Canada’s greenhouse gas quantification requirements (2024)
Canada’s Greenhouse Gas Quantification Requirements (PDF version)
Glossary
“2024 and 2025 GHGRP Notice” means the Notice with respect to reporting of greenhouse gases (GHGs) for 2024 and 2025, Canada Gazette, Part I.
“Aluminium production” means primary processes that are used to manufacture aluminium from alumina, including electrolysis in prebake and Søderberg cells, anode and cathode baking for prebake cells, and green coke calcination.
“Ammonia production” means processes in which ammonia is manufactured from fossilbased feedstock produced by steam reforming of a hydrocarbon. This also includes processes where ammonia is manufactured through the gasification of solid and liquid raw material.
“Base metal production” means the primary and secondary production processes that are used to recover copper, nickel, zinc, lead, and cobalt. Primary production includes the smelting or refining of base metals from feedstock that comes primarily from ore. Secondary production processes includes the recovery of base metals from various feedstock materials, such as recycled metals. Process activities may include the removal of impurities using carbonate flux reagents, the use of reducing agents to extract metals or slag cleaning, and the consumption of carbon electrodes.
“Biomass” means plants or plant materials, animal waste or any product made of either of these, including wood and wood products, charcoal, and agricultural residues; biologically derived organic matter in municipal and industrial wastes, landfill gas, bioalcohols, black liquor, sludge digestion gas and animal or plantderived oils.
“Bone dry tonne” means a mass of one tonne of solid material that contains no, i.e. zero percent (0%) moisture.
“Carbon dioxide equivalent (CO_{2} eq.)” means a unit of measure for comparison between greenhouse gases that have different global warming potentials (GWPs).
“Cement production” means all processes used to manufacture portland, ordinary portland, masonry, pozzolanic or other hydraulic cements.
“CEMS” means Continuous Emission Monitoring system.
“CKD” means cement kiln dust.
“CO_{2} capture” means the capture of CO_{2} at an integrated facility that would otherwise be directly released to the atmosphere or the capture of CO_{2} through Direct Air Capture (DAC).
“CO_{2} emissions from biomass decomposition” means releases of CO_{2} resulting from aerobic decomposition of biomass and from the fermentation of biomass.
“CO_{2} injection” means an activity that places captured CO_{2} into a longterm geological storage site or an enhanced fossil fuel recovery operation.
“CO_{2} recovered” means the recovery or capture of CO_{2} at a hydrogen production facility that would typically be delivered for downstream use in other manufacturing industries, used in onsite production or sent to permanent storage.
“CO_{2} storage” means storage of CO_{2} in a longterm geological formation.
“CO_{2} transport system” means a system transporting captured CO_{2} by any mode.
“CO_{2} utilization” means usage of captured CO_{2} in products or processes with a goal of longterm removal from the atmosphere, including CO_{2} injection at an enhanced fossil fuel recovery operation.
“Cogeneration unit” means a fuel combustion device which simultaneously generates electricity and other useful heat and/or steam.
“Continuous Emission Monitoring system” means the complete equipment for sampling, conditioning, and analyzing emissions or process parameters and for recording data.
“CSM” means cyclohexanesoluble matter.
“Dry reference condition” (dR) means gases measured at 101.325 kPa, 25°C and 0% moisture.
“Electricity generating unit” means any device that combusts solid, liquid, or gaseous fuel for the purpose of producing electricity either for sale or for use onsite. This includes cogeneration unit(s), but excludes portable or emergency generators that have less than 50 kW in nameplate generating capacity or that generate less than 2 MWh during the reporting year.
“Emissions” means direct releases to the atmosphere from sources that are located at the facility.
“Enhanced fossil fuel recovery operation” means enhanced oil recovery, enhanced natural gas recovery and enhanced coal bed methane recovery.
“Facility” means an integrated facility, a pipeline transportation system, or an offshore installation.
“Flaring emissions” means controlled releases of gases from industrial activities, from the combustion of a gas or liquid stream produced at the facility, the purpose of which is not to produce useful heat or work. This includes releases from: waste petroleum incineration; hazardous emission prevention systems (in pilot or active mode); well testing; natural gas gathering system; natural gas processing plant operations; crude oil production; pipeline operations; petroleum refining; chemical fertilizer production; steel production.
“Fossil fuel production and processing” means the exploration, extraction, processing including refining and upgrading, transmission, storage and use of solid, liquid or gaseous petroleum, coal or natural gas fuels, or any other fuels derived from these sources.
“Fugitive emissions” means releases from venting, flaring or leakage of gases from fossil fuel production and processing; iron and steel coke oven batteries; CO_{2} capture, transport, injection, utilization and storage infrastructure.
“GHGRP Technical Guide” means the Technical Guidance on Reporting Greenhouse Gas Emissions, January 2023, Environment and Climate Change Canada. (Cat No.: En8129EPDF).
“GHGs” means greenhouse gases.
“GWP” means global warming potential.
“HFCs” means hydrofluorocarbons.
“Industrial process emissions” means releases from an industrial process that involves a chemical or physical reaction the primary purpose of which is to produce a nonfuel product, as opposed to useful heat or work. This does not include process vents (i.e. hydrogen production) from fossil fuel production and processing.
“Industrial product use emissions” means releases from the use of a product, in an industrial process, that is not involved in a chemical or physical reaction and does not react in the process. This includes releases from the use of SF_{6}, HFCs and PFCs as cover gases, and the use of HFCs and PFCs in foam blowing. This does not include releases from PFCs and HFCs used in refrigeration, air conditioning, semiconductor production, fire extinguishing, solvents, aerosols and releases of SF_{6} used in explosion protection, leak detection, electronic applications and fire extinguishing.
“Integrated facility” means all buildings, equipment, structures, onsite transportation machinery, and stationary items that are located on a single site, on multiple sites or between multiple sites that are owned or operated by the same person or persons and that function as a single integrated site. “Integrated facility” excludes public roads.
“Iron and steel production” means primary iron and steel production processes, secondary steelmaking processes, iron production processes, coke oven battery production processes, iron ore pellet firing processes, or iron and steel powder processes.
“Leakage emissions” means accidental releases and leaks of gases from fossil fuel production and processing, transmission and distribution; iron and steel coke oven batteries; CO_{2} capture, transport, injection, utilization and storage infrastructure.
“Lime production” means all processes that are used to manufacture a lime product by calcination of limestone or other calcareous materials.
“NAICS” means the North American Industry Classification System.
“Nitric acid production” means the use of one or more trains to produce nitric acid through the catalytic oxidation of ammonia.
“Nonvariable fuels” means fuels with consistent properties and hydrocarbon composition.
“Offshore installation” means an offshore drilling unit, production platform or ship, or subsea installation that is attached or anchored to the continental shelf of Canada in connection with the exploitation of oil or natural gas.
“Onsite transportation emissions” means releases from machinery used for the transport or movement of substances, materials, equipment or products that are used in the production process at an integrated facility. This includes releases from vehicles without public road licences.
“Petroleum refining” means processes used to produce 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. This includes catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; coke calcining units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (i.e., compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; flares; sulphur recovery plants; and nonmerchant hydrogen plants that are owned or under the direct control of the refinery owner and operator. This does not include facilities that distill only pipeline transmix or produce lubricants, asphalt paving, roofing, and other saturated materials using already refined petroleum products.
“PFCs” means perfluorocarbons.
“Pipeline transportation system” means all pipelines that are owned or operated by the same person within a province or territory that transport/distribute CO_{2} or processed natural gas and their associated installations, including meter sets and storage installations but excluding straddle plants or other processing installations.
“Pulp and paper production” means separating cellulose fibres from other materials in fibre sources to produce pulp, paper and paper products. This includes converting paper into paperboard products, or operating coating and laminating processes.
“Stationary fuel combustion emissions” means releases from stationary fuel combustion sources, in which fuel is burned for the purpose of producing useful heat or work. This includes releases from the combustion of waste fuels to produce useful heat or work.
“Stationary fuel combustion sources” means devices that combust solid, liquid, gaseous, or waste fuel for the purpose of producing useful heat or work. This includes boilers, electricity generating units, cogeneration units, combustion turbines, engines, incinerators, process heaters, and other stationary combustion devices, but does not include emergency flares.
“Surface leakage” means CO_{2} emitted from geological formations used for long term storage of CO_{2}.
“Variable fuels” means fuels of variable composition.
“Venting emissions” means controlled releases of a process or waste gas, including releases of CO_{2} associated with carbon capture, transport, injection, utilization and storage; from hydrogen production associated with fossil fuel production and processing; of casing gas; of gases associated with a liquid or a solution gas; of treater, stabilizer or dehydrator offgas; of blanket gases; from pneumatic devices which use natural gas as a driver; from compressor startups, pipelines and other blowdowns; from metering and regulation station control loops.
“Waste emissions” means releases that result from waste disposal activities at a facility including, but not limited to, landfilling of solid waste, flaring of landfill gas, and waste or sewage sludge incineration. This does not include releases from the combustion of waste fuels to produce useful heat or work, or releases of CO_{2} from biomass combustion.
“Wastewater emissions” means releases resulting from wastewater and wastewater treatment at a facility. This includes, but is not limited to, releases from flaring of captured gas from wastewater treatment. It does not include releases of CO_{2} from biomass combustion or incineration of sewage sludge (see definition for Waste emissions).
Version  Date  Summary of revisions 

