Reporting greenhouse gas emissions data, technical guidance 2020: general description of reporting requirements
3.1 Basic and expanded reporting requirements
All facilities with emissions above the 10-kilotonne (kt) threshold will be required to report their emissions of greenhouse gases (GHGs). Facilities with activities outside the industrial sectors/activities listed in section 2.2, will report their GHG emissions by gas for each of the identified emission source categories (listed in section 4.1). These basic emissions reporting requirements are provided in Schedule 5 of the 2020 Greenhouse Gas Reporting Program (GHGRP) Notice.
Facilities engaged in the industrial activities/sectors listed in section 2.2 are also subject to requirements for additional information and the use of prescribed quantification methods. These facilities must provide expanded details of their emissions resulting from specific sources, including fuel combustion (both stationary and on-site transportation), flaring and certain industrial processes (see Figure 2).
For example, a facility involved in waste treatment activities would be subject to the basic emissions reporting requirements. Another facility involved in lime production would be subject to the expanded reporting requirements. However, a facility producing lime and engaged in waste treatment will report its GHG emissions from lime production using the expanded requirements, but would use the basic requirements to report its emissions from the waste treatment activities.
The reporting requirements for carbon capture, transport and storage (CCTS) apply to any facility involved in these activities. The 10-kt threshold does not apply in this case; any facility engaged in this activity must report its related emissions and other required information. However, the 10-kt threshold will apply to the non-CCTS related activities of those same facilities.
Reporters are reminded of the legal requirement to keep copies of the information submitted, together with any calculations, measurements and other data on which the information is based, for a minimum period of three years from the date the information must be submitted.
Figure 2: Expanded reporting process overview
Long description for Figure 2
Figure 2 is a flow chart of the expanded reporting process overview and thus applies to facilities subject to the expanded requirements. Facilities that are engaged in Phase 1 or Phase 2 activities or sectors are to follow the expanded requirements for the identified greenhouse gases. For carbon dioxide (CO2), methane (CH4) or nitrous oxide (N2O), these facilities are required to report on the sources of emissions identified as follows:
- Stationary fuel combustion, on-site transportation and flaring—follow the expanded reporting requirements as per schedule 7
- Industrial processes—follow the expanded reporting requirements as per:
- Schedule 8 for lime production
- Schedule 9 for cement production
- Schedule 10 for aluminium production
- Schedule 11 for iron and steel production
- Schedule 12 for Electricity and heat generation
- Schedule 13 for Ammonia production
- Schedule 14 for Nitric acid production
- Schedule 15 for Hydrogen production
- Schedule 16 for Petroleum Refining
- Schedule 17 Pulp and paper production
- Schedule 18 Base metal production
- Venting, leakage, waste and wastewater—follow the basic reporting requirements unless expanded reporting applies under another schedule
- For CCTS facilities, follow the expanded requirements as per schedule 6
For hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) or sulphur hexafluoride (SF6) where the sources of emissions covered are industrial processes and industrial product use, these facilities are required to follow the basic reporting requirements unless expanded reporting applies under another schedule.
3.2 Key elements in calculating emissions
3.2.1 Basic emissions quantification requirements
For facilities that are not involved in any of the industries/activities described in section 2.2 (i.e. not subject to expanded reporting), there are no specific protocols to define how reporting companies must calculate their GHG emissions. However, reporters must use methods that are consistent with the methodologies approved by the United Nations Framework Convention on Climate Change (UNFCCC) and developed by the 2006 Intergovernmental Panel on Climate Change (IPCC) Guidelines.Footnote 4 Reporters not subject to expanded reporting, although not required, may also use Canada’s Greenhouse Gas Quantification Requirements, where appropriate.
The reporting facility must identify and report the type of estimation method or methods used to determine the quantities of emissions reported. Such methods include monitoring or direct measurement, mass balance, emission factors and engineering estimates. These are defined below.
Monitoring or direct measurement:
This type of method may involve continuous emission monitoring systems (i.e., emissions recorded over an extended and uninterrupted period), predictive emission monitoring (correlations developed between measured emission rates and process parameters) or source testing (e.g., stack sampling).
This type of method involves the application of the law of conservation of mass to a facility, process or piece of equipment. Emissions are determined from the difference in the input and output of a unit operation where the accumulation and depletion of a substance are included in the calculations.
This method uses emission factors (EF) to estimate the rate at which a pollutant is released into the atmosphere (or captured) as a result of some process activity or unit throughput. The EFs used may be average or general EFs, or technology-specific EFs.
This type of method may involve estimating emissions based on engineering principles and judgment, using knowledge of the chemical and physical processes involved, the design features of the source, and an understanding of the applicable physical and chemical laws.
