for the proposed Regulations and the repeal of the RFR (an overall net “IN” under the one-for-one rule).footnote 126

Regulatory cooperation and alignment

International

Canada is working in partnership with the international community to implement the Paris Agreement, to support the goal of limiting temperature rise this century to well below 2°C and pursing efforts to limit the temperature increase to 1.5°C. As part of its commitments made under the Paris Agreement, Canada pledged to reduce national GHG emissions by 30% below 2005 levels by 2030. The Government of Canada has also committed to achieving net-zero emissions by 2050. The proposed Regulations would contribute to these GHG reduction targets.

No other jurisdictions have national regulations that are similar to the proposed Regulations. The EU has a similar policy in place called the Fuel Quality Directive that requires fuel suppliers to reduce lifecycle GHG emissions from fuels by up to 10% by 2020. The Fuel Quality Directive works in tandem with the EU Renewable Energy Directive, which stipulates that the share of biofuels in the transportation sector should be 10% (by energy content) for each member country by 2020. Some aspects of the proposed Regulations would align. For example, the proposed Regulations would have similar sustainability criteria as the EU’s Fuel Quality Directive in order to mitigate indirect land-use change impacts. However, despite similar objectives, the overall policy approach would differ from the EU.

United States

The United States does not have a national regulation that targets the lifecycle emissions of fossil fuel production. However, it does have the Renewable Fuel Standard (RFS), which requires a minimum volume of renewable fuel content in transportation fuel sold domestically.footnote 127 The proposed Regulations would not have any linkage to the RFS, as the two programs would be different in GHG reduction strategies. The proposed Regulations would provide an incentive to increase low-carbon fuel blending; however, the obligated parties would determine lifecycle carbon-intensity strategies.

California and Oregon have also enacted regulations that target CI reductions. California’s Low Carbon Fuel Standard (LCFS) was enacted in 2007, with a target of reducing the CI of transportation fuels at least 10% by 2020. In 2018, the California Air Resource Board approved amendments to the regulation, which requires fuel suppliers to reduce the CI of transportation fuels (petroleum fuels and those replacing them) they supply by at least 20% by 2030, from a 2010 baseline. Oregon’s Clean Fuel Program took effect in 2016 and requires a reduction in the annual average CI of Oregon’s transportation fuels (gasoline and diesel) by 10% from the 2015 level by 2025. It has similar objectives and approaches to California’s Low Carbon Fuel Standard and the proposed Regulations.

On June 26, 2019, the Minister of Environment and Climate Change and the Chair of the California Air Resources Board signed a new cooperation agreement to advance clean transportation. The agreement commits Canada and California to work together on their respective regulations to cut down on GHG pollution. Canada and California also committed to share best practices and technical information about regulating cleaner fuels, building on California’s Low Carbon Fuel Standard, Canada is also developing the proposed Regulations as part of this initiative.footnote 128

Despite similar objectives and approaches, the proposed Regulations would have several design elements specific to Canada. One such variation is the accounting of land use change while determining lifecycle CI of fuels. The California and Oregon regimes also differ partly because the proposed Regulations are targeting fuels not limited to transportation. The proposed Regulations and the California and Oregon programs would not have any interactions in the credit trading system.

Provinces and territories

The PCF was adopted by the Prime Minister and most First Ministers in December 2016. It sets out a collective plan to reduce GHG emissions, grow the economy and adapt to climate change. The proposed Regulations would be implemented as part of the PCF.

The proposed Regulations would aim to ensure compatibility with other federal and provincial policies such as federal and provincial carbon pricing systems, and BC’s RLCFRR. Participants would be able to create and bank credits for actions that include current federal and provincial renewable fuel regulatory requirements and BC’s RLCFRR. For GHG emission reduction projects, the proposed Regulations would recognize the following projects that reduce the CI of fossil fuels as eligible for credit creation:

The proposed Regulations allow for credit creation opportunities, even if a given project generate credits in another program (e.g. federal or provincial offset programs). However, it is important to note that different programs may decide not to provide credits for the same actions. Stakeholders seeking clarity should contact the programs they are interested in to determine if CFS credit creation would make a project ineligible for that particular program.

Quantification methodologies developed for credits in Compliance Category 1 would be made available and maintained by the Department. New quantification methodologies will be developed by a team of technical experts including Departmental representatives and reviewed by a broader consultative committee that includes stakeholders in industry, academia, other technical experts, etc. The development of new methodologies would take into consideration existing emission reduction accounting methodologies or offset protocols in other jurisdictions including offset protocols in provinces and territories. In development of the quantification methodologies, the Department will consider alignment with the CFS quantification methodologies and offset protocols of other jurisdictions; however, it is expected that the quantification approaches would differ on a national level when compared to provincial or territorial specific quantification methodologies. The Department would make the final determination on the addition of any new quantification methodologies, after having consulted the broader committee of technical experts.

Strategic environmental assessment

The proposed Regulations have been developed under the PCF. A strategic environmental assessment (SEA) was completed for this framework in 2016.footnote 129 The SEA concluded that proposals under the framework will reduce GHG emissions and are in line with the 2016–2019 Federal Sustainable Development Strategy (FSDS) goal of effective action on climate change.footnote 130

Rationale

GHGs are primary contributors to climate change. The extraction, processing and combustion of fossil fuels is one of the largest sources of GHG emissions in Canada. Canada intends to exceed its current commitment under the Paris Agreement to reduce GHG emissions by 30% below 2005 levels by 2030 and achieve the goal of net-zero emissions by 2050. Canada also made a commitment with provinces and territories to reduce GHGs under the PCF. To achieve these goals, a number of GHG reduction measures have been implemented or proposed, including the proposed Regulations.

The proposed Regulations would require liquid fossil fuel primary suppliers (i.e. producers and importers) to reduce the CI of liquid fossil fuels they produce and import in Canada by 12 gCO2e/MJ from 2016 intensity levels by 2030. The proposed Regulations are intended to be a flexible, performance-based policy tool that reduces the CI of liquid fossil fuels supplied in Canada. The proposed Regulations incorporate, but also improve upon the federal RFR by allowing more compliance flexibility and by incentivizing renewable and other clean fuels with the lowest carbon intensity. The proposed Regulations would also be complementary to carbon pricing as it would provide an additional incentive to reduce GHG emissions by reducing the CI of liquid fuels, which are primarily used in the transportation sector, thereby driving reduced emissions from transportation beyond what would be achieved by carbon pricing alone.

Since February 2017, the Department has held extensive consultation sessions with stakeholders and provincial partners on the proposed Regulations. Participation from industry stakeholders included fossil fuel producers and suppliers, low-carbon fuel producers and suppliers, EITE sectors, and various industry associations. Participation from non-industry stakeholders included provinces, territories, ENGOs and associations representing Indigenous Peoples. Stakeholders expressed a diverse range of views prior to prepublication of the proposed Regulations. ENGOs and stakeholders in the low-carbon energy sectors have indicated support for the proposed Regulations while provincial governments and stakeholders in the oil and gas sector have raised concerns about the costs of compliance. The Department has made a number of changes to the proposal in response to feedback received.

The proposed Regulations would be made under the Fuels Division in Part 7 of CEPA 1999. Consistent with the requirements of this Division, the Governor in Council is of the opinion that they would make a significant contribution to the prevention of, or reduction in, air pollution as proposed Regulations are estimated to result in a significant reduction in air pollution; this is because the cumulative GHG emission reductions attributable to the proposed Regulations are estimated to range, between 2021 and 2040, from 173 to 254 megatonnes of carbon dioxide equivalent (Mt CO2e), with a central estimate of approximately 221 Mt.

To achieve these GHG emission reductions, it is estimated that the proposed Regulations would result in societal costs that range from $14.1 to $26.7 billion, with a central estimate of $20.6 billion. Therefore, the GHG emission reductions would be achieved at an estimated societal cost per tonne between $64 to $128, with a central estimate of $94. To evaluate the central case results, a break-even analysis was conducted that compares the societal cost per tonne of the proposed Regulations to the value of the SCC in 2020 (estimated at $50/tCO2) as per TBS guidance, and more recently published estimates of the SCC value in 2020, found in the academic literature ranging between $135 and $440/tCO2. The Department’s current SCC has not been updated since 2013 and it is reasonable to conclude, looking at the key factors driving increases in more recently published academic estimates of the SCC, that an updated departmental SCC would result in a value that is higher than $50/tCO2 in 2020. Based on the range of SCC estimates in the academic literature, it is reasonable to conclude that the GHG benefits of the proposed Regulations would be greater than its costs. This Department is working with other government departments and academics, and is committed to a peer review of this approach during the Canada Gazette, Part I, comment period.

The proposed Regulations would increase production costs for primary suppliers, which would increase prices for liquid fuel consumers, households and industrial users. Credit creation would also generate revenue for low-carbon energy suppliers, which would make low carbon energy sources such as electricity less expensive in comparison. This would lead to decreased end-use demand for fossil fuels and increased end-use demand for lower carbon energy sources, thereby reducing national GHG emissions. To evaluate the impact of price effects due to the proposed Regulations on Canadian economic activity and GHG emissions, a macroeconomic analysis was completed. When price effects are taken into account, in 2030, it is estimated that the proposed Regulations would result in an overall GDP decrease of up to $6.4 billion (or up to 0.2% of total GDP) while reducing up to 20.6 Mt of GHG emissions, using an upper bound scenario where all credits are sold at the marginal cost per credit.

The proposed Regulations would work in combination with other federal, provincial, and territorial climate change policies to create an incentive for firms to invest in innovative technologies and fuels by setting long-term, predictable and stringent targets. Moreover, the long-term nature of the proposed Regulations and the increase in the CI reduction requirement between 2022 and 2030 would allow time for investment to take place and may give investors the certainty needed to make investments in clean technologies, production facilities, and infrastructure required for longer-term decarbonization. The broad range of compliance strategies allowed under the proposed Regulations would also allow fossil fuel suppliers the flexibility to choose the lowest cost compliance actions available. If the proposed Regulations induce more long-term innovation and economies of scale than currently estimated, they could result in lower costs and greater benefits, particularly over a longer time frame.

In addition, many Canadians view climate change as a global issue that requires Canada’s leadership that could encourage other countries to participate in collective action to exceed the Paris Agreement’s central objective to limit global temperatures to well below 2 °C and pursue efforts to limit it to 1.5°C, in addition to achieving the goal of net-zero emissions by 2050. Canada’s 2030 Paris commitment and net-zero 2050 goal require multiple policies, including the proposed Regulations. If the proposed Regulations are not implemented, then a policy alternative would need to be identified that could achieve the same amount of GHG emission reductions in order for Canada to exceed its 2030 commitment and achieve its 2050 goal.

Implementation, compliance and enforcement, and service standards

Implementation

Credit creators would be able to create credits upon registration of the final Regulations, anticipated to occur in 2021, subject to Governor in Council approval. Reduction requirements for liquid fossil fuels would begin for primary suppliers in December 2022.

The Department will proactively communicate with known primary suppliers and potential voluntary credit creators, as well as industry associations for these sectors, to ensure a maximum number of potential participants are aware of the publication of the proposed Regulations as well as relevant reporting requirements and deadlines.

Compliance and enforcement

Compliance promotion activities are intended to assist the regulated community in achieving compliance. The approach for the proposed Regulations includes developing and posting compliance promotion information such as frequently asked questions (FAQs) on the Department’s website to explain certain provisions in the proposed Regulations, as well as undertaking various outreach activities such as workshops and informational sessions. The Department would respond to all stakeholder inquiries to ensure that the requirements of the proposed Regulations are well understood. These activities are targeted at raising awareness and assisting the regulated community in achieving a high level of overall compliance as early as possible during the regulatory implementation process.

As the regulated community becomes more familiar with the requirements of the proposed Regulations, compliance promotion activities are expected to decline to a maintenance level. The compliance promotion activities would be adjusted according to compliance analyses or if unforeseen compliance challenges arise.

All reported information under the proposed Regulations would be subject to annual review by a qualified and independent third party to ensure accuracy of reported information. The Department would also review submitted information to assess compliance.

As the proposed Regulations would be made under CEPA, enforcement officers would, when verifying compliance, apply the Compliance and Enforcement Policy (the Policy) for CEPA. The Policy sets 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 would choose the appropriate enforcement action based on the Policy.

Contacts

Paola Mellow
Executive Director
Low Carbon Fuels Division
Carbon Pricing Bureau
Environmental Protection Branch
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.cfsncp.ec@canada.ca

Matthew Watkinson
Director
Regulatory Analysis and Valuation Division
Economic Analysis Directorate
Strategic Policy Branch
Environment and Climate Change Canada
200 Sacré-Cœur Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.darv-ravd.ec@canada.ca

PROPOSED REGULATORY TEXT

Notice is given, pursuant to subsection 332(1)footnote a of the Canadian Environmental Protection Act, 1999footnote b, that the Governor in Council, pursuant to sections 140footnote c and 326 of that Act and subsection 5(1) of the Environmental Violations Administrative Monetary Penalties Actfootnote d, proposes to make the annexed Clean Fuel Regulations.

Interested persons may, within 75 days after the date of publication of this notice, file with the Minister of the Environment comments with respect to the proposed Regulations or, within 60 days after the date of publication of this notice, file with the Minister a notice of objection requesting that a board of review be established under section 333 of that Act and stating the reasons for the objection. All comments and notices must cite the Canada Gazette, Part I, and the date of publication of this notice, and be addressed to Paola Mellow, Executive Director, Low Carbon Fuels Division, Carbon Markets Bureau, Department of the Environment, 351 Boulevard St. Joseph, Gatineau, Québec, K1A 0H3 (email ec.cfsncp.ec@canada.ca).

A person who provides information to the Minister of the Environment may submit with the information a request for confidentiality under section 313 of that Act.

Ottawa, November 26, 2020

Julie Adair
Assistant Clerk of the Privy Council

TABLE OF PROVISIONS

Clean Fuel Regulations

Interpretation

1 Definitions

2 Standard cubic metres

Application

3 Exemption — primary suppliers

Requirements for Liquid Fuels
Carbon Intensity Limits

4 Requirement — carbon intensity

5 Volumetric requirement — low carbon intensity fuel

6 Volumetric requirement — biodiesel and HDRD

7 Pools of liquid fuel — volume

Reduction Requirement

8 Reduction in tonnes

Registration as a Primary Supplier

9 Registration

Compliance Credits
Use

10 To satisfy reduction requirement

11 Satisfaction of gasoline volumetric requirement

12 Use of credits on June 30 — gasoline

13 Use of credits on November 30 — gasoline

14 Limits on credit use — contribution to funding program

15 Deferral of 10% of reduction requirements

16 Increase of deferred reduction requirement

17 Subsequent increase of deferred reduction requirement

Creation
Reduction or displacement of CO2e emissions

18 Creation of credit in respect of liquid class

19 Creation of credit in respect of gaseous class

20 Creation of credit in respect of solid class

21 Agreement to create credits

Creation of Provisional Compliance Credits

22 Creation of provisional credits

23 Loss of provisional status

Registration

24 Registration before creation

25 Change of information

Compliance Credit Accounts

26 Opening of account

27 Credit remains in account

CO2e Emissions Reduction or Removal Project

28 Series of actions

29 Application for recognition

30 Recognition by Minister

31 Federal or provincial legislation

Displacement of Use of Fossil Fuel
Land Use and Biodiversity Criteria for Low Carbon Intensity Fuels

32 Maximum volume

33 Eligibility requirements

34 Quantity of eligible feedstock

35 Protected areas

36 Cultivation, harvesting and transport

37 Crops — indirect land use change

38 Crops — excluded land

39 Deemed compliance — feedstock approved by EPA

40 Approval by Minister

41 Forest-based feedstock

42 Recognition of legislation — protected areas

43 Recognition of legislation — harvest

44 Recognition of legislation — regeneration

45 Publication

46 Classes of feedstock

47 Language of documents

48 Establishing of eligibility — low carbon intensity fuel

49 Establishment of eligibility — feedstock referred to in paragraph 33(1)(a)

50 Content of declaration — harvester

51 Producer records

52 Certification

53 Approval by Minister

54 Certification body

55 Eligibility

56 Technical accreditation

57 Outsourcing

58 Preceding compliance periods

59 Person responsible for making decision

60 Applicable standards for certification

61 Certification decision

Determination of Carbon Intensity

62 Default — low carbon intensity fuel

63 Fuel LCA Model — low carbon intensity fuels

64 Fuel LCA Model — compressed and liquefied gases

65 Fuel LCA Model — electricity

66 Application for approval of carbon intensity determination

67 Pathway approval

68 Information to be provided — low carbon intensity fuels

69 Information to be provided — LNG, CNG and LPG

70 Information to be provided — electricity

71 Approval

72 End of validity — low carbon intensity fuel

73 Default determination if no approved determination

74 Reapplication

75 Adjustment credits — low carbon intensity fuel

76 Adjustment — CNG, LNG, LPG and electricity

77 Number of adjusted compliance credits

78 Provisional approval of carbon intensity

79 Registration of foreign supplier

Low Carbon Intensity Fuels

80 Liquid low carbon intensity fuel

81 Gaseous low carbon intensity fuel

82 Biogas used to produce electricity

83 Fuel produced with multiple feedstocks

End User Fuel Switching

84 LPG, CNG and LNG

85 Renewable gaseous fuels and hydrogen

86 Creator — producer or importer

87 Electricity

88 Hydrogen

89 Use of revenue — electric vehicles

Trading System
Transfers in trade

90 Eligibility to transfer credits

91 Registered creator is participant

92 Request to transfer upon creation

Compliance Credit Clearance Mechanism

93 Pledging credits to mechanism

94 No need for clearance mechanism

95 Transfer through clearance mechanism

Registered Emissions Reduction Funding Program

96 Funding program — registration

97 Registration requirements

98 Cancelling registration

99 Annual audit

100 Publication

101 Contribution to funding program

102 No subsequent transfer

Reporting

103 Annual credit creation report

104 Quarterly credit creation reports

105 Carbon intensity pathway report

106 Material balance report for foreign supplier

107 Compliance credit revenue report

108 Compliance credit balance report

109 Compliance report

110 Fossil fuel production report

111 Complementary compliance report

112 Report respecting registered emissions reduction funding program

Validation and Verification
Obligation to Validate or Verify

113 Condition of eligibility

114 Validation of applications

115 Content of report

116 Verification of applications

117 Verification of reports

118 Submission of declarations

119 Content of report

120 Maintenance of records

121 Submission of all reports

122 Monitoring plan

Requirements Respecting Validation Bodies and Verification Bodies

123 Accredited body

124 Eligibility

125 Technical accreditation

126 Team leader

127 Lifecycle assessment reviewer

128 Chartered Professional Accountant

129 Outsourcing

130 Conflicts of interest

131 Decision by Minister

132 Preceding compliance periods

Applicable Standards

133 Standard — validation of application

134 Standards — application for approval

135 ISO Standard 14064-3:2019 — criteria

136 Canadian Generally Accepted Accounting Principles

Method to Follow

137 Method for validation and verification

138 Duties of validating body

139 Required evidence-gathering — verification

140 Site visits

141 Requirement to identify

142 Material quantitative misstatement

143 Data gaps identified by applicant

144 Calculation of uncertainty

145 Qualitative misstatements — declaration

146 Opinion

147 Disclaimer

148 Signature of opinion or disclaimer

Correction of Errors

149 Excess credits

150 Balancing excess credits

151 Notice of creation or transfer

152 Suspension of credits

153 Lifting of suspension

154 Insufficient number of equivalent credits

155 Notice of creation or transfer

156 Equivalent compliance credits

Measurement, Samples, Reporting Format and Records
Measurement of Volumes

157 Requirements

Electronic Reporting — Default

158 Electronic report or notice

Record-making and Retention of Information

159 When records are made

160 Retention of records

161 Copy of records

162 Amendments

Repeals

164 Renewable Fuels Regulations

165 Environmental Violations Administrative Monetary Penalties Regulations

Transitional Provisions

166 Gasoline compliance units

167 Distillate compliance units

168 Request for credits

169 Records related to compliance units

Coming into Force

170 Registration

Clean Fuel Regulations

Interpretation

Definitions

1 (1) The following definitions apply in these Regulations.

