## 2 Net GHG emissions

### 2.1 Methodology

Proponents of projects undergoing a federal impact assessment are required to provide an estimate of the project’s GHG emissions. This must be calculated as the net GHG emissions using Equation 1Footnote 7 below. Each term of this equation is described in further detail in the following sections.

Equation 1: Net GHG emissions

Net GHG emissions =

Direct GHG emissions
+ Acquired energy GHG emissions
– Avoided domestic GHG emissions
– Offset measures

The net GHG emissions for new projects and expansion projectsFootnote 8 are assessed differently:

• For new projects: the GHG emissions must reflect the maximum design throughput or capacity of the project.
• For expansion projects: GHG emissions are assessed based on the additional maximum throughput or capacity the project creates in comparison to the original design capacity.

If the project is expected to operate at a significantly different capacity from the maximum design capacity, the proponent can also provide the net GHG emissions for the expected operation capacity. The proponent can then use the net GHG emissions associated with the expected operation capacity when developing their plan for achieving net-zero emissions by 2050, if required.

The emissions of all GHGs outlined in the Schedule 3 of the Greenhouse Gas Pollution Pricing Act (GGPPA)Footnote 9 must be quantified and the net GHG emissions must be provided in CO2 eq using the global warming potentials provided in the GGPPA. The net GHG emissions must be quantified for all phases of a project (construction, operation and decommissioning) and for each year of the lifetime of the project.

The following sections provide additional details for the quantification of each term of Equation 1. Quantification approaches and emission factors alternative to those presented in sections 2.1.1 to 2.1.4 can be used provided that the methodology, data sources, assumptions and justification for the approach are documented, and that the methodology aligns with the principles of ISO 14064.

Specific requirements for the Planning Phase and Impact Statement Phase are provided in section 2.4 and 2.5.

#### 2.1.1 Direct GHG emissions

Direct GHG emissions are defined in Section 3.1.1 of the SACC as those generated by activities that are within the scope of the project. What might be within the scope of a project will depend on the nature of a particular project. The definition of a designated project in section 2 of the IAA sets out that a designated project consists of physical activities and those physical activities that are incidental to them. At the Planning Phase, the proponent provides a description of the project and if an impact assessment is required, the scope of the factors to be considered in an impact assessment is determined by IAAC and set out in the Tailored Impact Statement Guidelines. If transportation of equipment or products is considered to be a physical activity that is within the project as described, for example, then emissions generated by that transportation would be considered as direct GHG emissions.Footnote 10

Section 5.1.1 of the SACC states that the proponents must provide a description of the project’s main sources of GHG emissions and their estimated GHG emissions. For the purpose of quantification, main sources should be understood as groups of equipment (or bundles of technologies and practices) or activities that contribute 1% or more of the total direct GHG emissions of the project.

Direct GHG emissions must be quantified for the construction, operation and decommissioning phases of a project and for each year of the lifetime of the project. Examples of direct GHG emissions include GHG emissions from mobile or stationary combustion, land-use change, industrial processes, solid waste disposal, and flaring, venting and fugitive emissions as described in further detail below.

##### 2.1.1.1 GHG emissions from stationary and mobile combustion

Stationary fuel combustion sources include devices that combust fuel for the purpose of producing useful heat or work. This includes boilers, electricity generating units, cogeneration units, combustion turbines, engines, incinerators and process heaters.  Mobile combustion include devices that combust fuel that are not stationary (e.g.: transport activities - road, off-road, air, railways, and water-borne navigation).

The GHG emissions from stationary or mobile combustion can be quantified using Equation 2.

Equation 2: Emissions from stationary and mobile combustion

GHG emissions from fuel combustion =

Estimated quantity of fuel to be consumed  ×  Emission Factor

The project’s total GHG emissions from fuel combustion is the sum of Equation 2 for each fuel type and GHG considered.

If project-specific and equipment-specific fuel consumption data is not available, the proponent can refer to Annex A of this guide for resources to estimate fuel consumption by equipment.

Emissions factors associated with different fuels are available in Part 2, Annex 6 of the National Inventory Report: Greenhouse Gas Sources and Sinks in Canada (NIR). Table 1 below provides reference to the values published in the 2020 NIR, however proponents should use the most recent NIR emission factors.

Table 1:  Emission factors associated with the combustion of different fuels
Fuel GHG Reference for emission factors associated with the combustion of common fuels
Natural Gas CO2 NIR 2020, Part 2, Annex 6, Table A6.1-1
CH4 and N2O NIR 2020, Part 2, Annex 6, Table A6.1-2
Natural Gas Liquids CO2, CH4 and N2O NIR 2020, Part 2, Annex 6, Table A6.1-3
Refined Petroleum Products CO2, CH4 and N2O NIR 2020, Part 2, Annex 6, Table A6.1-4
Petroleum Coke and Still Gas CO2 NIR 2020, Part 2, Annex 6, Table A6.1-5
N2O NIR 2020, Part 2, Annex 6, Table A6.1-6
Still Gas (Refineries & Others) CH4 NIR 2020, Part 2, Annex 6, Table A6.1-7
Coal CO2 NIR 2020, Part 2, Annex 6, Table A6.1-8
Coal Products CO2 NIR 2020, Part 2, Annex 6, Table A6.1-9
Coal and coke products CH4 and N2O NIR 2020, Part 2, Annex 6, Table A6.1-10
Fuels for mobile combustion sources CO2, CH4 and N2O NIR 2020, Part 2, Annex 6, Table A6.1-13

Alternatively, the proponent may choose to use emission factors associated with similar equipment in operation in another facility if conditions are similar (same type of fuel).