7.0 
December 2023 

6.0 
December 2022 

5.0 
December 2021 

4.0 
December 2020 

3.0 
December 2019 

2.2 
August 2019 

2.1 
May 2019 

2.0 
December 2018 

1.1 
March 2018 

1.0 
December 2017 

Introduction
This document describes the quantification requirements for persons that are required to report information to Environment and Climate Change Canada under Schedules 6 through 18 of the 2024 and 2025 GHGRP Notice, for each of those calendar years. The 2024 and 2025 GHGRP Notice shall prevail over this document, should any inconsistencies be found between them. Note that this document is based upon updates made to Canada’s Greenhouse Gas Quantification Requirements, December 2022.
It is organized as follows:
 Section 1 deals with carbon capture, utilization, transport, and storage facilities
 Section 2 deals with fuel combustion that occurs in facilities
 Section 3 deals with calcination processes in lime manufacturing kilns
 Section 4 deals with clinker production in cement manufacturing kilns
 Section 5 deals with industrial processes in aluminium manufacturing
 Section 6 deals with industrial processes in iron and steel manufacturing
 Section 7 deals with generation of electricity and/or heat
 Section 8 deals with industrial processes in ammonia production (including associated hydrogen production)
 Section 9 deals with industrial processes in nitric acid production
 Section 10 deals with industrial processes (or venting) in hydrogen production (outside of ammonia production)
 Section 11 deals with petroleum refining
 Section 12 deals with industrial processes in pulp and paper production
 Section 13 deals with industrial processes in lead, zinc, copper, nickel, and cobalt production (smelting or refining)
Separate guidance is available in the GHGRP Technical Guide for those persons to whom Schedules 6 through 18 of the 2024 and 2025 GHGRP Notice do not apply.
1 Quantification methods for carbon capture, utilization, transport and storage
If a person subject to the requirements throughout this section is also subject to the OutputBased Pricing System Regulations, methods described in those regulations may be used, where applicable, to quantify the information that the person must report under the applicable schedule in the 2024 and 2025 GHGRP Notice.
 A CO_{2} carbon capture, utilization, transport and storage facility (CCUTS system) consists of some, or all, of the following components:
 A CO_{2} capture facility including all infrastructures, equipment and process modifications designed to capture otherwise vented CO_{2} emissions; calculate the total annual quantity of captured CO_{2} using Equation 11 or Equation 12.
 A CO_{2} pipeline, or other system, used to transport CO_{2}, within Canada, from the capture facility to the injection facility; calculate the total annual quantity of CO_{2} transported using Equation 13 or Equation 14.
 A longterm geological storage facility, including sites injecting CO_{2} both directly into deep saline aquifers and into enhanced fossil fuel recovery operations, with the final goal of longterm storage; calculate the total annual quantity of CO_{2} received for injection and injected using Equation 15 or Equation 16.
A utilization facility, including any sites incorporating captured CO_{2} in products or processes, with the final goal of no release to atmosphere; calculate the total annual quantity of CO_{2} received for injection and injected using Equation 15 or Equation 16.
Figure 11 presents an illustration of a CCUTS system, with required metered reporting locations.
Figure 11: Illustration of CCUTS site and metering points
Long description for Figure 11
"Figure 11: Illustration of CCUTS Site and Metering Points" provides a detailed 3D crosssectional view of a CCUTS facility. The "Domestic Capture CO_{2}" facility, with three grey stacks that emit a grey substance representing captured CO_{2}, is situated in the upper right corner and connects to a blue pipeline. This blue pipeline, featuring metering points 2 and 3, flows into a larger grey pipeline that traverses the facility's surface. Metering point 1, an injection point meter, is located on the blue pipeline where it descents underground, to “Longterm Geologic Storage.” "Imported CO_{2}" is introduced into the large grey pipeline on the left and passes through metering point 4. The grey pipeline spans the terrain with metering points 5 and 6, which are outgoing custody transfer meters, and loops towards the "Other Transport" road marked with a dashed line. The orange pipeline, marked with metering point 7, an incoming custody transfer meter, and metering point 9, an injection point meter, branches off from the grey pipeline and descends into the "Longterm Geologic Storage." The purple pipeline, metered by points 8 and 10, extends from the large grey pipeline and into the ground, through the "Enhanced Fossils Fuel Recovery Operations Site," the site's underground connection. From the purple pipeline is a grey box where the pipeline loops on itself, and “Produced Oil” exits from this box towards the outside of the map. This network of pipelines and metering points maps the journey of CO_{2} from its capture at the facility to its final geological storage.
Meters 1, 9, 10 – Injection point meters
Meters 2, 5, 6 – Outgoing custody transfer meter
Meters 3, 4, 7, 8 – Incoming custody transfer meter
1.A Calculation of annual CO_{2} quantities
To measure annual concentrations, densities, masses and volumes of any CO_{2} quantity captured, utilized, transported or injected, facility operators shall employ measuring and estimating methods published in Alberta Directive 017 – Measurement Requirements for Oil and Gas Operations, AER, 2016 (PDF) or Saskatchewan Directive PNG017 – Measurement Requirements for Oil and Gas Operations, sections 1 and 14. The weighted average parameters used to calculate annual mass of CO_{2} shall be based on all available measurements for the calendar year.
Facility operators shall estimate fugitive emissions associated with CCUTS using standards published in Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry, (PDF) American Petroleum Institute, 2009, section 2.2.5 and Appendix C3.8, or alternate methods proposed in the appropriate sections below.
1.A.1 CO_{2} capture facility
Calculate the annual mass of CO_{2} associated with the capture facility, as measured by the outgoing custody transfer flow meter (Figure 11, Meter 2), using the equations specified in this section.
1.A.1.a Mass flow approach
Calculate the annual mass of CO_{2} flowing through the outgoing custody transfer point flow meter using Equation 11.
Equation 11: Capture – Mass flow
Long description for Equation 11
This equation is used to calculate the annual mass of CO_{2} measured by the outgoing custody transfer point flow meter. For each measurement period "p", the total mass flow "M_p" measured by the outgoing custody transfer point flow meter is multiplied by the weighted average CO_{2} concentration "C_CO_{2} p" expressed as a decimal fraction. This multiplication is iteratively calculated for every period up to the total number "n" of measurement periods in the calendar year. Then, the values of all periods are summed to provide the annual mass of CO_{2} emissions.
Where:
CO_{2} = annual mass of CO_{2} measured by the outgoing custody transfer point flow meter (tonnes)
M_{ p} = total mass flow, measured by the outgoing custody transfer point flow meter, for specified measurement period “p” (tonnes)
C_{ CO2 p} = weighted average CO_{2} concentration at the outgoing custody transfer point flow meter, for specified measurement period “p,” expressed as a decimal fraction
n = number of measurement periods in calendar year
1.A.1.b Volumetric flow approach
Calculate the annual mass of CO_{2} flowing through the outgoing custody transfer flow meter using Equation 12.
Equation 12: Capture – Volumetric flow
Long description for Equation 12
This equation is used to calculate the annual mass of CO_{2} measured by the outgoing custody transfer point production flow meter. For each specified measurement period "p", the total volumetric flow "Q_p" measured by the outgoing custody transfer flow meter, at stated temperature and pressure, is multiplied by the weighted average density of volumetric flow "D_p", and then multiplied by the weighted average CO_{2} concentration "C_CO_{2} p" expressed as a decimal fraction. This process is repeated for every period up to the total 'n'. Finally, the outcomes of all periods are aggregated to yield the annual CO_{2} emissions.
Where:
CO_{2} = annual mass of CO_{2} measured by the outgoing custody transfer point production flow meter (tonnes)
Q_{ p} = total volumetric flow measured by the outgoing custody transfer flow meter, for specified measurement period “p” at stated temperature and pressure (m^{3})
D_{ p} = weighted average density of volumetric flow, for specified measurement period “p” at stated temperature and pressure (tonnes per m^{3})
C_{ CO2 p} = weighted average CO_{2} concentration at the outgoing custody transfer flow meter, for specified measurement period “p” (expressed as a decimal fraction)
n = number of measurement periods in calendar year
If CO_{2} is delivered through more than one flow meter, calculate the sum of the annual mass delivered through all meters.
1.A.2 CO_{2} transport system
Calculate the annual mass of CO_{2} associated with the transport system, measured by the incoming custody transfer flow meters (Figure 11, Meters 3 and 4) and the outgoing custody transfer flow meters (Figure 11, Meters 5 and 6) attached to the CO_{2} pipeline or other transport system, using the equations specified in this section.
1.A.2.a Mass flow approach
Calculate the annual mass of CO_{2} measured by the incoming custody transfer flow meter or the outgoing custody transfer flow meter, using Equation 13.
Equation 13: Transport – Mass flow
Long description for Equation 13
This equation is used to calculate the annual mass of CO_{2} measured by either the incoming custody transfer flow meter or the outgoing custody transfer flow meter attached to the CO_{2} pipeline or another mode of transport. For each measurement period "p", the total flow mass "M_p" measured by the respective custody transfer flow meter is multiplied by the weighted average CO_{2} concentration "C_CO_{2} p" expressed as a decimal fraction. This calculation is performed iteratively for every period until the total number "n" of periods in the calendar year. Subsequently, the results of all periods are summed to compute the annual CO_{2} emissions.
Where:
CO_{2} = annual mass of CO_{2} measured by the incoming custody transfer flow meter or the outgoing custody transfer flow meter attached to the CO_{2} pipeline or other transport mode (tonnes)
M_{ p} = total flow mass measured by the incoming custody transfer flow meter, or the outgoing custody transfer flow meter, for specified measurement period “p” (tonnes)
C_{ CO2 p} = weighted average CO_{2} concentration at the incoming custody transfer flow meter or the outgoing custody transfer flow meter, for specified measurement period “p” expressed as a decimal fraction
n = number of measurement periods in calendar year
1.A.2.b Volumetric flow approach
Calculate the annual mass of CO_{2}, measured by the incoming custody transfer flow meter or the outgoing custody transfer flow meter, using Equation 14.
Equation 14: Transport – Volumetric flow
Long description for Equation 14
This equation is used to calculate the annual mass of CO_{2} measured by either the incoming custody transfer flow meter or the outgoing custody transfer flow meter linked to the CO_{2} pipeline or another transport method. For each reporting period "p", the total volumetric flow "Q_p", gauged by the pertinent custody transfer flow meter at given temperature and pressure, is multiplied by the weighted average density "D_p" and subsequently by the weighted average CO_{2} concentration "C_CO_{2} p" represented as a decimal fraction. This procedure is reiterated for each period up to the total 'n'. Ultimately, the values from all periods are combined to deduce the annual CO_{2} emissions.
Where:
CO_{2} = annual mass of CO_{2} measured by the incoming custody transfer flow meter or the outgoing custody transfer flow meter attached to the CO_{2} pipeline or other transport mode (tonnes)
Q_{ p} = total volumetric flow measured by the incoming custody transfer flow meter, or the outgoing custody transfer flow meter, for specified measurement period “p” at stated temperature and pressure (m^{3})
D_{ p} = weighted average density of flow at stated temperature and pressure, for specified measurement period “p” (tonnes per m^{3})
C_{ CO2 p} = weighted average CO_{2} concentration at the incoming custody transfer flow meter, or the outgoing custody transfer flow meter, for specified measurement period “p” (expressed as a decimal fraction)
n = number of reporting periods in calendar year
If CO_{2} arrives through more than one incoming custody transfer flow meter, or is delivered through more than one outgoing custody transfer flow meter, sum the annual mass of all CO_{2} received or delivered.
1.A.3 CO_{2} injection or utilization sites
For all injection sites, calculate the annual mass of CO_{2} entering the injection site, measured by the incoming custody transfer flow meter (Figure 11, Meters 7 and 8), using Equation 15 or Equation 16.
For sites directly injecting CO_{2} into longterm geologic storage, calculate the annual mass of CO_{2} measured by the injection point flow meter (Figure 11, Meters 1 and 9), using Equation 15.
For sites injecting CO_{2} at enhanced fossil fuel recovery operations, with the final goal of longterm storage, calculate the annual mass of CO_{2} measured by the injection point flow meter (Figure 11, Meter 10), including all recycled CO_{2} volumes or masses, using Equation 15.
For all utilization sites, calculate the annual mass of CO_{2} entering the site, measured by the incoming custody transfer flow meter, using Equation 15 or Equation 16.
1.A.3.a Mass flow approach
Calculate the annual mass of CO_{2} measured by the incoming custody transfer or injection flow meter, using Equation 15.
Equation 15: Injection – Mass flow
Long description for Equation 15
This equation is used to calculate the annual mass of CO_{2} measured by the incoming custody transfer or injection flow meter. For each measurement period "p", the total mass flow "M_p" and the weighted average CO_{2} concentration "C_CO_{2} p" are considered. The core calculation multiplies the total mass flow by the weighted average CO_{2} concentration for each period. This calculation is repeated for every period up to the total "n". Then, the values of all periods are summed to provide the annual CO_{2} measured.
Where:
CO_{2} = annual mass of CO_{2} measured by the incoming custody transfer or injection flow meter (tonnes)
M_{ p} = total mass flow measured by the incoming custody transfer or injection flow meter, for specified measurement period “p” (tonnes)
C_{ CO2 p} = weighted average CO_{2} concentration at the incoming custody transfer or injection flow meter, for specified measurement period “p” expressed as a decimal fraction
n = number of measurement periods in calendar year
1.A.3.b Volumetric flow approach
Calculate the annual mass of CO_{2} measured by incoming custody transfer or injection flow meter, using Equation 16.
Equation 16: Injection – Volumetric flow
Long description for Equation 16
This equation is used to calculate the annual mass of CO_{2} measured by the incoming custody transfer or injection flow meter associated with CO_{2} injection. For each measurement period "p", the total volumetric flow "Q_p", the weighted average density of flow "D_p", and the weighted average CO_{2} concentration "C_CO_{2} p" are taken into account. The core operation multiplies the total volumetric flow by the weighted average density of flow and then by the weighted average CO_{2} concentration for each specific period. This procedure is executed for every period up to the total "n". The results for all periods are subsequently aggregated to yield the annual CO_{2} measured.
Where:
CO_{2} = annual mass of CO_{2} measured by the incoming custody transfer or injection flow meter associated with CO_{2} injection (tonnes)
Q_{ p} = total volumetric flow, measured by the incoming custody transfer or injection flow meter, for specified measurement period “p” at stated temperature and pressure (m^{3})
D_{ p} = weighted average density of flow at stated temperature and pressure, for specified measurement period “p” (tonnes per m^{3})
C_{ CO2 p} = weighted average CO_{2} concentration at the incoming custody transfer or injection flow meter, for specified measurement period “p” (expressed as a decimal fraction)
n = number of measurement periods in calendar year
If CO_{2} is received or injected by more than one incoming custody transfer or injection flow meter, sum the annual mass of all CO_{2} received or injected.
1.A.4 Carbon capture, utilization, transport and storage facility fugitive emissions
1.A.4.a CO_{2} capture
Calculate the annual mass of CO_{2} fugitive emissions from leaks and venting from equipment located between the capture infrastructure (Figure 11, labelled Domestic Capture CO_{2}) and the outgoing custody transfer flow meters or onsite injection wellhead (Figure 11, Meters 1 and 2), in tonnes. Calculate the mass using methods specified in the Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry, (PDF) A.P.I., 2009, section 2.2.5, or alternatively report the mass difference between the metered captured CO_{2 }and the CO_{2 }measured at the outgoing custody transfer meter, as fugitive emissions associated with CO_{2} capture.
1.A.4.b CO_{2} transport system
Calculate the annual mass of CO_{2} from equipment leaks and venting from pipelines, or other methods used to transport the liquefied CO_{2} between the receipt transfer point flow meters (Figure 11, Meters 3 and 4) and the delivery transfer point meters at the longterm storage site (Figure 11, Meters 5 and 6), in tonnes. Where a pipeline, or other transport system, crosses an international border, only calculate and report fugitive emissions for the portion within Canada. Calculate the mass using methods specified in the Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry, (PDF) A.P.I., 2009, section 2.2.5, or alternatively report the mass difference between the annual mass at receipt transfer point flow meters and the annual mass at the delivery transfer point meters as fugitive emissions associated with CO_{2} transport.
1.A.4.c CO_{2} injection or utilization
For injection sites, calculate the annual mass of CO_{2} from equipment leaks and venting from surface equipment located between the incoming custody transfer point flow meters (Figure 11, Meters 7 and 8) and the injection wellhead meters (Figure 11, Meters 9 and 10), in tonnes. Calculate the mass using methods specified in the Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry, (PDF) A.P.I., 2009, section 2.2.5, or alternatively report the mass difference between the incoming custody transfer point flow meters and the injection wellhead meters as fugitive emissions associated with CO_{2} injection.
For utilization sites, calculate the annual mass of CO_{2} from leaks and venting from equipment located between the incoming custody transfer point flow meters and equipment associated with CO_{2} utilization, in tonnes. Calculate the mass using methods specified in the Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry, (PDF) A.P.I., 2009, section 2.2.5, or alternatively report the mass difference between the incoming custody transfer point flow meters and the volume of utilized CO_{2} as fugitive emissions associated with CO_{2} utilization.
1.A.4.d Surface leakage from stored CO_{2}
Calculate the annual mass of CO_{2} from surface leakage associated with longterm geological storage sites, in tonnes. Calculate the mass as specified in the IPCC 2006 Guidelines, (PDF) section 5.7.1 and Appendix Tables A 5.4 and A 5.5.
2 Quantification methods for fuel combustion and flaring
If a person subject to the requirements throughout this section is also subject to the OutputBased Pricing System Regulations, methods described in those regulations may be used, where applicable, to quantify the information that the person must report under the applicable schedule in the 2024 and 2025 GHGRP Notice.
GHG emissions are released when solid, liquid, or gaseous fuels are combusted for the purpose of providing useful heat and work from boilers, simple and combined cycle combustion turbines, engines, incinerators, process heaters, onsite transportation equipment and any other combustion devices. Section 2.A presents CO_{2} estimation methods, while section 2.B presents methods to estimate CH_{4} and N_{2}O for fuel combustion sources.
Fuel combustion de minimis
If the sum of CO_{2}, CH_{4} and N_{2}O emissions (excluding CO_{2} from biomass), in CO_{2} equivalent, from the combustion of one or more fuels does not exceed 0.5% of the total facility GHG emissions from all fuels combusted (excluding CO_{2} from biomass combustion), these fuels and their emissions are not required to be reported.
Burning waste materials in flares releases fugitive emissions. Section 2.C presents methods to estimate emissions from flaring.
Flaring de minimis
If the sum of CO_{2}, CH_{4} and N_{2}O emissions, in CO_{2} equivalent (CO_{2} eq.) from any flare(s) does not exceed 0.5% of the facility total flaring GHG emissions, or 0.05% of facility total combustion GHG emissions, whichever is larger, then these flaring emissions are not required to be reported.
2.A CO_{2} emissions from fuel combustion
To calculate the annual mass of CO_{2} emissions from fuel combustion sources, facility operators can use one or a combination of the quantification methodologies specified in sections 2.A.1 to 2.A.3 for each fuel type. Facilities with Continuous Emission Monitoring (CEM) systems are not obligated to use the CEM system method (Methodology 3) and instead can apply the NonVariable (Methodology 1) and the Variable (Methodology 2) fuels methods. Specification on fuel sampling, analysis and measurement requirements are in section 2.D and guidance for the handling of mixtures of biomass and fossil fuels is in section 2.A.4.
1.A.1.f Methodology 1: Nonvariable fuels method
The method in section 2.A.1 applies to nonvariable fuels that have consistent composition with applicable CO_{2} emission factors.
 Use Equation 21 and Equation 22 for nonvariable fuels with CO_{2} emission factors listed in Table 21 and Table 22.
 Use Equation 23, Equation 24, and Equation 25 or the facilityspecific methodology in section 2.A.1.a(3) with appropriate documentation for onsite transportation, only when information required for Equation 21 or Equation 22 is unavailable.
Methodology 2: Variable fuels method
The variable fuels method in section 2.A.2 applies to fuels whose variable properties and composition require the determination of facility specific carbon content except for biofuels presented in Table 24. A variable fuel is any fuel not included in Table 21 and Table 22.
 Use Equation 26, Equation 27, and Equation 28 for fuels not listed in Table 21, Table 22 or Table 24; apply Equation 29 for natural gas where carbon content is not obtainable from fuel supplier or routinely measured.
 Use Equation 21 and Equation 22 for biomass fuels listed in Table 24 or apply Equation 211 for biomass fuels used to produce steam.
Methodology 3: Continuous emission monitoring (CEM) system
This method applies to combustion units with one or more installed CEM system(s) that include(s) both a flow monitor subsystem and a CO_{2} concentration monitor. Determine CO_{2} emissions data from CEM systems using the prescribed method in section 2.A.3.
Key notes
For mixtures of different fuels, determine and report the portion of each fuel type (e.g., natural gas, diesel, biodiesel, gasoline, ethanol) and apply the appropriate methods for each fuel type combusted.
For internally produced and consumed biomass fuel mixtures, determination of the portion of each fuel type in the mixture is not required. Facilities have the option to consider it as a mixed fuel type or to separate by each fuel type. These variable fuel types require reporting of corresponding information such as carbon content and heating value. An outline of supporting documentation required is presented in Appendix A.
When facilities producing steam to generate electricity and use as heat are unable to determine the actual quantity of fuel used for each purpose, facilities may use the annual quantity of each fuel combusted in the boiler, multiplied by the ratio of steam to produce electricity or heat, to calculate emissions from each. When a facility specific method is used to determine the quantity of fuel used for each purpose, supporting documentation of approach is required (refer to Appendix A for detail).
Use any applicable calculation methodology for one or more of the fuels combusted. For example, if a unit combusts propane and diesel fuel, a facility operator may elect to use the NonVariable Fuels Method for propane and the Variable Fuels Methods for diesel, even though the NonVariable Fuels methods is applicable to both fuel types.
Apply facility specific oxidation factor to CO_{2} emission estimates from fuel combustion, where such factor is based on facility specific unit operation. If applicable, supporting information must be documented and provided.
Provide result of and documentation of the method and information used to derive any facility specific fuel properties for carbon content, higher heating value, emission factor, moisture content for solid fuel along with temperature and pressure for gaseous fuel, when the approach differs from those specified in Section 2 Quantification Methods for Fuel Combustion and Flaring. An outline of contents to include in the document are presented in Appendix A.
2.A.1 Methodology 1: Nonvariable fuels method
This method uses higher heating values (HHV) provided by the supplier or measured at the facility. Nonvariable fuels consist of propane, ethane, butane, gasoline, diesel, ethanol, and biodiesel – all other fuels are variable (see section 2.A.2: Methodology 2: Variable Fuels Method).
Use Equation 21 or Equation 22 to calculate the annual mass of CO_{2} emissions from nonvariable fuels, using CO_{2} emission factors presented in Table 21 and Table 22.
For onsite transportation, if parameters required for Equation 21 or Equation 22 are not available, calculate CO_{2} emissions using either Equation 23, Equation 24 and Equation 25, or sitespecific method in section 2.A.1.a(3)
For facilities in Alberta, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used in place of Equations 21 and 22. More specifically, it is acceptable to use Alberta equation 11 or 11a (if using EF_{ene}) in place of ECCC Equation 21 and Alberta equation 11a (if using EF_{vol}) in place of ECCC Equation 22.
Equation 21: Energybased emissions equation
Long description for Equation 21
This equation is used to calculate the annual mass of CO_{2} emissions for a specific fuel type "i". For each period "p", it considers the energy quantity of fuel type "e", labeled as "Fuel_e", combusted in that period measured in MJ. This quantity is then multiplied by the specific CO_{2} emission factor for the respective fuel type "e", designated as "EF_e", which can be located in Table 21 and Table 22 in energy units. The product of these values is further multiplied by the conversion factor 10^6 to convert the result from grams to tonnes. This process is repeated for every period up to the total "n". Finally, the values of all periods are summed to provide the annual CO_{2} emissions for fuel type "i".
Or
Equation 22: Volume or massbased emissions equation
Long description for Equation 22
This equation is used to calculate is to determine the annual mass of CO_{2} emissions for a specific fuel type "i" based on either volume or mass. For each measurement or delivery period "p", it evaluates the mass or volume of fuel type "i", denoted as "Fuel_i", combusted in that period. The mass is measured in tonnes for solid fuel, whereas the volume is gauged in cubic meters at specific conditions of 15°C and 101.325 kPa for gaseous fuel. This value is then multiplied by the specific CO_{2} emission factor for fuel type "i", termed "EF_2i", which can be found in Table 21 and Table 22 in physical units. The resultant product is then multiplied by the conversion factor 10^3 to adjust the value from kilograms to tonnes. The calculations are performed iteratively across all periods up to the specified total "n". In conclusion, the emissions from all periods are aggregated to yield the annual CO_{2} emissions for the specific fuel type "i".
Where:
CO_{2 i} = annual mass of CO_{2} emissions for a specific fuel type “i” (tonnes)
n = number of fuel heat content measurements for the calendar year, as specified in section 2.D
Fuel_{ i p} = mass or volume of fuel type “i” combusted in measurement or delivery period “p” (mass in tonnes for solid fuel, volume in kilolitres for liquid fuel or volume in cubic meters, at 15°C and 101.325 kPa, for gaseous fuel), as specified in sections 2.D.1 and 2.D.2
Fuel_{ e p} = energy quantity of fuel type “e” combusted in measurement or delivery period “p” (in MJ), as specified in sections 2.D.1 and 2.D.2
EF_{ 1e} = fuel type “e” specific CO_{2} emission factors listed in Table 21 and Table 22, energy units
EF_{ 2 i} = fuel type “i” specific CO_{2} emission factors listed in Table 21 and Table 22, physical units
10^{3} = conversion factor from kilograms to tonnes
10^{6} = conversion factor from grams to tonnes
Fuel  kg/kl  g/MJ 