Act
means the Canadian Environmental Protection Act, 1999. (Loi)
authorized official
means
  • (a) in respect of a corporation, an officer of the corporation who is authorized to act on its behalf;
  • (b) in respect of an individual, that person or a person who is authorized to act on behalf of that person; and
  • (c) in respect of any other entity, a person who is authorized to act on its behalf. (agent autorisé)
baseline carbon intensity
means, in respect of the liquid class, the weighted average for 2016 of the carbon intensities of each of the fossil fuels of which that class consists, as set out in subsection 4(3). (intensité en carbone de base)
biodiesel
means a liquid fuel that
  • (a) consists of at least one mono-alkyl ester produced from one or more biomass-derived feedstocks in reaction with an alcohol reactant;
  • (b) is suitable for use in a diesel engine; and
  • (c) contains not more than a total of 1.5% by volume of substances that are neither the mono-alkyl esters described in paragraph (a) nor produced from feedstock that is derived from biomass. (biodiesel)
biogas
means a gaseous mixture that is recovered from the anaerobic decomposition of biomass, consists primarily of methane and carbon dioxide and contains other constituents that prevent it from meeting the standard for injection into the closest natural gas pipeline. (biogaz)
biomass
means the biodegradable fraction of products, waste and residues of a biological origin, including vegetal and animal substances from agriculture, forestry and other industries, including fisheries and aquaculture, as well as the fraction of waste, including industrial and municipal waste, of a biological origin. (biomasse)
carbon intensity,
in relation to a pool of a given type of fuel, means the quantity of CO2e in grams that is released during the activities conducted over the fuel’s lifecycle — including all emissions associated with the extraction or cultivation of the feedstock used to produce the fuel, with the processing, refining or upgrading of that feedstock to produce the fuel, with the transportation or distribution of that feedstock, of intermediary products or of the fuel and with the combustion of the fuel — per megajoule of energy produced during that combustion. (intensité en carbone)
charging network operator
means a person that operates a communication platform that collects data on the electricity supplied by a charging station and has a legal right to own that data. (exploitant d’un réseau de recharge)
charging site host
means the owner or lessee of a charging station that has the legal right to have the station installed on the site where it is located. (hôte d’un site de recharge)
charging station
means a device that is used in Canada to charge the battery on board an electric vehicle by supplying the vehicle with electricity and that is capable of communicating with a server through the Internet, a cellular signal or connected vehicle communications using software to report measurements of the quantity of electricity supplied and the time at which it is supplied. (borne de recharge)
compliance period
means
  • (a) the period that begins on the day on which these Regulations are registered and ends on November 30, 2022;
  • (b) the period that begins on December 1, 2022 and ends on December 21, 2022; and
  • (c) after December 31,2022, each calendar year. (période de conformité)
deferred reduction requirement
means, with respect to a reduction requirement calculated under section 8 for a compliance period, the portion that has been deferred in accordance with section 15, as increased or reduced in accordance with sections 16 and 17. (partie reportée de l’exigence de réduction)
destroy
means to convert hydrocarbons contained in hydrocarbon gas to carbon dioxide and other molecules for a purpose other than to produce useful heat or energy, and includes the flaring of hydrocarbon gas. (détruire)
diesel
means a liquid petroleum fuel that
  • (a) is sold or represented as diesel or as fuel suitable for use in a diesel engine; or
  • (b) evaporates at atmospheric pressure, boils within the range of 130°C to 400°C and is suitable for use in a diesel engine. (diesel)
electric vehicle
means a vehicle that is propelled by an electric motor whose source of electricity is a rechargeable battery that is charged from a source of electrical energy that is not on board the vehicle. It includes a plug-in hybrid electric vehicle. (véhicule électrique)
EPA
means the Environmental Protection Agency of the United States. (EPA)
foreign supplier
means a person that owns, leases, operates, controls, supervises or manages a facility outside Canada at which a low carbon intensity fuel is produced. (fournisseur étranger)
Fuel LCA Model
means the lifecycle analysis model — developed by the Minister in accordance with ISO Standard 14040 — that is the collection of procedures used to determine the carbon intensity of a fuel combusted in Canada using lifecycle inventories for various fuel and energy pathways. (modèle ACV des combustibles)
Fuel LCA Model Methodology
means the method used in the Fuel LCA Model that is the basis for the procedures for determining the carbon intensity of a fuel combusted in Canada. (méthode du modèle ACV des combustibles)
gaseous class
means the class that consists of propane and natural gas. (catégorie des combustibles gazeux)
gasoline
means a liquid petroleum fuel that
  • (a) is sold or represented as gasoline, as a fuel suitable for use in a spark-ignition engine or as only requiring the addition of a low carbon intensity fuel or oxygenate to make it suitable for use in a spark-ignition engine; or
  • (b) is suitable for use in a spark-ignition engine and has the following characteristics, as determined by the applicable test method listed in National Standard of Canada standard CAN/CGSB-3.5-04, entitled Unleaded Automotive Gasoline:
    • (i) a vapour pressure of at least 38 kPa,
    • (ii) an anti-knock index of at least 80,
    • (iii) a distillation temperature, at which 10% of the fuel has evaporated, of not less than 35°C and not more than 70°C, and
    • (iv) a distillation temperature, at which 50% of the fuel has evaporated, of not less than 65°C and not more than 120°C. (essence)
hydrogenation-derived renewable diesel or HDRD
means a liquid low carbon intensity fuel that is chemically indistinguishable from diesel and suitable for use in diesel engines. (diesel renouvelable produit par hydrogénation ou DRPH)
hydrogen fuel cell vehicle
means a vehicle propelled solely by an electric motor whose source of electricity is an electrochemical cell that produces electricity from hydrogen. (véhicule à hydrogène)
hydrogen fuelling station
means a facility in Canada at which hydrogen fuel cell vehicles are supplied with hydrogen. (station de ravitaillement en hydrogène)
import
means to import into Canada. (importer)
ISO/IEC Standard 17021
means International Standard ISO/IEC 17021, entitled Conformity assessment — Requirements for bodies providing audit and certification of management systems — Part 1: Requirements published by the International Organization for Standardization. (norme ISO/IEC 17021)
ISO/IEC Standard 17065
means the International Standard ISO/IEC 17065, entitled Conformity assessment — Requirements for bodies certifying products, processes and services, published by the International Organization for Standardization. (norme ISO/IEC 17065)
ISO Standard 14040
means the International Standard ISO 14040, entitled Environmental management — Life Cycle assessment — Principles and framework, published by the International Organization for Standardization. (norme ISO 14040)
ISO Standard 14044
means the International Standard ISO 14044, entitled Environmental management — Life cycle assessment — Requirements and guidelines, published by the International Organization for Standardization. (norme ISO 14044)
ISO Standard 14064-3:2019
means the International Standard ISO 14064-3:2019, entitled Greenhouse gases -- Part 3: Specification with guidance for the verification and validation of greenhouse gas statements, published by the International Organization for Standardization. (norme ISO 14064-3:2019)
ISO Standard 19011
means the International Standard ISO 19011, entitled Guidelines for auditing management systems, published by the International Organization for Standardization. (norme ISO 19011)
liquid class
means the class that consists of the fossil fuels that are set out in column 1 of the table to subsection 4(1). (catégorie des combustibles liquides)
low carbon intensity fuel
means a fuel, other than a fuel that is in the liquid class, gaseous class or solid class, that has a carbon intensity that is, for the compliance period during which the fuel was produced or imported, not more than
  • (a) for a fuel that is liquid at standard conditions, 90% of the reference carbon intensity set out in item 1 of Schedule 1;
  • (b) for biogas, renewable natural gas or hydrogen referred to in subsection 81(1) or biogas referred to in subsection 82(1), 90% of the reference carbon intensity set out in item 2 of Schedule 1;
  • (c) for renewable propane referred to in subsection 81(1), 90% of the reference carbon intensity set out in item 3 of Schedule 1;
  • (d) for compressed renewable natural gas, liquefied renewable natural gas, compressed hydrogen or liquefied hydrogen referred to in subsection 85(1) or renewable natural gas or hydrogen referred to in paragraph 86(1), the reference carbon intensity set out in item 2 of Schedule 1;
  • (e) for renewable liquefied petroleum gas referred to in paragraph 85(1) or renewable propane referred to in subsection 86(1), the reference carbon intensity set out in item 3 of Schedule 1; and
  • (f) for hydrogen referred to in paragraph 88(1), the reference carbon intensity set out in item 2 of Schedule 1. (combustible à faible intensité en carbone)
marine vessel
means a boat, ship or craft that is designed, used or capable of being used for navigation in, on or through water but is not designed for self-propulsion out of water. (bateau)
participant
means a primary supplier or a registered creator that participates in the compliance credit trading system. (participant)
primary supplier
means a person that
  • (a) owns, leases, operates, controls, supervises or manages the production facility at which a fuel in the liquid class is produced; or
  • (b) imports a fuel in the liquid class. (fournisseur principal)
production facility
means any facility in Canada at which fuel is produced, but does not include a blending facility unless it is part of or adjacent to a petroleum refinery. (installation de production)
provisional compliance credit
means a compliance credit that was created in accordance with subsection 22(1) but that has not yet been deposited in an account in accordance with subsection 23(3). (unité de conformité provisoire)
registered creator
means a person that is registered with the Minister in accordance with section 24. (créateur enregistré)
renewable natural gas
means gas that meets the standard for injection into the closest natural gas pipeline and that is either synthetic natural gas from biomass or derived from processing biogas. (gaz naturel renouvelable)
renewable propane
means a mixture that is gaseous at standard conditions, is recovered from processing biomass and consists primarily of propane. (propane renouvelable)
residue
means a substance that is produced in a production process that is not a primary aim of the process. It excludes any substance that the process has been deliberately modified to produce. (résidu)
riparian zone
means land within 30 m, measured on a slope distance following the topography of the land, from
  • (a) the high-water mark of a stream that is greater than 3 m in width; or
  • (b) the edges of a lake or permanent wetland that has an area greater than 5 ha. (zone riveraine)
scheme owner
has the same meaning as in subclause 3.11 of ISO/IEC Standard 17065. (propriétaire du régime)
solid class
means the class that consists of coal, coke and petroleum coke. (catégorie des combustibles solides)
standard conditions
means a temperature of 15.6°C (60°F) and a pressure of 101.325 kPa (14.696 psia). (conditions normales)

Compressed and liquefied gas

(2) In these Regulations

Incorporation by reference

(3) Unless otherwise provided, a standard or method that is incorporated by reference in these Regulations is incorporated as amended from time to time.

Interpretation of documents incorporated by reference

(4) For the purpose of interpreting any document that is incorporated by reference in these Regulations, “should” must be read to mean “must” and any recommendation or suggestion must be read as an obligation, unless the context requires otherwise. For greater certainty, the context of the accuracy or precision of a measurement can never require otherwise.

Standard cubic metres

2 (1) In these Regulations, a measurement of a volume of a gas or liquid that is expressed in cubic metres is a measurement of that gas or liquid at standard conditions.

Carbon dioxide equivalent

(2) For the purposes of these Regulations, the quantity of a greenhouse gas is expressed in CO2e, that is, the quantity of carbon dioxide, measured in grams or in tonnes as the case may be, that would have an equivalent warming effect over a given period, as determined in accordance with the Fuel LCA Model Methodology or by application of the Fuel LCA Model.

Application

Exemption — primary suppliers

3 (1) A primary supplier that produces in Canada or imports a volume of less than 400 m3 of any type of fuel in the liquid class during a given compliance period is exempt from the application of these Regulations with respect to that type of fuel.

Non-application — certain fuels

(2) These Regulations, other than sections 109 and 157 to 161, do not apply in respect of a fuel in the liquid class that is

Clarification

(3) For greater certainty, a volume of fuel described in subsection (2) is not to be included in the determination of a volume under subsection (1).

Requirements for Liquid Fuels

Carbon Intensity Limits

Requirement — carbon intensity

4 (1) For the purpose of section 139 of the Act, a primary supplier’s pool of a type of fossil fuel that is set out in column 1 of the table to this subsection must not have a carbon intensity that is greater than the limit set out in column 2 for the applicable compliance period set out in that column, expressed in grams of CO2e per megajoule(gCO2e/MJ).

Table — Carbon Intensity Fuel Limit
Item

Column 1

Liquid Fossil Fuel

Column 2

Limit per compliance period, in gCO2e/MJ

from December 1 to December 31, 2022 2023 2024 2025 2026 2027 2028 2029 2030 and after
1 Gasoline 93.6 92.4 91.2 90.0 88.8 87.6 86.4 85.2 84.0
2 Diesel 93.6 92.4 91.2 90.0 88.8 87.6 86.4 85.2 84.0
3 Kerosene 84.6 83.4 82.2 81.0 79.8 78.6 77.4 76.2 75.0
4 Light Fuel Oil 92.6 91.4 90.2 89.0 87.8 86.6 85.4 84.2 83.0
5 Heavy Fuel Oil 95.6 94.4 93.2 92.0 90.8 89.6 88.4 87.2 86.0
6 Jet Fuel 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0

Lowering carbon intensity

(2) A primary supplier complies with subsection (1) with respect to a type of fuel for a given compliance period by lowering the carbon intensity of their pool of that type of fuel for that compliance period by the difference, between the baseline carbon intensity and the limit set out in the table to that subsection for that type of fuel and that compliance period. The primary supplier establishes this lowering by satisfying the reduction requirement calculated under section 8 using compliance credits in accordance with subsection 10(1).

Baseline carbon intensity

(3) For the purpose of subsection (2), the baseline carbon intensity of the following types of fuels in the liquid class, expressed in grams of CO2e per megajoule, is

Non-application

(4) The section does not apply with respect to a fuel that is produced in Canada or imported before December 1, 2022.

Volumetric requirement — low carbon intensity fuel

5 (1) For the purpose of section 139 of the Act, at least 5% of the volume of a primary supplier’s pool of gasoline for each compliance period must be displaced by an equivalent volume of liquid low carbon intensity fuel, other than biodiesel and hydrogenation-derived renewable diesel.

Exception — Newfoundland and Labrador

(2) This section does not apply with respect to any volume of gasoline in a primary supplier’s pool of gasoline that they produced in or imported in Newfoundland and Labrador during a given compliance period, if they record information that establishes the volumes of gasoline that they produced in or imported in that province.

Non-application

(3) The section does not apply with respect to gasoline that is produced in Canada or imported before January 1, 2023.

Volumetric requirement — biodiesel and HDRD

6 (1) For the purpose of section 139 of the Act, at least 2% of the total of the volumes of a primary supplier’s pools of diesel and light fuel oil for each compliance period must be displaced by an equivalent volume of low carbon intensity fuel that is biodiesel or hydrogenation-derived renewable diesel.

Exception — Newfoundland and Labrador

(2) This section does not apply with respect to any volume of diesel and light fuel oil in a primary supplier’s pools of diesel or light fuel oil, as the case may be, that they produced in or imported in Newfoundland and Labrador during a given compliance period, if they record information that establishes the volumes of diesel and light fuel oil that they produced in or imported in that province.

Non-application

(3) The section does not apply with respect to diesel and light fuel oil that is produced in Canada or imported before January 1, 2023.

Pools of liquid fuel — volume

7 (1) For the purpose of sections 4 to 6, a primary supplier’s pool of a type of fuel in the liquid class set out in column 1 of the table to subsection 4(1), for a given compliance period, is the total volume, expressed in cubic metres, of that type of fuel that they

Subtracted volumes

(2) Despite subsection (1), a primary supplier may subtract from their pool of a type of fuel in the liquid class for a given compliance period any volume of that fuel if they make, before July 1 of the calendar year that follows the compliance period, a record that establishes that the volume was

Reduction Requirement

Reduction in tonnes

8 The carbon intensity of a pool of a type of fuel in the liquid class for a compliance period is lowered if the number of tonnes of CO2e released during the lifecycle of the fuel is reduced by the amount of the reduction requirement calculated in accordance with the following formula:

CIdiff × (Q × D) × 10-6
where
CIdiff
is the difference, expressed in grams of CO2e per megajoule, between the baseline carbon intensity of that type of fuel, as set out in subsection 4(3), and the limit for that type of fuel for that compliance period, as set out in subsection 4(1);
Q
is the quantity of that pool for the compliance period, determined in accordance with section 7 and expressed as a volume in cubic metres; and
D
is the energy density of the type of fuel, as set out in Schedule 2.

Registration as a Primary Supplier

Registration

9 (1) A primary supplier that is not already registered must register by submitting to the Minister a registration report that contains the information set out in items 1 to 3 of Schedule 3 not later than 10 days after they produce in Canada or import, during a given compliance period, a total volume of 400 m3 or more of any type of fuel in the liquid class.

Registration by December 31, 2021

(2) However, a primary supplier must register no later than December 31, 2021 if they produce in Canada or import during the period that begins on the day on which these Regulations are registered and ends on December 31, 2021 a total volume of 400 m3 or more of any type of fuel in the liquid class.

Change of information

(3) If the information that is referred to in item 1 of Schedule 3 and provided in the registration report changes, the primary supplier must send a notice to the Minister that includes the updated information no later than 30 days after the date of the change.

Notice of cancellation

(4) A registered primary supplier to which these Regulations do not apply for a given compliance period and that has complied with the obligations of these Regulations, including subsections 4(2), 5(1) and 6(1), for all previous compliance periods may cancel their registration by sending a notice to the Minister in which they request that the Minister cancel the compliance credits in their accounts that were opened under section 26.

Minister’s determination

(5) On receiving the notice, the Minister must determine whether the primary supplier has complied with those obligations.

Cancellation by Minister

(6) If the Minister is satisfied that the primary supplier has satisfied their obligations under these Regulations, the Minister must

Compliance Credits

Use

To satisfy reduction requirement

10 (1) A primary supplier uses compliance credits that they created under sections 18 to 20, or that were transferred to them in trade under section 90, 92 or 95, to satisfy the reduction requirement calculated under section 8, including any deferred reduction requirement, for a pool of a type of fuel in the liquid class and a given compliance period.

Deemed reduction

(2) The number of tonnes of CO2e that are released during the lifecycle of a type of fuel in the liquid class that is produced in Canada or imported during a given compliance period is deemed to be reduced by the number of tonnes that are represented by the compliance credits that are used by the primary supplier for that fuel type and compliance period.

Prior creation of provisional credit

(3) Only a compliance credit that was created either as a provisional compliance credit on or before the last day of a compliance period or under subsection 18(2) may be used to satisfy the reduction requirement for that compliance period calculated under section 8.

Cancellation after use

(4) The Minister must cancel a compliance credit once it is used.

Satisfaction of gasoline volumetric requirement

11 (1) A compliance credit that was created under paragraph 18(1)(b) or (c) by producing in Canada or importing a volume of low carbon intensity fuel, other than biodiesel or hydrogenation-derived renewable diesel, and that a primary supplier uses in accordance with section 10 for a given compliance period is deemed to displace the use of an equivalent volume of the primary supplier’s pool of gasoline for the compliance period for the purpose of subsection 5(1).

Satisfaction of diesel and LFO volumetric requirement

(2) A compliance credit that was created under paragraph 18(1)(b) or (c) by producing in Canada or importing a volume of low carbon intensity fuel that is biodiesel or hydrogenation-derived renewable diesel and that a primary supplier uses in accordance with section 10 for a given compliance period is deemed to displace the use of an equivalent volume of the primary supplier’s pool of diesel and light fuel oil for the compliance period for the purpose of subsection 6(1).

Prior creation of provisional credit

(3) Only a compliance credit that was created as a provisional compliance credit on or before the last day of a compliance period is eligible to be used to satisfy the requirement set out in subsection 5(1) or 6(1) for the compliance period.

Use of credits on June 30 — gasoline

12 (1) On the June 30 that follows a compliance period, the compliance credits in a primary supplier’s account opened under paragraph 26(a) that are described in subsection 11(1) and that satisfy subsection 11 (3) are used under section 10 and subsection 11(1) until either

Use of credits on June 30 — diesel and LFO

(2) On the June 30 that follows a compliance period, the compliance credits in a primary supplier’s account opened under paragraph 26(a) that are described in subsections 11(2) and (3) are used under section 10 and subsection 11(2) until either of the following circumstances applies:

Credits from contribution to funding program

(3) Subject to subsection 14(1), on the June 30 that follows a compliance period, the compliance credits created by a primary supplier by contributing to a registered emissions reduction funding program in accordance with paragraph 101(1)(a) must be used by the primary supplier to satisfy the reduction requirement calculated under section 8.

Credits in accounts

(4) Subject to subsections 14(2) and (3), on the June 30 that follows a compliance period, the compliance credits that are in the primary supplier’s accounts opened under paragraphs 26(a) to (c) and that satisfy the requirements of subsection 10(3) are to be used in accordance with section 10 until

Choice of credit

(5) If the circumstances described in paragraph (4)(a) occurs before the circumstances described in paragraph (4)(b), the reduction requirement calculated under section 8 is satisfied using the compliance credits that are chosen by the primary supplier, as indicated in the report they submitted under subsection 109(1).

July 1 cancellation of credits

(6) On July 1, the Minister must cancel any unused compliance credit that is referred to in subsection (3).

Non-application of subsections (1) and (2)

(7) Subsections (1) and (2) do not apply for any compliance period that ends before January 1, 2023.

Non-application of subsections (3) and (4)

(8) Subsections (3) and (4) do not apply for the compliance period that ends on November 30, 2022.

December 2022 compliance period

(9) For the compliance period that ends on December 31, 2022, the use of compliance credits that is referred to in sections (3) and (4) occurs on June 30, 2024.

Use of credits on November 30 — gasoline

13 (1) On the November 30 that follows a compliance period, the compliance credits in a primary supplier’s account opened under paragraph 26(a) that are described in subsections 11(1) and that satisfy subsection 11(3) are to be used under section 10 and subsection 11(1) until

Use of credits on November 30 — diesel and LFO

(2) On the November 30 that follows a compliance period, the compliance credits in a primary supplier’s account opened under paragraph 26(a) that are described in subsections 11(2) and that satisfy subsection 11(3) are to be used under section 10 and subsection 11(2) until

Other credits

(3) Subject to subsection 14(1), on the November 30 that follows a compliance period, the compliance credits that were transferred to the primary supplier in trade under section 95 or created by contributing to a registered emissions reduction funding program in accordance with paragraph 101(1)(b) must be used by the primary supplier to satisfy the reduction requirement calculated under section 8.

Satisfaction by November 30

(4) Subject to sections 15 to 17, a primary supplier must satisfy the volumetric requirements set out in subsections 5(1) and 6(1) and the reduction requirement calculated under section 8 in respect of all of their pools of fuel in the liquid class for a given compliance period no later than the November 30 that follows the end of the compliance period.

December 1

(5) On December 1, the Minister must cancel any unused compliance credit that is described in subsection (3).

Non-application of subsections (1) and (2)

(6) Subsections (1) and (2) do not apply for any compliance period that ends before January 1, 2023.

Non-application of subsections (3) and (4)

(7) Subsections (3) and (4) do not apply for the compliance period that ends on November 30, 2022.

December 2022 compliance period

(8) For the compliance period that ends on December 31, 2022, the use of compliance credits that is referred to in sections (3) and (4) occurs on November 30, 2024 and the cancellation referred to in subsection (5) occurs on December 1, 2024.