GHG emissions from marine shipping

Marine shipping GHG emissions include those generated from commercial vessels operating in waters within the scope of the project. The methodology used in Canada’s Marine Emissions Inventory ToolFootnote 11  can be used for the quantification of GHG emissions from marine shipping. This methodology will be outlined in the National Marine Emissions Inventory for Canada Methodology Report, which is expected to be published in 2021 on the Marine Emissions Inventory Tool website.Footnote 12  This report will consider emissions from a vessel’s main engine(s), auxiliary engines, and boilers.Footnote 13

GHG emissions from marine shipping can be quantified using the activity-based emissions, Equation 3.

Equation 3: Emissions from marine shipping

GHG Emissions from marine shipping =

Σi {(ME * LFME * ΔTME * EFME) + (AE * LFAE * ΔTAE * EFAE) + (BO * ΔTBO * EFBO)}

Where:

• i is the data point
• ME is the main engine capacity or maximum continuous rating (kW)
• AE is the total auxiliary engine capacity (kW)
• LF is the engine load factor
• EF is the emission factor (g/kWh for engines, kg/t fuel for boilers)
• BO is the boiler fuel consumption rate (t/h)
• ΔT is the time spent in the relevant mode (underway, berth or anchor) (hr)

The National Marine Emissions Inventory for Canada Methodology report provides emission factors for CO2, CH4, and N2O based on fuel type, engine type, and stroke type of the engine.

Proponents must describe all the assumptions associated with the number and type of vessels, fuel consumption, engine type, navigation distances, and trip frequency per year.

GHG emissions from rail transport

Emissions from railway locomotives within a port or terminal area can be calculated using the Port Emissions Inventory Tool. The tool and user guide are available from Environment and Climate Change Canada by contacting:

For railway locomotives in other applications, proponents can use the methodology and emission factors outlined in the most recent Locomotive Emissions Monitoring Report, produced annually by the Railway Association of Canada.Footnote 14

The 2018 Locomotive Emissions Monitoring Report is the most recent published report. Within this report, GHG emissions are calculated based on annual fuel consumption and fuel consumption rates (L/1,000 GTK), and are reported for Class 1 freight (separately for mainline locomotives and yard switchers/work trains) and various passenger operations (such as intercity, commuter, and VIA Rail). Proponents can consult Section 5 of the report (“Locomotive Emissions”) for information on the emission factors and methodology used to calculate GHG emissions. Please refer to Table 3, Canadian Rail Operations Fuel Consumption, 1990, 2006–2018 for a breakdown of reported fuel consumption, and Table 9, GHG Emissions and Emission Intensities by Railway Service in Canada 1990, 2006–2018 for an example of how GHG emissions are reported per sector (such as mainline freight or yard switcher).

GHG emissions from combustion of biogenic carbon

In line with the approach presented in the 2006 Intergovernmental Panel on Climate Change (IPCC) Guidelines for National Greenhouse Gas InventoriesFootnote 15 (IPCC 2006), it can be assumed that biogenic CO2 emissions from combustion are balanced by carbon uptake prior to harvest. In such a situation, only CH4 and N2O from combustion of biomass need to be considered in the quantification of direct GHG emissions from biomass combustion in stationary and mobile equipment.

##### 2.1.1.2 Emissions from land-use change

The GHG emissions and removals from land-use conversions as a direct result of project construction are included in the direct GHG emissions. Note that this does not include forgone carbon sequestration from land-use change that is included in the ‘Carbon Sinks’ quantification (see Section 4).

The quantification method for land-use change is outlined in Annex B of this guide. It is a tiered approach, providing three options of increasing complexity depending on the project area and proportion of project area on carbon dense lands (refer to Annex B, Figure 6). This method follows the approaches of the latest NIR and IPCC guidelines.

##### 2.1.1.3 GHG emissions from industrial processes

Industrial processes are defined as those involving a chemical or physical reaction, the primary purpose of which is to produce a product, as opposed to useful heat or work (GC 2020-4). The proponent can use the following methods to quantify GHG emissions from an industrial process (such as cement production, ammonia production or iron and steel):

• Technical Guidance on Reporting Greenhouse Gas Emissions,Footnote 16  under Canada’s Greenhouse Gas Reporting Program (GHGRP).
• Volume 3 of IPCC 2006; or
• The NIR

The proponent must ensure that industrial process emissions are identified and calculated separately from stationary combustion emissions.  Refer to IPCC 2006, Volumes 2 and 3 for further guidance.

##### 2.1.1.4 Flaring, venting and fugitive GHG emissions

Flaring, venting and fugitive GHG emissions are comprised of intentional or unintentional releases of GHGs from the production, processing, transmission, storage and delivery of fossil fuels. Table 2 categorizes these emissions based on categories in the NIR.