Ethane  986  57.3 
Propane  1 515  59.9 
Butane  1 747  61.4 
Source: McCann (2000) 
Fuel  kg/kl  g/MJ 

Diesel^{a}  2 681  69.9 
Gasoline^{a}  2 307  69.0 
Ethanol^{a, b}  1 508  64.4 
Biodiesel^{a, c}  2 472  70.3 
a. Environment and Climate Change Canada (2017b) 
2.A.1.a Onsite transportation (nonvariable fuels)
Calculate the annual mass of CO_{2} emissions from onsite transportation using the method described in paragraph 2.A.1.a(1) or calculate emissions using the method described in either paragraph 2.A.1.a(2) or 2.A.1.a(3).
 Calculate CO_{2} emissions from onsite transportation as described under section 2.A.1 Methodology 1: Nonvariable fuels method.
 When fuel consumption data is unavailable, calculate CO_{2} emissions from onsite transportation using Equation 23 or Equation 24 (based on fuel volume) and Equation 25.
Equation 23: Onsite transportation by equipment type – HHV
Long description for Equation 23
E_{CO2 i k q }= (h_{i k} × hp_{i k }× LF_{i k }× BSFC_{i k} × 10^{3}) × HHV_{i q} × EF_{1 i} × 10^{6}
or
Equation 24: Onsite transportation by equipment type – EF
Long description for Equation 24
E_{CO2 i k q} = (h_{i k }× hp_{i k} × LF_{i k} × BSFC_{i k}) × EF_{2 i }× 10^{6}
Equation 25: Onsite transportation
Long description for Equation 25
This equation is used to calculate the total CO_{2} emissions from onsite transportation. For each equipment type "k" and fuel type "q", the quarterly CO_{2} emissions, labeled as "E_CO_{2} i,k,q", are determined by Equations 23 and 24. The core calculation aggregates the emissions from each type of onsite transportation equipment and fuel by summing them together. This summation is iteratively done for each equipment type, up to equipment type "K", and for each fuel type "q", from 1 to 4. Then, the values of all equipment and fuel types are combined to provide the total CO_{2} emissions from onsite transportation.
Where:
E_{ CO2 i k q} = quarterly “q” mass of CO_{2} emissions from each type of onsite transportation equipment “k” and fuel “i” (tonnes)
h_{ i k} = quarterly hours of operation for each type of onsite transportation equipment “k” and fuel “i” (hours)
hp_{ i k} = rated equipment horsepower for each type of onsite transportation equipment “k” and fuel “i” (horsepower)
LF_{ i k} = load factor for each type of onsite transportation equipment “k” and fuel “i” (dimensionless; ranges between 0 and 1)
BSFC_{ i k} = brakespecific fuel consumption for each type of onsite transportation equipment “k” and fuel “i” (litres/horsepowerhour)
HHV_{ i q} = higher heating value of fuel type “i” (MJ/kl) per quarterly period “q” as specified in sections 2.D.1 and 2.D.3
EF_{ 1 i} = emission factor by fuel type “i” (g CO_{2}/MJ) listed in Table 22, energy units
EF_{ 2 i} = emission factor by fuel type “i” (kg CO_{2}/kl) listed in Table 22, physical units
E_{ Total CO2} = total annual mass of CO_{2} emissions by fuel type “i” for all onsite transportation equipment “k” (tonnes)
10^{6} = conversion factor from grams to tonnes
10^{3} = conversion factor from litres to kilolitres
 Onsite transportation equipmentspecific method: If the variables required for Equation 23, Equation 24 and Equation 25 are not available for onsite transportation sources, calculate mass of CO_{2} emissions using the following equipmentspecific method; conduct analysis of hourly fuel use from onsite transportation sources at the facility during a range of typical operations:
 Document and analyze a range of typical operating conditions for the onsite transportation sources at the facility, for each type of onsite transportation equipment in operation, for the calendar year.
 Calculate the average hourly fuel use rate for each range of typical operations.
 Determine the number of hours of each type of operation at the facility in the calendar year.
 Calculate the total annual mass of mobile emissions by multiplying the hours of operation with the average rate of fuel use and the fuelspecific emission factor for each of the typical operations.
 Document and report the methodology used, following the content outline in Appendix A.
2.A.2 Methodology 2: Variable fuels method
Calculate the annual mass of CO_{2} emissions for each type of variable fuel, using measurements of fuel carbon content conducted on site, or provided by the fuel supplier, and the quantity of fuel combusted. There is an alternative methodology for calculating CO_{2} emissions from natural gas combustion when carbon content data is not obtainable.
Note that for facilities in Alberta, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used in place of Equation 26, Equation 27, Equation 28, and Equation 29. More specifically, it is acceptable to use Alberta equation 13d in place of ECCC Equation 26; Alberta equation 13c in place of ECCC Equation 27; and Alberta equation 13a, 13b or 14a to 14c in place of ECCC Equation 28.
2.A.2.a Solid fuels
Use Equation 26 to calculate annual mass of CO_{2} emissions from each type of solid fuel combusted. The fuel quantity applied and carbon content must be based on or adjusted to the same percent moisture content.
Equation 26: Solid fuels
Long description for Equation 26
This equation is used to calculate the annual mass of CO_{2} emissions resulting from the combustion of solid fuel type "i". For each measurement period "p", the volume of solid fuel type 'Fuel_ip' is multiplied by the carbon content 'CC_ip' of that solid fuel type. This result is then multiplied by the ratio of molecular weights, 3.664, representing the CO_{2} to carbon ratio. The obtained values for each period are summed together to produce the annual CO_{2} emissions from the combustion of solid fuel type "i". It should be noted that the applied carbon content might need adjustment based on the moisture content of the fuel.
Where:
CO_{2 i} = annual mass of CO_{2} emissions from the combustion of solid fuel type “i” expressed in tonnes
n = number of carbon content determinations for the calendar year, as specified in section 2.D for solid fuel type “i”
Fuel_{ i p} = total quantity of solid fuel type “i” combusted in measurement period “p” (tonnes), as specified in sections 2.D.1 and 2.D.2
CC_{ i p} = carbon content of solid fuel type “i” from the fuel analysis results for measurement period “p” expressed as decimal mass fraction, as specified in section 2.D.4. The applied CC_{ip} must be adjusted based on percent moisture content of Fuel_{ip}
3.664 = ratio of molecular weights, CO_{2} to carbon
2.A.2.b Liquid fuels
Use Equation 27 to calculate annual mass of CO_{2} emission from each type of liquid fuel combusted.
Equation 27: Liquid fuels
Long description for Equation 27
This equation is used to calculate the annual mass of CO_{2} emissions from the combustion of liquid fuel type "i". For each measurement period "p", the volume of liquid fuel 'Fuel_ip' is multiplied by the carbon content 'CC_ip' for that specific liquid fuel type. Subsequently, this value is multiplied by the ratio of molecular weights, 3.664. The calculated values for all periods are then aggregated to provide the annual CO_{2} emissions from the combustion of liquid fuel type "t".
Where:
CO_{2 i} = annual mass of CO_{2} emissions from the combustion of liquid fuel type “i” (tonnes)
n = number of required carbon content determinations for the calendar year for liquid fuel type “i” as specified in section 2.D
Fuel_{ i p} = volume of liquid fuel type “i” combusted in measurement period “p” (kilolitres), as specified in sections 2.D.1 and 2.D.2
CC_{ i p} = carbon content of liquid fuel type “i” from the fuel analysis results for measurement period “p” (tonne C per kilolitre of fuel), as specified in section 2.D.4
3.664 = ratio of molecular weights, CO_{2} to carbon
2.A.2.c Gaseous fuels
Use Equation 28 to calculate the annual mass of CO_{2} emissions from each type of gaseous fuel combusted. For natural gas only, use Equation 29 when carbon content needed for Equation 28 is not obtainable. For these equations, give fuel volumes at standard conditions (15°C and 101.325 kPa).
Where volume of the gaseous fuel is determined at nonstandard conditions with temperatures between 50°C and 80°C or pressures between 10 kPa and 500 kPa, convert the volume using the ideal gas law presented in Equation 210. For conversion from other temperatures and pressures or for converting from liquid quantities to gaseous volumes, provide a summary of the method used.
Equation 28: All gaseous fuels
Long description for Equation 28
This equation is used to calculate the annual mass of CO_{2} emissions from combustion of gaseous fuel type "i". For each measurement period "p", the volume of gaseous fuel type "i" combusted in that period, labeled as "Fuel_ip", is multiplied by its carbon content, labeled as "CC_ip", and then by the conversion factor 10^3. This accounts for the transition from kilograms to tonnes. The process is carried out for every period up to the total "n". The values from all these periods are then aggregated to give the annual CO_{2}emissions from the combustion of the gaseous fuel.
Where:
CO_{2 i} = annual mass of CO_{2} emissions from combustion of gaseous fuel type “i” expressed in tonnes
n = number of carbon content determinations for the calendar year, as specified in section 2.D for gaseous fuel type “i”
Fuel_{ i p} = volume of gaseous fuel type “i” combusted in period “p” (cubic meters at 15°C and 101.325 kPa), section 2.D.1 and section 2.D.2
CC_{ i p} = carbon content of gaseous fuel type “i” from the fuel analysis results for the period “p” (kg C per cubic meter at 15°C and 101.325 kPa), as specified in sections 2.D.1 and 2.D.4
3.664 = ratio of molecular weights, CO_{2} to carbon
10^{3} = conversion factor from kilograms to tonnes
Equation 29: Natural gas
Long description for Equation 29
This equation is used to calculate the annual mass of CO_{2} emissions resulting from the combustion of natural gas. For each measurement period "p", the volume of natural gas combusted, denoted as "Fuel_p", is multiplied by an empirical equation representing the relationship between carbon dioxide and volume of natural gas, labeled as "(Slope x HHV_p – Intercept)". This product is further multiplied by the conversion factor 10^6 to account for the change from grams to tonnes. The calculations are executed for every period up to the specified "n". To conclude, the outcomes of all periods are consolidated to ascertain the annual CO_{2} emissions from natural gas combustion.
Where:
CO_{2 NG} = annual mass of CO_{2} emissions from combustion of natural gas expressed in tonnes
n = number of fuel heat content measurements for the calendar year, as specified in section 2.D.1
Fuel_{ p} = volume of natural gas fuel combusted during measurement period “p” (cubic meters at 15°C and 101.325 kPa), as specified in sections 2.D.1 and 2.D.2
HHV_{ p} = higher heating value of natural gas for the measurement period “p” (MJ/cubic meter, at 15°C and 101.325 kPa), as specified in sections 2.D.1 and 2.D.3
(Slope × HHV_{ p} – Intercept) = empirical equation (g of CO_{2}/cubic meter of natural gas) representing a very close relationship between carbon dioxide and volume of natural gas determined from composition data of a large discrete set of available data, see Table 23 for a list of slopes and intercepts by region
10^{6} = conversion factor from grams to tonnes
Region  Slope  Intercept 

Atlantic Provinces  62.39  469.7 
Alberta  65.53  581.9 
British Columbia  60.14  378.3 
Manitoba  67.35  654.4 
Ontario  66.20  617.7 
Quebec  62.83  483.2 
Saskatchewan  61.05  402.6 
Territories  60.14  378.3 
Equation 210: Ideal gas equation
Long description for Equation 210
This equation is used to calculate the volume of gaseous fuel at standard temperature and pressure. The measured pressure of the gas volume, indicated as "P_m", is multiplied by the measured volume of the gaseous fuel, "Fuel_m", and the standard temperature, "T_STP". The entire product is then divided by the product of the measured temperature of the gas volume, "T_m", and the standard pressure, "P_STP". Through this equation, one can deduce the volume of the gas under standard conditions from the volume at any given conditions.
Where:
Fuel_{ STP} = volume of gaseous fuel at standard temperature and pressure (volume in cubic meters, at 15°C and 101.325 kPa)
P_{ m} = measured pressure of gas volume, in kPa
Fuel_{ m} = measured volume of gaseous fuel, at P_{m}, in cubic meters
T_{ STP} = standard temperature, 288.15°K
T_{ m} = measured temperature of gas volume Fuel_{m}, in degrees Kelvin
P_{ STP} = standard pressure, 101.325 kPa
2.A.2.d Variable biomass fuels
This section describes methods for calculating CO_{2} emissions from biomass fuels not contained in either Table 21 or Table 22. For these variable biomass fuels, apply methods provided in section 2.A.2.a Solid fuels, 2.A.2.b Liquid fuels, and 2.A.2.c Gaseous fuels for each biomass type.
Alternatively, for biomass fuels listed in Table 24 the methodology in section 2.A.1 Methodology 1: Nonvariable fuels may be applied. Table 24 presents the required emission factors on a dry basis, therefore, the solid biomass fuel quantity applied must be based on or adjusted to a 0% moisture content.
When biomass fuel is used to produce steam use Equation 211: Biomass fuels to calculate the mass of CO_{2} emissions when information on the quantity and type of biomass fuel is not available.
Equation 211: Biomass fuels
Long description for Equation 211
CO_{2 i }= Steam × B × EF_{i} × 10^{6}
Where:
CO_{2 i} = annual mass of CO_{2} emissions from each type of solid biomass fuel “i” (tonnes)
Steam = total mass of steam generated by solid biomass fuel type “i” for the reporting year (tonnes steam)
B = ratio of the boiler’s designrated heat input capacity to its designrated steam output capacity (MJ/tonne steam)
EF_{ i} = emission factor for solid biomass fuel type “i” listed in Table 24, as applicable (g CO_{2}/MJ) or sitespecific emission factor determined through measurements and updated no less than every third year as provided in section 2.D.1, paragraph (8)
10^{6} = conversion factor from grams to tonnes
Biomass fuel  g/kg  g/MJ 