Limits on credit use — contribution to funding program

14 (1) The total number of compliance credits created under subsection 18(2) by contributing to a registered emissions reductions funding program and that are used in accordance with subsections 12(3) and 13(3), paragraph 16(2)(a), subsection 16(4), paragraph 17(2)(a) and subsection 17(4) during the calendar year that follows the end of a compliance period must not exceed 10% of the sum of the total, in respect of all fuel types in the liquid class, of a primary supplier’s reduction requirements calculated under section 8 for that compliance period and any deferred reduction requirement.

Limits on credit use — gaseous and solid fuels

(2) The total number of compliance credits in a primary supplier’s accounts opened under paragraph 26(b) or (c) that are used in accordance with subsections 12(4) and paragraphs 16(2)(b) and 17(2)(b) during the calendar year that follows the end of a compliance period must not exceed 10% of the sum of the total, in respect of all fuel types in the liquid class, of a primary supplier’s reduction requirements calculated under section 8 for that compliance period and any deferred reduction requirement.

Limit — generic quantification method

(3) The total number of compliance credits that are created under paragraph 18(1)(a), subsection 19(a) and section 20 for a project for which a generic emissions reduction quantification method has been provided under subsection 28(2) and that are used in accordance with subsections 12(4) and paragraphs 16(2)(b) and (c) and 17(2)(b) and (c) during the calendar year that follows the end of a compliance period must not exceed 10% of the sum of the total, in respect of all fuel types in the liquid class, of a primary supplier’s reduction requirements calculated under section 8 for that compliance period and any deferred reduction requirement.

December 2022 compliance period

(4) For the compliance period that ends on December 31, 2022, the relevant calendar year for this section is 2024.

Deferral of 10% of reduction requirements

15 (1) On the November 30 that follows the end of a compliance period, a primary supplier may defer satisfaction of up to 10% of the total of the reduction requirements calculated under section 8 for the period.

Condition for deferral

(2) The primary supplier is only eligible to defer satisfaction of a reduction requirement for a compliance period under subsection (1) if

Notification of fuel type

(3) The primary supplier must, in their complementary compliance report referred to in section 111 for the given compliance period, notify the Minister as to the type of fuel in the liquid class with respect to which the reduction requirement is deferred.

Obligation satisfied within two years

(4) A primary supplier that defers satisfaction of a reduction requirement for a compliance period under subsection (1) must satisfy that requirement no later than the November 30 that follows the second anniversary of the end of the compliance period.

December 2022 compliance period

(5) For the compliance period that ends on December 31, 2022, the deferral that is referred to in subsection (1) occurs on November 30, 2024 and the satisfaction referred to in subsection (4) must be done no later than November 30, 2026.

Compliance clearance mechanism — 2024

(6) For the compliance periods that end on December 31, 2022 or December 31, 2023, paragraph (2)(a) is satisfied if the Minister has sent a notice in accordance with section 94(2) or the primary supplier has acquired by transfer through the compliance credit clearance mechanism the number of compliance credits determined under paragraph 95(7)(b) for those compliance periods;

Increase of deferred reduction requirement

16 (1) On the December 1 that follows the end of the compliance period referred to in subsection 15(1), the deferred reduction requirement is multiplied by 1.2.

Reduction of deferred reduction requirement — June 30

(2) On the June 30 that follows the first anniversary of the end of that compliance period, the primary supplier must use the following compliance credits that are in their accounts opened under section 26 and that exceed the number required to satisfy the reduction requirement calculated under section 8 for the compliance period that ends on that anniversary to reduce the deferred reduction requirement in accordance with subsections 10(1) and (2):

Election

(3) If the primary supplier has more credits than are required to satisfy the deferred reduction requirement in accordance with subsection (2), they may elect the number of compliance credits referred to in paragraph (2)(b) and (c) to be used.

Reduction of deferred reduction requirement — November 30

(4) Subject to subsection 14(1), on the November 30 that follows the first anniversary of the end of the compliance period referred to in subsection 15(1), the primary supplier must use all of the compliance credits that are in their account opened under paragraph 26(a) that were either transferred in trade to them through the credit clearance mechanism under section 95 or created by contributing to a registered emissions reduction funding program under paragraph 101(1)(b) and that are in excess of those needed to satisfy the reduction requirements calculated under section 8 for the compliance period that ends on that anniversary to reduce the deferred reduction requirement in accordance with subsections 10(1) and (2).

December 2022 compliance period

(5) With respect to a deferred reduction requirement for the compliance period that ends on December 31, 2022

Subsequent increase of deferred reduction requirement

17 (1) On the December 1 that follows the first anniversary of the end of the compliance period referred to in subsection 15(1), the deferred reduction requirement is multiplied by 1.2.

Reduction of deferred reduction requirement — June 30

(2) On the June 30 that follows the second anniversary of the end of that compliance period, the primary supplier must use the following compliance credits that are in their accounts opened under section 26 and that exceed the number required to satisfy the reduction requirement calculated under section 8 for the compliance period that ends on that anniversary to reduce the deferred reduction requirement in accordance with subsections 10(1) and (2):

Election

(3) If the primary supplier has more credits than are required to reduce the deferred reduction requirement to zero in accordance with subsection (2), they may elect the number of compliance credits referred to in paragraphs (2)(b) and (c) to be used.

Reduction of deferred reduction requirement — November 30

(4) Subject to subsection 14(1), on the November 30 that follows the second anniversary of the end of the compliance period referred to in subsection 15(1), the primary supplier must use all of the compliance credits that are in their account opened under paragraph 26(a) that were either transferred in trade to them through the credit clearance mechanism under section 95 or created by contributing to a registered emissions reduction funding program in accordance with paragraph 101(1)(b) and that are in excess of those needed to satisfy the reduction requirements calculated under section 8 for the compliance period that ends on that anniversary to reduce the deferred reduction requirement in accordance with subsections 10(1) and (2).

December 2022 compliance period

(5) With respect to the deferred reduction requirement for the compliance period that ends on December 31, 2022

Creation

Reduction or displacement of CO2e emissions

Creation of credit in respect of liquid class

18 (1) A registered creator may create a compliance credit in respect of the liquid class when

Contribution to funding program

(2) A primary supplier may create a compliance credit in respect of the liquid class when they make a contribution to a registered emissions reduction funding program in accordance with section 101.

Creation of credit in respect of gaseous class

19 A registered creator may create a compliance credit in respect of the gaseous class when

Creation of credit in respect of solid class

20 A registered creator may create a compliance credit in respect of the solid class when they or a person with which they have entered into an agreement described in section 21 reduces the carbon intensity of a type of fuel in the solid class by carrying out a CO2e emissions reduction or removal project in respect of that type of fuel that is recognized under subsection 30(1).

Agreement to create credits

21 (1) A person may, before they create provisional compliance credits, enter into an agreement to create compliance credits during a compliance period

Requirements of valid agreement

(2) An agreement is valid for the purpose of subsection (1) only if it is signed by both parties and contains

Creation of Provisional Compliance Credits

Creation of provisional credits

22 (1) A compliance credit, other than one created under subsection 18(2), is a provisional compliance credit when it is created.

No use of provisional credit

(2) A provisional compliance credit cannot be used to comply with subsections 4(1), 5(1) or 6(1) or be transferred in accordance with section 90.

Loss of provisional status

23 (1) A provisional compliance credit that is the subject of a credit creation report referred to in section 103 or 104 ceases to be provisional when the Minister deposits it in a compliance credit account in accordance with subsection (3).

Adjustment of credits

(2) The Minister must deposit compliance credits created under section 75 or 76 in a compliance credit account in accordance with subsection (3) when they are the subject of a credit creation report referred to in section 103 or 104.

Type of account

(3) Subject to subsection (4), the Minister is to deposit compliance credits in the registered creator’s accounts as follows:

Choice of account — emissions reduction or removal project

(4) Compliance credits created by carrying out a project that is referred to in more than one of paragraphs 18(1)(a) and 19(a) and section 20 are deposited in accordance with the applicable election referred to in paragraphs 29(2)(b) to (e).

Unique identification number

(5) The Minister must assign a unique identification number to each compliance credit when it is deposited into a compliance credit account.

Registration

Registration before creation

24 (1) A provisional compliance credit may only be created if, on the day before it was created, its creator was a registered creator.

Registration report

(2) For a person to become a registered creator on the basis of activities referred to in subsection 18(1) or section 19 or 20 that they or a person with which they have entered into an agreement described in section 21 performs, they must submit a registration report to the Minister that contains the information referred to in item 1 of Schedule 3 and in whichever of items 4 to 11 of that Schedule apply.

Change of information

25 (1) If the information referred to in item 1 of Schedule 3 that is provided in the registration report changes, the registered creator must send a notice to the Minister that sets out the updated information no later than 30 days after the change.

Items 4 to 10 of Schedule 3

(2) If the information referred to in any of items 4 to 10 of Schedule 3 that is provided in the registration report changes, the registered creator must send a notice to the Minister that provides the updated information no later than the day on which they next submit a report under subsection 103(1) or 104(1).

New agreement

(3) If a registered creator enters into a new agreement under subsection 21(1), they must send a written notice to the Minister, no later than the day before a provisional compliance credit is first created under the agreement, that contains the information set out in item 1 of Schedule 3 and in whichever of items 4 to 11 of that Schedule apply to the activities carried out by the person with which they entered into the new agreement no later than the day before the day on which a provisional compliance credit is first created under that new agreement.

Compliance Credit Accounts

Opening of account

26 On the registration of a primary supplier under subsection 9(1) or of a registered creator under subsection 24(1), the Minister must open the following compliance credit accounts for the primary supplier or the registered creator in the compliance credit trading system administered by the Minister:

Credit remains in account

27 A compliance credit that is deposited into an account remains in that account until the compliance credit is cancelled or transferred.

CO2e Emissions Reduction or Removal Project

Series of actions

28 (1) A CO2e emissions reduction or removal project referred to in paragraph 18(1)(a) or 19(a) or section 20 consists of a series of actions implemented in Canada in respect of a type of fuel that results in

Quantification method

(2) The Minister may provide an emissions reduction quantification method for a type of project and the Minister may provide a generic emissions reduction quantification method. Each emissions reductions quantification method must

Exception

(3) However, the Minister must not provide an emissions reduction quantification method for the following types of projects and they do not create compliance credits under paragraph 18(1)(a) or 19(a) or section 20:

Conditions — generic quantification method

(4) To be eligible to use the generic emissions reduction quantification method referred to in subsection (2), a project must be of a type

Application for recognition

29 (1) A person may apply to the Minister to have a CO2e emissions reduction or removal project that is referred to in subsection 28(1) be recognized as one that may create compliance credits.

Content of application

(2) The application must be signed by the authorized official of the applicant and contain

Extension of period

(3) During the year that precedes the day on which the period established under paragraph 28(2)(d) ends, a person may apply to the Minister for that period to be extended for a single period of five years.

Content of application

(4) The application for the extension of the period must be signed by the authorized official of the applicant and indicate any change in the content of the original application since the project was recognized.

Recognition by Minister

30 (1) The Minister must recognize the project if the Minister is satisfied, based on the information provided to the Minister by the applicant, that

Unique alphanumeric identifier

(2) The Minister must assign a unique alphanumeric identifier to a project when it is recognized.

Number of compliance credits

(3) Once a CO2e emissions reduction or removal project is recognized, the participant that made the application may create a number of provisional compliance credits, for each compliance period, that is determined in accordance with the emissions reduction quantification method for the type of project, or, if applicable, the generic emissions reduction quantification method, that is provided by the Minister.

Federal or provincial legislation

31 (1) If an action that is part of a CO2e emissions reduction or removal project becomes required by federal or provincial legislation, the number of compliance credits created by the project is reduced in proportion to the reduction or removal of CO2e emissions caused by the action.

End of project

(2) A CO2e emissions reduction or removal project ceases to create compliance credits on the day after the period referred to in paragraph 28(2)(d) or subsection 29(3), as the case may be, ends.

Displacement of Use of Fossil Fuel

Land Use and Biodiversity Criteria for Low Carbon Intensity Fuels

Maximum volume

32 (1) The maximum volume of a low carbon intensity fuel with a carbon intensity that has a given unique alphanumeric identifier referred to in subsection 71(2) and is produced at a given facility by a producer in Canada or a foreign supplier during each period set out in subsection (2) that may be used to create compliance credits in accordance with sections 80 to 82, 85 and 86 is determined by the formula

Vfuel x Qeligible/(Qeligible + Qineligible)
where
Vfuel
is the total volume of the low carbon intensity fuel that they produce at the facility during the period;
Qeligible
is the quantity of the feedstock that satisfies the requirements of section 34 and was used at the given facility by the given producer in Canada or foreign supplier to produce that low carbon intensity fuel during the period, measured in kilograms for solid feedstock or in cubic metres for liquid or gaseous feedstock;
Qineligible
is the quantity of the feedstock, other than the quantity of the eligible feedstock, that was used at the given facility by the given producer in Canada or foreign supplier to produce that low carbon intensity fuel during the period, measured in kilograms for solid feedstock and in cubic metres for liquid or gaseous feedstock.

Periods

(2) The periods for producing low carbon intensity fuels are, for any compliance period that ends after January 1, 2023

Exclusive use

(3) A quantity of low carbon intensity fuel that is used to comply with the requirement of a jurisdiction outside Canada that relates to greenhouse gas emissions cannot be used to create compliance credits under sections 80 to 82, 85 or 86.

Non-application

(4) Subsection (3) does not apply to the creation of provisional compliance credits during any compliance period that ends before January 1, 2023.

Eligibility requirements

33 (1) For the purpose of section 32 and subject to subsection (2) and sections 35 to 44, a quantity of a feedstock is eligible if the feedstock

Intentionally used feedstocks

(2) A feedstock that is intentionally used, harvested or allowed to become inedible for the sole purpose of being described in any of subparagraphs (1)(b)(ii) to (iv) and (ix) must satisfy all the requirements that apply with respect to feedstock described in paragraph (1)(c).

Quantity of eligible feedstock

34 (1) Each quantity of an eligible feedstock of a given type that exits, after December 31, 2022, a site where the feedstock is harvested, obtained, mixed, processed or divided must be not more than the amount determined by the formula

Q inventory + Qincoming
where
Q inventory
is the quantity of the eligible feedstock of that type that was at the site after the previous time that a quantity of the eligible feedstock exited the site, measured in kilograms for solid feedstock or in cubic metres for liquid or gaseous feedstock; and
Qincoming
is the quantity of the eligible feedstock of that type that was harvested at the site or brought to the site since the previous time that a quantity of the eligible feedstock exited the site, measured in kilograms for solid feedstock or in cubic metres for liquid or gaseous feedstock.

Production of fuel

(2) For each period set out in subsection 32(2) the total of the quantity of the eligible feedstock of a given type that is used to produce a low carbon intensity fuel at a facility and the quantity of that eligible feedstock that is at the facility at the end of the period must be not more than the amount determined by the formula

Q inventory + Qincoming
where
Q inventory
is the quantity of the eligible feedstock of that type that was at the facility at the beginning of the period, measured in kilograms for solid feedstock or in cubic metres for liquid or gaseous feedstock; and
Qincoming
is the quantity of the eligible feedstock of that type that was brought to the facility during the period, measured in kilograms for solid feedstock or in cubic metres for liquid or gaseous feedstock.

Protected areas

35 (1) A feedstock referred to in paragraph 33(1)(c) must not be harvested or cultivated on land in an area that is designated by any of the following as an area for the protection of any rare, vulnerable or threatened species or its habitat or of a vulnerable ecosystem:

Exception

(2) However, the Minister may, on application from a person that harvests feedstock referred to in paragraph 33(1)(c) or that produces fuel from such feedstock, authorize feedstock to be obtained from rehabilitation or habitat improvement activities in a protected area that are approved by the appropriate level of government, if the Minister is of the opinion that the harvest of the feedstock did not interfere with the protection of nature within the area.

Application

(3) The application must

Cultivation, harvesting and transport

36 A feedstock referred to in paragraph 33(1)(c)

Crops — indirect land use change

37 (1) A feedstock referred to in one of subparagraphs 33(1)(b)(iii) to (v) or paragraph 33(1)(c) that is a crop, crop byproduct, crop residue or short rotation woody biomass crop must be cultivated in a way that does not create a high risk of an indirect land use change that has negative environmental impact.

Commission Delegated Regulation (EU)

(2) For the purpose of subsection (1), the cultivation of a feedstock has a high risk of causing an indirect land use change that has negative environmental impact if in the Annex to the Commission Delegated Regulation (EU) 2019/807 of 13.3.2019 the value with respect to the feedstock

Crops — excluded land

38 A feedstock referred to in paragraph 33(1)(c) that is a crop, crop byproduct, crop residue or short-rotation woody biomass crop must not have been cultivated on

Deemed compliance — feedstock approved by EPA

39 (1) Feedstock that is a crop, crop byproduct, crop residue or short-rotation woody biomass crop and is approved by the EPA under section 80.1457(a) of Subchapter C of Chapter I of Title 40 of the Code of Federal Regulations of the United States is deemed not to have been cultivated on land referred to in section 38 if the Minister has received the following from the country from which the feedstock originates:

Application

(2) Subsection (1) applies from

Non-application

(3) Subsection (1) ceases to apply on the earlier of

Publication

(4) The Minister must publish the name of each country to which this section applies on the Department of the Environment’s Internet site.

Approval by Minister

40 (1) A feedstock that is a crop, crop byproduct, crop residue or short-rotation woody biomass crop is also deemed not to have been cultivated on land referred to in section 38 if the Minister decides that

Information considered

(2) Before making a decision referred to in subsection (1), the Minister must consider the following information:

Restriction

(3) The Minister must not issue a decision unless the Minister has received the information referred to in paragraphs (2)(a) to (g) from a competent authority of the country in question, and it is accompanied by a letter that is signed by an individual with a role comparable to a Minister who is responsible for the part of the government with primary expertise in agricultural land use patterns, practices, data and statistics, in which letter the individual

Competent authority

(4) For the purpose of subsection (3), a competent authority is a national government or a credible and reliable entity appointed by a national government to represent it.

Language of information or letter

(5) If information referred to in subsection (2) or the letter referred to in subsection (3) was not originally in English or French, the Minister makes the decision on the basis of an English or French version of the information or document, as the case may be, that is provided to the Minister.

Public comment

(6) The Minister must not render a decision referred to in subsection (1) unless the information referred to in paragraphs (2)(a) to (g) and (i) have been published on the Department of the Environment’s Internet site, and the public has been given an opportunity to comment on it for a period of 60 days.

Publication

(7) The Minister must publish the name of each country with respect to which a decision was made under subsection (1) and the date of that decision, on the Department of the Environment’s Internet site.

End of effect

(8) Subsection (1) ceases to have effect with respect to a country one year after the Minister renders a decision with respect to that country, unless the Minister renders a new decision with respect to that country in accordance with this section.

Forest-based feedstock

41 (1) A feedstock referred to in paragraph 33(1)(c) that is sourced from forest biomass must be harvested in accordance with a management plan that is implemented by the person that is responsible for harvesting the feedstock and can be evaluated by a verification body. The person responsible for the harvest must monitor the plan and keep it up to date based on the results of the monitoring in order to promote adaptive management and detail the practices that will be followed to ensure

Definition of old growth stands or forests

(2) In paragraph (1)(b), old-growth stands or forests means naturally regenerated forests that

Recognition of legislation — protected areas

42 The Minister may decide that all feedstock of a given class that is from a given region satisfies the requirements of subsection 35(1) if the Minister is satisfied that the legislation that applies in the region effectively prevents the cultivation and harvesting of the feedstock of that class in areas referred to in that subsection.

Recognition of legislation — harvest

43 (1) The Minister may decide that all feedstock of a given class that is from a given region satisfies the requirements of paragraph 36(a) if the Minister is satisfied that the legislation referred to in that paragraph includes monitoring and enforcement requirements and is generally followed and enforced with respect to feedstock of that class.

Recognition of legislation — damaging agents

(2) The Minister may decide that all feedstock of a given class that is from a given region satisfies the requirements of paragraph 36(b) if the Minister is satisfied that the legislation referred to in that paragraph is generally followed and enforced with respect to feedstock of that class.

Recognition of legislation — regeneration

44 (1) The Minister may decide that all feedstock of a given class that is from a given region satisfies the requirements of paragraph 41(1)(a) if the Minister is satisfied that the legislation that applies in the region or management plans that apply to the entire region

Recognition of legislation — negative impact

(2) The Minister may decide that all feedstock of a given class that is from a given region satisfies the requirements of paragraph 41(1)(b) if the Minister is satisfied that the legislation that applies in the region or regional management plans

Recognition of legislation — soil

(3) The Minister may decide that all feedstock of a given class that is from a given region satisfies the requirements of subparagraph 41(1)(c)(i) if the Minister is satisfied that the legislation that applies in the region or regional management plans

Recognition of legislation — water

(4) The Minister may decide that all feedstock of a given class that is from a given region satisfies the requirements of subparagraph 41(1)(c)(ii) if the Minister is satisfied that the legislation that applies in the region or regional management plans

Recognition of legislation — biodiversity

(5) The Minister may decide that all feedstock of a given class that is from a given region satisfies the requirements of subparagraph 41(1)(c)(iii) if the Minister is satisfied that the legislation that applies in the region or regional management plans

Recognition of legislation — watercourses

(6) The Minister may decide that all feedstock of a given class that is from a given region satisfies the requirements of paragraph 41(1)(d) if the Minister is satisfied that the legislation that applies in the region or regional management plans

Publication

45 The Minister must publish the name of each class of the feedstock and each region with respect to which a decision was rendered under any of section 42 and subsections 43(1) and (2) and 44(1) to (6) on the Department of the Environment’s Internet site.