Table 2: Emission sources categorized as flaring, venting and fugitive emissions
Emission source Category
Flaring Flaring
Exposed Mine Face (Oil Sands) Fugitive
Fugitive Equipment Leaks Fugitive
Spills/Pipeline Ruptures Fugitive
Storage Losses Fugitive
Surface Casing Vent Flow/Gas Migration Fugitive
Tailings Ponds (Oil Sands) Fugitive
Formation CO2 Venting
Glycol Dehydrator Off-Gas Venting
Reported Venting Venting
Unreported Venting - Compressor Seals Venting
Unreported Venting - Pneumatic Instruments Venting
Unreported Venting - Pneumatic Pumps Venting
Unreported Venting - Start Gas Venting
Unreported Venting - Sulphur Pouring Venting
Unreported Venting - Undifferentiated Venting
Unreported Venting - Well Drill-Stem Test Venting

Emission factors for flaring, venting and fugitives GHG emissions from the oil and gas industry sectors are provided in Table 3. These were developed by ECCC based on historical GHG emissions from the NIR and a range of resources including Statistics Canada publications.

Table 3: Emission factors for flaring, venting and fugitives GHG emissions by oil and gas sector
Oil and gas sector Basis for emission factor Emission factor unit Emission factor
Flaring Venting Fugitives
Natural Gas Production Non-associated gas production g CO2 eq / m3 3.27 37.52 56.83
Natural Gas Processing Gross natural gas production g CO2 eq / m3 3.10 19.56 2.24
Light/Medium Crude Oil Production Light/medium crude oil production kg CO2 eq / m3 57.32 164.74 42.83
Heavy Crude Oil Production + Primary Oil Sands Heavy crude oil production + primary oil sands production kg CO2 eq / m3 20.63 163.55 35.21
Oil Sands Mining and Extraction Mined Bitumen Production kg CO2 eq / m3 1.88 0.15 21.67
Upgrading Synthetic Crude Oil Production kg CO2 eq / m3 19.82 66.25 1.59
Thermal Oil Sands Production (CSS + SAGD) CSS + Steam-Assisted Gravity Drainage Production kg CO2 eq / m3 2.08 0.96 3.57
Natural Gas Transmission and Storage Length of transmission pipeline t CO2 eq / km 0.08 9.77 14.63
Petroleum Refining Crude oil charged to refineries kg CO2 eq / GJ 0.05 0.25 0.03
Petroleum Refining Refined petroleum products (RPP) production kg CO2 eq / GJ 0.04 0.22 0.02

For fugitive emissions associated with coal mining, emission factors are provided in Part 2 Annex 6 of the NIR. Proponents will select the appropriate emission factor based on the project location, coal type and mine type.

##### 2.1.1.5 GHG emissions from waste

Methodologies for estimating GHG emissions for several waste categories are available in the NIR, Part 2 Annex 3.6. The approaches outlined in the NIR are consistent with methodology presented in Volume 5 of IPCC 2006. Table 4 outlines the applicable sections for the NIR and IPCC 2006 for each waste category considered.

Table 4: Sources of methodologies to estimate GHG emissions from management of project wastes
Waste category Methodology source GHG and activities considered
Solid Waste Disposal (Landfill) NIR 2020, Part 2, Section A3.6.1. or IPCC 2006, Volume 5, Chapter 3 Estimates CH4 emissions from municipal solid waste landfills and wood waste landfills using first-order decay method
Biological Treatment of Solid Waste NIR 2020, Part 2, Section A3.6.2. or IPCC 2006, Volume 5, Chapter 4 Estimates CH4 and N2O emissions from composting and anaerobic digestion
Incineration and Open Burning of Waste NIR 2020, Part 2, Section A.3.6.3. or IPCC 2006, Volume 5, Chapter 5 Estimates CH4, N2O and CO2 emissions for municipal solid waste, hazardous waste, clinical waste, and sewage sludge incineration (excludes CO2)
Wastewater Treatment and Discharge NIR 2020, Part 2, Section A.3.6.4. or IPCC 2006, Volume 5, Chapter 6 Estimates CH4 and N2O emissions for treated and untreated wastewater

ECCC developed a tool to support analysis of GHG emissions from organic waste management practices, called the Greenhouse Gas Calculator for Organic Waste Management. This tool is currently available upon request. Please contact ec.ges-dechets-ghg-waste.ec@canada.ca to obtain a copy.

#### 2.1.2 Acquired energy GHG emissions

Acquired Energy GHG emissions are those associated with the generation of electricity, heat, steam or cooling, purchased or acquired from a third party for the project (see Section 3.1.1 of the SACC). Hydrogen use as fuel is also considered as an acquired energy if generated off site by a third party.

The following sections provide guidance to quantify acquired energy GHG emissions for the main sources of acquired energy.

##### 2.1.2.1 Electricity

To quantify annual GHG emissions from acquired electricity, the proponent can use projected provincial emission intensities for electrical utilities, developed by ECCC.  Emission intensity (EI) projections developed in 2020 are provided in Annex C of this guide.  The annual update to EI projections are expected to be available in the open data tables of Canada’s Greenhouse Gas Emissions Projections webpageFootnote 17  but are not available at the time of publication of this document.