Wood fuel / Wood waste^{a}  1 715  83.9 
Spent pulping liquor – softwood^{b}  1 270  89.5 
Spent pulping liquor – hardwood^{b}  1 230  88.8 
Spent pulping liquor – straw^{b}  1 320  90.1 
a. Adapted from U.S. EPA (2003), assuming 0% moisture content and a higher heating value of 20.44 MJ/kg. 
2.A.2.e Onsite transportation (variable fuels)
Where variable fuels are used, calculate the annual mass of CO_{2} emissions from onsite transportation using Equation 27. If fuel carbon content information required for Equation 27 is not obtainable, derive onsite transportation equipment specific emission factors and follow the approach in section 2.A.1.a. Document and report the approach and information used to derive any onsite transportation equipment specific emission factors, refer to Appendix A for detail.
2.A.3 Methodology 3: Continuous emission monitoring (CEM) system
Calculate the annual mass of CO_{2} emissions from all fuels combusted in a stationary combustion unit, using data from a CEM system as specified in paragraphs 2.A.3(1) through 2.A.3(7). This methodology requires a CO_{2} monitor and a flow monitoring subsystem, except as otherwise provided in paragraph 2.A.3(3). CEM systems shall use methodologies provided in the guidance document on Protocols and Performance Specifications for Continuous Monitoring of Gaseous Emissions from Thermal Power Generation and Other Sources (May 2023, Cat. No.: En832/172023EPDF), hereafter referred to as the “CEMS guidance document.”
 For a facility that operates a CEM system in response to a federal, provincial, or local regulation, use CO_{2} or O_{2} concentrations and flue gas flow measurements to determine hourly CO_{2} mass emissions using methodologies provided in the CEMS guidance document.
 Calculate the annual mass CO_{2} emissions for the reporting year, expressed in tonnes, based on the sum of hourly CO_{2} mass emissions for the calendar year.
 Facility operators may use an oxygen (O_{2}) concentration monitor in place of a CO_{2} concentration to determine the hourly CO_{2} concentrations, under two conditions.
 One, if the effluent gas stream monitored by the CEM system consists solely of combustion products (i.e. no process CO_{2} emissions or CO_{2} emissions from acid gas control are mixed with the combustion products).
 Two, if only the following fuels are combusted in the unit: coal, petroleum coke, oil and refined petroleum products, natural gas, propane, butane, wood bark, or wood residue.
Additionally:
a) Units combusting wastederived fuels (as defined in the General Provisions and including municipal solid waste), should not base emissions calculations on O_{2} concentrations.
b) Facilities combusting biomass fuels and using O_{2} concentrations to calculate CO_{2} concentrations, should demonstrate, using annual source testing, that calculated CO_{2} concentrations compared to measured CO_{2} concentrations, meet the Relative Accuracy Test Audit (RATA) requirements in the CEMS guidance document.
 If both biomass and fossil fuels (including fuels that are partially biomass) are combusted during the year, determine the biogenic CO_{2} mass emissions separately, as described in section 2.A.4.
 For any units using CEM system data, provide industrial process and stationary combustion CO_{2} emissions separately; determine the annual quantities of each type of fossil fuel and biomass consumed, using the fuel sampling approach in sections 2.D.1 and 2.D.2.
 If a facility subject to requirements for continuous monitoring of gaseous emissions chooses to add devices to an existing CEM system for the purpose of measuring CO_{2} concentrations or flue gas flow, select and operate the added devices using appropriate requirements for the facility, as applicable in Canada.^{Footnote 1}
 If a facility does not have a CEM system and chooses to add one in order to measure CO_{2} concentrations, select and operate the CEM system using the appropriate requirements or equivalent requirements as applicable in Canada1 —CEM systems added are subject to the specifications in paragraphs 2.A.3(1) through 2.A.3(5), if applicable.
2.A.4 CO_{2} emissions from combustion of mixtures of biomass and fossil fuels
Use the procedures in this section to estimate biogenic CO_{2} emissions from units that combust a combination of biomass and fossil fuels, including combustion of wastederived fuels (e.g. wood waste and tires) that are partially biomass.
1. If a CEM system is not used to measure CO_{2} and the facility combusts biomass fuels that does not include wastederived fuels, use Methodology 1 or 2, as applicable, to calculate the annual biogenic CO_{2} mass emissions from the combustion of biomass fuels.
 Determine the quantity of biomass combusted using either company records or, for premixed fuels that contain biomass and fossil fuels (e.g., mixtures containing biodiesel), the best available supplier information and document the procedure.
2. If a CEM system is used to measure CO_{2} (or O_{2} as a surrogate) and the facility combusts biomass fuels that do not include wastederived fuels, use Methodology 1 or 2 to calculate the annual CO_{2} mass emissions from the combustion of fossil fuels.
 Calculate biomass fuel emissions by subtracting the fossil fuelrelated emissions from the total CO_{2} emissions determined from the CEM system methodology.
3. If combusted fuels or fuel mixtures contain a biomass fraction that is unknown or cannot be documented (e.g., tirederived fuel), or biomass fuels with no CO_{2} emission factor provided in Table 22 and Table 24, use the following to estimate biogenic CO_{2} emissions:
a) Methodology 2 or Methodology 3 to calculate the total annual CO_{2} mass emissions, as applicable.
b) Determine the biogenic portion of the CO_{2} emissions using ASTM D686616  Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis.
 This procedure is not required for fuels containing less than 5 percent biomass by weight or for wastederived fuels that are less than 30 percent by weight of total fuels combusted in the emissions reporting year, except, if a person wishes to report a biomass fuel fraction of CO_{2} emissions.
c) Conduct analysis of representative fuel or exhaust gas samples at least every three months, using ASTM D686616.
 Collect the exhaust gas samples over a minimum of 24 consecutive hours following the standard practice specified by ASTM D745908 (2016) Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and FossilDerived Carbon Dioxide Emitted from Stationary Emissions Sources.
 If municipal solid waste is combusted, perform ASTM D686616 analysis on the exhaust gas stream.
d) Divide total CO_{2} emissions between biomass fuel emissions and nonbiomass fuel emissions using the average proportions of the samples analyzed in the reporting year.
e) If there is a common fuel source for multiple units at the same facility, ASTM D686616 analysis may be done at only one unit.
2.B CH_{4} and N_{2}O emissions from fuel combustion
Calculate the annual mass of CH_{4} and N_{2}O emissions from fuel combustion sources, for each fuel type, using methods specified in this section.
For facilities in Alberta, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used where appropriate. More specifically, it is acceptable to use Alberta equation 15 or 15a (if using EF_{ene}) in place of ECCC Equation 212; Alberta equation 15a (if using EF_{vol}) in place of ECCC Equation 213; and Alberta equation 15b in place of ECCC Equation 218.
 If directly measured, or fuel supplier provided, higher heating values (HHVs) are available, calculate annual CH_{4} and N_{2}O emissions using Equation 212.
Equation 212: CH_{4} and N_{2}O HHV methods, in energy units
Long description for Equation 212
This equation is used to calculate the annual mass of CH₄ or N₂O emissions for a specific fuel type 'e'. For each measurement or delivery period 'p', the energy quantity of the fuel type 'e' combusted is labeled as 'Fuel_ep'. This is multiplied by the CH₄ or N₂O emission factor for the fuel type 'e', denoted as 'EF_e'. The emission factor 'EF_e' is provided in tables ranging from Table 25 to Table 212 by the fuel supplier or equipment manufacturer, or it might be derived at the facility. The product of this multiplication is then multiplied by the appropriate conversion factor 'k'. The value of 'k' depends on the units of the 'EF' and is typically obtained from the tables mentioned or derived at the facility. The majority of energy based 'EF's in Table 25 to Table 212 require a conversion factor of 10^3. The calculation is repeated for every period up to the total 'n'. Then, the values of all periods are summed to provide the annual CH₄ or N₂O emissions.
Where:
CH_{4 e} or N_{2}O_{e} = annual mass of CH_{4} or N_{2}O emissions for fuel type “e” tonnes CH_{4} or N_{2}O per year.
Fuel_{ e p} = energy quantity of fuel type “e” combusted in measurement or delivery period “p” (in MJ), as specified in sections 2.D.1 and 2.D.2
EF_{e} = CH_{4} or N_{2}O emission factor by fuel type “e” provided in Table 25 through Table 212 or provided by the fuel supplier or equipment manufacturer, in energy units
n = number of measurement periods in calendar year
k = the appropriate conversion factor to tonnes CH_{4} or N_{2}O, depending on the units of the EF either obtained from Table 25 to Table 212, from the fuel supplier or equipment manufacturer, or derived at the facility (the majority of energy based EFs in Table 25 to Table 212 (g/GJ) require conversion factor of 10^{9})
2. Where HHV is not available from fuel supplier or routinely measured, use Equation 213 to calculate the annual CH_{4} and N_{2}O emissions.
Equation 213: CH_{4} and N_{2}O HHV value methods, in physical units
Long description for Equation 213
This equation is used to calculate the annual mass of CH₄ or N₂O emissions from fuel type 'e'. For each measurement or delivery period 'p', the mass or volume of the fuel type 'e' combusted is designated as 'Fuel_ep'. For solid fuels, this is given in tonnes, while for liquid fuel it is in kilolitres, and for gaseous fuel, it's in cubic meters. This is multiplied by the CH₄ or N₂O emission factor for the fuel type 'e', labeled as 'EF_i'. This emission factor can be found in tables ranging from Table 25 to Table 212, provided by the fuel supplier, equipment manufacturer, or can be derived at the facility. The resulting product is multiplied by the conversion factor 'k', which is 10^3 for liquid and solid fuels and 10^6 for gaseous fuels. This calculation is iteratively performed for each period up to the total 'n'. Finally, the values of all periods are aggregated to yield the annual CH₄ or N₂O emissions.
Where:
CH_{4 i} or N_{2}O_{i} = annual mass of CH_{4} or N_{2}O emissions for fuel type “i” tonnes CH_{4} or N_{2}O per year
Fuel_{ i p} = mass or volume of fuel type “i” combusted in measurement or delivery period “p” (mass in tonnes for solid fuel, volume in kilolitres for liquid fuel or volume in cubic meters, at 15°C and 101.325 kPa, for gaseous fuel), as specified in sections 2.D.1 and 2.D.2
EF_{ i} = CH_{4} or N_{2}O emission factor by fuel type “i” provided in Table 25 through Table 212, provided by the fuel supplier or equipment manufacturer, or facility derived, in physical units
n = number of measurement periods in calendar year
k = 10^{3} for liquid and solid fuels; 10^{6} for gaseous fuels; or otherwise, the appropriate conversion factor to tonnes CH_{4} or N_{2}O, depending on the units of the EF either obtained from the fuel supplier or equipment manufacturer or derived at the facility
 Facility or equipment specific emission factors may also be determined based on source tests or from equipment manufacturer for use in quantifying CH_{4} and N_{2}O emissions using Equation 213.
 For coke oven battery CH_{4} and N_{2}O emissions, if the fuel mass or volume by fuel type is unknown, the total annual quantity of coke produced (tonnes) may be used.
 Document the method used to derive facility specific CH_{4} and N_{2}O emission factors (See Appendix A).
 CEMS – Estimate the annual mass of CH_{4} and N_{2}O emissions, for units using Methodology 3 (CEMS) and with year round monitored heat input, using Equation 214.
Equation 214: CH_{4} and N_{2}O CEM methods
Long description for Equation 214
CH_{4 i }or N_{2}O_{i} = (HI)_{A i} × EF_{i} × 10^{6}
Where:
CH_{4i} or N_{2}O_{i} = annual mass of CH_{4} or N_{2}O emissions from the combustion of a specific type of fuel “i” expressed in tonnes
(HI)_{A i} = cumulative annual heat input from the fuel (MJ), provided by fuel type “i”
EF_{ i} = fuelspecific emission factor for CH_{4} or N_{2}O by fuel type “i” listed in Table 25 to Table 212 (grams/MJ or grams/kilogram of coal)
10^{6} = conversion factor from grams to tonnes
Source  CH_{4} g/m^{3} 
N_{2}O g/m^{3} 
CH_{4} g/GJ 
N_{2}O g/GJ 

Electric Utilities  0.49  0.049  13  1.3 
Industrial  0.037  0.033  0.98  0.87 
Producer Consumption (NonMarketable)^{a}  6.4  0.06  140  1.3 
Pipelines  1.9  0.05  50  1.3 
Cement  0.037  0.034  0.98  0.90 
Manufacturing Industries  0.037  0.033  0.98  0.87 
Residential, Construction, Commercial/Institutional, Agriculture  0.037  0.035  0.98  0.92 
OnSite Transportation^{b}  9  0.06  0.2  0.002 
Source: SGA Energy (2000) 
Fuel  CH_{4} kg/kl 
N_{2}O kg/kl 
CH_{4} g/GJ 
N_{2}O g/GJ 

Ethane  0.024  0.108  1.4  6.3 
Propane – Industry  0.024  0.108  0.95  4.3 
Propane – OnSite Transportationa,^{a, b}  0.64  0.087  25  3.4 
Butane  0.024  0.108  0.84  3.8 
Source: SGA Energy (2000) 
Fuel by source or by technology  CH_{4} kg/kl 
N_{2}O kg/kl 
CH_{4} g/GJ 
N_{2}O g/GJ 

Diesel: All Industry – Stationary Combustion^{a}  0.078  0.02  2.0  0.58 
Diesel: Upgraders – Stationary Combustion^{a}  0.078  0.02  2.0  0.58 
Diesel: Onsite Transportation, <19kW^{a}  0.073  0.02  1.9  0.58 
Diesel: Onsite Transportation, >=19kW, Tier 13^{a}  0.073  0.02  1.9  0.58 
Diesel: Onsite Transportation, >= 19kW, Tier 4^{a}  0.073  0.23  1.9  5.9 
Gasoline: All Industry – Stationary Combustion^{c}  0.1  0.02  3.0  0.6 
Gasoline: Onsite Transportation, 2stroke^{a}  10.6  0.013  320  0.38 
Gasoline: Onsite Transportation, 4stroke^{a}  5.08  0.064  150  1.9 
Light Fuel Oil: Utilities^{b}  0.18  0.031  4.6  0.80 
Light Fuel Oil: Industrial^{b}  0.006  0.031  0.15  0.80 
Light Fuel Oil: Forestry, Construction, Public Administration and Commercial/Institutional^{b}  0.026  0.031  0.67  0.80 
Heavy Fuel Oil: Utilities^{b}  0.034  0.064  0.80  1.5 
Heavy Fuel Oil: Industrial^{b}  0.12  0.064  2.8  1.5 
Heavy Fuel Oil: Forestry, Construction, Public Administration and Commercial/Institutional^{b}  0.057  0.064  1.3  1.5 
Kerosene: Electric Utilities^{b}  0.006  0.031  0.16  0.83 
Kerosene: Industrial^{b}  0.006  0.031  0.16  0.83 
Kerosene: Forestry, Construction, Public Administration and Commercial/Institutional^{b}  0.026  0.031  0.70  0.83 
Ethanol:* All Industry – Stationary Combustion^{a}  0.1  0.02  4.3  0.85 
Ethanol: Onsite Transportation, 2stroke  10.6  0.013  450  0.54 
Ethanol: Onsite Transportation, 4stroke  5.08  0.064  220  2.7 
Biodiesel:** All Industry – Stationary Combustion^{a}  0.078  0.02  2.2  0.63 
Biodiesel: Upgraders – Stationary Combustion^{a}  0.078  0.02  2.2  0.63 
Biodiesel: Onsite Transportation, <19kW^{a}  0.073  0.02  2.1  0.63 
Biodiesel: Onsite Transportation, >=19kW, Tier 13^{a}  0.073  0.02  2.1  0.63 
Biodiesel: Onsite Transportation, >= 19kW, Tier 4^{a}  0.073  0.23  2.1  6.4 
a. Oak Leaf Environmental (2017) 
Source by coal type and by region  CH_{4} g/kg 
N_{2}O g/kg 
CH_{4} g/GJ 
N_{2}O g/GJ 

Electric Utilities: Anthracite  0.022  0.032  0.70  1.0 
Electric Utilities: Canadian Bituminous  0.022  0.032  0.78  1.1 
Electric Utilities: Foreign Bituminous  0.022  0.032  0.74  1.1 
Electric Utilities: Lignite (Saskatchewan)  0.022  0.032  1.4  2.0 
Electric Utilities: Lignite (All other provinces)  0.022  0.032  1.4  2.0 
Electric Utilities: SubBituminous (Manitoba, Ontario)  0.022  0.032  1.1  1.5 
Electric Utilities: SubBituminous (Alberta, British Columbia, Saskatchewan)  0.022  0.032  1.2  1.7 
Electric Utilities: SubBituminous (New Brunswicka)  0.022  0.032  0.8  1.2 
Electric Utilities: SubBituminous (all other provinces)  0.022  0.032  1.1  1.7 
Industry and Heat & Steam Plants: Anthracite  0.03  0.02  0.9  0.63 
Industry and Heat & Steam Plants: Canadian Bituminous  0.03  0.02  1.1  0.70 
Industry and Heat & Steam Plants: Foreign Bituminous  0.03  0.02  1.0  0.67 
Industry and Heat & Steam Plants: Lignite (Saskatchewan)  0.03  0.02  1.8  1.2 
Industry and Heat & Steam Plants: Lignite (All other provinces)  0.03  0.02  1.9  1.2 
Industry and Heat & Steam Plants: SubBituminous (Manitoba, Ontario)  0.03  0.02  1.4  1.0 
Industry and Heat & Steam Plants: SubBituminous (Alberta, British Columbia, Saskatchewan)  0.03  0.02  1.6  1.1 
Industry and Heat & Steam Plants: SubBituminous (all other provinces)  0.03  0.02  1.6  1.0 
Residential, Public Administration: Anthracite  4  0.02  100  0.63 
Residential, Public Administration: Canadian Bituminous  4  0.02  100  0.70 
Residential, Public Administration: Foreign Bituminous  4  0.02  100  0.67 
Residential, Public Administration: Lignite (Saskatchewan)  4  0.02  200  1.2 
Residential, Public Administration: Lignite (all other provinces)  4  0.02  200  1.2 
Residential, Public Administration: SubBituminous (Manitoba, Ontario)  4  0.02  200  1.0 
Residential, Public Administration: SubBituminous (Alberta, British Columbia, Saskatchewan)  4  0.02  200  1.1 
Residential, Public Administration: SubBituminous (all other provinces)  4  0.02  200  1.0 
Residential, Public Administration: Coke  0.03  0.02  1.0  0.69 
Residential, Public Administration: Coke Oven Gas  0.037 g/m^{3}  0.035 g/m^{3}  1.9  1.8 
Source: SGA Energy (2000) 
Petroleum Coke  CH_{4} (kg/m^{3})  CH_{4} (g/GJ)  N_{2}O (kg/m^{3})  N_{2}O (g/GJ) 