Classes of feedstock

46 For the purpose of sections 42 to 45, the classes of the feedstock are crops, crop residue, short-rotation woody biomass crops and forest biomass.

Language of documents

47 If a document that is relevant to a decision under any of section 42 and subsections 43(1) and (2) and 44(1) to (6) was not originally in English or French, the Minister makes the decision on the basis of an English or French version of the document that is provided to the Minister.

Establishing of eligibility — low carbon intensity fuel

48 (1) The eligibility of a low carbon intensity fuel is established only if

Production before December 31, 2022

(2) However, any low carbon intensity fuel that is produced during the period that begins on the day on which these Regulations are registered and ends on December 31, 2022 is eligible.

Establishment of eligibility — feedstock referred to in paragraph 33(1)(a)

49 (1) The eligibility of a quantity of a feedstock that is referred to in paragraph 33(1)(a) is established only if the person that produces a low carbon intensity fuel from the feedstock retains records in accordance with paragraph 51(1)(a) or (c) and, if applicable, the person that imports a low carbon intensity fuel that is produced from the feedstock retains records in accordance with subsection 51(2).

Establishment of eligibility — feedstock referred to in paragraph 33(1)(b) or (c)

(2) The eligibility of a quantity of a feedstock that is referred to in paragraph 33(1)(b) or (c) is established only if

Content of declaration — harvester

50 (1) A declaration made by a person referred to in subparagraph 49(2)(a)(v) must contain

Certification

(2) However, a declaration made by a person referred to in subparagraph 49(2)(a)(v) with respect to a feedstock that is referred to in paragraph 33(1)(c) and has been certified under section 52 may, if it is accompanied by a copy of the certificate, contain the following information instead of the confirmations referred to in paragraphs (1)(i) to (n):

Declaration by registered creator or foreign supplier

(3) A declaration made by a person referred to in one of subparagraphs 49(2)(a)(i) to (iv) that is a registered creator or foreign supplier must indicate

Declaration by other person

(4) A declaration made by a person referred to in one of subparagraphs 49(2)(a)(i) to (iv), other than a registered creator or foreign supplier must indicate

Unique identifier

(5) The unique identifier referred to in paragraphs (1)(o), (3)(l) and (4)(i) must be used in all records related to material balances at the site to which it applies. The identifier must be unique to each declaration and indicate the lot number of the feedstock to which it applies.

Producer records

51 (1) The producer of a low carbon intensity fuel produced using a feedstock referred to in paragraph 33(1)(b) or (c) must maintain the following documents in their records:

Importer records

(2) The importer of a quantity of low carbon intensity fuel must maintain the following documents in their records:

Certification

52 A feedstock referred to in paragraph 33(1)(c) may be certified by a certification body that meets the requirements of sections 54 to 56 in accordance with sections 57 to 60 and a certification scheme that is approved under section 53.

Approval by Minister

53 (1) The Minister may approve a certification scheme if the Minister is satisfied that all feedstock that is certified using the procedures in the certification scheme will satisfy the applicable requirements of sections 35 to 38 and 41.

Scheme owner

(2) The Minister must not approve a certification scheme unless it is developed and maintained by a scheme owner that

Competencies of certification body

(3) The Minister must not approve a certification scheme unless it describes in detail the specific competencies required of a certification body and the way in which the satisfaction of those requirements is demonstrated.

Review of scheme

(4) The Minister must not approve a certification scheme unless

Information publicly available

(5) The Minister must not approve a certification scheme unless it includes procedures to ensure that the following is publicly available:

Group auditing

(6) The Minister must not approve a certification scheme that permits a group of producers to be certified together unless it requires that

Non-compliance

(7) The Minister must not approve a certification scheme unless it indicates the actions that a certification body must take if a feedstock harvester does not comply with the certification scheme.

Use of certificates

(8) The Minister must not approve a certification scheme unless

End of approval

(9) A certification scheme is no longer approved on the earlier of the following days:

Material site

(10) For the purpose of paragraph (6)(b), a site is material if any misstatement that relates to the site is likely to result in a quantitative material error in a report that relates to the certified feedstock.

Certification body

54 The certification of a feedstock must be performed by a certification body that is accredited in accordance with the certification scheme that is used, which accreditation is neither suspended nor revoked.

Eligibility

55 (1) A person is eligible to be accredited as a certification body by the Standard Council of Canada, the ANSI National Accreditation Board or a designated accreditation body if the person

Designation of accreditation body

(2) The Minister may designate an accreditation body if it is a member of the International Accreditation Forum and satisfies the requirements of International Standard ISO 17011, entitled Conformity assessment — General requirements for accreditation bodies accrediting conformity assessment bodies published by the International Organization for Standardization.

Technical accreditation

56 (1) A certification must be performed by a body that is accredited, in accordance with section 55, as one that is competent in each of the following areas that is relevant to the feedstock being certified:

Forest, agriculture or other land use

(2) A certification body cannot be accredited as one referred to in paragraph (1)(a) unless it employs an individual who is an expert in forest or agriculture or other land use, as the case may be, and who is accredited

Biodiversity

(3) A certification body cannot be accredited as one referred to in paragraph (1)(b) unless it employs an individual who is an expert in biodiversity and who is

Outsourcing

57 Sections 54 to 56 apply with respect to a person to which part of the certification is outsourced by a certification body.

Preceding compliance periods

58 A team that performs a certification must not include an individual, including one to whom work is outsourced, who has contributed to the certification of that feedstock for five consecutive compliance periods, unless three compliance periods have elapsed after the most recent compliance period for which they contributed to such a certification.

Person responsible for making decision

59 (1) The members of a certification team must be appointed in accordance with section 7 of ISO Standard 19011.

Employees

(2) The person responsible for making a certification decision must have the same competencies as those set out for an audit team leader under subclause 7.2.3.4 of ISO Standard 19011.

Employees

(3) The person responsible for making the certification decision, the audit team leader and, if applicable, the independent reviewer must be employees of the certification body.

Applicable standards for certification

60 (1) A certification body must conduct a certification in accordance with the Method for Validation, Verification and Certification - Clean Fuel Regulations, published by the Minister, and the following standards, at a reasonable level of assurance:

Interpretation of ISO/IEC Standard 17065

(2) ISO/IEC Standard 17065 is to be read with

International Standard ISO/IEC 17021

(3) International Standard ISO/IEC 17021 is to be read with

ISO Standard 14064-3:2019

(4) ISO Standard 14064-3:2019 is to be read with

Site visits

(5) The first certification of a feedstock conducted by a given certification body must include a site visit. Subsequent certifications do not require a site visit if

Certification decision

61 (1) A certification body must not issue a certification with respect to a feedstock unless it concludes that the certification requirements referred to in paragraph 60(2)(a) or the criteria for the certification referred to in paragraph 60(3)(a) or (4)(a), as the case may be, have been satisfied with respect to that feedstock.

Unambiguous certification

(2) A certificate must unambiguously identify the feedstock to which it applies.

Non-compliance with other scheme

(3) If a certification body certifies, under a given certification scheme, a feedstock that was determined not to comply with another certification scheme, the certification body must notify the scheme owner of the given certification scheme before they issue the certification.

End of certification

(4) A certification ceases to be valid on the earlier of the following:

Determination of Carbon Intensity

Default — low carbon intensity fuel

62 (1) The carbon intensity of a fuel or hydrogen, other than a fossil fuel or hydrogen produced from natural gas, is determined by the formula

CIf + CIp + CItd+ CICL+ CIe + CIc
where
CIf
is the quantity of CO2e emissions set out in item 1 of Schedule 5 that represents the quantity of CO2e that is associated with the extraction or cultivation, as the case may be, of the feedstock from which the fuel or hydrogen is produced, per megajoule of energy produced;
CIp
is the quantity of CO2e emissions set out in item 2 of Schedule 5 that represents the quantity of CO2e that is released during the production of the fuel or hydrogen from the given feedstock, the transportation of the given feedstock and intermediary products used to produce the fuel or hydrogen, and the distribution of the fuel or hydrogen to end users, per megajoule of energy produced;
CICL
is the quantity of CO2e emissions set out in item 3 of Schedule 5 that represents the quantity of CO2e that is released during the compression or liquefaction process of the fuel or hydrogen, per megajoule of energy produced;
CIe
is the quantity of CO2e emissions set out in item 4 of Schedule 5 that represents the additional quantity of CO2e that is associated with the production of electricity used during the production of the fuel or hydrogen, per megajoule of energy produced;
CItd
is the quantity of CO2e emissions set out in item 5 of Schedule 5 that represents the additional quantity of CO2e that is released during the transportation of the given feedstock and intermediary products used to produce the type of fuel or hydrogen and the distribution of the fuel or hydrogen to end users, per megajoule of energy produced, in the case of a total transportation distance of not less than 1500 km;
CIc
is the quantity of CO2e emissions set out in item 6 of Schedule 5 that represents the quantity of CO2 that is released during the combustion of the fuel or the use of hydrogen as an energy source, per megajoule of energy produced.

Fossil fuels

(2) For the purpose of subsections 84(2), 85(3) and (4) and 88(2), the carbon intensity of hydrogen, propane, liquefied petroleum gas, natural gas, liquefied natural gas and compressed natural gas is, at the election of the registered creator, the amount

Electricity

(3) The carbon intensity of electricity in a province in which a charging station is located is, at the election of the registered creator, the amount

Fuel LCA Model — low carbon intensity fuels

63 (1) Instead of determining the carbon intensity of any of their renewable propane, renewable natural gas, hydrogen or other low carbon intensity fuels by the formula set out in subsection 62(1), a registered creator or a foreign supplier may elect to make that determination using the Fuel LCA Model as applied to one of the options set out in paragraphs (2)(a) to (c), if they have input data for the period of 24 consecutive months immediately preceding the date of the election, derived from the activities referred to in the definition carbon intensity that are carried out over the lifecycle of the fuel.

Options on election

(2) The registered creator or foreign supplier may determine the carbon intensity based on the input data for that period of 24 consecutive months as applied to one of the following options:

Fuel LCA Model — compressed and liquefied gases

64 (1) Instead of determining the carbon intensity of liquefied petroleum gas, liquefied natural gas, compressed natural gas, compressed hydrogen and liquefied hydrogen in accordance with subsection 62(2), a person referred to in subsections 84(1) or 85(1), as the case may be, may elect to make that determination using the Fuel LCA Model as applied to one of the options set out in paragraphs (3)(a) or (b) if they have input data, for the period of 24 consecutive months immediately preceding the date of the election, respecting the compression or liquefaction process of their liquefied petroleum gas, renewable liquefied petroleum gas, compressed natural gas, renewable compressed natural gas, liquefied natural gas, renewable liquefied natural gas, compressed hydrogen or liquefied hydrogen.

Hydrogen and renewable fuels

(2) In the case of renewable liquefied petroleum gas, renewable compressed natural gas, renewable liquefied natural gas, compressed hydrogen or liquefied hydrogen, the determination is to be made as if their

Options on election

(3) The person may determine the carbon intensity based on the input data for that period of 24 consecutive months as applied to

Fuel LCA Model — electricity

65 (1) Instead of determining the carbon intensity of electricity in accordance with subsection 62(3), a registered creator may elect to make that determination using the Fuel LCA Model in accordance with subsection (2) if they have input data for the period of 24 consecutive months immediately preceding the date of the election regarding the source and quantity of electrical energy supplied to electric vehicles at a charging station that is not intended for residential charging.

Options on election

(2) The registered creator may determine the carbon intensity based on that input data for a period of 24 consecutive months as applied to an existing pathway from the Fuel LCA Model.

Application for approval of carbon intensity determination

66 (1) A registered creator or a foreign supplier may apply to the Minister for approval of the carbon intensity that they determine under subsection 62(1) or section 63, 64 or 65.

Imported fuel

(2) In the case of a fuel produced outside Canada, only the foreign supplier of the fuel may make the application.

Different carbon intensities per feedstock

(3) A separate application is required per type of feedstock used to create a low carbon intensity fuel.

Multiple feedstocks

(4) If a low carbon intensity fuel is created with more than one type of feedstock, the carbon intensity of the proportion of the fuel produced using each type of feedstock requires a separate application for approval.

Multiple co-products

(5) A registered creator or foreign supplier referred to in subsection (1) may, in respect of a low carbon intensity fuel whose production results in more than one co-product, apply for the approval of a single carbon intensity of the fuel or of one carbon intensity of each portion of the fuel whose production results in each co-product.

Pathway approval

67 (1) A registered creator or a foreign supplier must have the applicable pathway approved by the Minister before they apply under subsection 66(1) for the approval of a carbon intensity with respect to a modification of the unit processes referred to in paragraph 63(2)(b) or a pathway referred to in 64(3)(b) or the creation of a new pathway referred to in paragraph 63(2)(c).

Application

(2) The registered creator or foreign supplier applies for the approval of the pathway by submitting the following information:

Approval

(3) The Minister must approve the pathway application if the Minister is satisfied that the pathway of the fuel is based on

Unique identifier

(4) On approval of the pathway, the Minister must assign a unique alphanumeric identifier to it.

Information to be provided — low carbon intensity fuels

68 (1) An application referred to in section 66 in respect of a low carbon intensity fuel must contain the information set out in item 1 of Schedule 6.

Additional Information — subsection 62(1)

(2) In the case of a carbon intensity that is determined in accordance with subsection 62(1), the application must contain the information set out in item 2 of Schedule 6 in addition to that referred to in subsection (1).

Additional Information — section 63

(3) In the case of a carbon intensity that is determined in accordance with section 63, the application must contain the information set out in item 3 of Schedule 6 in addition to that referred to in subsection (1).

Information to be provided — LNG, CNG and LPG

69 In the case of a carbon intensity that is determined in accordance with section 64, the application referred to in section 66 must contain the information set out in item 4 of Schedule 6.

Information to be provided — electricity

70 In the case of a carbon intensity that is determined in accordance with section 65, the application referred to in section 66 must contain the information set out in item 5 of Schedule 6.

Approval

71 (1) The Minister must approve the carbon intensity referred to in the application made under section 66 if the Minister is satisfied that the carbon intensity is based on

Unique alphanumeric identifier

(2) On approval of a carbon intensity, the Minister must round it to the nearest whole number and assign a unique alphanumeric identifier to it.

End of validity — low carbon intensity fuel

72 (1) The approved carbon intensity of a low carbon intensity fuel is no longer valid if there is a change in the extraction or cultivation of feedstock or in the production processes for the fuel that is not consistent with the emission factors, input data, background data sets and a methodology used for that determination and would likely result

Failure to submit records

(2) The approved carbon intensity of a low carbon intensity fuel is no longer valid if the registered creator or foreign supplier referred to in subsection 66(1) does not comply with section 161.

End of validity — LNG, CNG and LPG

(3) The approved carbon intensity of liquefied petroleum gas, compressed natural gas or liquefied natural gas that was determined in accordance with section 64 is no longer valid if there is a change in the compression or liquefaction process for the fuel that is not consistent with the emission factors, input data, background data sets and a methodology used for that determination and would likely result in the actual carbon intensity of the fuel being at least 0.5 gCO2e/MJ greater than the approved carbon intensity of the fuel.

End of validity — electricity

(4) The approved carbon intensity of electricity is no longer valid if there is a change in the source and quantity of electrical energy supplied to electric vehicles that would likely result in the actual carbon intensity of the electricity being at least 0.5 gCO2e/MJ greater than the approved carbon intensity of the electricity as determined in accordance with section 65.

Default determination if no approved determination

73 In the absence of a valid approved carbon intensity of a low carbon intensity fuel, the registered creator or foreign supplier referred to in subsection 66(1) must, under section 66, apply to the Minister for approval of the carbon intensity of the fuel before credits can be created by importing or producing that fuel.

Reapplication

74 A registered creator or foreign supplier may reapply under section 66 for approval of a carbon intensity of a fuel or electricity if they have determined, under section 63, 64 or 65, as the case may be, that the actual carbon intensity of the fuel or electricity is lower than the approved carbon intensity by an amount that is at least the greater of 1 g/MJ and 5% of that approved carbon intensity.

Adjustment credits — low carbon intensity fuel

75 In the first report that a registered creator makes under section 103 or 104 after the day on which the Minister approves, in accordance with section 71, the carbon intensity of a fuel that was determined under section 63, the registered creator may request that compliance credits be created with respect to the shorter of the following periods:

Adjustment — CNG, LNG, LPG and electricity

76 In the first report that a registered creator makes under section 103 or 104 after the day on which the Minister approves, in accordance with section 71, the carbon intensity of a fuel or of electricity that was determined under section 64 or 65, respectively, the registered creator may request that compliance credits be created for the shorter of the following periods:

Number of adjusted compliance credits

77 (1) The number of compliance credits that are created by the registered creator is equal to the number of compliance credits that would have been created in the period referred to in section 75 or 76, determined using the information contained in reports that were submitted under sections 103 and 104 in respect of that period and the carbon intensity determined under section 63, 64 or 65, as the case may be, less the sum of

Cancellation of excess credits

(2) If the number calculated in accordance with subsection (1) is negative, the Minister must cancel that number of compliance credits that are equivalent, within the meaning of section 156, to the compliance credits that are described in paragraph (1)(a) to (c).

Provisional approval of carbon intensity

78 (1) A registered creator or foreign supplier referred to in subsection 66(1) that has data on operation of a facility for a period of 3 or more consecutive months, but less than 24 consecutive months, with respect to the activities referred to in the definition carbon intensity may apply for provisional approval of a carbon intensity.

Determination of carbon intensity

(2) The carbon intensity is to be determined in accordance with section 63, 64 or 65, as the case may be, using the data for the period referred to in subsection (1) instead of the data with respect to 24 consecutive months that is required in those sections.

Application for provisional approval

(3) The application is made in accordance with sections 66 to 70.

Provisional approval

(4) The Minister must provisionally approve the carbon intensity referred to in the application if the Minister is satisfied that the determination of the carbon intensity of the fuel is based on the factors set out in paragraphs 71(1)(a) to (e), and must assign a unique alphanumeric identifier for the provisionally approved carbon intensity of the fuel based on that determination.

Equivalent to approved carbon intensity

(5) The carbon intensity that is provisionally approved under subsection (4) is to be treated as if it were a carbon intensity approved under section 71 until the earlier of

Period of validity

(6) The provisionally approved carbon intensity ceases to be valid on the day referred to in paragraph (5)(a) or (b) or at any earlier time at which there is a change in the extraction or cultivation of the feedstock or in the production processes for the fuel that is not consistent with the emission factors, input data, background data sets or methodology used for that determination, and that would likely result in the actual carbon intensity of the fuel being at least 0.5 gCO2e/MJ greater than the approved carbon intensity of the fuel.

Registration of foreign supplier

79 (1) An application referred to in section 66, 67 or 78 that is made by an unregistered foreign supplier that is not a registered creator is not eligible to be processed.

Method of registration

(2) The foreign supplier may register by sending to the Minister a registration report that contains the following information:

Low Carbon Intensity Fuels

Liquid low carbon intensity fuel

80 (1) A person that produces in Canada or imports, or both produces in Canada and imports, a volume of liquid low carbon intensity fuel during a compliance period that displaces or was sold to displace what would otherwise be the use of a volume of a type of fuel in the liquid class is eligible to create compliance credits in respect of the liquid class for the compliance period.

Number of compliance credits

(2) The number of compliance credits that the person may create for a compliance period is determined by the formula

CIdiff × (Q × D) × 10-6
where
CIdiff
is the difference between the liquid class reference carbon intensity for the compliance period as set out in item 1 of Schedule 1 and the carbon intensity of the low carbon intensity fuel as approved under subsection 71(1);
Q
is, subject to subsection 32(1), the quantity of that low carbon intensity fuel produced in Canada or imported by the person during the period for use as a fuel in Canada, expressed as a volume in cubic metres; and
D
is the energy density of that low carbon intensity fuel, as set out in Schedule 2.

Gaseous low carbon intensity fuel

81 (1) A person that produces in Canada or imports, or both produces in Canada and imports, a volume of biogas, renewable natural gas, renewable propane or hydrogen during a compliance period that displaces or was sold to displace what would otherwise be the use of a volume of a type of fuel in the gaseous class is eligible to create compliance credits in respect of the gaseous class for the compliance period.

Excluded gases

(2) Compliance credits are not created under subsection (1) for producing or importing

Exception — producing electricity with biogas

(3) Biogas that is used in equipment that produces electricity cannot be used to create credits under subsection (1) if the amount determined by the following formula with respect to that equipment is less than 0.7:

(E + H)/(Q × D)
where
E
is the electrical energy produced by the equipment, expressed in megajoules;
H
is the heat energy that is produced by the equipment and used, expressed in megajoules;
Q
is, subject to subsection 32(1), the quantity of that biogas used in the equipment, expressed as a volume in cubic metres; and
D
is the energy density of that biogas as set out in Schedule 2.

Number of compliance credits

(4) The number of compliance credits that the person may create for a compliance period and a given fuel is determined by the formula

CIdiff × (Q × D) × 10-6
where
CIdiff
is the difference between
  • (a) in the case of biogas, renewable natural gas or hydrogen, the reference carbon intensity of biogas, renewable natural gas and hydrogen as set out in item 2 of Schedule 1 and the carbon intensity of the biogas, renewable natural gas or hydrogen, as the case may be, as approved under subsection 71(1); and
  • (b) in the case of renewable propane, the reference carbon intensity of renewable propane as set out in item 3 of Schedule 1 and the carbon intensity of the renewable propane, as approved under subsection 71(1);
Q
is, subject to section 32, the quantity of that biogas — other than biogas referred to in paragraph (2)(a) or subsection (3) — or renewable natural gas, renewable propane or hydrogen — other than the renewable natural gas, renewable propane or hydrogen referred to in paragraph (2)(b) — that was produced in Canada or imported by the person during the period for use as a fuel in Canada, expressed as a volume in cubic metres, in the case of biogas, renewable natural gas or renewable propane, and in kilograms, in the case of hydrogen; and
D
is the energy density of that biogas, renewable natural gas, renewable propane or hydrogen, as set out in Schedule 2.