The projections include time series of EIs that reflect emission reductions expected from policies and measures over time. These projections were developed using ECCC’s Energy, Emissions and Economy Model for Canada (E3MC) built off NIR 2020, and were calculated as the total projected GHG emissions associated with electricity generated by electric utilities and net industrial generation sold to the grid divided by electricity consumption from the grid for each province (e.g. t CO2 eq/GWh per year).

For the portion of the project that extends beyond the current projections, the proponent can use provincial policies to establish trends in the vicinity of the project location.  The resulting EI estimates should be conservative, and the methodology, data sources, assumptions and justification must be documented.

##### 2.1.2.2 Hydrogen used as fuel

To quantify GHG emissions from acquired hydrogen used as fuel in their project, proponents can use the EIs provided in Table 5.

Table 5: Emission intensities for hydrogen production processes
Hydrogen production process Emission intensityFootnote 18
(t CO2 eq / t H2)
Steam Methane Reforming (SMR) or Partial Oxidation of Hydrocarbons 10.0Footnote 19
Autothermal Reforming (ATR) 8.98Footnote 20
SMR with carbon capture and storage (CCS) 5.0
ATR with CCS 0.45

If hydrogen used for the project is not acquired but instead produced within the scope of the project, the proponent should use the quantification approach described in section 2.1.1.

The EI for the production of hydrogen via SMR with CCS assumes a capture rate of 50%Footnote 21  while the EI for the production of hydrogen via ATR with CCS assumes a capture rate of 95%.Footnote 22

The GHG emissions for hydrogen acquired via electrolysis can be quantified using a default electricity consumption rateFootnote 23  of 50.0 kWh/kg of H2 and the provincial grid electricity EI projection in Annex C for the province in which the hydrogen is produced.

##### 2.1.2.3 Steam

To quantify GHG emissions from acquired steam, the proponent can use an emission factor of 223 t CO2 eq/GWh thermal (or 0.062 t CO2 eq/GJ thermal).  This assumes a boiler fed with natural gas with an 80% efficiency.

##### 2.1.2.4 Waste-derived energy

Energy that is derived from waste, co-products or biogas can be assumed to have an emission factor of 0 if the energy can be produced directly without first undergoing waste conversion processes that would emit GHGs. Examples could include use of landfill biogas for heat and steam, use of steam produced from incineration or combustion of waste, or waste-derived fuels. If this energy is not acquired but produced and used within the scope of the project, the proponent can consider this under the avoided domestic GHG emissions term of Equation 1 (see Section 2.1.3 below).

#### 2.1.3 Avoided domestic GHG emissions

Avoided domestic GHG emissions are defined in Section 3.1.1 of the SACC as GHG emissions that are reduced or eliminated in Canada as a result of the project. The SACC states that avoided domestic GHG emissions can also include GHG emissions removed as a result of mitigation measures separate from the project and not reflected in the project's direct GHG emissions.  This type of emission removals or reductions are now captured under corporate-level initiatives (see section 2.1.4.3). Not all projects will have avoided domestic GHG emissions. Considering avoided domestic GHG emissions in the net GHG emissions is optional.

Avoided domestic GHG emissions could be considered in the net GHG emissions of a project to reflect that a project may enable emission reductions that could benefit Canada at a national level. For example:

• In the case of an expansion, the emissions reduction resulting from the replacement of existing equipment with more energy-efficient equipment on the project site.
• In the case of a new project, the emissions reduction resulting from the replacement of a high-emitting facility with a lower-emitting facility.
• In the case of any facility that generates and sells surplus energy, the amount of emissions saved from producing that energy from the previous, higher-emitting source.

The general requirements for avoided domestic GHG emissions are outlined below:

Avoided domestic GHG emissions must:

• Only apply to the project’s net GHG emissions (not to upstream or downstream GHG emissions);
• Represent reductions or removals that are real, additional, quantified, verifiable, unique, and permanent that can be assigned to the project (the same avoided emissions cannot be claimed more than once);
• Be from existing sources or sinks in Canada (not from a hypothetical scenario).

Avoided domestic GHG emissions cannot be:

• Emission reductions required by law and regulations;
• Emission reductions or removals that are used to generate offset measures (see Section 2.1.4 below);
• Emission reductions or removals funded or subsidised through other government programs and initiatives;
• Arising from impact on carbon sinks on the land affected by the project (as these are quantified separately from the net GHG emissions, see Section 4);
• Avoided foreign GHG emissions (proponents have the possibility to describe how the project would impact global GHG emissions, see Section 5.1.3 of the SACC);
• Emissions avoided from another hypothetical new project that might be built if this project does not proceed or from alternative technology that could be used for the project;
• Emission reductions that occur after the end of the project lifetime.

As more stringent policies come into force, avoided domestic GHG emissions that continue to meet the above requirements are expected to decrease with time. Therefore, in 2050 and thereafter, there will be no avoided domestic GHG emissions.

The quantification approach for avoided domestic GHG emissions involves the four steps outlined below.

##### Step 1: Establish assessment scope

Proponents must establish the scope for assessing the avoided domestic GHG emissions and describe it. The avoided domestic GHG emissions must be associated with the direct GHG emissions or acquired energy GHG emissions of the project (not to upstream or downstream GHG emissions).