Upgrading Facilities^{a}  0.12  3.0  0.024  0.59 
Refineries & Others^{b}  0.12  2.5  0.0275  0.579 
Source: Emission Factors: Adapted from IPCC (2006) (PDF) 
Fuel  CH_{4} (g/m^{3})  CH_{4} (g/GJ)  N_{2}O (g/m^{3})  N_{2}O (g/GJ) 

Still Gas^{a, b}  0.032  0.83  0.02  0.5 
a. Adapted from IPCC (2006) (PDF) and CEEDC (Griffin, B. 2020). 
Fuel  CH_{4} (kg/GJ)  N_{2}O (kg/GJ) 

Waste  0.03  0.004 
Adapted from IPCC (2006) (PDF) 
Biomass Fuel  CH_{4} (g/kg)  N_{2}O (g/kg)  CH_{4} (g/GJ)  N_{2}O (g/GJ) 

Wood Fuel / Wood Waste^{a}  0.10  0.07  4.74  3.25 
Spent Pulping Liquor^{b}  0.029  0.005  2.09  0.38 
a. Adapted from U.S. EPA (2003) and NCASI (2012), assuming 0% moisture content and a higher heating value of 20.44 MJ/kg. 
2. OnSite Transportation – Calculate the annual mass of CH_{4} or N_{2}O emissions from onsite transportation using the method described in paragraph 2.B(1) or 2.B(2) with the emission factors presented in Table 27.
 If Table 27 does not present the required emission factor, derive onsite transportation equipment specific CH_{4} and N_{2}O emission factors and document and report the methods used.
 If fuel consumption data is not obtainable from fuel supplier or routinely measured, calculate emissions using either of the alternative calculation methods described in paragraphs 2.B(5)(A) or 2.B(5)(B).
(A) Alternative calculation – Calculate the annual mass of CH_{4} or N_{2}O emissions from onsite transportation for each fuel type using Equation 215 and Equation 217; use Equation 216 in place of Equation 215, if the HHV is not obtainable from fuel supplier or routinely measured.
Equation 215: Onsite transportation by type of equipment in energy units
Long description for Equation 215
E_{g i k q} = (h_{i k} × hp_{i k} x LF_{i k }× BSFC_{i k}) × HHV_{i q} × EF_{1 g i} × 10^{6}
Or
Equation 216: Onsite transportation by type of equipment in physical units
Long description for Equation 216
E_{g i k q }= (h_{i k }× hp_{i k }× LF_{i k} × BSFC_{i k}) × EF_{2 g i }× 10^{3}
Equation 217: Onsite transportation
Long description for Equation 217
This equation aggregates the greenhouse gas emissions from all distinct types of onsite transportation equipment and fuels. It calculates emissions for each equipment type "k" and fuel type "l" represented as "E_gikl". The equation methodically combines all these individual emission values, resulting in a comprehensive total emission for all equipment and fuel categories, using summation notation.
Where:
E_{ g i k q} = quarterly “q” mass of greenhouse gas “g” (CH_{4} or N_{2}O) emissions from each type of onsite transportation equipment “k” and fuel “i” (tonnes)
h_{ i k} = quarterly hours of operation for each type of onsite transportation equipment “k” and fuel “i” (hours)
hp_{ i k} = rated equipment horsepower for each type of onsite transportation equipment “k” and fuel “i” (horsepower)
LF_{ i k} = load factor for each type of onsite transportation equipment “k” and fuel “i” (dimensionless; ranges between 0 and 1)
BSFC_{ i k} = brakespecific fuel consumption for each type of onsite transportation equipment “k” and fuel “i” (litres/horsepowerhour)
HHV_{ i q} = higher heating value of fuel type “i” (MJ/kl) per quarterly period “q” as specified in sections 2.D.1 and 2.D.3
EF_{ 1 g i} = emission factor by CH_{4} or N_{2}O “g” and by fuel type “i” listed in Table 27, in energy units
EF_{ 2 g i} = emission factor by CH_{4} or N_{2}O “g” and by fuel type “i” listed in Table 27, in physical units
E_{ Total g i} = total annual mass of greenhouse gas “g” (CH_{4} or N_{2}O) emissions by fuel type “i” for all onsite transportation equipment “k” (tonnes)
10^{3} = conversion factor from kilograms to tonnes
10^{6} = conversion factor from grams to tonnes
 (B) Alternative calculation – Calculate the annual mass of CH_{4} or N_{2}O emissions using the following facility specific method; conduct analysis of hourly fuel use from onsite transportation sources at the facility during a range of typical operations:
 Document and analyze a range of typical operating conditions for the onsite transportation sources at the facility, for each type of onsite transportation equipment in operation, for the calendar year.
 Calculate the average hourly fuel use rate for each range of typical operations.
 Determine the number of hours of each type of operation at the facility in the calendar year.
 Calculate the total annual mass of mobile emissions by multiplying the hours of operation with the average fuel use rate and the fuelspecific emission factor from for each of the typical operations.
 Document and report the methodology used.
3. Biomass – Use Equation 218 to estimate CH_{4} and N_{2}O emissions for biomass combustion based on quantity of steam generated when unable to determine the quantity of biomass fuel to apply Equation 212 or Equation 213.
Equation 218: CH_{4} and N_{2}O biomass method
Long description for Equation 218
CH_{4} or N_{2}O = Steam × B × EF × 10^{6}
Where:
CH_{4} or N_{2}O = annual mass of CH_{4} or N_{2}O emissions from the combustion of biomass (tonnes)
Steam = total mass of steam generated by biomass combustion during the reporting year (tonnes steam)
B = ratio of the boiler design rated heat input capacity to design rated steam output (MJ/tonne steam)
EF = fuelspecific emission factor for CH_{4} or N_{2}O from Table 212, as applicable (grams per MJ)
10^{6} = conversion factor from grams to tonnes
2.C Fugitive emissions from flaring
Calculate and report CO_{2}, CH_{4} and N_{2}O emissions resulting from the combustion of flare pilot and hydrocarbons routed to flares for destruction using the appropriate method(s) specified.
2.C.1 CO_{2} emissions from flaring
(1) Heat value or carbon content measurement – if continuously monitoring HHV or gas composition at the flare or if monitoring these parameters at least weekly, use the measured HHV or carbon content value in calculating the CO_{2 }emissions from the flare using the applicable methods in paragraphs (A) and (B) of this section.
 (A) For monitored gas composition, calculate the CO_{2} emissions from the flare using Equation 219 of this section.
Equation 219: CO_{2} from flaring – CC
Long description for Equation 219
This equation is used to calculate the annual CO₂ emissions from flaring for a specific fuel type. For each measurement period "p," the volume of flare gas "Flare_p," given in cubic meters, is specified for petroleum refineries at reference conditions and is multiplied by the ratio of molecular weights 3.664. This product is then multiplied by the average molecular weight of the flare gas "MW_p," divided by the molar volume conversion factor "MVC" which is defined as 8.3145 times the sum of 273.16 and the reference temperature in °C, divided by the reference pressure in kilopascal. This value is further multiplied by the average carbon content of the flare gas "CC_p," given in kg C per kg flare gas. The resulting value is multiplied by the flare combustion efficiency "CE" and the conversion factor 10^3. This process is repeated for every period up to the total "n." Then, the values of all periods are summed to provide the annual CO₂ emissions for the specified fuel type.
Where:
CO_{2i} = annual CO_{2} emissions for a specific fuel type “i” (tonnes)
CE = flare combustion efficiency measured at the facility; assume a 0.98 flare combustion efficiency if facility efficiency data is unavailable
10^{3} = conversion factor from kilograms to tonnes
n = number of measurement periods as specified in section 2.C.1(1)
3.664 = ratio of molecular weights, CO_{2} to carbon
(Flare)_{p} = volume of flare gas during measurement period “p” at 15°C and 101.325 kPa for gaseous fuels (m^{3}/period) or, specific to petroleum refineries, at dry reference condition at 25°C, 101.325 kPa and 0% moisture (dRm^{3}/period); if a mass flow meter is used, measure flare gas flow rate in kg/period and set (MW)_{p}/MVC= 1
(MW)_{p} = average molecular weight of the flare gas combusted during measurement period “p” (kg/kgmole); if measurements are more frequent than daily, use the arithmetic average of measurement values within the day
MVC = molar volume conversion factor at the same reference conditions as the above (Flare)_{p} (m^{3}/kgmole)
= 8.3145 * [273.16 + reference temperature in °C]/[reference pressure in kilopascal]
(CC)_{p} = average carbon content of the flare gas combusted during measurement period “p” (kg C per kg flare gas) as specified in section 2.D.4; if measurements are more frequent than daily, use the arithmetic average of measurement values within the day)
 (B) For monitored heat content, when gas composition is not obtainable, calculate the CO_{2} emissions from the flare using Equation 220 of this section.
Equation 220: CO_{2} from flaring – HHV
Long description for Equation 220
This equation is used to calculate the annual CO₂ emissions from flaring based on a specific fuel type's high heat value (HHV). For each measurement period "p," the volume of flare gas "Flare_p," provided in cubic meters, is taken at the reference conditions established by the facility and multiplied by the fuel's high heat value "HHV_p" and the specific CO₂ emission factor "EF." The product is then multiplied by the flare combustion efficiency "CE" and the conversion factor 10^3. This calculation is iteratively performed for every period until the total number "n" is reached. The values for all periods are then aggregated to yield the annual CO₂ emissions for the designated fuel type.
Where:
CO_{2i} = annual CO_{2} emissions for a specific fuel type “i” (tonnes)
CE = flare combustion efficiency measured at the facility. Assume a 0.98 flare combustion efficiency if facility efficiency data is unavailable
10^{3} = conversion factor from kilograms to tonnes
n = number of measurement periods as specified in section 2.C.1(1)
(Flare)_{p} = volume of flare gas during measurement period “p” at reference temperature and pressure conditions as used by the facility (m^{3}/period); if a mass flow meter is used, also measure molecular weight and convert the mass flow to a volumetric flow as follows: Flare[m^{3}] = Flare[kg] ×MVC/(MW)_{p}, where MVC is the molar volume conversion factor at the same reference conditions as (Flare)_{p} ,15°C and 101.325 kPa for gaseous fuels (m^{3}/ kgmole) or, specific to petroleum refineries, dry reference condition, 25°C, 101.325 kPa and 0% moisture (dRm^{3}/kgmole), and (MW)_{p} is the average molecular weight of the flare gas during measurement period p (kg/kgmole)
(HHV)_{p} = high heat value for the flare gas combusted during measurement period “p” (GJ per m^{3}); for measurement frequencies greater than daily, use the arithmetic average of measurement values within the day
EF = apply facility specific CO_{2} emission factor. When facility specific factor is not available assume default CO_{2} emission factor of 62.4 kg CO_{2}/GJ (HHV basis)
(2) Alternative Method – for startup, shutdown, and malfunctions during which there are no measured parameters required by Equation 219 and Equation 220 of this section, determine the quantity of gas discharged to the flare separately for each startup, shutdown, or malfunction, and calculate the CO_{2} emissions as specified in paragraphs (A) and (B).
 (A) For periods of startup, shutdown, or malfunction, use engineering calculations and process knowledge to estimate the carbon content of the flared gas for each startup, shutdown, or malfunction event.
 (B) Calculate the CO_{2} emissions using Equation 221 of this section.
Equation 221: CO_{2} from flaring – Alternative
Long description for Equation 221
This equation is used to calculate the annual CO₂ emissions from flaring in scenarios such as startups, shutdowns, or malfunctions throughout the year. For each event "p," the volume of flare gas during such events "Flare_SSM p" is derived from engineering calculations and is multiplied by the ratio of molecular weights 3.664. The product is then multiplied by the average molecular weight of the flare gas "MW_p," divided by the molar volume conversion factor "MVC" which is specified in a similar fashion to the prior equations. This result is then further multiplied by the average carbon content "CC_p" of the flare gas. Multiplying by the flare combustion efficiency "CE" and the conversion factor 10^3 completes the calculation for each event. This method is iterated for every event up to the specified total, and the resultant values are summed to determine the annual CO₂ emissions for the fuel type.
Where:
CO_{2i} = annual CO_{2} emissions for a specific fuel type “i” (tonnes)
CE = flare combustion efficiency measured at the facility; assume a 0.98 flare combustion efficiency, if facility efficiency data is unavailable
10^{3} = conversion factor from kilograms to tonnes
n = number of startup, shutdown, and malfunction events during the reporting year
(Flare_{SSM})_{p} = volume of flare gas during startup, shutdown, or malfunction event “p” from engineering calculations, at 15°C and 101.325 kPa (m^{3}/ event) or specific to petroleum refineries at dry reference conditions 25°C, 101.325 kPa and 0% moisture (dRm^{3}/event); if a mass flow meter is used, measure the flare gas in kg per event and set (MW)_{p}/MVC= 1
(MW)_{p} = average molecular weight of the flare gas, from the analysis results or engineering calculations for the event “p” (kg/kgmole)
MVC = molar volume conversion factor at the same reference conditions as the above (Flare_{SSM})_{p} (m^{3}/kgmole)
= 8.3145 * [273.16 + reference temperature in °C]/[reference pressure in kilopascal]
(CC)_{p} = average carbon content of the flare gas, from analysis results or engineering calculations for the event “p” (kg C per kg flare gas)
3.664 = ratio of molecular weights, CO_{2} to carbon
2.C.2 CH_{4} and N_{2}O emissions from flaring
Calculate and report CH_{4} and N_{2}O emissions resulting from the combustion of hydrocarbons routed to flares for destruction using the methods specified in paragraphs (1) and (2):
(1) Calculate CH_{4} emissions using Equation 222 of this section.
Equation 222: CH_{4} from flaring
Long description for Equation 222
This equation is used to calculate the annual methane emissions originating from flared gas. It considers the CO₂ emissions "CO₂" previously determined from flared gas and multiplies them by the fuelspecific CH₄ emission factor "EF_CH4," divided by the CO₂ emission factor "EF." This product is added to the difference of 1 and the flare combustion efficiency "CE", divided by "CE", and multiplied by a ratio of molecular weights 16/44 and the weight fraction "f_CH4" of carbon in the flare gas attributed to methane, which has a default value of 0.4. The final result yields the annual methane emissions from the flared gas.
Where:
CH_{4} = annual methane emissions from flared gas (tonnes)
CO_{2} = emissions of CO_{2} from flared gas calculated in paragraph 2.C.1 (tonnes)
EF_{CH4} = apply facility specific CH_{4} emission factor. When facility specific factor is not available assume default CH_{4} emission factor of 0.83 x 10^{3} kg/GJ^{Footnote 2}
EF = apply facility specific CO_{2} emission factor. When facility specific factor is not available assume default CO_{2} emission factor for flare gas of 62.4 kg CO_{2}/GJ (HHV basis)
CE = flare combustion efficiency measured at the facility (assume a 0.98 flare combustion efficiency if facility efficiency data is unavailable)
(1 – CE)/CE = correction factor for flare combustion efficiency
16/44 = ratio of molecular weights, CH_{4} to CO_{2}
f_{CH4} = weight fraction of carbon in the flare gas prior to combustion that is contributed by methane from measurement values or engineering calculations (kg C in methane in flare gas/kg C in flare gas); default is 0.4
(2) Calculate N_{2}O emissions using Equation 223 of this section.
Equation 223: N_{2}O from flaring
Long description for Equation 223
This equation is used to calculate the annual nitrous oxide emissions from flared gas. The calculation involves the multiplication of the emission rate of CO₂ from flared gas, labeled as "CO₂", with the facilityspecific N₂O emission factor, labeled as "EF_N2O". When a facilityspecific factor is not available, a default N₂O emission factor for petroleum products of 0.5 x 10^3 kg N₂O/GJ is assumed. The product is then divided by the specific CO₂ emission factor "EF". In the absence of a facilityspecific CO₂ emission factor, a default CO₂ emission factor for flare gas of 62.4 kilograms CO₂/GJ (HHV basis) is used.
Where:
N_{2}O = annual nitrous oxide emissions from flared gas (tonnes)
CO_{2} = emission rate of CO_{2} from flared gas calculated in paragraph 2.C.1 (tonnes)
EF_{N2O} = apply facility specific N_{2}O emission factor. When facility specific factor is not available assume default N_{2}O emission factor for petroleum products of 0.5 x 10^{3} kg N_{2}O/GJ^{Footnote 3}
EF = apply facility specific CO_{2} emission factor; when facility specific factor is not available assume default CO_{2} emission factor for flare gas of 62.4 kilograms CO_{2}/GJ (HHV basis)
2.C.3 Other CO_{2} emissions
Where low Btu gases (e.g. coker flue gas, gases from vapor recovery systems, casing vents and product storage tanks) are destroyed using methods other than flares (e.g. incineration, combustion as a supplemental fuel in heaters or boilers) calculate CO_{2} emissions using Equation 224. Determine CC_{A} and MW_{A} quarterly using methods specified in section 2.D and use the annual average values of CC_{A} and MW_{A} to calculate CO_{2} emissions.
Equation 224: Flaring – Other
Long description for Equation 224
This equation is used to calculate the annual CO₂ emissions from destruction methods other than flares. The calculation starts by multiplying the annual volume of gas A destroyed at specific conditions, labeled as "GV_A", with the carbon content of gas A, labeled as "CC_A". This product is further multiplied by the ratio of the molecular weight of gas A "MW_A" to the molar volume "MVC", and then multiplied by the conversion factor 3.664 x 10^3. The 3.664 is the ratio of molecular weights of CO₂ to carbon. The result provides the CO₂ emissions for a specific destruction method.
Where:
CO_{2} = annual CO_{2} emissions from destruction methods other than flares (tonnes)
GV_{A} = annual volume of gas A destroyed at 15°C and 101.325 kPa (m^{3}) or specific to petroleum refineries at reference conditions of 25°C and 101.325 kPa (dRm^{3}); when using a mass flow meter, measure the gas destroyed in kg and replace the term “MW_{A}/MVC” with “1”
CC_{A} = carbon content of gas A (kg C/kg fuel)
MW_{A} = molecular weight of gas A
MVC = molar volume factor at the same reference conditions as the GV_{A }variable (m^{3}/kgmole)
= 8.3145 * [273.16 + reference temperature in °C]/[reference pressure in kilopascal]
3.664 = ratio of molecular weights, CO_{2} to carbon
10^{3}^{ } = conversion factor from kilograms to tonnes
2.D Sampling, analysis and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
2.D.1 Fuel measurement and sampling requirements
Fuel sampling must be conducted, or fuel sampling results received from the fuel supplier, at the minimum frequency specified in paragraphs 2.D.1(1) to 2.D.1(7) of this section, when sampling frequencies are not specified in section 2.A, 2.B and 2.C. Take all fuel samples, at a location in the fuel handling system that is representative of the fuel combusted, as follows:
(1) Once for each new fuel shipment or delivery for coal; sample continuously delivered coal, such as, from conveyor systems or ongoing truck deliveries, as often as necessary to capture variations in carbon content and heat value and to ensure a representative annual composition, but no less than monthly.
(2) Once for each new fuel shipment or delivery of fuels, or quarterly for each of the fuels listed in Table 21, Table 22 or Table 24.
(3) Monthly for marketable (commercial) natural gas; the fuel supplier should provide monthly analysis or, should that not be possible, as often as the supplier can provide, but no less than semiannually.
(4) Quarterly for all liquid fuels including renewables and biofuels except for fuels listed in Table 21 and Table 22 (when these tables are used).
(5) Quarterly for renewable and biomass gaseous fuels derived from biomass including landfill gas and biogas from wastewater treatment or agricultural processes.
(6) For all other gaseous fuels including renewables and biomass (other than marketable natural gas, and gases derived from biomass and biogas), and if the necessary measurement equipment is in place, perform daily sampling and analysis to determine the carbon content and molecular weight of the fuel.
 If the necessary measurement equipment is not in place, perform weekly sampling and analysis.
 If using online instrumentation to perform daily sampling and analysis of carbon content and molecular weight the measurements shall be accurate to ±5 percent.
(7) Monthly for all other solid fuels including renewables and biomass except for coal and wastederived fuels, as specified below:
 The monthly solid fuel sample shall be a composite sample of weekly samples.
 Sample the solid fuel at a location before fuel consumption but after all fuel treatment operations; the samples shall be representative of the fuel chemical and physical characteristics immediately prior to combustion.
 Collect each weekly subsample at a time (day and hour) of the week when the fuel consumption rate is representative and unbiased.
 Combine four weekly samples (or a sample collected during each week of operation during the month) of equal mass to form the monthly composite sample.
 The monthly composite sample shall be homogenized and well mixed prior to withdrawing a sample for analysis.
 Randomly select one in twelve composite samples for additional analysis of its discrete constituent samples, for use in monitoring the homogeneity of the composite.
(8) For all other biomass fuels and wastederived fuels, the following may apply in lieu of paragraph 2.D.1(4) to 2.D.1(7)
 If calculating CO_{2} emissions using equations requiring HHV or carbon content, determine the fuelspecific HHV or carbon content annually.
 If CO_{2} emissions are calculated using Equation 211 and a sitespecific emission factor, adjust the emission factor, in kg CO_{2}/MJ, at least every third year.
 Use a stack test measurement of CO_{2} and the applicable ASME Performance Test Code to determine heat input from all heat outputs, including the steam, flue gases, ash and losses.
2.D.2 Fuel consumption monitoring requirements
(1) Determine fuel consumption based on direct measurement or recorded fuel purchase or sales invoices measuring any stock change using Equation 225.
 Follow the fuel measurement and sampling requirement in section 2.D.1.
 For feedstock and nonenergy use of fossil fuels, consult sections according to the specific sector or activity.
Equation 225: Fuel consumption
Long description for Equation 225
Fuel_{i} = Purchases_{i} – Sales_{i} + Stored_{SY I} – Stored_{YE I} – Feedstock_{i}
Where:
Fuel_{ i} = total annual fuel combusted by type “i” expressed in tonnes for solid fuel, kilolitres for liquid fuel or cubic meters, at 15°C and 101.325 kPa, for gaseous fuel
Purchases_{ i} = total annual fuel purchases by type “i” expressed in tonnes (t), kilolitres (kL) or cubic metres (m^{3})
Sales_{ i} = total annual fuel sales by type “i” expressed in tonnes (t), kilolitres (kL) or cubic metres (m^{3})
Stored_{ SY i} = quantity of fuel stored by type “i” at start of year, expressed in tonnes (t), kilolitres (kL) or cubic metres (m^{3})
Stored_{ YE i} = quantity of fuel stored by type “i” at yearend, expressed in tonnes (t), kilolitres (kL) or cubic metres (m^{3})
Feedstock_{ i} = annual quantity feedstock or nonenergy fuel use by type “i” expressed in tonnes (t), kilolitres (kL) or cubic metres (m^{3})
(2) Convert fuel consumption measured in MJ to the required mass or volume metrics, or vice versa, using heat content values provided by the supplier or measured at the facility, when applicable.
(3) Calibrate all fuel oil and gas flow meters (except for gas billing meters) using procedures specified by the flow meter manufacturer.
 Recalibrate fuel flow meters once every three years, upon replacement of a previously calibrated meter or at the minimum frequency specified by the manufacturer.
 For orifice, nozzle, and venturi flow meters, the calibration shall consist of insitu calibration of the differential pressure (deltaP), total pressure, and temperature transmitters.
 For flow meters used for natural gas, the facilities shall follow the requirements of the Weights and Measures Act.
(4) For fuel oil, tank drop measurements may also be used.
(5) Use fuel volume flow meters for liquid fuels, if appropriate fuel densities are available to convert volumetric flow rates to mass readings; measure the density at the same frequency as the carbon content, using ASTM D129899 (Reapproved 2005) “Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method.”
(6) Facilities using Calculation Methodology 1 for CO_{2} emissions may use the default density values in Table 213 for fuel oil, in lieu of using the ASTM method in paragraph 2.D.2(5) of this section; do not use these default densities for facilities using Calculation Method 2.
Fuel oil  No. 1 Oil  No. 2 Oil  No. 6 Oil 