Biogas used to produce electricity

82 (1) A person that produces in Canada a volume of biogas that is used in equipment referred to in subsection 81(3) to produce electricity during a compliance period in a manner that displaces what would otherwise be the use of a volume of a type of fuel in the gaseous class in accordance with paragraph 19(b) or (c) is eligible to create compliance credits in respect of the gaseous class for that compliance period.

Carbon intensity — electricity produced by biogas

(2) The electricity that is produced from using biogas in that equipment has a carbon intensity determined by the following formula:

CIbiogas × (Q × D) / E
where
CIbiogas
is the carbon intensity of the biogas being used to produce electricity, as approved under subsection 71(1);
Q
is, subject to subsection 32(1), the quantity of that biogas used in the equipment, expressed as a volume in cubic metres; and
D
is the energy density of that biogas as set out in Schedule 2.
E
is the electrical energy produced by the equipment, expressed in megajoules.

Number of credits

(3) The number of compliance credits that the person may create for a compliance period is determined by the formula

CIdiff × E × 10-6
where
CIdiff
is the difference between the carbon intensity for that compliance period of the electricity in the province in which the equipment is located and the carbon intensity, determined in accordance with subsection (2), of electricity produced by the biogas; and
E
is the electrical energy produced by the equipment, expressed in megajoules.

Carbon intensity of electricity in a province

(4) The carbon intensity of electricity in a province in which equipment that uses biogas to produce electricity is located is, at the election of the registered creator, the amount

Fuel produced with multiple feedstocks

83 (1) For the purpose of sections 80 to 82, a low carbon intensity fuel that is produced using more than one type of feedstock is treated as if it were multiple fuels, each with a volume that is equal to the proportion of the low carbon intensity fuel that is produced with each type of feedstock.

Multiple co-products

(2) For the purpose of sections 80 to 82, a low carbon intensity fuel whose production results in more than one co-product is, if an application that was made in respect of each of those co-products in accordance with subsection 66(5) was approved under section 71, treated as if it were multiple fuels, each with a volume that is equal to the proportion of the low carbon intensity fuel that results in each co-product.

Determination of proportion

(3) The proportion of the low carbon intensity fuel that is produced with each feedstock or that results in each co-product, as the case may be, must be determined in accordance with the Fuel LCA Model Methodology.

End User Fuel Switching

LPG, CNG and LNG

84 (1) A person that is the owner or operator of a fuelling station that supplies liquefied petroleum gas, compressed natural gas, or liquefied natural gas as a fuel for a vehicle in Canada is eligible to create compliance credits in respect of the liquid class for a compliance period based on the switching of fuels by the end user.

Compliance credits

(2) The number of compliance credits that a person that is the owner or operator of a fuelling station that supplies liquefied petroleum gas, compressed natural gas or liquefied natural gas may create is determined by the formula

CIdiff× (Q × D) × 10-6
where
CIdiff
is the difference between
  • (a) the liquid class reference carbon intensity for the compliance period as set out in item 1 Schedule 1, and
  • (b) the carbon intensity of liquefied petroleum gas, compressed natural gas or liquefied natural gas, determined in accordance with subsection 62(2) or, if applicable, determined in accordance with section 64 and approved in accordance with section 71;
Q
is the difference between the quantity, expressed in cubic metres, of the liquefied petroleum gas, compressed natural gas or liquefied natural gas, as the case may be, supplied to the vehicles, as measured by a meter and
  • (a) in the case of liquefied petroleum gas, the quantity of renewable liquefied petroleum gas supplied to the vehicles, as determined from the supporting documents referred to in subsection 85(2); and
  • (b) in the case of compressed natural gas or liquefied natural gas, the total quantity of renewable natural gas and hydrogen supplied to the vehicles, as determined from the supporting documents referred to in subsection 85(2);
D
is the energy density of the liquefied petroleum gas, compressed natural gas or liquefied natural gas, as the case may be, as set out in Schedule 2.

Renewable gaseous fuels and hydrogen

85 (1) A person that is the owner or operator of a fuelling station that supplies low carbon intensity fuel that is renewable liquefied petroleum gas, compressed renewable natural gas, liquefied renewable natural gas, compressed hydrogen or liquefied hydrogen as a fuel for a vehicle in Canada is eligible to create compliance credits in respect of the liquid class for a compliance period based on the switching of fuels by the end user if they possess the required supporting documents.

Supporting documents

(2) The supporting documents referred to in subsection (1) must indicate the quantity of the fuel supplied during the compliance period, the person from which the fuel was purchased, the carbon intensity that is approved by the Minister under 71(1) and the unique alphanumeric identifier assigned to that carbon intensity under subsection 71(2).

Compliance credits — renewable natural gas and hydrogen

(3) The number of compliance credits that the owner or operator a fuelling station that supplies a low carbon intensity fuel that is compressed renewable natural gas, liquefied renewable natural gas, compressed hydrogen or liquefied hydrogen may create for a compliance period is determined by the formula

(CIdiff1 + CIdiff2)× (Q × D) × 10-6
where
CIdiff1
is the difference between
  • (a) the liquid class reference carbon intensity for the compliance period as set out in item 1 of Schedule 1, and
  • (b) the carbon intensity of the compressed natural gas or liquefied natural gas, determined in accordance with subsection 62(2) or, if applicable, determined in accordance with section 64 and approved in accordance with section 71;
CIdiff2
is the difference between
  • (a) the carbon intensity of natural gas determined in accordance with subsection 62(2), and
  • (b) the reference carbon intensity of renewable natural gas and hydrogen as set out in item 2 of Schedule 1;
Q
is, subject to subsection 32(1), the quantity of renewable natural gas or hydrogen, as the case may be, supplied to the vehicles, as determined from the supporting documents referred to in subsection (2) and expressed in cubic metres;
D
is the energy density of the renewable natural gas or hydrogen, as the case may be, as set out in Schedule 2.

Compliance credits — renewable propane

(4) The number of compliance credits that the owner or operator of a fuelling station that supplies a low carbon intensity fuel that is renewable liquefied petroleum gas may create for a compliance period is determined by the formula

(CIdiff1 + CIdiff2) × (Q × D) × 10-6
where
CIdiff1
is the difference between
  • (a) the liquid class reference carbon intensity for the compliance period as set out in item 1 of Schedule 1, and
  • (b) the carbon intensity of the liquefied petroleum gas, determined in accordance with subsection 62(2) or, if applicable, determined in accordance with section 64 and approved in accordance with section 71;
CIdiff2
is the difference between
  • (a) the carbon intensity of propane determined in accordance with subsection 62(2), and
  • (b) the reference carbon intensity of renewable propane as set out in item 3 of Schedule 1;
Q
is, subject to subsection 32(1), the quantity of renewable propane supplied to the vehicles, as determined from the supporting documents referred to in subsection (2) and expressed in cubic metres;
D
is the energy density of the renewable propane, as set out in Schedule 2.

Creator — producer or importer

86 (1) A person that produces in Canada or imports, or both produces in Canada and imports, a volume of low carbon intensity fuel that is renewable propane, renewable natural gas or hydrogen during a compliance period for the purpose of using it as a fuel for a vehicle in Canada is eligible to create compliance credits in respect of the liquid class for the compliance period based on the switching of fuels by end users if they possess the required supporting documents.

Supporting documents

(2) The supporting documents referred to in subsection (1) must establish that the fuel was supplied to a fuelling station and indicate the volume of the fuel supplied during the compliance period and the owner or operator of the fuelling station at which the fuel was supplied.

Number of credits

(3) The number of compliance credits that the person may create for a compliance period and a given fuel is determined by the formula

CIdiff × (Q × D) × 10-6
where
CIdiff
is
  • (a) in the case of renewable natural gas or hydrogen, the difference between the reference carbon intensity of renewable natural gas and hydrogen as set out in item 2 of Schedule 1 and the carbon intensity of the renewable natural gas or hydrogen, as the case may be, as approved under subsection 71(1); and
  • (b) in the case of renewable propane, the difference between the reference carbon intensity of renewable propane as set out in item 3 of Schedule 1 and the carbon intensity of the renewable propane, as approved under subsection 71(1);
Q
is, subject to subsection 32(1), the quantity of the given fuel supplied to the fuelling station, as indicated in the supporting documents referred to in subsection (2) and expressed in cubic metres;
D
is the energy density of the given fuel, as set out in Schedule 2.

Electricity

87 (1) The following persons are eligible to create compliance credits in respect of the liquid class for a compliance period based on the displacement as a result of end user fuel switching, during the compliance period of the use of a volume of fuel in the liquid class with the use in Canada of electricity as an energy source in a class of electric vehicle that is listed in the Fuel LCA Model Methodology:

Number of compliance credits

(2) A person referred to in subsection (1) may create the number of compliance credits for a compliance period by supplying electricity of a given carbon intensity that is determined by the formula

F × CIdiff × (Q × D) × 10-6
where
F
is
  • (a) in the case of electricity supplied by a charging site host or by a charging station in a public location, 1,
  • (b) in the case of electricity that is supplied by a charging station that is installed in a residence no later than December 31, 2030
    • (i) 1 if the compliance period begins no later than January 1, 2035, and
    • (ii) 0 if the compliance period begins after January 1, 2035, and
  • (c) in the case of electricity that is supplied by a charging station that is installed in a residence later than December 31, 2030, 0;
CIdiff
is the difference between the liquid class reference carbon intensity as set out in item 1 of Schedule 1, as adjusted by the energy efficiency ratio of the electric vehicles in question, and the carbon intensity of the electricity used by those vehicles, determined by the formula
(Ree × CIref) - CIe
where
Ree
is, at the election of the registered creator, 3 or the energy efficiency ratio for the class of the electric vehicles set out in the Fuel LCA Model Methodology,
CIref
is the liquid class reference carbon intensity for the compliance period as set out in item 1 of Schedule 1 for that compliance period, and
CIe
is carbon intensity of the electricity, as approved under subsection 71(1) or determined in accordance with subsection 62(3), as the case may be, used to propel the electric vehicles in question;
Q
is the quantity of electrical energy of a given carbon intensity supplied to the electric vehicles or measured
  • (a) in the case of a charging network operator, by charging stations that are used to charge those electric vehicles in residential or public locations, expressed in kilowatt-hours, and
  • (b) in the case of a charging site host, by charging stations, other than those in residences or that are primarily intended for the use of the general public, that are used to charge those electric vehicles, expressed in kilowatt-hours; and
D
is 3.6 megajoules per kilowatt-hour.

Hydrogen

88 (1) A person that is the owner or operator of a hydrogen fuelling station is eligible to create compliance credits in respect of the liquid class for a compliance period based on the displacement as a result of end user fuel switching during that compliance period, of the use of a volume of fuel in the liquid class by the use in Canada of hydrogen as an energy source in a class of hydrogen fuel cell vehicle that is listed in the Fuel LCA Model Methodology.

Number of compliance credits

(2) A person referred to in subsection (1) may create the number of compliance credits for a compliance period by supplying hydrogen of a given carbon intensity that is determined by the formula

CIdiff × (Q × D) × 10-6
where
CIdiff
is the difference between the liquid class reference carbon intensity as set out in item 1 of Schedule 1, as adjusted by the energy efficiency ratio of the hydrogen fuel cell vehicles in question, and the carbon intensity of the hydrogen used by those vehicles, determined by the formula
(Ree × CIref) - CIh
where
Ree
is, at the election of the registered creator, 1.5 or the energy efficiency ratio for the class of the hydrogen fuel cell vehicles set out in the Fuel LCA Model Methodology,
CIref
is the liquid class reference carbon intensity for the compliance period as set out in item 1 of Schedule 1 for that compliance period, and
CIh
is the carbon intensity of the hydrogen, as approved under subsection 71(1) or determined in accordance with subsection 62(2), as the case may be, used to propel the hydrogen fuel cell vehicles in question;
Q
is the quantity of hydrogen of the given carbon intensity supplied to the hydrogen fuel cell vehicles in question, as measured by hydrogen fuel dispensers, expressed in kilograms;
D
is the energy density of hydrogen, as set out in Schedule 2.

Use of revenue — electric vehicles

89 (1) A charging network operator referred to in paragraph 87(1)(a) is not eligible to create compliance credits during a given compliance period unless all of the revenue they received from the transfer of any such compliance credits that were created during all previous compliance periods was used within the period set out in subsection (3) to support the following activities:

Allocation as between activities

(2) The charging network operator may, at their discretion, allocate the use of those revenues as between those activities.

Period for use

(3) The revenues received from the transfer of a compliance credit must be used no later than the second anniversary of the end of the compliance period during which the charging network operator transferred the compliance credit.

Cancellation of credits

(4) The Minister must cancel an equivalent number of compliance credits to the number of compliance credits that were transferred if the revenue from that transfer was not used in accordance with subsection (1) within the period set out in subsection (3).

Trading System

Transfers in trade

Eligibility to transfer credits

90 (1) Only a participant may transfer a compliance credit, and the transfer must be to another participant.

Form submitted by transferor

(2) To transfer a compliance credit, the transferor must submit a form to the Minister that is signed by an authorized official that contains

Confirmation by transferee

(3) The authorized representative of the transferee must review the information submitted in accordance with subsection (2) and sign the form to confirm that the information is accurate and that the transferee approves of the transfer.

Transfer of credits

(4) After the Minister receives the form signed by both authorized representatives, the compliance credits that are described in the form are transferred from the transferor’s account and deposited into the account of the transferee.

Type of account

(5) For the purpose of subsection (4), a compliance credit that is transferred from an account of the transferor that is opened under paragraph 26(a), (b) or (c) is deposited into the account of the transferee that is opened under the same paragraph.

Registered creator is participant

91 (1) A registered creator that is not a primary supplier is a participant in the compliance credit trading system as of the first day on which the person creates a provisional compliance credit.

End of participation

(2) A registered creator may end their participation in the trading system if they

Effective end of participation

(3) A registered creator’s participation in the program is ended and their compliance credits in their accounts opened under section 26 are cancelled on the date referred to in subsection (2) if the Minister receives, before that date, a verification report and an opinion issued in accordance with paragraph 146(a) respecting the credit creation report for the compliance period during which the notice referred to in paragraph (2)(a) was sent to the Minister.

Request to transfer upon creation

92 (1) A registered creator that has created provisional compliance credits by producing in Canada or importing a quantity of low carbon intensity fuel may request that any of those credits be transferred in trade to another participant that purchases the fuel by providing the Minister with a form, signed by the registered creator and the transferee, that indicates their intention to have the credits immediately transferred during the compliance period and that contains the following information:

Immediate transfer

(2) If a registered creator makes such a request, any compliance credits that the Minister deposits in accordance with subsection 23(3) are immediately transferred from the registered creator’s account and deposited into the account of the other participant that was opened under the same paragraph of section 26.

Compliance Credit Clearance Mechanism

Pledging credits to mechanism

93 (1) A participant may, in a report submitted under subsection 108(1) or 109(1), as the case may be, pledge to offer to transfer through the compliance credit clearance mechanism any credits that

Restriction on use of transfer

(2) During the period beginning on the day on which the report referred to in subsection (1) is submitted and ending on the following October 1, or, if applicable, the day on which a notice is sent in accordance with subsection 94(1), a compliance credit that has been pledged cannot be transferred except through the compliance credit clearance mechanism, and cannot be used by the participant that pledged to offer to transfer it.

No need for clearance mechanism

94 (1) If the compliance reports submitted under subsection 109(1) by primary suppliers indicate that all primary suppliers have satisfied the reduction requirement calculated under section 8 for the compliance period and any deferred reduction requirement, the Minister must, before the following August 1, notify each participant that pledged compliance credits under section 93 that there will be no compliance credit clearance mechanism for that compliance period.

No credits pledged

(2) If no participant pledges, in accordance with subsection 93(1), to offer to transfer a compliance credit through the compliance credit clearance mechanism, the Minister must, before the following August 1, notify each primary supplier that has not satisfied the reduction requirement calculated under section 8 for the compliance period or any deferred reduction requirement that there will be no compliance credit clearance mechanism for that compliance period.

Notice to participants

(3) If the Minister does not notify participants in accordance with subsection (1) or (2), the Minister must, before the August 1 that follows the compliance period, provide a notice to each participant that pledged compliance credits and each primary supplier that has not yet satisfied the reduction requirement calculated under section 8 for that compliance period or any deferred reduction requirement that includes

Transfer through clearance mechanism

95 (1) A compliance credit that is transferred in trade through the compliance credit clearance mechanism must be transferred to a primary supplier that submitted a report under subsection 109(1) for a compliance period that indicates that they have not satisfied the reduction requirement calculated under section 8 for that compliance period or any deferred reduction requirement and must be transferred during the period beginning on the August 1 that follows the compliance period and ending on the following September 30.

Maximum price

(2) A participant that has pledged a compliance credit must, if the compliance credit is in their account, accept an offer to acquire the compliance credit by transfer through the compliance credit clearance mechanism if the price offered for the transfer is equal to

$300 × (CpiA/CpiB)
where
CpiA
is the average Consumer Price Index for the 12 months of the compliance period to which the compliance credit clearance market relates, as published by Statistics Canada under the authority of the Statistics Act; and
CpiB
is the average Consumer Price Index for the 12 months of the year 2022, as published by Statistics Canada under the authority of the Statistics Act.

Prohibition

(3) A participant that has pledged a compliance credit must not accept an offer to acquire the compliance credit by transfer through the compliance credit clearance mechanism if the price offered for the transfer is greater than the one set out in subsection (2).

Credits per primary supplier

(4) A primary supplier may not acquire more compliance credits by transfer through the compliance credit clearance mechanism than the lesser of

C × (RP/RT)
where
C
is the total number of compliance credits that have been pledged by all participants under section 93,
RP
is the sum of the number of compliance credits the primary supplier requires in order to satisfy the reduction requirement calculated under section 8 and the number of compliance credits that the primary supplier requires in order to satisfy their deferred reduction requirement, and
RT
is the sum of the total number of compliance credits that all primary suppliers require in order to satisfy the reduction requirement calculated under section 8 and the total number of compliance credits that all primary suppliers require in order to satisfy the deferred reduction requirement.

2024 year

(5) During the year 2024, a compliance credit may be transferred in accordance with subsection (1) during the period beginning on August 1 and ending on the following September 30 to a primary supplier that

Consumer price index

(6) During the year 2024, the value CpiA referred to in subsection (2) is the average Consumer Price Index for the 12 months of the year 2023, as published by Statistics Canada under the authority of the Statistics Act.

Credits per primary supplier in 2024

(7) Despite subsection (4), a primary supplier may not acquire more compliance credits by transfer through the compliance credit clearance mechanism in the year 2024 than the lesser of

C × (RP/RT)
where
C
is the total number of compliance credits that have been pledged by all participants under section 93,
RP
is the sum of the number of compliance credits the primary supplier requires in order to satisfy the reduction requirement calculated under section 8 for the compliance period that ends on December 31, 2022 and the compliance period that ends on December 31, 2023, and
RT
is the sum of the total number of compliance credits that all primary suppliers require in order to satisfy the reduction requirement calculated under section 8 for the compliance period that ends on December 31, 2022 and the compliance period that ends on December 31, 2023.

Registered Emissions Reduction Funding Program

Funding program — registration

96 (1) A person that administers an emissions reductions funding program to reduce the quantity of CO2e emissions may apply to the Minister to have the program registered. The application must contain the information set out in Schedule 7 and is accompanied by an attestation, signed by the authorized official of the person, that indicates that the program will distribute contributions to projects that are referred to in subsection 97(1) and make information respecting those funds publicly available on an annual basis.

Conditions for eligibility of application

(2) The person that administers an emissions reduction funding program may only apply for the program to be registered if the following conditions are met:

Registration requirements

97 (1) The Minister must not register the emissions reduction funding program unless the Minister is satisfied that all contributions to the program will be used to fund projects that support the deployment or commercialization of technologies or processes that will reduce CO2e emissions no later than

Factors

(2) In deciding whether to register an emissions reduction funding program, the Minister must take into consideration

Cancelling registration

98 The Minister must cancel the registration of an emissions reduction funding program if the conditions set out in subsection 96(2) are no longer met or if the Minister is no longer satisfied that contributions to the program will be used in accordance with subsection 97(1).

Annual audit

99 The person that administers a registered emissions reduction funding program must, on an annual basis, hire an independent body to conduct a financial audit of the emissions reduction funding program.

Publication

100 The Minister must make a list of all registered emissions reduction funding programs available.

Contribution to funding program

101 (1) A primary supplier may create compliance credits for a compliance period by contributing to a registered emissions reduction funding program

Receipt

(2) To create the compliance credits, the primary supplier must provide a receipt issued by the emissions reduction funding program that establishes that they made the contribution with the report they submit in accordance with section 109 or 111, as the case may be.

Credits created

(3) A number of compliance credits that is determined in accordance with the following formula, rounded down is deposited into the supplier’s account that was opened under paragraph 26(a):

A/P
where
A
is the amount of the primary supplier’s contribution to the emissions reduction funding program; and
P
is $350.

Consumer price index

(4) On every January 1 that follows a compliance period, the amount set out in subsection (3) for P is replaced by the result of the following formula, rounded to the nearest dollar:

$350 x (CpiA/CpiB)
where
CpiA
is the average Consumer Price Index for the 12 months of the compliance period, as published by Statistics Canada under the authority of the Statistics Act; and
CpiB
is the average Consumer Price Index for the 12 months of the year 2022, as published by Statistics Canada under the authority of the Statistics Act.