##### Step 2: Establish Baseline Emissions Scenario (without the project)

Proponents must establish the Baseline Emissions Scenario (without the project) representing an equal throughput or capacity to the project emissions scenario.  The Baseline Emissions Scenario must exist and cannot be hypothetical.

For example, if a pipeline project would replace product transport by railway, the scenario with rail transport must exist. Proponents must describe the existing scenario and provide details on the rail transportation mode, transportation capacity, distance travelled and frequency, and emissions that could become avoided in the project emission scenario in Step 3.

The Baseline Emissions Scenario must be developed for a time series until the end of the project, or the end of 2049, whichever is earlier. It is assumed that by 2050, the measures (policies, regulations, programs) and market conditions in place will render avoided domestic GHG emissions irrelevant, therefore they can no longer be considered part of a project’s net GHG emissions in 2050 and thereafter. The time series must take into account announced measures (policies, regulations, programs) and market conditions. It must also account for replacement of technologies or equipment at the end of life, where applicable. It is possible that the measures (policies, regulations, programs) and market conditions in place will render avoided domestic GHG emissions irrelevant before 2049.

The quantification for the Baseline Emissions Scenario can be done using the approach for direct GHG emissions and acquired energy GHG emissions described in Sections 2.1.1 and 2.1.2, respectively.  Proponents must describe the methodology as well as provide data, emission factors and assumptions used for quantification of the Baseline Emissions Scenario.

##### Step 3: Establish Project Emissions Scenario (with the project)

Proponents must establish the Project Emissions Scenario for a time series until the end of the project, or the end of 2049, whichever is earlier.  As in Step 2, the project emissions scenario must take into account announced measures and market conditions.

The quantification for the Project Emissions Scenario can be done using the approach for direct GHG emissions and acquired energy GHG emissions described in Sections 2.1.1 and 2.1.2, respectively.  Proponents must describe the methodology as well as provide data, emission factors and assumptions used for quantification of the Project Emissions Scenario.

Note that direct GHG emissions and acquired energy GHG emissions of the Project Emissions Scenario may not be the same as those from the project’s net GHG emissions calculation. This is because some avoided domestic GHG emissions may occur in the Project Emissions Scenario that are outside the scope of the project. This must be taken into account in the establishment of the scenarios. For example, a hypothetical new rail project uses a Baseline Emissions Scenario where goods are currently transported by trucks. In the Project Emissions Scenario, some of the goods transported by trucks are transported by rail (with appropriate documentation). Both the rail cars and trucks need to be considered for the avoided domestic GHG emissions evaluation, whereas those goods transported by trucks may not be within the scope of the rail project.

##### Step 4: Calculate avoided domestic GHG emissions

The total avoided domestic GHG emissions is the absolute value of the difference between Step 3 and 2.  To report avoided domestic GHG emissions, those from the Project Emissions Scenario must be less than those from the Baseline Emissions Scenario.

Avoided domestic GHG emissions must be presented for each year of the operation phase of the project up to 2049, if applicable.

A checklist for the avoided domestic GHG emissions is provided in Table 6.

Table 6: Checklist for avoided domestic GHG emissions

• Is the project expected to generate avoided domestic GHG emissions?
• Does the Baseline Emissions Scenario currently exist (real vs hypothetical)?
• Do the scenarios consider announced measures (regulations, plans and programs) and market conditions and are the assumptions reasonable?
• Are the avoided domestic GHG emissions real, additional, quantified, verifiable, unique, and permanent?
• Are avoided domestic GHG emissions quantified for each year of the operation phase of the project (up to 2049 maximum)?
• Are the avoided domestic emissions declining over time as measures become more stringent and electrification rate increases? Are avoided emissions still relevant considering announced measures (regulations, plans and programs) and market conditions?
• Do the avoided domestic GHG emissions represent reductions in Canada?
• Are the methodology description, data, emission factors and assumptions provided, and are they appropriate?

#### 2.1.4 Offset measures

The offset measures term of Equation 1 encompasses the sum of offset credits, CO2 captured and stored, and corporate-level initiatives. These are described in further detail in sections 2.1.4.1 to 2.1.4.3 below. Offset measures can also include other mitigation measures such as land-use changes to mitigate carbon sink disturbance through restoration, afforestation, compensation and conservation (see Sections 3.4.3 and 3.5.3).

##### 2.1.4.1 Offset credits

Offset credits are defined in Section 3.1.1 of the SACC as GHG emission reductions or removals generated from activities that are additional to what would have occurred in the absence of the offset project (i.e., generated from activities that go beyond legal requirements and a business-as-usual standard). Each offset credit generated by an offset project represents one tonne of carbon dioxide equivalent (CO2 eq) reduced or removed from the atmosphere.

Offset credits can apply to the project’s net GHG emissions (not to upstream or downstream GHG emissions).

With the exception of offsets that satisfy the requirements of foreign offset credits, offset credits applied against the new emissions of a project under the SACC must be sourced from a project registered in a Canadian federal, provincial or territorial regulatory offset program that aligns with the best practices outlined in the Canadian Council of Ministers of the Environment Pan-Canadian Offsets Framework.