Default density (kg/l) 
0.81  0.86  0.97 
(7) Determine annual mass of spent liquor solids using one of the methods specified in subparagraph (A) or (B)
 Measure mass of annual spent liquor solids using TAPPI T650 om15 “Solids Content of Black Liquor.”
 Determine mass of annual spent liquor solids based on records of measurements made with an online measurement system that determines the mass of spent liquor solids fired in a chemical recovery furnace or chemical recovery combustion unit; measure the quantity of black liquor produced each month.
2.D.3 Fuel heat content monitoring requirements
Base higher heating values on the results of fuel sampling and analysis received from the fuel supplier or as determined using an applicable analytical method in paragraphs (1) to (6) of this section. Follow the fuel measurement and sampling requirement in section 2.D.1. For fuel heat content monitoring of natural gas, follow the requirements of the Weights and Measures Act.
(1) For gases, use specific test procedures outlined in ASTM D1826 – Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, ASTM D3588 – Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, or ASTM D4891, GPA Standard 2261 – Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography.
(2) For middle distillates and oil, or liquid wastederived fuels, use the specific test procedures outlined in ASTM D240 – Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter or ASTM D4809 – Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method).
(3) For solid, and solid biomassderived fuels, use the specific test procedures outlined in ASTM D5865 – Standard Test Method for Gross Calorific Value of Coal and Coke.
(4) For wastederived fuels, use the specific test procedures outlined in ASTM D5865 and ASTM D5468 – Standard Test Method for Gross Calorific and Ash Value of Waste Materials; determine the biomass fuel portion of CO_{2} emissions, if combusting wastederived fuels that are not pure biomass.
(5) For black liquor, use Technical Association of the Pulp and Paper Industry (TAPPI) T684 om15 – Gross High Heating Value of Black Liquor.
(6) When using measured heat content to calculate CO_{2} emissions, use Equation 226 to develop the weighted annual heat content of the fuel.
Equation 226: HHV
Long description for Equation 226
This equation is used to calculate the weighted annual average higher heating value of the fuel by type "i". For each measurement period "p", the higher heating value of the fuel by type "i" during that period, labeled as "HHV_ip", is multiplied by the mass or volume of the fuel combusted during the same period, labeled as "Fuel_ip". This process is repeated for every period up to the total "n". Then, the values of all periods are summed, and the summation is divided by the total fuel combusted over all periods for type "i" to derive the annual HHV for that fuel type. The units for fuel type "i" are given in MJ per tonne for solid fuel, MJ per kilolitre for liquid fuel, or MJ per cubic meter for gaseous fuel.
Where:
HHV_{ Annual i} = weighted annual average higher heating value of the fuel by type “I” (MJ per tonne for solid fuel, MJ per kilolitre for liquid fuel, or MJ per cubic meter for gaseous fuel)
HHV_{ i p} = higher heating value of the fuel by type “i” for measurement period “p” (MJ per tonne for solid fuel, MJ per kilolitre for liquid fuel, or MJ per cubic meter for gaseous fuel)
Fuel_{ i p} = mass or volume of the fuel combusted by type “i” during measurement period “p” (mass in tonnes for solid fuel, volume in kilolitres for liquid fuel or volume in cubic meters, at 15°C and 101.325 kPa, for gaseous fuel)
n = number of measurement periods per calendar year that fuel is burned by type “i” in the unit
2.D.4 Fuel carbon content monitoring requirements
Base the fuel carbon content on the results of fuel sampling and analysis received from the fuel supplier or as determined by the facility operator, using an applicable analytical method in paragraphs 2.D.4(1) to 2.D.4(5) of this section. Follow the fuel measurement and sampling requirement in section 2.D.1. For carbon content monitoring of natural gas, follow the requirements of the Weights and Measures Act.
(1) For coal and coke, solid biomass fuels, and wastederived fuels, use the specific test procedures in ASTM 5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal.”
(2) For petroleumbased liquid fuels and liquid wastederived fuels, use ASTM D5291 – Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, ultimate analysis of oil or computations based on ASTM D3238, and either ASTM D2502 – Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils From Viscosity Measurements, or ASTM D2503 – Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure.
(3) For refinery fuel gas and flexigas, use either ASTM D194503 (Reapproved 2006) or ASTM D194690 (Reapproved 2006).
 Alternatively, the results of chromatographic analysis of the fuel gas may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to manufacturer instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in a plan.
(4) For other gaseous fuels, use ASTM D1945 – Standard Test Method for Analysis of Natural Gas by Gas Chromatography or ASTM D1946 – Standard Practice for Analysis of Reformed Gas by Gas Chromatography.
(5) When using measured carbon content to calculate CO_{2} emissions, use Equation 227 to develop the weighted annual average carbon content of the fuels.
Equation 227: Annual carbon content
Long description for Equation 227
This equation is used to calculate the weighted annual average carbon content of the fuel type. For each measurement period "p" for a specific fuel type "i", labeled as "Fuel_ip", the carbon content of the fuel type "i" for that period, "CC_ip", is multiplied by the mass or volume of the fuel type "i" combusted during that period, "Fuel_ip". The product of this multiplication is then divided by the total mass or volume of the fuel type "i" for that measurement period. It's crucial to note the different units: carbon content can be expressed in terms of 'tonnes C per tonne' for solid fuel, 'tonnes C per kilolitre' for liquid fuel, or 'tonnes C per cubic meter' for gaseous fuel. The mass for solid fuel is given in 'tonnes', volume in 'kilolitres' for liquid fuel, and in cubic meters for gaseous fuel, each at specific conditions of temperature and pressure. This process is repeated for every measurement period up to the total number 'n'. Finally, the values from all measurement periods are summed to provide the annual carbon content for the fuel type.
Where:
CC_{ Annual i} = weighted annual average carbon content of the fuel type “i” expressed as tonnes C per tonne solid fuel, tonnes C per kilolitre liquid fuel, or tonnes C per cubic meter gaseous fuel
CC_{ i p} = carbon content of the fuel type “i” for measurement period “p” (ratio C per tonne for solid fuel, mass C per kilolitre for liquid fuel or mass C per cubic meter for gaseous fuel)
Fuel_{ i p} = mass or volume of the fuel type “i” combusted during measurement period “p” (mass in tonnes for solid fuel, volume in kilolitres for liquid fuel or volume in cubic meters, at 15°C and 101.325 kPa, for gaseous fuel)
n = number of measurement periods in calendar year that the fuel type “i” is burned in the unit
2.D.5 Fuel analytical data capture
When the applicable methodologies in sections 2.A, 2.B and 2.C require periodic collection of fuel analytical data for an emissions source, demonstrate every effort to obtain a fuel analytical data capture rate of 100 percent for each report year. In any case, fuel analytical data capture shall be 80 percent or more.
If the fuel analytical data capture rate is between 80 percent and 100 percent for any emissions source identified in sections 2.A, 2.B and 2.C, use the methods in paragraph 2.E(2) to substitute for the missing values for the period of missing data.
2.D.6 Onsite transportation consumption of biofuels
Determine the fuel use and emission factors as specified in this section.
(1) For biofuels, the portion(s) of ethanol or biodiesel from vendor specifications.
(2) Conventional fuels and biofuels have emission factors listed in Table 22.
(3) Determine biofuel volumes from vendor receipts, quarterly, starting January 1st of the calendar year.
2.D.7 Flares and other control devices
(1) Where a continuous flow monitor on the flare exists, use the measured flow rates when the monitor is operational and the flow rate is within the calibrated range of the measurement device to calculate the flare gas flow; where no continuous flow monitor on the flare exists and for periods when the monitor is not operational or the flow rate is outside the calibrated range of the measurement device, use engineering calculations, company records, or similar estimates of volumetric flare gas flow.
(2) If using the method specified in section 2.C.1(1)(A), monitor the carbon content of the flare gas daily if the flare is already equipped with the necessary measurement devices (at least weekly if not).
(3) If using the method specified in section 2.C.1(1)(B), monitor the HHV of the flare gas daily if the flare is already equipped with the necessary measurement devices (at least weekly if not).
2.E Procedures for estimating missing analytical data
Whenever a qualityassured value of a required parameter is unavailable (e.g., if a CEM system malfunctions during unit operation or a required fuel sample not taken), a substitute data value for the missing parameter shall be used in the calculations.
(1) For sources subject to the requirements of section 2 that monitor and report emissions using a CEM system, follow the missing data backfilling procedures in the CEMS guidance document for CO_{2} concentration, stack gas flow rate, fuel flow rate, HHV, and fuel carbon content.
(2) For sources using Methodologies 1, 2, or 3, perform the following missing data substitution for each parameter:
 For each missing value of the HHV, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the qualityassured values of that parameter immediately preceding and immediately following the missing data incident.
 If the “after” value has not been obtained by the time that the GHG emissions must be calculated, use the “before” value for missing data substitution or the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours).
 If, for a particular parameter, no quality assured data are available prior to the missing data incident, substitute the first qualityassured value obtained after the missing data period.
 For missing records of CO_{2} concentration, stack gas flow rate, moisture percentage, fuel usage, and sorbent usage, substitute the best available estimate of that parameter, based on all available process data (e.g., electrical load, steam production, operating hours, etc.); document and retain records of the procedures used for all such estimates.
(3) For missing data that concerns carbon content, temperature, pressure or gas concentration, determine the sampling or measurement rate using Equation 228 and, replace the missing data as follows:
 If R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
Equation 228: Sampling rate
Long description for Equation 228
This equation is used to calculate the sampling or measurement rate that was used by the facility operator. The quantity of actual samples or measurements obtained by the facility operator, labeled "QS_ACT", is divided by the quantity of samples or measurements that are required, denoted as "QS_REQUIRED". The resulting ratio represents the sampling or measurement rate expressed as a percentage.
Where:
R = sampling or measurement rate that was used (%)
QS_{ ACT} = quantity of actual samples or measurements obtained by the facility operator
QS_{ REQUIRED} = quantity of samples or measurements required for section 2
(4) For missing data that concerns CEM systems, determine the replacement data using the procedure in the CEMS guidance document or using Equation 229:
 If R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
Equation 229: Sampling rate
Long description for Equation 229
This equation is used to calculate the sampling or measurement rate undertaken by an individual. For each sample or measurement, the quantity of actual samples or measurements collected by the person, denoted as "HS_ACT", is divided by the quantity of samples or measurements required for section 2, represented as "HS_REQUIRED". This division yields the sampling or measurement rate, showcased as a percentage.
Where:
R = sampling or measurement rate that was used (%)
HS_{ ACT} = quantity of actual samples or measurements obtained by the person
HS_{ REQUIRED} = quantity of samples or measurements required for section 2
3 Quantification methods for lime production
3.A CO_{2} emissions from lime production
Calculate the annual CO_{2} emissions from lime production for all kilns combined using the methods in this section. Persons operating a facility with installed CEMS may calculate the annual CO_{2} emissions from lime production as specified in section 3.A.3 or using Equation 31 through Equation 33. For emissions from lime kilns at a pulp and paper production facility, refer to section 12.
For facilities in Alberta, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used where appropriate. More specifically, it is acceptable to use Alberta equation 88 in place of ECCC Equation 31 in this section.
Equation 31: CO_{2} from lime production
Long description for Equation 31
This equation is used to calculate the total annual quantity of CO₂ emissions stemming from lime production. For each lime type "i" in a given month "m", the quantity of each lime type "QL_mi" is multiplied by the plantspecific emission factor "EFL_mi", which is based on the method in section 3.A.1. Simultaneously, for every byproduct/waste type "j" in a specified quarter "q", the total quantity of calcined byproducts/wastes "QCBW_qj" is multiplied by the plantspecific emission factor "EFCBW_qj" detailed in section 3.A.2. The results from these multiplications for all lime types and all byproduct/waste types are then added together. The collective value from these operations gives the total CO₂ emissions from lime production for the year.
Where:
E_{ CO2} = the total annual quantity of CO_{2} emissions from lime production (tonnes)
QL_{ m i} = the total quantity of each lime type “i” in month “m” (tonnes)
EFL_{ m i} = the plant specific emission factor for each lime type “i” in month “m” (tonnes CO_{2} / tonnes lime), using the method in section 3.A.1
QCBW_{ q j} = the total quantity of calcined byproducts/wastes for each byproduct/waste type “j” in quarter “q” (tonnes byproduct/waste)
EFCBW_{ q j} = the plant specific emission factor for each calcined byproduct/waste type “j” in quarter “q” (tonnes CO_{2}/tonnes byproduct/waste), using the method in section 3.A.2
3.A.1 Monthly lime emission factor
Calculate the monthly plant specific emission factor for each lime type using Equation 32.
Equation 32: Lime emission factor
Long description for Equation 32
EFL_{m i} = [(fCaO_{m i} × 0.785) + (fMGO_{m i} × 1.092)]
Where:
EFL_{ m i} = the plant specific emission factor for each lime type “i” in month “m” (tonnes CO_{2} / tonnes lime)
fCaO_{ m i} = the calcium oxide (CaO) content for each lime type “i” in month “m” calculated by subtracting the total CaO content of feed material entering the kiln from CaO content of lime exiting the kiln, (tonnes CaO / tonnes lime)
0.785 = ratio of molecular weights of CO_{2} to CaO
fMgO_{ m i} = the magnesium oxide (MgO) content for each lime type “i” in month “m” calculated by subtracting the total MgO content of feed material entering the kiln from MgO content of lime exiting the kiln (tonnes MgO / tonne lime)
1.092 = ratio of molecular weights of CO_{2} to MgO
3.A.2 Quarterly calcined byproduct/waste emission factor
Calculate the quarterly calcined byproduct/waste plant emission factor for each calcined byproduct/waste type using Equation 33.
Equation 33: Byproduct emission factor
Long description for Equation 33
EFCBW_{q j} = [(fCaO_{q j} × 0.785) + (fMGO_{q j} × 1.092)]
Where:
EFCBW_{ q j} = the plant specific emission factor for each calcined byproduct/waste type “j” in quarter “q” (tonnes CO_{2} / tonnes calcined byproduct/waste)
fCaO_{ q j} = the calcium oxide (CaO) content of each byproduct/waste type “j” in quarter “q” calculated by subtracting CaO content of byproduct/waste in uncalcined CaCO_{3} remaining in calcined byproduct/waste from total CaO content of byproduct/waste (tonnes CaO / tonnes byproduct/waste)
