Scope 3 Emissions Estimator
Canada

Scope 3 emissions reporting in Canada: Canadian Sustainability Disclosure Standards (CSDS) based on ISSB S1/S2; Greenhouse Gas Reporting Program (GHGRP); Provincial GHG reporting requirements (British Columbia, Quebec, Ontario, Alberta)

Canada's sustainability disclosure framework is evolving rapidly. The Canadian Sustainability Standards Board (CSSB) published CSDS 1 (General Requirements) and CSDS 2 (Climate-related Disclosures) in 2024, based on ISSB S1 and S2 with Canadian modifications. The Canadian Securities Administrators (CSA) are expected to adopt these standards for publicly listed entities, though the implementation timeline has been subject to political and regulatory discussion. Several provinces already require GHG reporting. British Columbia's Greenhouse Gas Industrial Reporting and Control Act, Quebec's Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere, Alberta's Technology Innovation and Emissions Reduction (TIER) Regulation, and Ontario's Greenhouse Gas Reporting Regulation each set provincial thresholds and requirements. At the federal level, Environment and Climate Change Canada (ECCC) administers the Greenhouse Gas Reporting Program (GHGRP), which requires facilities emitting 10 kilotonnes CO2e or more to report annually. Like Australia's NGER, the GHGRP covers Scope 1 only, but the data feeds into Canada's National Inventory Report (NIR) and provides a foundation for Scope 3 estimation.

Regulatory context: Canadian Securities Administrators (CSA) for disclosure requirements; Environment and Climate Change Canada (ECCC) for GHG reporting; Provincial regulators for regional emissions requirements

The CSA is the umbrella organisation for Canada's 13 provincial and territorial securities regulators. National Instrument 51-107 (Disclosure of Climate-related Matters) was proposed to mandate TCFD-aligned disclosures for Canadian reporting issuers, but the timeline for finalisation has been extended. The CSSB's CSDS standards provide the technical content, but regulatory adoption by the CSA determines when they become mandatory. For now, Scope 3 disclosure is voluntary for most Canadian entities, though institutional investors (particularly Canadian pension funds like CPP Investments, CDPQ, and OTPP) increasingly request Scope 3 data from portfolio companies. ECCC publishes Canada's National Inventory Report annually, which provides sectoral emission data used for national GHG accounting. ECCC also publishes the National Inventory Report Emission Factors, which provide Canadian-specific factors for fuels, electricity by province, and industrial processes. The Output-Based Pricing System (OBPS) under the federal carbon pricing framework sets emission standards for large industrial emitters, generating verified Scope 1 data for covered facilities.

Practical guidance for Canada

Canadian entities estimating Scope 3 should use ECCC's NIR emission factors for Canadian activities. For electricity, Canada's grid emission factor varies enormously by province, reflecting the diverse generation mix. Quebec and Manitoba produce over 95% of electricity from hydropower, yielding emission factors below 0.005 kg CO2e per kWh. Ontario's nuclear and hydro mix produces approximately 0.025 kg CO2e per kWh. Alberta's gas and coal-dependent grid produces approximately 0.44 kg CO2e per kWh. Saskatchewan's factor exceeds 0.58 kg CO2e per kWh. Nova Scotia, still reliant on coal, exceeds 0.65 kg CO2e per kWh. These provincial differences are among the widest of any country and make the choice of grid factor a material judgment for Scope 3 categories involving electricity. For Category 1, Canadian entities in the oil sands sector face Category 1 emissions from diluent procurement, drilling consumables, and chemical inputs. For Category 11, Canadian oil and gas exporters (Canada is the world's fourth-largest oil producer) face the same Category 11 challenge as Australian mining companies: the combustion of exported products generates Scope 3 emissions measured in hundreds of millions of tonnes. For transport, Canada's vast distances (the Trans-Canada Highway alone spans 7,800 km) make freight transport emission factors material for Categories 4 and 9.

Audit expectations

Canadian assurance providers apply CPA Canada guidance and CSAE 3410 (Assurance Engagements on Greenhouse Gas Statements) for GHG verification engagements. As CSDS adoption progresses, assurance requirements will follow the IAASB's sustainability assurance standards. Canadian auditors expect entities to document provincial-specific emission factors (particularly for electricity), justify the organisational boundary (equity share versus operational control, which matters significantly for joint venture oil sands operations), and provide category-level Scope 3 breakdowns rather than single aggregate figures. For entities in the resource sector, assurance providers will focus on Category 11 completeness and the consistency of product volume data between GHG calculations and financial reporting (revenue recognition for commodity sales should reconcile with the volumes used for Category 11 emission calculations).

Canada-specific considerations

Canada's provincial grid emission factor variation creates unique Scope 3 implications. A data centre in Quebec (hydro-powered grid, near-zero emission factor) produces negligible Scope 2 and Scope 3 Category 3 emissions, while the same data centre in Alberta would produce approximately 90 times more. Canadian entities should use the province-specific grid emission factors published by ECCC in the National Inventory Report. The federal carbon price (C$80 per tonne CO2e in 2024, rising to C$170 by 2030) applies across Canada but with provincial variations in implementation (Quebec uses a cap-and-trade system linked to California; Alberta uses the TIER regulation). This carbon price affects procurement costs for energy-intensive inputs, which may influence spend-based Scope 3 estimates. Canada's oil sands operations in Alberta use energy-intensive extraction methods (steam-assisted gravity drainage, SAGD, for in-situ operations) with Scope 1 emission intensities of approximately 0.08 to 0.12 tonnes CO2e per barrel, higher than conventional crude. These high upstream emission intensities carry through to Canadian oil purchasers' Scope 3 Category 1 calculations. NRCan (Natural Resources Canada) publishes energy efficiency data for buildings and vehicles that supports Category 7 and Category 8 estimation.

Common inspection findings

The CSA's 2024 staff review of voluntary climate disclosures by TSX-listed companies found that only 30% of companies disclosing Scope 3 provided category-level breakdowns, with the majority reporting a single aggregate figure or disclosing only one or two categories.

ECCC's GHGRP verification programme identified that some facilities reported lower Scope 1 figures to the provincial regulator than to ECCC for the same reporting period, suggesting inconsistencies that cascade into downstream Scope 3 calculations.

Canadian assurance providers found that oil and gas companies frequently excluded equity-accounted joint venture production from their Category 11 calculations, materially understating Scope 3. The boundary treatment of joint ventures in the oil sands is a recurring area of judgment that assurance providers challenge.

Alberta's TIER program compliance data showed inconsistencies between TIER-reported emissions and sustainability report emissions for the same facilities, with differences attributable to different treatment of cogeneration emissions, flaring, and venting.

Provincial securities regulators noted that some Canadian entities disclosed Scope 3 emission reductions that were driven by asset sales or production declines rather than efficiency improvements, without adequate disclosure of the underlying driver.