At the time of releasing this technical guide, the federal GHG offset system was under development. Information regarding the federal system is available at Federal Greenhouse Gas Offset System - Canada.ca.

Offset credits will be purchased by the project proponent and retired or voluntarily cancelled in the associated offset system registries. To purchase offset credits, contracts would need to be negotiated between project proponents and interested sellers. Transfers of offset credits from one party to another would be tracked in the offset system’s registry or credit tracking system. Third parties, such as carbon trade exchanges or brokerage services, may play a role in facilitating transactions. Proponents should ensure that they are aware of the terms, conditions and requirements of the offset program from which they are purchasing and using credits before pursuing this option.

Offset credits used toward the Impact Statement’s net emissions calculation must not have been already retired or canceled for any other purpose, including compliance with any regulatory requirement, voluntary claim by the proponent (e.g. for purposes unrelated to the impact assessment), or compliance or voluntary purposes by any other entity. This will ensure that the offsets identified represent incremental emission reductions and are offsetting emissions that cannot be mitigated any other way (e.g. emissions from the construction phase of the project).

Offset credits used to compensate for project emissions in a given year must have been issued no more than five years prior to their use for the SACC, and represent emission reductions or removals of one or more of the GHGs reported in Canada’s most recent NIR.

Foreign Offset Credits:

Foreign Offset Credits or Internationally Transferred Mitigation Outcomes (ITMO)s are not acceptable as an offset credit at the time of publication of this draft technical guide.

When the rules for the transfer of mitigation outcomes between Canada and foreign countries are established, it is anticipated that foreign offset credits will be acceptable if they fully comply with the rules for Internationally Transferred Mitigation Outcomes (ITMOs) established in Article 6 of the Paris Agreement, all applicable decisions adopted by the Conference of the Parties and any further criteria for international offset credits to be developed by ECCC.Footnote 24

##### 2.1.4.2 CO2 captured and stored

CO2 captured and stored (CCS) is defined in Section 3.1.1 of the SACC as CO2 emissions that are generated by the project and permanently stored in a storage project that meets the following criteria:

• the geological site into which the CO2 is injected is a deep saline aquifer for the sole purpose of storage of CO2, or a depleted oil reservoir for the purpose of enhanced oil recovery; and
• the quantity of CO2 stored for the purposes of the project is captured, transported and stored in accordance with federal, provincial, U.S., or state laws.

Proponents can store CO2 in a storage project or product that does not align with the criteria above if supporting documentation that the CO2 will be sequestered permanently (i.e. for a minimum of 100 years) is provided, and is to the satisfaction of federal authorities.

Proponents incorporating CO2 capture and storage in their project must provide a description of the capture and storage system, including capture and storage locations (with anticipated storage capacity) or end uses (for storage in products), and the associated technologies and transportation infrastructure. Proponents must also indicate the targeted efficiency of CO2 capture and storage for the project.

For each year of the project lifetime in which the CO2 capture and storage system will be operational, the proponent must provide an estimate of the annual amount of CO2 captured, and the annual amount of CO2 stored. These values are to be represented separately. The direct GHG emissions associated with capture and storage that occur within the scope of the project must be included in the direct GHG emissions estimate (Section 2.1.1).

##### 2.1.4.3 Corporate-level initiatives

Actions and initiatives taken at the corporate level include GHG emissions removed as a result of mitigation measures separate from the project and not reflected in the project's direct GHG emissions. Although these GHG emissions are outside of the scope of the project, they must be assigned exclusively to the project (i.e. the same GHG emission removals cannot be counted toward multiple projects). The GHG emissions removed must also represent real, additional, quantifiable, verifiable, unique and permanent removals in Canada.

Similar to avoided domestic GHG emissions, corporate-level GHG removals cannot be:

• Emission reductions required by law and regulations
• Emission reductions or removals funded or subsidised through other government programs and initiatives
• Impact on carbon sinks on the land affected by the project (as these are quantified separately from the net GHG emissions, see Section 4)
• Emission reductions that occur after the end of the project lifetime.

The proponent must provide information on the corporate initiatives that will count toward offset measures. This includes a description of the specific actions and initiatives and relevant technologies, intended schedule of implementation, and the time series of the quantity of offset measures. Any data, emission factors and assumptions used in determining the amount of GHG emissions removed must be provided.

#### 2.1.5 Project emission intensity

When applicable, proponents will calculate the project EI, using the following equation:

Equation 4: Project emission intensity

$\text{Project emission intensity}=\frac{\text{Net GHG emissions}}{\text{Units produced}}$

The units produced term in Equation 4 must correspond with production at the maximum design capacity of the project or additional maximum capacity the project creates, as described for Equation 1.

The project EI units will be specified in the TISG. Examples of possible EI units by project type are provided in Table 7.

Table 7: Examples of emission intensity units by project type
Project type Emission intensity unit
Natural gas electricity generation t CO2 eq / GWh generated
Hydro electricity generation t CO2 eq / GWh generated
Liquefied natural gas (LNG) t CO2 eq / t LNG produced
Oil pipeline t CO2 eq / barrel (bbl) transported
Gas pipeline t CO2 eq / million cubic feet (MMcf) transported
Metal mines t CO2 eq / t metal produced
Industrial facility t CO2 eq / t output produced

For some project types, the project EI estimate may not be possible nor relevant, and will not be requested in the TISG.