fMgO_{ q j} = the magnesium oxide (MgO) content of each calcined byproduct/waste “j” in quarter “q” calculated by subtracting MgO content of byproduct/waste in uncalcined MgCO_{3} remaining in byproduct/waste from total MgO content of byproduct/waste (tonnes MgO / tonnes byproduct/waste)
0.785 = ratio of molecular weights of CO_{2} to CaO
1.092 = ratio of molecular weights of CO_{2} to MgO
3.A.3 CO_{2} Emissions from lime production using CEMS
Persons operating a facility with installed CEMS may calculate CO_{2} emissions from lime production using Equation 34.
Equation 34: CEMS
Long description for Equation 34
E_{CO2} = E_{CO2 CEMS} – E_{CO2 FC}
Where:
E_{ CO2} = the total annual quantity of CO_{2} emissions for lime production from all kilns combined (tonnes), calculated by subtracting CO_{2} fuel combustion emissions as specified in section 2 from the total annual CO_{2} quantity measured using CEMS
E_{ CO2 CEMS} = the total annual quantity of CO_{2} emissions from CEMS including fuel combustion and lime production emissions from all kilns (tonnes)
E_{ CO2 FC} = the total annual CO_{2} fuel combustion emissions from all kilns, calculated as specified in section 2
3.B Sampling, analysis and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
Use the testing methods provided in this section to determine the chemical composition of CaO and MgO contents of each lime type and each calcined byproduct/waste type. Samples for analysis of the calcium oxide and magnesium oxide content of each lime type and each calcined byproduct/waste type shall be collected during the same month or quarter as the production data. At least one sample shall be collected monthly for each lime type that is produced monthly and, at least one sample shall be collected quarterly for each calcined byproduct/waste type that is produced quarterly.
(1) ASTM C2506 – Standard Test Methods for Chemical Analysis of Limestone, Quicklime and Hydrated Lime
(2) Analytical Methods section of the National Lime Association “CO_{2} Emissions Calculation Protocol for the Lime Industry English Units Version”
(3) ASM CS104 UNS No. G10460 “Carbon Steel of Medium Carbon Content”
(4) ASME Performance Test Codes
(5) ASTM C25 – Standard Test Method for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime
(6) ASTM D70 – Standard Test Method for Density of SemiSolid Asphalt Binder (Pycnometer Method)
(7) ASTM C114 – Standard Test Methods for Chemical Analysis of Hydraulic Cement
(8) ASTM D240 – Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimetre
(9) ASTM D1298 – Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method
(10) ASTM D1826 – Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimetre
(11) ASTM D1945 – Standard Test Method for Analysis of Natural Gas by Gas Chromatography
(12) ASTM D1946 – Standard Practice for Analysis of Reformed Gas by Gas Chromatography
(13) ASTM D2013 – Standard Practice of Preparing Coal Samples for Analysis
(14) ASTM D2163 – Standard Test Method for Determination of Hydrocarbons in Liquefied Petroleum (LP) Gases and Propane/Propene Mixtures by Gas Chromatography
(15) ASTM D2234/D2234M – Standard Practice for Collection of a Gross Sample of Coal
(16) CO_{2} Emissions Calculation Protocol for the Lime Industry – English Units Version, February 5, 2008 Revision – National Lime Association
3.B.1.
Determine the quantity of lime produced and sold monthly using direct measurements (i.e.: rail and truck scales) of lime sales for each lime type, and adjusted to take into account the difference in the beginning and endofperiod inventories of each lime type. The inventory period shall be annual at a minimum.
3.B.2.
Determine the quantity of calcined byproduct/waste sold monthly using direct measurements (i.e.: rail and truck scales) of calcined byproduct/waste sales for each calcined byproduct/waste type, and adjusted to take into account the difference in the beginning and endofperiod inventories of each calcined byproduct/waste type. The inventory period shall be annual at a minimum. Determine the quantity of unsold calcined byproduct/waste annually at a minimum for each calcined/byproduct waste type using direct measurements (i.e.: rail and truck scales), or a calcined byproduct/waste generation rate (i.e. calcined byproduct produced as a factor of lime production).
3.B.3.
Follow the quality assurance/quality control procedures (including documentation) in National Lime Association’s CO_{2} Emissions Calculation Protocol for the Lime Industry (English Units Version, February 5, 2008 Revision – National Lime Association).
3.C Procedures for estimating missing analytical data
Use the methods prescribed in this section to reanalyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period for missing analytical data.
3.C.1.
Whenever sampling, analysis and measurement data required for section 3.A for the calculation of emissions is missing, a person shall ensure the data is replaced using the missing data procedures specified in this section.
 For missing data that concerns carbon content, temperature, pressure or gas concentration, determine the sampling or measurement rate using Equation 35 and, replace the missing data as specified in paragraphs (2) to (4) of this section.
 If R ≥ 0.9: a person shall replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, a person shall use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: a person shall replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: a person shall replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
Equation 35: Sampling rate
Long description for Equation 35
This equation is used to calculate the sampling or measurement rate used. The rate, represented as "R", is derived by dividing the quantity of actual samples or measurements obtained by the person, labeled as "QS_ACT", by the quantity of samples or measurements required for section 3, labeled as "QS_REQUIRED". The resultant value represents the percentage of the sampling or measurement rate that was used.
Where:
R = sampling or measurement rate that was used (%)
QS_{ ACT} = quantity of actual samples or measurements obtained by the person
QS_{ REQUIRED} = quantity of samples or measurements required for section 3
3.C.2.
For missing data that concerns lime production or missing calcined byproduct/waste production; the replacement data shall be generated from the best available estimate based on all available process data.
3.C.3.
For missing data that concerns missing values related to the CaO and MgO content; a new composition test shall be conducted.
3.C.4.
For all units that monitor and report emissions using CEMS; the missing data backfilling procedures in the CEMS guidance document can be used or Equation 36 to determine CO_{2} concentration, stack gas flow rate, fuel flow rate, HHV, and fuel carbon content.
 If R ≥ 0.9: a person shall replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, a person shall use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: a person shall replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: a person shall replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
Equation 36: Sampling rate
Long description for Equation 36
This equation is used to calculate the sampling or measurement rate that was used, expressed as a percentage. For each sample taken, the equation references the "quantity of actual samples or measurements obtained by the person," labeled as "HS_ACT." This is then divided by the "quantity of samples or measurements required for section 3," denoted as "HS_REQUIRED." The result of this division provides the sampling or measurement rate "R." The equation simply gives the percentage of actual samples taken against the required number of samples for a given section.
Where:
R = sampling or measurement rate that was used (%)
HS_{ ACT} = quantity of actual samples or measurements obtained by the person
HS_{ REQUIRED} = quantity of samples or measurements required for section 3
4 Quantification methods for cement production
4.A CO_{2} emissions from cement production
Calculate the annual CO_{2} emissions from cement production for all kilns combined using the methods in this section. Persons operating a facility with installed CEMS may calculate the annual CO_{2} emissions from cement production as specified in Equation 46 or using Equation 41 through Equation 45.
Equation 41: CO_{2} emissions from cement production
Long description for Equation 41
E_{CO2 }= E_{CO2 CLI} + E_{CO2 CKD} + E_{CO2 RM}
Equation 42: CO_{2} emissions from cement production
Equation 42 (See long description below)
This equation is used to calculate the total annual quantity of CO_{2} emissions from cement production in detail. For each month "m" and quarter "q", it introduces the "total quantity of clinker," labeled "Q_CLIm," which multiplies the "plant specific emission factor of clinker," labeled "EF_CLm." For cement kiln dust, labeled "Q_CKDq," it multiplies the "plant specific emission factor," denoted "EF_CKDq." Additionally, the "total annual organic carbon content in raw material," labeled "TOC_RM," is multiplied by the total annual quantity of raw material consumption “RM” and by the conversion factor 3.664, which represents the ratio of molecular weights of CO_{2} to C. All these values are then summed together. This calculation is repeated for every month and quarter. Finally, the values for all months and quarters are aggregated to furnish the annual CO_{2} emissions.
Where:
E_{ CO2} = the total annual quantity of CO_{2} emissions from cement production (tonnes)
E_{ CO2 CLI} = the total annual quantity of CO_{2} emissions from clinker production (tonnes)
E_{ CO2 CKD} = the total annual quantity of CO_{2} emissions from cement kiln dust (CKD) (tonnes)
E_{ CO2 RM} = the total annual quantity of CO_{2} emissions from organic carbon oxidation (tonnes)
Q_{ CLI m} = the total quantity of clinker in month “m” (tonnes)
EF_{ CLI m} = the plant specific emission factor of clinker in month “m” (tonnes CO_{2} / tonnes clinker), using Equation 43
Q_{ CKD q} = the total quantity of cement kiln dust not recycled back to the kiln in quarter “q” (tonnes)
EF_{ CKD q} = the plant specific emission factor of cement kiln dust not recycled back to the kiln in quarter “q” (tonnes CO_{2} / tonnes cement kiln dust), using Equation 44
TOC_{ RM} = the measured annual organic carbon content in raw material, or using a default value of 0.002 (0.2%)
RM = the total annual quantity of raw material consumption (tonnes)
3.664 = ratio of molecular weights of CO_{2} to C
4.A.1 Monthly clinker emission factor
Calculate the monthly plant specific emission factor for clinker using Equation 43. The monthly clinker emission factor is calculated using monthly measurements of the weight fractions of calcium oxide (CaO) and magnesium oxide (MgO) content in clinker.
For facilities in Alberta, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used where appropriate. More specifically, it is acceptable to use Alberta equation 88a in place of ECCC Equation 43 in this section.
Equation 43: Monthly clinker emission factor
Long description for Equation 43
EF_{CLI m }= [CaO_{CLI m }– fCaOm] × 0.785 + [MgO_{CLI m }– fMgO_{m}] × 1.092
Where:
EF_{ CLI m} = the plant specific emission factor of clinker in month “m” (tonnes CO_{2} / tonnes clinker)
CaO_{ CLI m} = the total calcium oxide (CaO) content of clinker in month “m” (tonnes CaO / tonnes clinker)
fCaO_{ m} = the noncalcined calcium oxide (CaO) content of clinker in month “m” (tonne CaO / tonne clinker)
MgO_{ CLI m} = the total magnesium oxide (MgO) content of clinker in month “m” (tonne MgO / tonne clinker)
fMgO_{ m} = the noncalcined magnesium oxide (MgO) content of clinker in month “m” (tonne MgO / tonne clinker)
0.785 = ratio of molecular weights of CO_{2} to CaO
1.092 = ratio of molecular weights of CO_{2} to MgO
4.A.2 Quarterly CKD emission factor
Calculate the quarterly CKD emission factor using Equation 44. The quarterly plant specific CKD emission factor shall be calculated only if it is not recycled back to the kiln. The CKD emission factor is calculated using quarterly measurements of the weight fractions of calcium oxide (CaO) and magnesium oxide (MgO) content in CKD not recycled back to the kiln.
For facilities in Alberta, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used where appropriate. More specifically, it is acceptable to use Alberta equation 88b in place of ECCC Equation 44 in this section.
Equation 44: Quarterly CKD emission factor
Long description for Equation 44
EF_{CKD q }= [CaO_{CKD q }– fCaO_{q}] × 0.785 + [MgO_{CKD q} – fMgO_{q}] × 1.092
Where:
EF_{ CKD q} = the plant specific emission factor of CKD not recycled back to the kiln in quarter “q” (tonnes CO_{2} / tonnes CKD)
CaO_{ CKD q} = the total calcium (expressed as CaO) content of CKD not recycled back to the kiln in quarter “q” (tonnes CaO / tonnes CKD)
fCaO_{ q} = the noncalcined calcium oxide (CaO) content of CKD not recycled back to the kiln in quarter “q” (tonne CaO / tonne CKD)
MgO_{ CKD q} = the total magnesium (expressed as MgO) content of CKD not recycled back to the kiln in quarter “q” (tonne MgO / tonne CKD)
fMgO_{ q} = the noncalcined magnesium oxide (MgO) content of CKD not recycled back to the kiln in quarter “q” (tonne MgO / tonne CKD)
0.785 = ratio of molecular weights of CO_{2} to CaO
1.092 = ratio of molecular weights of CO_{2} to MgO
4.A.3 Organic carbon oxidation emissions
Calculate the annual CO_{2} emissions from total organic content in raw materials using Equation 45.
For facilities in Alberta, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used where appropriate. More specifically, it is acceptable to use Alberta equation 89 in place of ECCC Equation 45 in this section.
Equation 45: Organic carbon oxidation emissions
Long description for Equation 45
E_{CO2RM }= [TOC_{RM} × RM × 3.664]
Where:
E_{ CO2 RM} = the total annual quantity of CO_{2} emissions from organic carbon oxidation (tonnes)
TOC_{ RM} = the measured annual organic carbon content in raw material, or using a default value of 0.002 (0.2%)
RM = the total annual quantity of raw material consumption (tonnes)
3.664 = ratio of molecular weights of CO_{2} to C
4.A.4 CO_{2} emissions from cement production using CEMS
Persons operating a facility with installed CEMS may calculate CO_{2} emissions from cement production using Equation 46.
Equation 46: CEMS
Long description for Equation 46
E_{CO2} = E_{CO2 CEMS} – E_{CO2 FC}
Where:
E_{ CO2} = the total annual quantity of CO_{2} emissions from cement production from all kilns combined (tonnes), calculated by subtracting fuel combustion emissions for CO_{2} as specified in section 2 from the total annual CO_{2} quantity measured using CEMS
E_{ CO2 CEMS} = the total annual quantity of CO_{2} emissions from CEMS including fuel combustion and cement production emissions from all kilns (tonnes)
E_{ CO2 FC} = the total annual CO_{2} fuel combustion emissions from all kilns, calculated as specified in section 2
4.B Sampling, analysis and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
Use the testing methods provided in this section to determine the monthly plant specific weight fractions of total calcium oxide (CaO) and total magnesium oxide (MgO) in clinker using ASTM C114Standard Test Methods for Chemical Analysis of Hydraulic Cement. The monitoring shall be conducted either daily from clinker drawn from the exit of the kiln or monthly from clinker drawn from bulk storage.
4.B.1.
Determine the quarterly plant specific weight fractions of total calcium oxide (CaO) and total magnesium oxide (MgO) in CKD using ASTM C114Standard Test Methods for Chemical Analysis of Hydraulic Cement. The monitoring shall be conducted either daily from CKD samples drawn from the exit of the kiln or quarterly from CKD samples drawn from bulk storage.
4.B.2.
Determine the monthly plant specific weight fractions of calcium oxide (CaO) and magnesium oxide (MgO) that enter the kiln as noncarbonate species to clinker, by chemical analysis of feed material using a documented analytical method. If this is not possible, use a value of 0.0.
4.B.3.
Determine the quarterly plant specific weight fractions of calcium oxide (CaO) and magnesium oxide (MgO) that enter the kiln as a noncarbonate species to CKD, by chemical analysis of feed material using a documented analytical method. If this is not possible, use a value of 0.0.
4.B.4.
Determine the monthly plant specific weight fractions of calcium oxide (CaO) and magnesium oxide (MgO) that remain in clinker, by chemical analysis of feed material using a documented analytical method. If this is not possible, use a value of 0.0.