The following key characteristics of the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC, 2006) are useful for reporters when calculating their facility’s GHG emissions:
- The availability of a number of differing “tiers” of calculation methods
For various categories of emission sources, there are several ways of calculating the emissions, described as tiers (e.g., Tier 1, Tier 2, Tier 3), and each tier has an associated increasing level of detail and accuracy (e.g., a Tier 2 method is considered more accurate than a Tier 1 method).
- The use of specific emission factors or data
An emission factor is a value that quantifies emissions associated with an activity (e.g., fuel combustion). To evaluate GHG emissions, “default emission factors” are provided for many different fuels and activities. These default emission factors are considered to be less accurate than country-specific factors and even less accurate than process-specific factors. Reporters should use Canada-specific emission factorsFootnote 5 or, better yet, industry-specific or technology-specific ones, where available. For example, the combustion of natural gas in a boiler results in emissions of GHGs such as CO2, CH4 and N2O. Each has published emission factors that relate its emission rates to quantities of natural gas burned. To determine emissions, a facility would need to determine the total quantity of natural gas consumed during the calendar year (using billing records or meter reading) and multiply this quantity by the emission factor for each GHG. Canada’s latest inventory report provides up-to-date Canada-specific emission factors and information to assist in quantifying emissions.
- A focus on the prioritization of effort
The IPCC suggests that the most effort on quantifying emissions should be spent on those sources that are the most critical: those that make up the largest quantity, are responsible for the greatest increase or decrease, or have the highest level of uncertainty associated with them.
Although comprehensive and rigorous, the IPCC Guidelines provide a flexible approach to GHG calculation procedures. The prioritization of emission sources of greatest importance is also emphasized. In prioritizing the work, these guidelines recognize that the more specific the emission factor or methodology (in terms of geography, facility or process), the better the emission estimate should be.
In the spirit of the IPCC Guidelines, reporters should prioritize their efforts when calculating their GHG emissions. This concept can be applied by identifying the emission sources of greatest significance at the facility and using a higher level of effort when calculating emissions from these sources. Since these emission sources have a greater impact on the totals, the use of more detailed methods would be appropriate. For example, for significant sources, efforts could be focused on using available facility- or process-specific emission factors or estimation methods, as opposed to general or default emission factors or estimation methods. Applying a lower level of effort (i.e., less detailed methods) to calculate emissions for less significant sources would minimize the impact on the level of accuracy.
For further details on the IPCC methodologies, reporters should refer to Table 2, which presents specific references to the relevant sections of the 2006 IPCC Guidelines for the emission sources subject to reporting . Facilities can also refer to Annexes 3 (Methodologies) and 6 (Emission Factors) of Part 2 of Canada’s GHG Inventory Report to obtain detailed explanations of estimation methodologies and emission factors used by Environment and Climate Change Canada in the development of the estimates.
|Emission Source Category||2006 IPCC Guidelines|
|Stationary Fuel Combustion
(CO2, CH4, N2O)
|Volume 2 (Energy), Chapter 2 (Stationary Combustion), pages 2.1–2.47|
|Industrial Process (CO2, CH4, N2O)||Volume 3 (Industrial Process and Product Use), Chapters 1–8|
|Fugitive (flaring, venting, leakage)
(CO2, CH4, N2O)
|Volume 2 (Energy), Chapter 4 (Fugitive Emissions), pages 2.1–2.47|
(CO2, CH4, N2O)
|Volume 5 (Waste), Chapters 1–5|
(CO2, CH4, N2O)
|Volume 5 (Waste), Chapter 6 (Wastewater Treatment and Discharge), pages 6.1–6.28|
(CO2, CH4, N2O)
|Volume 2 (Energy), Chapter 3 (Mobile Combustion), pages 3.1–3.78|
|HFCs||Various chapters, including:
|PFCs||Various chapters, including:
|SF6||Various chapters, including:
3.2.2 Expanded emissions quantification requirements
All facilities engaged in the activities or sectors listed in section 2.2 are required to monitor and report additional data used to determine the identified emissions and, to follow specific quantification requirements described in Canada’s 2020 Greenhouse Gas Quantification Requirements. In most cases, more than one quantification method is available for each sector or activity (i.e.: described below) depending on the information available to the reporter. This approach to GHG calculation procedures continues to allow flexibility, while building consistency in the methods used and the resulting data.