December 2022 compliance period

(5) A primary supplier may create compliance credits for the compliance period that ends on December 31, 2022 by contributing to a registered emissions reduction funding program

No subsequent transfer

102 (1) A compliance credit created under subsection 18(2) cannot be transferred by the primary supplier that creates it under subsection 101(1).

Cancellation on December 1

(2) The Minister cancels any compliance credit that was created under subsection 18(2) and that has not been used on the December 1 that follows its creation.

Reporting

Annual credit creation report

103 (1) A registered creator that creates a provisional compliance credit under paragraph 18(1)(a) or (d) or 19(a) or section 20 during a compliance period must submit to the Minister a creation report for the compliance period that is signed by an authorized official of the registered creator and includes

January 31

(2) The credit creation report must be submitted on or before January 31 of the calendar year that follows the compliance period.

January 31, 2023

(3) However, the report submitted under subsection (1) for the compliance period that ends November 30, 2022 and the report submitted under that subsection for the compliance period that ends December 31, 2022 are combined into a single report that must be submitted on or before January 31, 2023.

Quarterly credit creation reports

104 (1) A registered creator that creates a provisional compliance credit under paragraph 18(1)(b) or (c) or 19(b) or (c) during a compliance period must submit a credit creation report to the Minister on or before

Content of report

(2) A credit creation report referred to in subsection (1) must be signed by an authorized official of the registered creator and include, for the period to which it applies,

January 31, 2023

(3) However, all reports submitted under subsection (1) for the compliance period that ends November 30, 2022 and the compliance period that ends December 31, 2022 are combined into a single report that must be submitted on or before January 31, 2023.

Carbon intensity pathway report

105 (1) A carbon intensity that was approved under subsection 71(1) ceases to be valid unless, no later than the April 30 that follows the end of each compliance period, the registered creator or the foreign supplier that applied for approval of the carbon intensity submits a carbon intensity pathway report for the compliance period.

Content of report

(2) The report must contain the information set out in Schedule 9 for the compliance period and be signed by an authorized official of the registered creator or foreign supplier.

Material balance report for foreign supplier

106 (1) A carbon intensity that was approved under subsection 71(1) or 78(4) as a result of an application made by a foreign supplier in respect of a gaseous or liquid low carbon intensity fuel that was produced from a quantity of an eligible feedstock referred to in paragraph 33(1)(b) or (c) ceases to be valid unless, no later than the April 30 that follows the end of each compliance period, the foreign supplier submits a material balance report for the compliance period to the Minister.

Content of report

(2) The report must contain the information set out in Schedule 10 with respect to the low carbon intensity fuel for the compliance period and be signed by an authorized official of the foreign supplier.

Copy to importer

(3) The foreign supplier must provide a copy of the report to each person that imports the low carbon intensity fuel.

Non-application

(4) This section does not apply for any compliance period that ends before January 1, 2023.

Compliance credit revenue report

107 (1) A registered creator that is a charging network operator referred to in paragraph 87(1)(a) that transferred compliance credits that it created in accordance with subsection 87(2) during a given compliance period must

Content of report

(2) The report must contain the information set out in Schedule 11 and be signed by an authorized official of the registered creator.

Compliance credit balance report

108 (1) A registered creator that is not a primary supplier must submit a compliance credit balance report no later than the June 30 that follows the end of a compliance period.

Content of report

(2) The report must contain the information set out in Schedule 12 with respect to credits in the registered creator’s accounts on the day on which the report is submitted and be signed by an authorized official of the registered creator.

Non-application

(3) This section does not apply for any compliance period that ends before January 1, 2023.

Compliance report

109 (1) A primary supplier must submit a compliance report with respect to the manner in which they will satisfy the reduction requirement calculated under section 8 and the volumetric requirements referred to in subsection 5(1) and 6(1) for a compliance period set out in column 2 to the table to subsection 4(1) no later than the June 30 that follows the end of the compliance period.

Content of report

(2) The report must contain the information set out in Schedule 13 for the compliance period and be signed by an authorized official of the primary supplier.

Non-application

(3) This section does not apply for the compliance period that ends November 30, 2022.

June 30, 2024

(4) The report submitted under subsection (1) for the compliance period that ends December 31, 2022 must be submitted on or before June 30, 2024.

Fossil fuel production report

110 (1) A primary supplier that produces fuel in the liquid class using a production facility in Canada during a compliance period must, for each such production facility, submit a fossil fuel production report no later than the June 30 that follows the end of a compliance period.

Content of report

(2) The report must contain the information set out in Schedule 14 for the compliance period and be signed by an authorized official of the primary supplier.

Non-application

(3) This section does not apply for the compliance period that ends November 30, 2022.

June 30, 2024

(4) The report submitted under subsection (1) for the compliance period that ends December 31, 2022 must be submitted on or before June 30, 2024.

Complementary compliance report

111 (1) A primary supplier that, on the June 30 that follows the end of a compliance period, has not satisfied all of their reduction requirements calculated under section 8 for the compliance period and their deferred reduction requirements must submit a complementary compliance report no later than the November 30 that follows the end of that compliance period.

Content of report

(2) The report must contain the information set out in Schedule 15 for the compliance period and be signed by an authorized official of the primary supplier.

Non-application

(3) This section does not apply for the compliance period that ends November 30, 2022.

November 30, 2024

(4) The report submitted under subsection (1) for the compliance period that ends December 31, 2022 must be submitted on or before November 30, 2024.

Report respecting registered emissions reduction funding program

112 (1) The person that administers a registered emissions reduction funding program must make a report with respect to the operation of the emissions reduction funding program during each compliance period publicly available.

Date made available

(2) The report for the first compliance period in which the emissions reduction funding program accepts contributions must be made publicly available no later than the first anniversary of the day on which the funding program is registered, and all reports for subsequent compliance periods must be made available no later than the anniversary of the day on which the first report was made available that follows the end of each compliance period.

Content of report

(3) The report must contain the information set out in Schedule 16.

Validation and Verification

Obligation to Validate or Verify

Condition of eligibility

113 A report or application that is not validated or verified, as the case may be, in accordance with sections 114 to 148 is ineligible and does not satisfy any requirement of these Regulations.

Validation of applications

114 A person that makes one of the following applications must have it validated by a validation body and submit the validation report with the application:

Content of report

115 The validation report contains

Verification of applications

116 A person that makes one of the following applications must have it verified by a verification body and submit the verification report with the application:

Verification of reports

117 (1) A person that submits a report in accordance with one of sections 103 to 107 and 109 to 111 must have it verified by a verification body.

Exception

(2) However, a report is not required to be verified if

Deadline for verification

(3) The person must submit the verification report to the Minister no later than

Submission of declarations

118 A person that is having one of the following reports verified must submit copies of all declarations set out in paragraph 49(2)(a) to the verification body:

Content of report

119 The verification report contains

Maintenance of records

120 (1) The person that is having an application or report validated or verified must require that the validation body or verification body, as the case may be, maintain any documents related to the verification or validation for ten years after the verification or validation is completed.

Management system and processes

(2) The documents related to the verification or validation include any that

Submission of all reports

121 A person that makes an application or submits a report and obtains a validation report, verification report or disclaimer with respect to that application or report must, if they obtain a subsequent validation report, verification report or disclaimer with respect to the application or report, submit all the validation reports, verification reports or disclaimers to the Minister.

Monitoring plan

122 (1) A person that makes an application or submits a report that must be validated or verified, as the case may be, must prepare a monitoring plan, keep it up to date and submit it to the body that validates or verifies the application or report, as the case may be.

Content of plan

(2) The monitoring plan must contain the information set out in Schedule 19.

Requirements Respecting Validation Bodies and Verification Bodies

Accredited body

123 (1) The validation or verification is only to be performed by an accredited validation or verification body whose accreditation is neither suspended nor revoked.

Project level accreditation — validation

(2) The validation of an application referred to in section 29 must be conducted by a validation body that is accredited at the project level.

Project level accreditation — verification

(3) The verification of a report that is submitted under section 103 that contains information with respect to a CO2e emissions reduction or removal project referred to in subsection 28(1) must be conducted by a verification body that is accredited at the project level.

Organizational level accreditation — verification

(4) Any other application or report must be validated or verified, as the case may be, by a validation body or verification body that is accredited at the organizational level.

Eligibility

124 (1) A person that is not an individual is eligible to be accredited as a validation body or a verification body by the Standard Council of Canada, the ANSI National Accreditation Board or a designated accreditation body if the person

Designation of accreditation body

(2) The Minister may designate an accreditation body if it is a member of the International Accreditation Forum and satisfies the requirements of International Standard ISO 17011, entitled Conformity assessment — General requirements for accreditation bodies accrediting conformity assessment bodies published by the International Organization for Standardization.

Independent reviewer

(3) For the purpose of subclause 8.5 of the standard referred to in paragraph (1)(a), the independent reviewer must, at a minimum, have the same competencies as those set out in that standard for a team leader.

Technical accreditation

125 (1) A validation or verification must be performed by a body that is accredited, in accordance with section 124, as a validation body or verification body that is competent in each of the following areas that is within the scope of the application or report being validated or verified:

Forest, agriculture or other land use

(2) A validation body or verification body cannot be accredited as one referred to in paragraph (1)(i) unless it employs an individual who is an expert in forest or agriculture or other land use, as the case may be, and who is accredited

Biodiversity

(3) A validation body or verification body cannot be accredited as one referred to in paragraph (1)(j) unless it employs an individual who is an expert in biodiversity and who is

Definition of distribution

(4) For the purpose of subsection (1), distribution includes distribution at a fuelling station.

Team leader

126 (1) Each validation or verification must be conducted by a team that includes a team leader who is an employee of the body that conducts the validation or verification.

Independent reviewer

(2) Each validation or verification must be reviewed by an independent reviewer referred to in subsection 124(3) who is an employee of the body that conducts the validation or verification.

Lifecycle assessment reviewer

127 An application referred to in section 116 must be verified by a verification team that includes a lifecycle assessment reviewer who

Chartered Professional Accountant

128 A report submitted under section 107 or 111 must be verified by a verification team that includes a person recognized as a Chartered Professional Accountant in Canada.

Outsourcing

129 A person to which a validation body or verification body outsources a validation or verification must meet the requirements of sections 124 and 125 and, if applicable, sections 127 and 128.

Conflicts of interest

130 (1) Subject to subsection 131(1), the validation or verification body that validates or verifies an application or report, and any individual that performs the validation or verification, must be independent of

Informing Minister of conflict

(2) The person that is making the application or is submitting the report must inform the Minister of whether or not a conflict of interest exists between any individual who performs validation or verification and a person referred to in paragraph (1)(a) or (b) not later than 60 days before the validation or verification body begins the work related to the verification or validation of the application or report.

Discovery of conflict

(3) A person that discovers such a conflict of interest after the day referred to in subsection (2), must inform the Minister of the conflict within five days after its discovery.

Measures taken to manage conflict

(4) The person must, when they inform the Minister of a conflict of interest under subsection (2) or (3), provide the details of the conflict and the measures that will be taken to manage it.

Decision by Minister

131 (1) If a conflict of interest exists, no work can be performed on the validation or verification by that verification body or validation body unless the Minister decides that the measures referred to in subsection 130(4) will effectively manage that conflict.

Decision within 20 days

(2) The Minister must inform the person referred to in section 130 of the Minister’s decision within 20 days after the day on which the Minister is informed of the conflict.

Preceding compliance periods

132 (1) A person that makes an application or submits a report must not have any part of the validation or verification work performed by a validation body or verification body, an individual who is a member of a validation team or verification team of such a body or another person to which validation or verification work is outsourced by such a body if the body, individual or other person has contributed to the validation or verification of an application of that type that they made or report of that type that they submitted for five consecutive compliance periods, unless three compliance periods have elapsed after the most recent compliance period for which they contributed to such a validation or verification.

Applications or reports respecting a facility

(2) A person that makes an application or submits a report in respect of a facility must not have any part of the validation or verification work performed by a validation body or verification body, an individual who is a member of a validation team or verification team of such a body or another person to which validation or verification work is outsourced by such a body if the body, individual or other person has contributed to the validation or verification of an application or report of that type in respect of that facility for five consecutive compliance periods, unless three compliance periods have elapsed after the most recent compliance period for which they contributed to such a validation or verification.

Changing verification body

(3) A person that has a report for a given compliance period verified by a verification body and that does not have it verified by the body for the compliance period that immediately follows the given compliance period must not have the report for the second or third compliance periods that follow the given compliance period verified by that verification body.

Applicable Standards

Standard — validation of application

133 A validation of an application referred to in section 29 or an application made in accordance with subsection 66(1) in respect of a carbon intensity that is determined under subsection 62(1) must be conducted in accordance with ISO Standard 14064-3:2019.

Standards — application for approval

134 (1) A verification of an application made in accordance with subsection 66(1) in respect of a carbon intensity that is determined under any of sections 63 to 65 must be conducted in accordance with ISO Standard 14064-3:2019, at a reasonable level of assurance, and the critical review of the lifecycle assessment must be conducted by a lifecycle assessment expert reviewer in accordance with ISO Standard 14044.

Standard — application for provisional approval

(2) A verification of an application for provisional approval of a carbon intensity referred to in subsection 78(1) must be conducted in accordance with ISO Standard 14064-3:2019, at a reasonable level of assurance, and the critical review of the lifecycle assessment must be conducted by a lifecycle assessment expert reviewer in accordance with ISO Standard 14044.

Standards — verification of reports

(3) A verification of a report submitted under one of sections 103, 104 and 110 must be conducted in accordance with ISO Standard 14064-3:2019, at a reasonable level of assurance.

Standards — verification of pathway report

(4) A verification of a report made in accordance with section 105 must be conducted in accordance with ISO Standard 14064-3:2019, at a reasonable level of assurance, and the critical review of the lifecycle assessment must be conducted by a lifecycle assessment expert reviewer in accordance with ISO Standard 14044.

Verification — reports under sections 107, 109 or 111

(5) A verification of a report made in accordance with section 107, 109 or 111 must be conducted in accordance with ISO Standard 14064-3:2019, at a reasonable assurance level of assurance, and must include an audit at that level of assurance of the financial information it contains that is done in accordance with Canadian auditing standards, the primary source of which is the CPA Canada Handbook – Assurance.

ISO Standard 14064-3:2019 — criteria

135 (1) ISO Standard 14064-3:2019, is to be read with the definition “criteria” in subclause 3.6.10 read

Materiality threshold

(2) For the purpose of subclause 5.1.7 of ISO Standard 14064-3:2019, the materiality thresholds that are required are set out in sections 142 to 145.

Canadian Generally Accepted Accounting Principles

136 An audit referred to in subsection 134(5) must determine whether or not the financial information in the report is in accordance with Canadian Generally Accepted Accounting Principles, which are set out in the Chartered Professional Accountants of Canada Handbook — Accounting.

Method to Follow

Method for validation and verification

137 A validation or verification must be done in accordance with the Method for Validation, Verification and Certification - Clean Fuel Regulations published by the Minister.

Duties of validating body

138 (1) A body that validates an application in accordance with section 133 must

Duties of verification body

(2) A body that verifies an application or report in accordance with section 134 must

Assessment of monitoring plan

(3) A body that validates an application referred to in section 114 or that verifies an application referred to in section 116 or a report referred to in section 117, must perform an assessment of the monitoring plan that satisfies the requirements set out in section 122.

Required evidence-gathering — verification

139 (1) A body that validates or verifies an application or report, as the case may be, must gather information, in particular by

Materiality

(2) For the purpose of subsection (1), an emission or site is material if any misstatement that relates to the emission or site is likely to result in a quantitative material error in the final reported value for that emission or that site.

Site visits

140 (1) In addition to the requirements of ISO Standard 14064-3:2019, the verification body must conduct a site visit at each site that has not been the subject of a site visit during the preceding four compliance periods.

Definition of “site”

(2) ISO Standard 14064-3:2019, is to be read with the definition “site” in subclause 3.6.13 read as

Requirement to identify

141 (1) The body must identify a supporting datum that is required to calculate a value in the application or report as

Quantitative misstatement

(2) Each error, omission or misreporting referred to in subsection (1) is a quantitative misstatement.

Aggregation of quantitative misstatements

(3) A body that validates or verifies an application or report, as the case may be, must aggregate all quantitative misstatements in the application or report to determine the total effect on the information contained in the report or application.

Material quantitative misstatement

142 (1) There is a material quantitative misstatement in a quantitative value that is in an application or report and set out in column 1 of the table to this subsection in a circumstance set out in column 2 to that table if the relative error, percent relative error, absolute error or percent absolute error, as the case may be, meets any of the materiality thresholds set out in column 3.

Table — Material Quantitative Misstatements

Item

Column 1

Application or Report

Column 2

Circumstances

Column 3

Materiality Threshold for Quantitative Error

1

Any report referred to in section 118

All circumstances

  • (i) a percent relative error with respect to the quantity of an eligible feedstock, referred to in the declaration referred to in paragraph 49(2)(a) and calculated under subsection 34(1), that is equal to or greater than 1%,
  • (ii) a percent absolute error with respect to the quantity of an eligible feedstock, referred to in the declaration referred to in paragraph 49(2)(a) and calculated under subsection 34(1), that is equal to or greater than 2%,

2

Application referred to in subsection 66(1) or 78(1)

All circumstances

  • (i) a relative error that is equal to or greater than 1 gCO2e/MJ,
  • (ii) a percent absolute error with respect to carbon intensity that is equal to or greater than 2%.

3

Credit creation report referred to in section 103 or 104

(a) Compliance credits were created by carrying out an emissions reduction or removal project in accordance with sections 28 to 30

  • (i) a percent relative error or a percent absolute error with respect to any quantitative value contained in the report that is greater than the threshold for that value set out in the emissions reduction quantification method referred to in subsection 28(2) for the type of project,
  • (ii) a relative error with respect to the number of compliance credits created that is equal to or greater than one, or a percent relative error with respect to that number that is equal to or greater than 1%;

(b) Compliance credits were created by producing low carbon intensity fuel in Canada in accordance with sections 80 to 83

  • (i) a percent relative error, with respect to a value that is contained in the report and referred to in sections 32 or 34, that is equal to or greater than 1%,
  • (ii) a percent absolute error, with respect to a value that is contained in the report and referred to in sections 32 or 34, that is equal to or greater than 2%,
  • (iii) a relative error with respect to the number of compliance credits created that is equal to or greater than one, or a percent relative error with respect to that number that is equal to or greater than 1%;

(c) Compliance credits were created by importing low carbon intensity fuel in accordance with sections 80 to 83

  • (i) a percent relative error with respect to the volume of liquid low carbon intensity fuel used to generate credits that is equal to or greater than 1%,
  • (ii) a percent absolute error with respect to the volume of liquid low carbon intensity fuel used to generate credits that is equal to or greater than 2%,
  • (iii) a relative error with respect to the number of compliance credits created that is equal to or greater than one, or a percent relative error with respect to that number that is equal to or greater than 1%;

(d) Compliance credits were created by end user fuel switching in accordance with sections 84 to 89

  • (i) a percent relative error with respect to the volume of gaseous low carbon intensity fuel, liquefied petroleum gas, compressed natural gas, liquefied natural gas or hydrogen used to create compliance credits that is equal to or greater than 1%,
  • (ii) a percent absolute error with respect to the volume of gaseous low carbon intensity fuel, liquefied petroleum gas, compressed natural gas, liquefied natural gas or hydrogen used to create compliance credits that is equal to or greater than 2%,
  • (iii) a percent relative error with respect to the quantity of electricity used to create compliance credits that is equal to or greater than 1%,
  • (iv) a percent absolute error with respect to the quantity of electricity used to create compliance credits that is equal to or greater than 2%,
  • (v) a relative error with respect to the number of compliance credits created that is equal to or greater than one, or a percent relative error with respect to that number that is equal to or greater than 1%.

4

Carbon intensity Pathway Report referred to in section 105

All circumstances

  • (i) a relative error that is equal to or greater than 1 gCO2e/MJ,
  • (ii) the percent absolute error with respect to carbon intensity is equal to or greater than 2%.

5

Material balance report referred to in section 106

All circumstances

  • (i) a percent relative error with respect to any quantitative value contained in the report that is equal to or greater than 1%,
  • (ii) a percent absolute error with respect to any quantitative value contained in the report that is equal to or greater than 2%.

6

Compliance credit revenue report referred to in section 107

All circumstances

  • (i) a relative error with respect to the number of compliance credits transferred is equal to or greater than one, or a percent relative error with respect to that number that is equal to or greater than 1%,
  • (ii) the percent relative error with respect to the revenue from the transfer of compliance credits is equal to or greater than 1%,
  • (iii) the percent absolute error with respect to the revenue from the transfer of compliance credits is equal to or greater than 2%,
  • (iv) the percent relative error with respect to the use of the revenue from the transfer of compliance credits referred to in paragraph 89((1)a), (b) or (c) is equal to or greater than 1%,
  • (v) the percent absolute error with respect to the use of the revenue from the transfer of compliance credits referred to in paragraph 89((1)a), (b) or (c) is equal to or greater than 2%.