The project EI estimate will be calculated in the Impact Statement for each year of the project’s operation phase. Projects that provide both the maximum and net GHG emissions associated with the expected operation capacity as described in Section 2.1 can provide both corresponding project EIs.

### 2.2 Possible accident or malfunction

In the Impact Statement Phase, project proponents will provide a description of large sources of GHG emissions that may be the consequence of possible accidents or malfunctions.

### 2.3 Discussion on the development of emission estimates and uncertainty assessment

In the Impact Statement Phase, project proponents will describe the uncertainty associated with their project’s net GHG emissions estimates. This description should be both qualitative and quantitative, where possible.

There are two types of uncertainty to be considered:

1. uncertainty related to data; and
2. uncertainty related to methods and models.

The discussion of uncertainty related to data will identify any assumptions made in selecting the data, its applicability to the project, its representativeness, and its completeness. The discussion will explain how the data may be improved with more certainty on the project design and variables (type and volume of fuel used for example) as the design progresses toward finalization. A comparison of the data to comparable data sets may inform the uncertainty discussion. The discussion of uncertainty will acknowledge that the uncertainty of GHG emissions estimates generally increases for years further out into the future. The discussion will also include a description of possible circumstances under which accidents or malfunctions as described in Section 2.2 may occur.

The discussion on uncertainty of the methods and models, if applicable, will list the assumptions related to the method or model used and their rationale. Where possible, the uncertainty could be quantitatively represented using different methods and models, or by developing scenarios with varying data inputs to generate a range of reasonable emissions. There could be scenarios related to changes in project design and/or external considerations that may affect a project’s GHG emissions over time. Examples include a qualitative discussion on how the economics surrounding the project could influence the project’s emissions, such as the price of commodities and/or utilization of the project, uncertainties related to the EI of acquired energy GHG emissions, and how the emissions could change depending on the type of equipment, fuel or other source of energy used.

Finally, the discussion on uncertainty will describe how the uncertainty of the emissions estimates was reduced.

### 2.4 Planning phase

The Information and Management of Time Limits Regulations require project proponents to provide an estimate of any GHG emissions associated with the project in the Initial Project Description and Detailed Project Description. This should be calculated as the maximum annual net GHG emissions for each phase of the project, including a breakdown of each term of Equation 1. The proponent must also provide the methodology, data, emission factors and assumptions used.

During the Planning Phase, proponents may not have sufficient information to determine precise net GHG emissions for each year of the project lifetime. Project proponents are to provide the information in Part 1 of Table 8 in the Initial and Detailed Project Descriptions. The proponent is also encouraged to provide information in Part 2 of Table 8 to help IAAC, or relevant lifecycle regulators, understand potential GHG emissions associated with the project.

Table 8: Information to provide in the Initial and Detailed Project Descriptions
Part 1:  Mandatory information
Net GHG emissions
• An estimate of the maximum annual net GHG emissions for each phase of the project, including a breakdown of each term of Equation 1, based on the information available in the Planning Phase.
• A description of the methodology, data, emission factors and assumptions used.
Part 2:  Supporting information for the net GHG emissions estimate
Direct GHG Emissions
• An indication of the anticipated main sources of GHG emissions
• An estimate of the maximum annual direct GHG emissions for each phase of the project (construction, operation, decommissioning), with a description of the methodology, emission factors and assumptions used for the quantification.
• An estimate of the expected area of impacted land in each IPCC land-use category: Forest Land, Wetlands, Cropland, Grassland.
Acquired Energy GHG Emissions

A confirmation of whether the project will acquire energy, and if applicable and available:

• A description of the acquired energy to be used for each phase of the project.
• The expected annual quantity of acquired energy and the annual acquired energy GHG emissions for each phase of the project.
• The identification of the years during which the project is expected to use each acquired energy.
Avoided Domestic GHG Emissions

A confirmation of whether the project will generate avoided domestic GHG emissions, and if applicable and available:

• A description of the avoided domestic GHG emissions including a description of the proposed Baseline Emissions Scenarios.
• A list of new measures, such as policies, regulations, programs as well as other considerations (such as market condition and electrification rate) that will be taken into account when developing the Baseline Emissions Scenario and the Project Emissions Scenario time series.
• The years for which avoided domestic GHG emissions could be generated.
Offset Measures

An indication of whether the proponent intends to use offset measures for the project, and if applicable and available:

• For offset credits:
• Indication of offset programs providing credits.
• The estimated annual amount of offset credits to be purchased for each phase of the project.
• For CO2 captured and stored:
• A description of CO2 capture, transportation and storage system, including whether partial or complete capture of CO2 will be targeted (efficiency) and whether the CO2 storage project is within the scope of the project or outside of the scope.
• An indication of the expected annual amount of CO2 that would be captured by the system.
• For storage projects:
• A description of the CO2 storage project including the location and expected total storage capacity.
• For storage in products:
• A description of the end use of the CO2 (i.e. products produced).
• An indication of the expected annual amount of CO2 stored (in a project or product).
• For corporate-level initiatives:
• A description of the corporate initiatives or actions, the location and area covered if applicable.
• An identification of the years of the project lifetime for which offset measures will be used

### 2.5 Impact Statement phase

In the Impact Statement, project proponents will quantify the project’s net GHG emissions for each year of the lifetime of the project, and the project EI, for each year of the operation phase of the project. Quantification must reflect the final design including the mitigation measures identified in Section 3 (the BAT/BEPs, additional mitigation measures, and offset measures).