(i) Carbon capture, transport and storage (section 1 of the quantification requirements)
Any facility engaged in CO2 capture, CO2 transport, CO2 injection and/or CO2 storage is required to apply the prescribed quantification requirements in section 1. Since enhanced oil recovery (EOR) is integrated in these activities, this will include companies engaged in EOR using CO2. The CO2 activities covered would include CO2 injected directly into
long-term geological storage as well as CO2 used for EOR planned for long term geological storage.
(ii) Fuel combustion and Flaring (section 2 of the quantification requirements)
Fuel combustion and flaring quantification requirements have been issued for all facilities involved in the industrial activities/sectors (listed in section 2.2). The fuel combustion quantification requirements include stationary fuel combustion and on-site transportation emissions source categories, as well as their related flaring emissions. Facilities are not required to report fuels and associated emissions when the sum of CO2 equivalent emissions (excluding CO2 from biomass) from the combustion of one or more fuels do not exceed 0.5% of the total facility CO2 equivalent emissions from all fuels combusted (excluding CO2 from biomass combustion). Facilities are also not required to report flaring emissions if the sum of CO2 equivalent emissions from any flare(s) do not exceed 0.5% of the total facility CO2 equivalent flaring emissions, or 0.05% of the total facility CO2 equivalent combustion emissions, whichever is larger.
(iii) Mining (section 2 and 6 of the quantification requirements)
Expanded requirements continue to apply for facilities engaged in mining, beneficiating or otherwise preparing metallic and non-metallic minerals, including coal. Facilities are required to apply fuel combustion and flaring quantification requirements. Facilities that are involved in iron ore pelletizing are also subject to methods prescribed for iron and steel production in section 6 of the quantification requirements.
(iv) Ethanol Production (section 2 of the quantification requirements)
Expanded requirements continue to apply for facilities engaged in ethanol production processes that produce grain ethanol for use in industrial applications or as a fuel. Facilities in this sector must use the prescribed fuel combustion and flaring quantification requirements to determine their emissions.
(v) Lime production (section 3 of the quantification requirements)
Expanded requirements continue to apply for facilities engaged in lime production. Lime production involves three main processes: stone preparation, calcination, and hydration. During the calcination process, lime is heated which generates process-related CO2 emissions. Facilities are required to apply site‐specific methodologies to quantify process-related CO2 emissions.
(vi) Cement production (section 4 of the quantification requirements)
Expanded requirements continue to apply for facilities engaged in cement production. The cement production process is comprised of two steps: (i) clinker production and (ii) finish grinding. Process-related GHG emissions from cement production arise from process-related CO2 emissions generated during clinker production. Facilities are required to apply site‐specific methodologies to quantify process-related CO2 emissions.
(vii) Aluminium production (section 5 of the quantification requirements)
Expanded requirements continue to apply for facilities engaged in aluminium production. The production of primary aluminium results in process-related emissions of CO2, two perfluorocarbons (PFCs), namely, perfluoromethane, (C44) and perfluoroethane (C2F6), as well as sulphur hexafluoride (SF6). Process related CO2, C44 and C2F6 emissions from aluminium production will be categorized under industrial process emissions, while SF6 emissions will be categorized under industrial product use emissions.
(viii) Iron and steel production (section 6 of the quantification requirements)
Expanded requirements continue to apply for facilities engaged in iron and steel production. Quantification and reporting of CO2 emissions are required from major process units and processes where raw materials, usually in combination with fuel combustion, contribute to GHG emissions. CO2 emissions from identified process units are to be quantified (and CH4 for emissions from the coke oven battery).
For facilities that manufacture iron and steel, carbon process inputs and outputs that contribute less than 1% of the total mass of carbon into or out of the process are exempt from requirements. For facilities that manufacture iron and steel powder, carbon process inputs and outputs that contribute less than 0.5% of the total mass of carbon into or out of the process are exempt from requirements. All process related CO2 emissions from iron and steel and iron and steel power production will be categorized under industrial process emissions with the exception of emissions arising from coke oven batteries which are to be categorized as stationary fuel combustion and/or flaring emissions.
(ix) Electricity and Heat Generation (section 7 of the quantification requirements)
Expanded requirements continue to apply for facilities that generate electricity and/or heat. In addition to reporting fuel combustion emissions, facilities are required to apply prescribed quantification requirements to report annual emissions from acid gas scrubbers and reagents.
(x) Ammonia Production (section 8 of the quantification requirements)
Expanded requirements continue to apply for facilities engaged in ammonia production. Ammonia is manufactured from fossil-based feedstock which is produced by steam reforming of a hydrocarbon. This also includes processes where ammonia is manufactured through the gasification of solid and liquid raw material. Facilities are required to apply prescribed methods (e.g. feedstock-use methods) to quantify and report their annual emissions data.