7

Compliance Report referred to in section 109 or Complementary Compliance Report referred to in section 111

All circumstances

  • (i) the relative error with respect to the number of compliance credits that are created under a given provision and, if applicable, created with respect to a given type of low carbon intensity fuel, and are used to comply with these Regulations is equal to or greater than one, or the percent relative error with respect to that number is equal to or greater than 1%,
  • (ii) the percent relative error with respect to the amount paid to a registered emissions reduction funding program is equal to or greater than 1%,
  • (iii) the percent relative error with respect to the amount of the reduction requirement calculated under section 8 that is deferred to the subsequent compliance period is equal to or greater than 1%,
  • (iv) the absolute error with respect to the number of compliance credits that are created under a given provision and, if applicable, with respect to a given type of low carbon intensity fuel, and are used to comply with these Regulations is equal to or greater than one, or the percent absolute error with respect to that number is equal to or greater than 2%,
  • (v) the percent absolute error with respect to the amount paid to a registered emissions reduction funding program is equal to or greater than 2%,
  • (vi) the percent absolute error with respect to the amount of the reduction requirement calculated under section 8 that is deferred to the subsequent compliance period is equal to or greater than 2%.

8

Fossil fuel production report referred to in section 110

All circumstances

  • (i) a percent relative error with respect to any quantitative value contained in the report results in an overstatement that is equal to or greater than 1%,
  • (ii) a percent absolute error with respect to any quantitative value contained in the report that is equal to or greater than 2%.

Relative error

(2) For the purpose of subsection (1), the relative error is the sum of

Percent relative error

(3) For the purpose of subsection (1), the percent relative error is one hundred percent times the relative error determined in accordance with subsection (2) divided by the absolute corrected value that the data are used to calculate.

Absolute error

(4) For the purpose of subsection (1), the absolute error is the sum of

Percent absolute error

(5) For the purpose of subsection (1), the percent absolute error is one hundred percent times the absolute error determined in accordance with subsection (4) divided by the absolute corrected value that the data are used to calculate.

Definitions

(6) The following definitions apply to this section:

corrected datum
means a datum that, in the opinion of the body that conducts the validation or verification, the person that is making the application or is submitting the report should have used to calculate a value that appears in the application or report. (donnée corrigée)
corrected value
means the value that, in the opinion of the body that conducts the validation or verification, the person that is making an application or is submitting a report would have included in the application or report if that person had performed the required calculations using corrected data. (valeur corrigée)

Data gaps identified by applicant

143 (1) If there are data gaps in the evidence possessed by the person that is making the application or is submitting the report, that person must

Data gaps — obligations of body

(2) The body that validates or verifies the application or report, as the case may be, must

Materiality

(3) For the purpose of subsections (2), a data gap meets the materiality threshold if

Calculation of uncertainty

144 A body that validates or verifies an application or report must determine the uncertainty that is caused by the measurement method used to produce the reported value, calculate the manner in which such uncertainties propagate and indicate the method used to calculate the uncertainty.

Qualitative misstatements — declaration

145 (1) A declaration referred to in paragraph 49(2)(a) contains a material qualitative misstatement in the following circumstances:

Qualitative misstatements — emissions reduction or removal project

(2) An application for the recognition of an emissions reduction or removal project referred to in section 29 contains a material qualitative misstatement in the following circumstances:

Qualitative misstatements — carbon intensity

(3) An application for approval of a carbon intensity referred to in section 66 contains a material qualitative misstatement in the following circumstances:

Qualitative misstatements — credit creation

(4) An annual credit creation report referred to in section 103 or a quarterly credit creation report made in accordance with section 104 contains a material qualitative misstatement in the following circumstances:

Qualitative misstatements — carbon intensity pathway

(5) A carbon intensity pathway report referred to in section 105 contains a material qualitative misstatement in the following circumstances:

Qualitative misstatements — material balance report

(6) A material balance report referred to in section 106 contains a material qualitative misstatement in the following circumstances:

Qualitative misstatements — revenue report

(7) A compliance credits revenue report referred to in section 107 contains a material qualitative misstatement in the following circumstances:

Qualitative misstatements — compliance report

(8) A compliance report referred to in section 109 contains a material qualitative misstatement in the following circumstances:

Qualitative misstatements — fossil fuel production

(9) A fossil fuel production report referred to in section 110 contains a material qualitative misstatement if there is an incorrect identification of the point of origin of a feedstock referred to in the report.

Qualitative misstatements — complementary compliance report

(10) A complementary compliance report referred to in section 111 contains a material qualitative misstatement if the report indicates that compliance credits were created under paragraph 101(1)(b), but does not include the receipt referred to in subsection 101(2).

Opinion

146 The body that validates or verifies an application or a report issues

Disclaimer

147 If the person that makes an application or submits a report does not provide the information required by these Regulations to the body that is validating or verifying it the body that is validating or verifying it must issue a disclaimer that states that an opinion cannot be provided, and the reasons for which it cannot be provided.

Signature of opinion or disclaimer

148 (1) The opinion or disclaimer must be signed by the individual who acted as team leader under subsection 126(1) for the verification or validation and the individual who acted as independent reviewer under subsection 126(2).

Chartered Professional Accountant

(2) An opinion or disclaimer that relates to a report submitted under section 107 or 111 must also be signed by the Chartered Professional Accountant who participated in the verification.

Correction of Errors

Excess credits

149 (1) A registered creator must, not more than five days after they learn of an error that was made in a report made in accordance with subsection 103(1) or 104(1) and that resulted in the deposit of excess credits into an account opened under section 26, send a written notice of that error to the Minister that includes

Exported fuels

(2) For greater certainty, credits that were created by importing or producing fuel for use in Canada were created in error if that fuel is ever exported, even if it had not been exported when the compliance credits were created.

Cancellation of excess credits

(3) Upon receipt of the written notice, the Minister must cancel any of the excess credits that remain in the registered creator’s account.

Balancing excess credits

150 If any of the excess compliance credits referred to in subsection 149(1) cannot be cancelled because they are no longer in the account into which they were deposited, the registered creator must, not more than 90 days after they send the written notice in accordance with subsection 149(1), balance the number of excess compliance credits that were not cancelled by the same number of equivalent credits.

Notice of creation or transfer

151 (1) A registered creator must, after their account contains the equivalent compliance credits required under section 150 and before the expiry of the period referred to in that section, send a written notice to the Minister that their account contains those equivalent compliance credits.

Cancellation of equivalent credits

(2) Upon receipt of the written notice, the Minister must cancel the equivalent compliance credits.

Suspension of credits

152 (1) The Minister may suspend compliance credits that have been deposited in a registered creator’s account that was opened under subsection 26 if the Minister has reason to believe that a report submitted in accordance with subsection 103(1) or 104(1) contains an error that resulted in the deposit of excess compliance credits in that account.

Suspension of equivalent credits

(2) If a number of the compliance credits referred to in subsection (1) are no longer in the account into which they were deposited, the Minister may suspend that number of equivalent compliance credits that are in the account or that are deposited while the Minister still has reason to believe the error referred to in subsection (1) exists.

Notice of suspension

(3) When the Minister suspends compliance credits in accordance with subsection (1) and the first time the Minister suspends compliance credits in accordance with subsection (2) with respect to a suspected error, the Minister must send a written notice to the registered creator that includes

No use or transfer in trade

(4) From the time the notice referred to in subsection (3) is sent until the suspension is lifted, the suspended compliance credits cannot be used to comply with subsection 4(1) and cannot be transferred in trade.

Lifting of suspension

153 (1) If an additional review by the Minister confirms that the report referred to in subsection 152(1) does not contain an error that resulted in the deposit of excess compliance credits, the Minister must lift the suspension of the compliance credits.

Cancellation of excess credits

(2) If an additional review by the Minister confirms that the report referred to in subsection 152(1) contains an error that resulted in the deposit of a number of excess compliance credits, the Minister must cancel that number of equivalent credits.

Insufficient number of equivalent credits

154 (1) If the number of equivalent compliance credits that must be cancelled under subsection 77(2) or 153(2) is greater than the number of equivalent compliance credits in the account, the Minister must send a written notice to the registered creator that indicates the amount of the shortfall.

Obligation to replace credits

(2) The registered creator must, not more than 90 days after the written notice is sent, balance the number of excess compliance credits that were not cancelled by the same number of equivalent credits in the same account.

Notice of creation or transfer

155 (1) A registered creator must, after their account contains the equivalent compliance credits required under subsection 154(2) and before the expiry of the period referred to in that subsection, send a written notice to the Minister that their account contains those equivalent compliance credits.

Cancellation of credits

(2) Upon receipt of the written notice, the Minister must cancel the equivalent compliance credits.

Equivalent compliance credits

156 For the purpose of subsection 77(2) and sections 150 to 155, a compliance credit is equivalent to an excess compliance credit if

Measurement, Samples, Reporting Format and Records

Measurement of Volumes

Requirements

157 (1) Subject to subsections (2) and (3), any volume that a person is required to record under these Regulations must be determined

Non-application of subsection (1)

(2) If there is no measurement device, standard or method referred to in subsection (1) that would allow the person to determine the volume in accordance with that subsection, that person must record the volume as accurately determined by another person that is independent of them. They must record the following information obtained from the other person:

Volumetric correction

(3) A volume referred to in subsection (1) must be corrected to a temperature of 15.6°C and 1 atmosphere of pressure. However, a person that imports an amount of fuel may correct the volume of the amount to 60°F, if the person records that they made the correction.

Cubic metres

(4) A volume that is to be recorded or reported must be in cubic metres.

Rounding

(5) Unless otherwise specified, a person that submits a report must round all values in accordance with section 6 of the ASTM International method ASTM E 29-93a, entitled Standard Practice for Using Significant Digits in Test Data to Determine Conformance with Specifications.

Electronic Reporting — Default

Electronic report or notice

158 (1) A report or notice that is required under these Regulations must be sent electronically in the form and format specified by the Minister and must bear the electronic signature of an authorized official.

Paper report or notice

(2) If the Minister has not specified an electronic form and format or if it is impractical to send the report or notice electronically in accordance with subsection (1) because of circumstances beyond the person’s control, the report or notice must be sent on paper, signed by an authorized official, and in the form and format specified by the Minister. However, if no form and format has been so specified, it may be in any form and format.

Record-making and Retention of Information

When records are made

159 Except as otherwise provided in these Regulations, records must be made no later than 30 days after the information to be recorded becomes available.

Retention of records

160 (1) A person that is required under these Regulations to record information or keep information up-to-date or send a report or notice must keep the record or a copy of the report or notice, as well as any supporting documents that relate to the information contained in that record or copy, for ten years after they make or update the record or send the report or notice.

Validation and verification

(2) A validation body or verification body must, in accordance with the Method for Validation, Verification and Certification - Clean Fuel Regulations published by the Minister, keep the books and records they have validated, verified or certified, or a copy of those books and records, for ten years after the validation, or verification is performed.

Projects

(3) In addition, a record or copy of a report or notice that relates to a project referred to in paragraph 18(1)(a) or 19(a) or section 20, and supporting documents that relate to the information contained in that record or copy, must be kept for ten years after the project ceases to create compliance credits.

Record location

(4) A record, copy or supporting document referred to in subsection (1) or (3) that is kept by a primary supplier or registered creator must be kept at the primary supplier or registered creator’s principal place of business in Canada or at any other place in Canada where it can be inspected. If the record or copy is kept at one of those other places, the primary supplier or registered creator must provide the Minister with the civic address of the place it is kept.

Record accessible

(5) In addition to the circumstances set out in section 72, an approved carbon intensity of a low carbon intensity fuel produced by a foreign supplier ceases to be valid unless

Copy of records

161 A person that is required to record information under these Regulations must, on request, provide a copy of the record to the Minister.

Amendments

162 The definitions distillate compliance period and gasoline compliance period in subsection 1(1) of the Renewable Fuels Regulationsfootnote 131 are replaced by the following:

distillate compliance period
means
  • (a) the period that begins on July 1, 2011 and that ends on December 31, 2012;
  • (b) the period that begins on January 1, 2013 and that ends on December 31, 2014; and
  • (c) after December 31, 2014, each calendar year until December 31, 2022. (période de conformité visant le distillat)
gasoline compliance period
means
  • (a) the period that begins on December 15, 2010 and that ends on December 31, 2012; and
  • (b) after 2012, each calendar year until December 31, 2022. (période de conformité visant l’essence)

163 Schedule 1 to the Environmental Violations Administrative Monetary Penalties Regulationsfootnote 132 is amended by adding the following after division 17 of part 5:

DIVISION 18

Clean Fuel Regulations

Item

Column 1

Provision

Column 2

Violation Type

1 9(1) A
2 9(2) A
3 9(3) A
4 13(4) B
5 15(3) A
6 16(2) B
7 16(4) B
8 17(2) B
9 17(4) B
10 24(2) A
11 25(1) A
12 25(2) A
13 25(3) A
14 31(3) B
15 39(1) A
16 39(2) A
17 39(3) A
18 39(4) A
19 40(1) A
20 40(2) A
21 46(1) A
22 47(1) A
23 47(2) A
24 48 A
25 53 B
26 67(3) B
27 73(1) B
28 73(3) A
29 74(1) B
30 74(2) B
31 74(3) B
32 79(3) A
33 80(2) A
34 84(2) A
35 85(1) B
36 86(1) B
37 87(1) B
38 87(2) B
39 88(2) B
40 90(1) B
41 90(2) B
42 91(1) A
43 91(2) B
44 92(1) B
45 92(2) B
46 93(1) B
47 93(2) B
48 94(1) B
49 94(2) B
50 150(1) A
51 150(2) A
52 150(3) A

Repeals

Renewable Fuels Regulations

164 The Renewable Fuels Regulationsfootnote 131 are repealed.

Environmental Violations Administrative Monetary Penalties Regulations

165 Division 14 of part 5 of Schedule 1 to the Environmental Violations Administrative Monetary Penalties Regulationsfootnote 132 is repealed.

Transitional Provisions

Gasoline compliance units

166 (1) If, on November 30, 2023, a primary supplier owns gasoline compliance units under the Renewable Fuels Regulations, the number of compliance credits that is determined by the following formula is deposited in their account opened under paragraph 26(a):

CIdiff × (GCU × D) × 10-9
where
CIdiff
is the reference carbon intensity of the liquid class referred to in item 1 of Schedule 1, less 59 g/MJ;
GCU
is the number of gasoline compliance units that the primary supplier owned at the end of the trading period set out in those Regulations for the 2022 compliance period; and
D
is 23,419 MJ/m3.

Volumetric requirement

(2) For the purpose of subsection 10(4), each credit is deemed to be created under paragraph 18(1)(b) or (c) by producing or importing an equivalent volume of low carbon intensity fuel whose fuel type is ethanol.

Distillate compliance units

167 (1) If, on November 30, 2023, a primary supplier owns distillate compliance units under the Renewable Fuels Regulations, the number of compliance credits that is determined by the following formula is deposited in their account opened under paragraph 26(a):

CIdiff × (DCU × D) × 10-9
where
CIdiff
is the reference carbon intensity of the liquid class referred to in item 1 of Schedule 1, less 35 g/MJ;
DCU
is the number of distillate compliance units that the primary supplier owned at the end of the trading period set out in those Regulations for the 2022 compliance period; and
D
is 35,057 MJ/m3.

Volumetric requirement

(2) For the purpose of subsection 10(4), each credit is deemed to be created under paragraph 18(1)(b) or (c) by producing or importing an equivalent volume of low carbon intensity fuel whose fuel type is biodiesel or hydrogenation-derived renewable diesel.

Request for credits

168 In order to obtain compliance credits in accordance with section 166 or 167, a primary supplier must provide to the Minister a form that is signed by their authorized official and contains the following information:

Records related to compliance units

169 (1) A primary supplier that, on December 31, 2022, is required under section 38 of the Renewable Fuels Regulations to keep a record, a copy of a report or notice or a supporting document that is related to a gasoline compliance unit referred to in subsection 166(1) or a distillate compliance credit referred to in subsection 167(2) is required to keep those documents until March 31, 2033.

Other records

(2) A primary supplier that, on December 31, 2023, is required under that section to keep any other record or copy of a report or notice must keep that record or copy, as well as any supporting documents that relate to the information contained in it, for at least five years after they make the record or send the report or notice.

Location of records

(3) A record, a copy of a report or notice or a supporting document referred to in subsections (1) or (2) must be kept in accordance with subsection 160(4).

Coming into Force

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

January 1, 2023
(2) Sections 35 to 47 and 49 to 51 come into force on January 1, 2023.

January 1, 2024
(3) Sections 164 and 165 come into force on January 1, 2024.

SCHEDULE 1

(Subsections 1(1), 80(2), 81(4), 84(2), 85(3) and (4), 86(3), 87(2), 88(2), 166(1) and 167(1) )

Reference Carbon Intensity

Table — Reference Carbon Intensity

Item

Column 1

Fuel

Column 2

Reference Carbon Intensity, in gCO2e/MJ

2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
and after
1 Fuels in the liquid class 91.8 91.8 90.7 89.5 88.4 87.2 86.0 84.9 83.7 82.5
2 Biogas, renewable natural gas and hydrogen 61.8 61.8 61.8 61.8 61.8 61.8 61.8 61.8 61.8 61.8
3 Renewable propane 74.8 74.8 74.8 74.8 74.8 74.8 74.8 74.8 74.8 74.8

SCHEDULE 2

(Section 8 and subsections 80(2), 81(3) and (4), 82(2), 84(2), 85(3) and (4), 86(3),and 88(2))

Energy Density of Fuels

Item

Column 1

Fuel or Energy Source

Column 2

Energy Density

Column 3

Measurement Unit

1 Biogas 19.9 MJ/m3
2 Renewable Natural Gas 38 MJ/m3
3 Natural Gas 39.03 MJ/m3
4 Compressed Natural Gas 39.03 MJ/m3
5 Hydrogen 141.9 MJ/kg
6 Ethanol 23,419 MJ/m3
7 Liquefied Natural Gas 24,003 MJ/m3
8 Renewable Propane 25,310 MJ/m3
9 Liquefied Petroleum Gas 26,410 MJ/m3
10 Gasoline 33,452 MJ/m3
11 Hydrogenation-derived renewable diesel 34,921 MJ/m3
12 Biodiesel 35,183 MJ/m3
13 Biojet 37,400 MJ/m3
14 Jet fuel 37,400 MJ/m3
15 Kerosene 37,680 MJ/m3
16 Diesel fuel 38,352 MJ/m3
17 Light Fuel Oil 38,800 MJ/m3
18 Heavy Fuel Oil 42 500 MJ/m3
19 Petroleum coke 43,460 MJ/kg

SCHEDULE 3

(Section 9, subsection 24(2) and section 25)

Registration Report — Information Required from a Primary Supplier or a Registered Creator

1 The following information with respect to the primary supplier or registered creator, as the case may be:

2 The following information with respect to each facility at which the primary supplier produces fuel in the liquid class:

3 The name of each province into which the primary supplier imports fuel in the liquid class from outside Canada.

4 Which of the following methods, if any, the primary supplier or creator intends to use to create compliance credits:

5 If an emissions reduction or removal project referred to in any of paragraphs 4(a) to (c) will be carried out at a facility, the following information with respect to the facility:

6 If an emissions reduction or removal project referred to in any of paragraphs 4(a) to (c) will be carried out at a location other than a facility, the following information with respect to the equipment that will be used:

7 In the case of the production of a low carbon intensity fuel referred to in paragraph 4(d), the following information with respect to each facility at which the low carbon intensity fuel is produced:

8 In the case of the importing of a low carbon intensity fuel referred to in paragraph 4(e)

9 In the case of a displacement of fuel in the liquid class that is referred to in paragraph 4(h) or (i), as the case may be, and is the subject of an agreement referred to in section 21 of the Regulations, the following information with respect to the fuelling station or charging station at which the fuel, electricity or hydrogen that displaces the fuel in the liquid class was supplied:

10 In the case of the use of biogas to produce to electricity referred to in paragraph 4(j), the following information with respect to each facility where the electricity is produced:

SCHEDULE 4

(Paragraph 29(2)(a))

Application for Recognition of CO2e Emissions Reduction or Removal Project — Required Information

1 The following information with respect to the applicant:

2 A description of the project including

SCHEDULE 5

(Section 62 and paragraph 82(4)(a))

Default Carbon Intensity

1 The quantity of CO2e per megajoule that is associated with the extraction or cultivation, as the case may be, of a feedstock is

2 The quantity of CO2e per megajoule that represents the amount of CO2e that is released during the production of the fuel or hydrogen from the feedstock, the transportation of the feedstock and intermediary products used to produce the fuel or hydrogen, and the distribution of the fuel or hydrogen to end users is

3 The quantity of CO2e per megajoule that represents the quantity of CO2e that is released during the compression or liquefaction process of the fuel or hydrogen is

4 The quantity of CO2e per megajoule that represents the additional quantity of CO2e that is associated with the production of electricity used during the production of the fuel,or hydrogen is

5 The quantity of CO2e per megajoule that represents the additional quantity of CO2e that is released during the transportation of the given feedstock and intermediary products used to produce the type of fuel or hydrogen, and the distribution of the fuel or hydrogen to end users, in the case of a total transportation distance not less than 1500 km, is

6 The quantity of CO2e per megajoule that represents the quantity ofCO2e that is released during the combustion of the fuel or the use of hydrogen as an energy source, per megajoule of energy produced is

7 The carbon intensity of fossil fuels and energy sources is equal to

8 The carbon intensity of electricity in a province in which a charging station is located is

SCHEDULE 6

(Sections 68, 69 and 70)

Application for Approval of Carbon Intensity

1 The following information, if the application relates to a low carbon intensity fuel:

2 In the case of a carbon intensity that is determined in accordance with subsection 62(1) of the Regulations, the following information:

3 In the case of a carbon intensity that is determined in accordance with section 63 of the Regulations, the following information:

4 In the case of a carbon intensity that is determined in accordance with section 64 of the Regulations, the following information:

5 In the case of a carbon intensity that is determined in accordance with section 65 of the Regulations, the following information:

SCHEDULE 7

(Subsection 96(1))

Application for Registration of an Emissions Reduction Funding Program — Required Information

1 The following information with respect to the person that administers the emissions reduction funding program

2 The following information with respect to the emissions reduction funding program:

SCHEDULE 8

(Paragraphs 103(1)(a), 104(2)(a), 149(1)(b) and 152(3)(b))

Credit Creation Report — Information Provided by Registered Creator

1 The name of the registered creator.

2 The following information with respect to each CO2e emissions reduction or removal project carried out:

3 The following information with respect to each liquid or gaseous low carbon intensity fuel that is produced in Canada during the period referred to in the report, has a carbon intensity for which a unique alphanumeric identifier has been assigned and will result in the depositing of compliance credits in the account of the person that created them as provisional compliance credits:

4 The following information with respect to each liquid or gaseous low carbon intensity fuel that has a carbon intensity with a given alphanumeric identifier that is imported during the period referred to in the report and that will result in the depositing of compliance credits in the account of the person who created them as provisional compliance credits:

7 If applicable, the quantity of each low carbon intensity fuel that is referred to in item 3 and for which the associated credits are to be transferred to each other participant in accordance with subsection 92(2) of the Regulations, expressed in cubic metres, the number of compliance credits created by the production or importing of that quantity, the alphanumeric identifier for the approved carbon intensity of the low carbon intensity fuel and the name of each participant to which the compliance credits are to be transferred.