In the Impact Statement, each term of Equation 1 must be provided along with methodologies, a description of any models used, data, EIs and any assumption used. The impact statement should contain a greater level of detail and accuracy that reflects the new information gathered and decisions made subsequent to the Planning Phase Project Description. At a minimum, the proponent must provide the information requested in Table 9:

Table 9: Checklist of minimum information that will be required from the proponent in the Impact Statement
Topic Minimum information required
Direct GHG Emissions
• A description of the main sources of GHG emissions, including details on equipment types and activities.
• An estimate of the annual direct GHG emissions from each main source for the lifetime of the project.
• An estimate of the annual direct GHG emissions for each year of the lifetime of the project.
• A description of the methodology, data, emission factors and assumptions used to quantify the direct GHG emissions.
Acquired Energy GHG Emissions

A confirmation of whether the project will acquire energy, and if applicable:

• A description of the types of acquired energy, including sources of the energy and supporting information.
• The quantity of acquired energy for each year of the lifetime of the project.
• An estimate of the annual acquired energy GHG emissions for each year of the lifetime of the project for each type of acquired energy.
• A description of the methodology, data, emission factors and assumptions used for the quantification of acquired energy GHG emissions.
Avoided Domestic GHG Emissions

A confirmation of whether the project will generate avoided domestic GHG emissions, and if applicable:

• A description of the avoided domestic GHG emissions including a description of the Baseline Emissions Scenario.
• A list of new measures, such as policies, regulations, programs as well as other considerations (such as market conditions and electrification rate) that are taken into account in the Baseline Emissions Scenario and the Project Emissions Scenario time series.
• An estimate of the annual avoided domestic GHG emissions for each year of the operation life of the project.
• A description of the methodology, data, EIs and assumptions used for the quantification the Baseline Emissions Scenario and the Project Emissions Scenario, including a demonstration of reasonableness and conservativeness.
Offset Measures

A confirmation of whether the proponent intends to use offset measures for the project, and if applicable:

• For offset credits:
• Whether the proponent intends to purchase offset credits, and if applicable:
• The number of GHG offset credits intended to be used, for each year of the project life.
• The GHG offset programs from which each offset credit will be sourced.
• Confirmation that any offset credits are sourced from a project registered in a Canadian federal, provincial or territorial regulatory offset program.
• For CO2 captured and stored:
• A confirmation of whether the project will capture or store CO2, and if applicable:
• A description of the CO2 capture and storage systems, and locations (i.e. capture site, storage project site or product manufacturing site).
• The expected annual amount of CO2 captured for each year or the operation phase of the project.
• For storage projects:
• Geological characteristics of the storage site, including total capacity.
• Annual amount of CO2 expected to be stored for each year of the operation phase of the project.
• For storage in products:
• A description of the end use of the CO2 (i.e. product) and the associated life cycle.
• The annual amount of CO2 expected to be stored in products (i.e. amount per product unit and total number of product units produced) for each year of the operation phase of the project.
• Technologies used for capture, transportation, injection and monitoring, including any project-specific considerations and whether the technology has been demonstrated elsewhere (location and capture rate).
• Identify any specific protocols used or adhered to for the quantification.
• An explanation, and supporting documentation, of how the project will ensure that the CO2 is stored permanently, and a discussion of the feasibility and risk of transportation of CO2 captured to the storage location.
• Identify any contracts that are in place or being negotiated between the proponent, storage project, and/or government(s) as applicable.
• For corporate-level initiatives:
• An estimate of the annual GHG emissions removed as a result of corporate initiatives for each year of the lifetime of the project.
• A description of the corporate initiatives that will be assigned to the project, and supporting documentation, if applicable.
• The proposed schedule of implementation.
• Confirmation of how the proponent will ensure that corporate initiatives will not be double counted by other projects that are submitted for impact assessment.
• A description of the methodology, data, EIs and assumptions used for the quantification of offset measures, if applicable.
Net GHG emissions
• Net GHG emissions by year for each phase of the project based on the project’s maximum throughput or capacity (new project) or additional throughput or capacity (expansion project).
• Optionally, if the project is expected to operate at a significantly different capacity from the maximum design capacity, the proponent can also provide the net GHG emissions for the expected operation capacity. The proponent can then use the net GHG emissions associated with the expected operation capacity if a plan for achieving net-zero emissions by 2050 is required.
Project Emission Intensity
• An estimate of the project’s EI by year for the operation phase, based on the net GHG emissions calculated above.
• A description and quantity of the “unit produced” from Equation 2 for each year of the operation phase.
Possible accident or malfunction
• A description of large sources of GHG emissions that may be the consequence of accidents or malfunctions.
Uncertainty
• Discussion on the development of emissions estimates and uncertainty assessment (Section 2.3).