(xi) Nitric Acid Production (section 9 of the quantification requirements)
Expanded requirements continue to apply for facilities that produce nitric acid. Nitric acid production requires one or more trains to produce weak nitric acid that is 30 to 70 percent in strength. Facilities are required to apply prescribed methods (e.g. use site-specific emission factors and production data) to quantify and report total annual N2O emissions.
(xii) Hydrogen Production (section 10 of the quantification requirements)
Hydrogen production facilities produce hydrogen gas by steam hydrocarbon reforming, partial oxidation of hydrocarbons, or other transformation of hydrocarbon feedstock. This activity includes hydrogen that is produced at any of the facilities falling within the sectors subject to the expanded requirements (typically petroleum refineries or
stand-alone hydrogen producers). Note that hydrogen production emissions in association with ammonia production are quantified using methods prescribed under ammonia production.
Facilities are required to apply prescribed facility-specific quantification methodologies (or make use of CEMS data, if available) to quantify and report their annual emissions data. Under the facility-specific methodologies, process related CO2 emissions are calculated using an approach based on the type, composition and quantity of feedstock that is consumed and CO2 that is recovered.
(xiii) Petroleum Refining (section 11 of the quantification requirements)
Expanded requirements continue to apply for facilities engaged in petroleum refining processes. This includes the production of gasoline, aromatics, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt, or other products through the refining of crude oil or through redistillation, cracking, rearrangement or reforming of unfinished petroleum derivatives. All process-related CO2, CH4, and N2O emissions from petroleum refineries will be categorized under venting, flaring or leakage emissions.
(xiv) Pulp and Paper Production (section 12 of the quantification requirements)
Expanded requirements continue to apply for facilities engaged in pulp and paper production. Covered processes include the separation of cellulose fibres from other impurities in fibre sources to produce pulp and paper products. Processes that convert paper into paperboard products and the operation of coating and laminating are also included. Facilities are required to quantify and report the total annual CO2 emissions from the chemical recovery process and the total annual CH4 and N2O emissions from on-site wastewater treatment plants.
(xv) Base Metal Production (section 13 of the quantification requirements):
Expanded requirements continue to apply for facilities engaged in base metal production. Covered processes include primary and secondary production processes that are used to recover copper, nickel, zinc, lead, and cobalt. Carbon process inputs that contribute less than 0.5% of the total mass of carbon into the process are exempt from the requirements.
(xvi) Facilities subject to federal Output Based Pricing System (OBPS) Regulations or Alberta’s Specified Gas Reporting Regulation
For facilities engaged in any of the activities listed above (i.e., subject to GHGRP expanded reporting requirements) and that are also subject to the federal OBPS Regulations, an option is provided to allow these facilities to use OBPS-specific emission quantification methodologies to quantify emissions for GHGRP reporting purposes. Also, while an “OBPS to GHGRP printout” is available to reporters in the OBPS reporting application to assist them in preparing their OBPS and GHGRP reports, it should not be used by reporters who must meet GHGRP expanded reporting requirements
(see section 1.3).
For facilities in Alberta that are also subject to the provincial Specified Gas Reporting Regulation, federal reporting identifies Alberta-specific methodologies that may be used by these facilities for reporting to the GHGRP.
3.3 Review and verification
Environment and Climate Change Canada (ECCC) reviews the information submitted by facilities and conducts a number of data quality checks of the submitted data for compliance purposes and for completeness. ECCC also follows up with individual facilities if there are any clarifications needed regarding their data. Reporting companies are required to keep copies of the requested information, together with any calculations, measurements and other data on which the information is based, at the facility to which it relates or at that facility’s parent company, located in Canada. All information must be kept for a period of three years from the date the report must be submitted.
Reporting companies are also required to submit a Statement of Certification, signed by an authorized signing officer, stating that the information submitted is true, accurate and complete.
Companies that meet reporting requirements but fail to report, fail to report on time, or knowingly submit false or misleading information, face penalties as listed under sections 272 and 273 of CEPA. Facilities that did not meet the reporting criteria in previous years should review their status to determine whether they are required to report for the current reporting year.
Currently, there are no specific requirements for a facility to have its emissions verified by a third party. The information reported by a facility should nevertheless be verifiable, which means that any information that would allow a facility’s emissions to be verified by the government or a third party certified by the government to carry out such verifications should be retained. Facilities can choose to have their emissions verified by a third party if they wish.
Note: While ECCC does not require third-party verification as part of the mandatory reporting obligations issued under the GHGRP, facilities subject to the Output Based Pricing System Regulations are required to have OBPS annual reports verified.
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