8 The following information with respect to liquefied petroleum gas, compressed natural gas or liquefied natural gas for which provisional compliance credits were created as a result of end user fuel switching in accordance with subsection 84(2) of the Regulations by the owner or operator of the fuelling station during the period referred to in the report:

9 The following information with respect to renewable liquefied petroleum gas, renewable compressed natural gas, renewable liquefied natural gas, compressed hydrogen or liquefied hydrogen for which provisional credits were created as a result of end user fuel switching in accordance with subsection 85(3) of the Regulations by the owner or operator of the fuelling station during the period referred to in the report:

10 The following information with respect to each quantity of renewable propane, renewable natural gas or hydrogen for which provisional compliance credits were created as a result of end user fuel switching: in accordance with subsection 86(1) of the Regulations by the producer or importer of the fuel during the period referred to in the report:

11 The following information from a registered creator that is a charging network operator with respect to electricity for which provisional compliance credits were created by supplying it to an electric vehicle in accordance with subsection 87(2) of the Regulations:

12 The following information from a registered creator that is a charging site host with respect to electricity for which provisional compliance credits were created by supplying it to an electric vehicle in accordance with subsection 87(2) of the Regulations:

13 The following information with respect to each hydrogen fuelling station at which provisional compliance credits were created by supplying hydrogen as an energy source for hydrogen fuel cell vehicles in accordance with section 88 of the Regulations by the owner or operator of the hydrogen fuelling station, referred to in subsection 88(1) of the Regulations:

14 The following information with respect to each quantity of electricity that is produced using biogas for which provisional compliance credits were created in accordance with subsection 82(3) of the Regulations during the period referred to in the report:

SCHEDULE 9

(subsection 105(2))

Carbon Intensity Pathway Report — Required Information

1 In the case of a fuel with an approved carbon intensity that is determined in accordance with section 62 or 63 of the Regulations

2 In the case of a carbon intensity that is determined in accordance with section 64 of the Regulations

3 In the case of a carbon intensity that is determined in accordance with section 65 of the Regulations

SCHEDULE 10

(Subsection 106(2))

Material Balance Report for Foreign Supplier

1 The following information with respect to the foreign supplier:

2 An indication of whether the feedstock used to produce the low carbon intensity fuel is referred to in paragraph 33(1)(a), (b) or (c) of the Regulations.

3 The type of feedstock used to produce the fuel.

4 The unique alphanumeric identifier assigned to the carbon intensity of the fuel under subsection 71(2) of the Regulations.

5 The total volume of the low carbon intensity fuel that was produced outside Canada using feedstock referred to in subsection 33(1) of the Regulations and imported for the purpose of creating compliance credits.

6 For each importer to which the foreign supplier provided a quantity of the low carbon intensity fuel

7 The total volume of low carbon intensity fuel referred to in subsection 32(1) of the Regulations with the same unique alphanumeric identifier that was produced at each of the foreign supplier’s facilities, measured in cubic metres.

8 The quantity of the eligible feedstock referred to in subsection 32(1) of the Regulations that was used at each of those facilities to produce that low carbon intensity fuel during the compliance period measured in kilograms for solid feedstock and in cubic metres for liquid or gaseous feedstock.

9 The quantity of the feedstock, other than the quantity of an eligible feedstock referred to in subsection 32(1) of the Regulations, that was used at each of those facilities to produce that low carbon intensity fuel during the compliance period measured in kilograms for solid feedstock and in cubic metres for liquid or gaseous feedstock.

10 The quantity of the eligible feedstock of the type that was used to produce that low carbon intensity fuel that was in each of those facilities at the start of each period set out in subsection 32(2) of the Regulations, measured in kilograms for solid feedstock and cubic metres for gaseous or liquid feedstock.

11 The quantity of the eligible feedstock of the type used to produce that low carbon intensity fuel that was harvested at or brought to each of those facilities during each period set out in subsection 32(2) of the Regulations, measured in kilograms for solid feedstock and cubic metres for gaseous or liquid feedstock.

12 A description, with a list of supporting documents, of the methodology referred to in paragraph 49(2)(d) of the Regulations.

13 For each of those facilities, the ratio of the quantity of the eligible feedstock used at the facility to produce that low carbon intensity fuel and the volume of that low carbon intensity fuel that is produced during each period set out in subsection 32(2) of the Regulations.

SCHEDULE 11

(Subsection 107(2))

Compliance Credit Revenue Report

1 The following information with respect to the registered creator:

2 The number of compliance credits the registered creator transferred during the compliance period referred to in paragraph 107(1)(a) of the Regulations.

3 The total revenue from the transfer of the compliance credits described in item 2.

4 The amount that the registered creator spent during each of the compliance periods referred to in paragraph 107(1)(b) of the Regulations

5 A description of each activity that the registered creator carried out that is referred to in item 4.

6 The amount of revenue from the transferring of compliance credits during the given compliance period referred to in paragraph 107(1)(b) of the Regulations that must be used in accordance with subsection 89(1) of the Regulations, and that have not yet been used.

7 If applicable, the amount of revenue that remains from the transferring of compliance credits in each previous compliance period.

SCHEDULE 12

(Subsection 108(2))

Compliance Credit Balance Report — Required Information from the Registered Creator

1 The name of the registered creator.

2 The number of compliance credits in each of their accounts opened under section 26 of the Regulations that they created as provisional compliance credits during the compliance period.

3 The number of compliance credits that were transferred from each of their accounts in accordance with subsection 90(4) of the Regulations during the compliance period.

4 The number of credits that were transferred from each of their accounts in accordance with subsection 92(2) of the Regulations during the compliance period.

5 For each of their accounts opened under section 26 of the Regulations, the number of compliance credits that were created as provisional compliance credits during the given compliance period or any preceding compliance period and were in the account on the June 30 that followed the end of the given compliance period.

6 The number of compliance credits referred to in item 5 that the registered creator pledges to offer to transfer through the compliance credit clearance mechanism in accordance with subsection 93(1) of the Regulations.

7 Of the compliance credits referred to in item 5, the number that were created under paragraph 18(1)(b) or (c) of the Regulations.

8 The number of compliance credits that were transferred during the compliance period preceding the current compliance period from their account opened under paragraph 26(a) of the Regulations in accordance with subsection 95(1) of the Regulations.

SCHEDULE 13

(subsection 109(2))

Compliance Report — Required Information from the Primary Supplier

1 The name of the primary supplier.

2 The following information with respect to each type of liquid fuel that is described in paragraph 7(1)(a) or (b) of the Regulations:

3 If the primary supplier made a contribution to a registered emissions reduction funding program in accordance with paragraph 101(1)(a) of the Regulations

4 The following information with respect to the compliance credits that the primary supplier will use to satisfy the reduction requirement in respect of each pool of a type of fuel in the liquid class in accordance with subsection 10(1) of the Regulations:

5 If the primary supplier, in accordance with subsection 15(1) of the Regulations, deferred satisfaction of a reduction requirement in respect of a pool of a type of fuel in the liquid class for the compliance period that immediately precedes the compliance period to which the report relates

6 If the primary supplier, in accordance with subsection 15(1) of the Regulations, deferred satisfaction of a reduction requirement in respect of a pool of a type of fuel in the liquid class for the compliance period that began two years before the day on which the compliance period to which the report relates began

7 The number of compliance credits that will remain in each of the primary supplier’s accounts after they have used credits in accordance with subsections 10(1), 16(2) and 17(2) of the Regulations.

8 If the primary supplier requires additional compliance credits to satisfy the reduction requirement calculated under section 8 of the Regulations, whether the primary supplier is willing to have their name shared with other participants in the compliance credit clearance mechanism.

9 The number of compliance credits referred to in item 7 that the primary supplier pledges to offer to transfer through the compliance credit clearance mechanism in accordance with subsection 93(1) of the Regulations.

10 The quantity of each fuel referred to in paragraph 3(2)(a) to (d) of the Regulations that the primary supplier imported and subtracted from their pool of fuel in the liquid class, expressed in cubic metres.

SCHEDULE 14

(Subsection 110(2))

Fossil Fuel Production Report — Information Required

1 The following information with respect to the primary supplier:

2 The name, either civic address or GPS coordinates and mailing address of the production facility.

3 Which of the following fuels is produced at the production facility during the compliance period:

4 For each fuel produced at the production facility during the compliance period

5 The amount of each of the following that was directly emitted into the atmosphere by the production facility during the compliance period:

6 The amount of each of the following that was produced by the production facility and sequestered or sold during the compliance period:

7 The type and quantity of thermal energy consumed by the production facility per calendar day of the compliance period, expressed in cubic metres at standard conditions or kilograms, as the case may be.

8 With respect to each source of electricity, the name of the source and the following information for the compliance period:

9 With respect to hydrogen, the following information for the compliance period:

10 With respect to steam, the following information for the compliance period:

11 With respect to still gas, the following information for the compliance period:

12 In the case of a production facility that is a refinery, the utilized capacity during the compliance period of each process unit set out in column 1 of the following table that is at the refinery, on the basis set out in column 2 and expressed using the unit set out in column 3:

Table — Utilized Capacity of Production Facilities

Item

Column 1

Process Unit

Column 2

Capacity Basis

Column 3

Unit

1 Atmospheric crude distillation feed barrels per calendar day
2 Vacuum distillation feed barrels per calendar day
3 Visbreaker feed barrels per calendar day
4 Delayed coker feed barrels per calendar day
5 Fluid coker feed barrels per calendar day
6 FlexicokerTM feed barrels per calendar day
7 Fluid catalytic cracking feed barrels per calendar day
8 Mild residual fluid catalytic cracking feed barrels per calendar day
9 Residual fluid catalytic cracking feed barrels per calendar day
10 Other fluid catalytic cracking feed barrels per calendar day
11 Thermal cracking feed barrels per calendar day
12 Naphtha/Distillate hydrocracker feed barrels per calendar day
13 Residual hydrocracker (H-Oil; LC-FiningTM and Hycon) feed barrels per calendar day
14 Gasoline/Naphtha desulphurization and hydrotreater feed barrels per calendar day
15 Kerosene desulphurization and hydrotreater feed barrels per calendar day
16 Distillate desulphurization and hydrotreater feed barrels per calendar day
17 Residual desulphurization and hydrotreater feed barrels per calendar day
18 Vacuum gas oil hydrotreater feed barrels per calendar day
19 Reformer - including AROMAX® feed barrels per calendar day
20 Solvent deasphalter feed barrels per calendar day
21 C4 isomer production feed barrels per calendar day
22 C5/C6Isomer production, including ISOSIV feed barrels per calendar day
23 Aromatics Production (All) feed barrels per calendar day
24 Hydrodealkylation feed barrels per calendar day
25 Toluene disproportionation/ transalkylation feed barrels per calendar day
26 Xylene Isomerization feed barrels per calendar day
27 Solvent extraction for lubricants feed barrels per calendar day
28 Solvent dewaxing for lubricants feed barrels per calendar day
29 Catalytic dewaxing for lubricants feed barrels per calendar day
30 Lube hydrocracking feed barrels per calendar day
31 Lube hydrofinishing feed barrels per calendar day
32 Wax deoiling for lubricants feed barrels per calendar day
33 Wax hydrofinishing for lubricants feed barrels per calendar day
34 Special fractionation feed barrels per calendar day
35 Propane/propylene splitter feed barrels per calendar day
36 Cryogenic liquefied petroleum gas recovery feed thousand cubic feet per calendar day on a dry basis, at 15 °C and 1 atmosphere of pressure
37 Flare gas recovery feed thousand cubic feet per calendar day on a dry basis, at 15 °C and 1 atmosphere of pressure
38 Flue gas desulphurizing feed thousand cubic feet per calendar day on a dry basis, at 15 °C and 1 atmosphere of pressure
39 Alkylation / poly / dimersol product barrels per calendar day
40 Sulphuric acid regeneration product short tons per calendar day
41 Coke calciner product short tons per calendar day
42 Hydrogen generation by steam-methane reforming product thousand cubic feet per calendar day on a dry basis, at 15 °C and 1 atmosphere of pressure
43 Hydrogen generation by steam-naphtha reforming product thousand cubic feet per calendar day on a dry basis, at 15 °C and 1 atmosphere of pressure
44 Hydrogen generation by partial oxidation product thousand cubic feet per calendar day on a dry basis, at 15 °C and 1 atmosphere of pressure
45 Sulphur recovery unit (including tailgas) product long tons per calendar day
46 Cyclohexane production product barrels per calendar day
47 Paraxylene production product barrels per calendar day
48 Ethylbenzene production product barrels per calendar day
49 Cumene production product barrels per calendar day
50 Asphalt production product barrels per calendar day
51 Oxygenates product barrels per calendar day
52 Partial oxidation unit that produces synthetic gas for use as fuel product thousand cubic feet per calendar day on a dry basis, at 15 °C and 1 atmosphere of pressure
53 Methanol synthesis product barrels per calendar day
54 CO2 liquefaction product short tons per calendar day
55 Ammonia recovery unit product short tons per calendar day
56 Desalination product thousand gallons per calendar day
57 Fuel gas sales treating and compression power horsepower

13 If applicable, the coke on catalyst consumption during the compliance period of each of the following catalytic cracking process units at a production facility that is a refinery, expressed as a percentage of the volume of fresh feed:

14 In the case of a production facility that is a refinery, the total amount — of crude oil and condensate, crude diluents and feedstock that are processed in any process unit that is not set out in column 1 of the table to item 12, blend stock that is blended into refinery products and additives to the finished product — that is used during the compliance period as input in a refinery, expressed in barrels per calendar day.

15 In the case of a production facility that is a refinery, the total amount of each feedstock that is processed during the compliance period in any process unit set out in column 1 of the table to item 12, other than crude oil and returns from a lube refinery or chemical plant that is within a refining/petrochemical complex, and non-processed blend stock, expressed in barrels per calendar day.

16 For each type of crude that is processed at a production facility that is a refinery during the compliance period

17 In the case of a production facility that is an upgrader, the utilized capacity during the compliance period, of each process unit set out in column 1 of the following table that is at the refinery, on the basis set out in column 2 and expressed using the unit set out in column 3:

Table — Utilized Capacity of Process Units

Item

Column 1

Process Unit

Column 2

Capacity Basis

Column 3

Unit

1 Bitumen upgrader atmospheric distillation feed barrels per calendar day
2 Bitumen upgrader vacuum distillation feed barrels per calendar day
3 Delayed coker feed barrels per calendar day
4 Fluid coker feed barrels per calendar day
5 FlexicokerTM feed barrels per calendar day
6 Naphtha/Distillate hydrocracker feed barrels per calendar day
7 Residual hydrocracker (H-Oil; LC-FiningTM and Hycon) feed barrels per calendar day
8 Gasoline/Naphtha hydrotreater feed barrels per calendar day
9 Kerosene desulphurization and hydrotreater feed barrels per calendar day
10 Distillate desulphurization and hydrotreater feed barrels per calendar day
11 Residual desulphurization and hydrotreater feed barrels per calendar day
12 Selective hydrotreater feed barrels per calendar day
13 Special fractionation feed barrels per calendar day
14 Flare gas recovery feed thousand cubic feet per calendar day, at 15 °C and 1 atmosphere of pressure
15 Flue gas desulphurizing feed thousand cubic feet per calendar day, at 15 °C and 1 atmosphere of pressure
16 Fuels solvent deasphalter feed barrels per calendar day
17 Hydrogen generation by steam-methane reforming product thousand cubic feet per calendar day, at 15 °C and 1 atmosphere of pressure
18 Hydrogen Generation by steam-naphtha reforming product thousand cubic feet per calendar day, at 15 °C and 1 atmosphere of pressure
19 Hydrogen generation by oxidation product thousand cubic feet per calendar day, at 15 °C and 1 atmosphere of pressure
20 Sulphur recovery unit (including tail gas) product long tons per calendar day
21 Partial oxidation unit that produces synthetic gas for use as fuel product thousand cubic feet per calendar day, at 15 °C and 1 atmosphere of pressure
22 CO2 liquefaction product short tons per calendar day
23 Ammonia recovery unit product short tons per calendar day

18 With respect to synthetic gas that is produced during the compliance period at a production facility that is an upgrader

19 In the case of a production facility that is an upgrader, the amount of heat other than steam, that is transferred during the compliance period from the production facility to another location, expressed in thousands of British thermal units per calendar day.

20 In the case of a production facility that is an upgrader, the sum, excluding material that it is purchased solely for use as a fuel within the upgrader or sold or transferred outside of the upgrader without processing or blending within the upgrader, of

21 In the case of a production facility that is an upgrader, the sum, excluding material that it is purchased solely for use as a fuel within the upgrader or sold or transferred outside of the upgrader without processing or blending within the upgrader, of

SCHEDULE 15

(subsection 111(2))

Complementary Compliance Report — Information Required from a Primary Supplier

1 The name of the primary supplier.

2 The amount of the reduction requirement, if any, that the primary supplier had not satisfied in respect of each type of fuel in the liquid class on the June 30 that follows the compliance period, expressed in tCO2e.

3 The number of compliance credits that were transferred to the primary supplier through the credit clearance mechanism in accordance with section 95 of the Regulations.

4 The number of compliance credits referred to in item 3 that were created with respect to biodiesel or hydrogenation-derived renewable diesel and, for each compliance credit, the alphanumeric identifier for the approved carbon intensity of the biodiesel or hydrogenation-derived renewable diesel and the year it was created as a provisional compliance credit.

5 The number of compliance credits referred to in item 3 that were created with respect to a low carbon intensity fuel other than biodiesel and hydrogenation-derived renewable diesel and, for each credit, the alphanumeric identifier for the approved carbon intensity of the low carbon intensity fuel and the year it was created as a provisional compliance credit.

6 If the primary supplier made a contribution to a registered emissions reduction funding program in accordance with paragraph 101(1)(b) of the Regulations

7 If the primary supplier will defer satisfaction of the reduction requirement with respect to one or more types of fuel in the liquid class for the compliance period in accordance with subsection 15(1) of the Regulations, the amount of that deferral.

8 If the primary supplier, in accordance with subsection 15(1) of the Regulations, deferred satisfaction of a reduction requirement in respect of a type of fuel in the liquid class for the compliance period that immediately precedes the compliance period to which the report relates

9 If the primary supplier, in accordance with subsection 15(1) of the Regulations, deferred satisfaction of a reduction requirement in respect of a type of fuel in the liquid class for the compliance period that began two years before the day on which the compliance period to which the report relates began

SCHEDULE 16

(Subsection 112(3))

Report Respecting Emissions Reduction Funding Program

1 The following information with respect to each project that the program funds:

2 A copy of the financial audit conducted under section 99 of the Regulations.

SCHEDULE 17

(Section 115)

Content of Validation Report

1 The validation statement contains

2 The following information with respect to the registered creator or foreign supplier that is making the application that is being validated:

3 The following information with respect to each facility referred to in the application that is being validated:

4 The following information with respect to the owner or operator of each facility referred to in the application that is being validated:

5 The name of the individual who signed the application that is being validated.

6 The following information with respect to the validation body:

7 The following information with respect to the validation:

SCHEDULE 18

(Section 119)

Content of Verification Report

1 The verification statement contains

2 The following information with respect to the registered creator, foreign supplier or the foreign supplier that is making the application or is submitting the report that is being verified:

3 The following information with respect to each facility referred to in the application or report that is being verified:

4 The following information with respect to the owner or operator of each facility referred to in the application or report that is being verified:

5 The name of the individual who signed the application or report that is being verified.

6 The following information with respect to the verification body:

7 The following information with respect to the verification:

SCHEDULE 19

(subsection 122(2))

Contents of Monitoring Plan

1 A list of other systems of tradeable units in which the participant or foreign supplier participates and other third-party audit programs with which they comply.

2 A description of the operations to be validated or verified that includes a description of

3 A simplified block diagram of those operations to be validated or verified that includes

4 A description of each source of data on which the application or report is based that includes any of the following that applies:

5 A description of the data management system that is used to manage the data on which the application or report is based that includes the following:

6 The following information with respect to each measurement device used to measure data on which the application or report is based:

7 Information with respect to the calculation and use of data for reporting in the application or report, including

8 If the validation or verification is in respect of an application made under section 29 or 66 of the Regulations or a report submitted in accordance with section 105 of the Regulations,

9 If the validation or verification is in respect of a credit creation report referred to in sections 103, 104 of the Regulations, a compliance report referred to in section 109 of the Regulations or a fossil fuel production report referred to in section 110 of the Regulations a reference to the documentation that relates to the quantity of any fuel produced and the sale, purchase or transport of any fuel.