4.B.5.
Determine the plant specific weight fractions of calcium oxide (CaO) and magnesium oxide (MgO) that remain in CKD, by chemical analysis of feed material using a documented analytical method. If this is not possible, use a value of 0.0.
4.B.6.
Determine the total annual organic carbon content in raw material using ASTM C114 or a default value of 0.002. The analysis shall be conducted on samples drawn from bulk raw material storage for each category of raw material.
4.B.7.
Determine the monthly quantity of clinker production using one of the following procedures:
 Direct weight measurement using the same plant instruments used for accounting purposes, such as reconciling measurements using weigh hoppers or belt weigh feeders against inventory measurements, or
 Direct measurement of raw kiln feed and application of a kiln specific feed to clinker factor; a person that chooses to use a feed to clinker factor, shall verify the accuracy of this factor monthly.
4.B.8.
Determine the quarterly quantity of CKD not recycled back to the kiln using the same plant techniques used for accounting purposes, such as direct weight measurement using weigh hoppers or belt weigh feeders, and/or material balances.
4.B.9.
Determine the monthly total quantity of raw materials consumed (i.e. limestone, sand, shale, iron oxide, alumina, and noncarbonate raw material) by direct weight measurement using the same plant instruments used for accounting purposes, such as reconciling weigh hoppers or belt weigh feeders.
4.C Procedures for estimating missing analytical data
Use the methods prescribed in this section to reanalyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period for missing analytical data.
4.C.1.
Whenever sampling, analysis and measurement data required for section 4.A for the calculation of emissions is missing, a person shall ensure the data is replaced using the missing data procedures specified in this section.
 For missing data that concerns carbon content, temperature, pressure or gas concentration, determine the sampling or measurement rate using Equation 47 and, replace the missing data as specified in paragraphs (B) to (D) of this section.
 If R ≥ 0.9: a person shall replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, a person shall use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: a person shall replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: a person shall replace the missing data by the highest data value sampled or analyzed during the three preceding years.
Equation 47: Sampling rate
Long description for Equation 47
This equation is used to calculate the sampling or measurement rate employed. It divides the quantity of actual samples or measurements taken by an individual, denoted "QS_ACT", by the predetermined quantity of samples or measurements needed for section 4, labeled "QS_REQUIRED". The outcome, "R", provides the sampling or measurement rate in percentage terms for the task. This equation doesn't involve iterative processes or final summations.
Where:
R = sampling or measurement rate that was used (%)
QS_{ ACT} = quantity of actual samples or measurements obtained by the person
QS_{ REQUIRED} = quantity of samples or measurements required for section 4
4.C.2.
For missing data that concerns clinker production, use the first data estimated after the period for which the data is missing or use the maximum daily production capacity and multiply it by the number of days in the month.
4.C.3.
For missing data that concerns raw material consumption, use the first data estimated after the period for which the data is missing or use the maximum rate of raw materials entering the kiln and multiply by the number of days in the month.
4.C.4.
For missing data that concerns the quantity of dust, or the quantity of limestone, the replacement data shall be generated from best estimates based on all of the data relating to the processes.
4.C.5.
For all units that monitor and report emissions using CEMS; the missing data backfilling procedures in the CEMS guidance document can be used or Equation 48 to determine CO_{2} concentration, stack gas flow rate, fuel flow rate, HHV , and fuel carbon content.
 If R ≥ 0.9: a person shall replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, a person shall use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: a person shall replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: a person shall replace the missing data by the highest data value sampled or analyzed during the three preceding years.
Equation 48: Sampling rate
Long description for Equation 48
This equation is used to calculate the sampling or measurement rate that was utilized. The primary variables in this equation are the quantity of actual samples or measurements obtained by an individual, labeled as "HS_ACT", and the quantity of samples or measurements required for section 4, labeled as "HS_REQUIRED". The core calculation process divides "HS_ACT" by "HS_REQUIRED". The outcome directly provides the sampling rate as a percentage.
Where:
R = sampling or measurement rate that was used (%)
HS_{ ACT} = quantity of actual samples or measurements obtained by the person
HS_{ REQUIRED} = quantity of samples or measurements required for section 4
5 Quantification methods for aluminium production
5.A CO_{2} emissions from aluminium production
Calculate the annual CO_{2}, CF_{4}, C_{2}F_{6} and SF_{6} emissions from aluminium production using the methods specified in this section. While the emissions are calculated based on monthly sampling, only annual values (e.g., annual production, annual consumption and annual average contents) are required to be reported.
5.A.1 CO_{2} emissions from prebaked anode consumption
Calculate the total annual CO_{2} emissions from prebaked anodes consumption using Equation 51.
Equation 51: Prebaked anode consumption
Long description for Equation 51
This equation is used to calculate the total annual quantity of CO_{2} emissions resulting from the consumption of prebaked anodes. For each month "m", the main variables are the net anode consumption for liquid aluminum production, labeled as "NAC", the total quantity of liquid aluminum production, labeled as "MP", the sulfur content in prebaked anodes, labeled as "S_a", and the ash content in prebaked anodes, labeled as "Ash_a". The core calculation process involves multiplying the product of "NAC" and "MP" with a factor dependent on sulfur and ash contents, “1  S_a  Ash_a”, then multiplying the result by the conversion factor 3.664. The calculation is repeated for every month up to the total of 12 months. Finally, the values for all months are summed to yield the annual CO_{2}emissions from prebaked anode consumption.
Where:
E_{ CO2 PA} = the total annual quantity of CO_{2} emissions from the consumption of prebaked anodes (tonnes)
NAC = the net anode consumption for liquid aluminium production in month “m” (tonnes anodes/tonnes liquid aluminium)
MP = the total quantity of liquid aluminium production in month “m” (tonnes)
S_{ a} = the sulphur content in prebaked anodes in month “m” (kg S / kg prebaked anodes)
Ash _{a} = the ash content in prebaked anodes in month “m” (kg ash / kg prebaked anodes)
3.664 = ratio of molecular weights of CO_{2} to C
5.A.2 CO_{2} emissions from anode consumption from Søderberg electrolysis cells
Calculate the total annual CO_{2} emissions from anode consumption from Søderberg electrolysis cells using Equation 52.
Equation 52: Anode consumption from Søderberg electrolysis cells
Long description for Equation 52
This equation is used to calculate the total annual quantity of CO_{2} emissions attributable to anode consumption from Søderberg electrolysis cells, labeled as "E_CO_{2} AS." For each month "m", ranging from 1 to 12, it multiplies the total quantity of anode paste consumption labeled as "PC," and the total quantity of liquid aluminium production labeled as "MP." The equation subtracts the product of emissions from cyclohexanesoluble matter "CSM" and "MP" divided by 1000 from the multiplication of "PC" and "MP." From this, it subtracts the product of the average pitch content "BC," "PC," "MP," and the sum of sulphur content "S p," ash content "Ash_p," and hydrogen content "H_p." Furthermore, it subtracts the result of the multiplication of one minus "BC," "PC," and "MP" with the sum of sulphur content in calcinated coke "S_c" and ash content in calcinated coke "Ash_c," from the product of "MP" and carbon content "CP." The final result is then multiplied by the conversion factor 3.664, which represents the ratio of molecular weights, CO_{2} to C. All calculated values for each month are summed to provide the annual CO_{2} emissions.
Where:
E_{ CO2 AS} = the total annual quantity of CO_{2} emissions attributable to anode consumption from Søderberg electrolysis cells (tonnes)
PC = the total quantity of anode paste consumption in month “m” (tonnes paste / tonnes liquid aluminium)
MP = the total quantity of liquid aluminium production in month “m” (tonnes)
CSM = emissions from cyclohexanesoluble matter (CSM) (tonnes) or the International Aluminium Institute factor used Table 51 (kg CSM / tonnes liquid aluminium)
BC = the average pitch content or other binding agent in paste in month “m” (kg pitch or other binding agent / kg paste)
S_{ p} = the sulphur content or other binding agent in pitch in month “m” (kg S or other binding agent / kg pitch)
Ash _{p} = the ash content or other binding agent in pitch (kg ash / kg pitch)
H_{ p} = the hydrogen content or other binding agent in pitch or the International Aluminium Institute factor used, listed in Table 51 (kg H_{2} or other binding agent / kg pitch)
S_{ c} = the sulphur content in calcinated coke (kg S / kg calcinated coke)
Ash_{ c} = the ash content in calcinated coke (kg ash / kg calcinated coke)
CP = the carbon content in dust from Søderberg electrolysis cells (kg C / kg liquid aluminium, or a value of 0)
3.664 = ratio of molecular weights, CO_{2} to C
5.A.3 CO_{2} emissions from anode and cathode baking
Calculate the total annual CO_{2} emissions from anode and cathode baking using Equation 53.
Equation 53: Anode and cathode baking
Long description for Equation 53
E_{CO2 AC }= E_{CO2 PM} + E_{CO2 P}
Where:
E_{ CO2 AC} = the total annual quantity of CO_{2} emissions from anode and cathode baking (tonnes)
E_{ CO2 PM} = the total annual quantity of CO_{2} emissions from packing material, as specified in Equation 54
E_{ CO2 P} = the total annual quantity of CO_{2} emissions from the coking of pitch or another binding agent, as specified in Equation 55
5.A.4 CO_{2} emissions from packing material
Calculate the total annual CO_{2} emissions from packing material using Equation 54.
Equation 54: Packing material
Long description for Equation 54
This equation is used to calculate the total annual quantity of CO_{2} emissions from packing material consumption. For each month "m", it considers the quantity of packing material consumption labeled as "CPM", and the quantity of baked anodes or cathodes removed from the furnace, labeled as "BAC". These quantities are multiplied together, and the product is multiplied by the subtraction of the ash content "Ash_pm" and the sulphur content "S_pm" of the packing material from 1, and then multiplied by the conversion factor 3.664, which represents the ratio of molecular weights of CO_{2} to C. This calculation is repeated for every month up to the total of 12 months. Finally, the values of all months are summed to provide the annual CO_{2} emissions from packing material consumption.
Where:
E_{ CO2 PM} = the total annual quantity of CO_{2} emissions from packing material consumption (tonnes)
CPM = the quantity of packing material consumption in month “m” (tonnes packing material / tonnes baked anodes or cathodes)
BAC = the quantity of baked anodes or cathodes removed from furnace in month “m” (tonnes)
Ash _{p m} = the ash content of packing material in month “m” (kg ash / kg packing material)
S_{ p m} = the sulphur content of packing material in month “m” (kg S / kg packing material)
3.664 = ratio of molecular weights, CO_{2} to C
5.A.5 CO_{2} emissions from coking of pitch or other binding agent
Calculate the total annual CO_{2} emissions from coking of pitch or other binding using Equation 55.
Equation 55: Coking of pitch or other binding agent
Long description for Equation 55
This equation is used to calculate the total annual quantity of CO_{2} emissions resulting from the coking of pitch or other binding agents. For each month "m", it evaluates the total quantity of green anodes or cathodes introduced into the furnace, represented as "GAC", and subtracts the quantity of baked anodes or cathodes removed from the furnace, labeled as "BAC", and the product of the hydrogen content in pitch or another binding agent labeled as "H_p", “GAC”, and the pitch or other binding agent content in green anodes or cathodes labeled as "PC". This adjusted value is further reduced by the quantity of recovered tar in the month "RT" and then multiplied by the conversion factor 3.664. The process is iteratively carried out for all 12 months, after which the monthly results are aggregated to yield the annual CO_{2} emissions from coking of pitch or other binding agents.
Where:
E_{ CO2 P} = the total annual quantity of CO_{2} emissions from coking of pitch or other binding agent (tonnes)
GAC = the total quantity of green anodes or cathodes put into furnace in month “m” (tonnes)
BAC = the total quantity of baked anodes or cathodes removed from furnace in month “m” (tonnes)
H_{ p} = the hydrogen content in pitch or other binding agent or the International Aluminium Institute factor used in month “m” listed in Table 51 (kg H_{2} / kg pitch or other binding agent)
PC = the pitch or other binding agent content in green anodes or cathodes in month “m” (kg pitch or other binding agent / kg anodes or cathodes)
RT = the total quantity of recovered tar in month “m” (tonnes)
3.664 = ratio of molecular weights, CO_{2} to carbon
5.A.6 CO_{2} emissions from green coke calcination
Calculate the total annual CO_{2} emissions from green coke calcination using Equation 56.
Equation 56: Green coke calcination
Long description for Equation 56
This equation is used to calculate the total annual quantity of CO_{2} emissions from green coke calcination, labeled as "E_CO_{2}_GC." For each month "m," the total quantity of green coke consumption is denoted as "GC." From this quantity, the water content "H2O_GC," volatiles content "V_GC," and sulphur content "S_GC" are subtracted, respectively. This value is then subtracted from the product of the sum of calcinated coke production "CC" and undercalcinated coke production "UCC," and the total quantity of emissions from coke dust "ED" all multiplied by the difference of one minus the sulphur content in calcinated coke "S_cc." This resultant product is then multiplied by the constant 3.664, which is the ratio of molecular weights of CO_{2} to carbon. Additionally, green coke "GC" is multiplied by 0.035, which represents the CH_{4} and tar content in coke volatiles contributing to CO_{2} emissions. This product is then further multiplied by 2.75, which is the conversion factor from CH_{4} to CO_{2}. Finally, the sum of these calculations for all 12 months provides the total annual CO_{2} emissions.
Where:
E_{ CO2 GC} = the total annual quantity of CO_{2} emissions from green coke calcination (tonnes)
GC = the total quantity of green coke consumption in month “m” (tonnes)
H_{2}O_{ GC} = the water content in green coke in month “m” (kg H_{2}O / kg green coke)
V_{ GC} = the volatiles content in green coke in month “m” (kg volatiles / kg green coke)
S_{ GC} = the sulphur content in green coke in month “m” (kg S / kg green coke)
CC = the total quantity of calcinated coke production in month “m” (tonnes)
UCC = the total quantity of undercalcinated coke production in month “m” (tonnes)
ED = the total quantity of emissions from coke dust in month “m” (tonnes)
S_{ cc} = the sulphur content in calcinated coke in month “m” (kg S / kg calcinated coke)
3.664 = ratio of molecular weights, CO_{2} to carbon
0.035 = CH_{4} and tar content in coke volatiles contributing to CO_{2} emissions
2.75 = conversion factor, CH_{4} to CO_{2}
5.A.7 CF_{4} and C_{2}F_{6} emissions from anode effects
Calculate the total annual CF_{4} and C_{2}F_{6} emissions from anode effects for each series of pots using the same technology as specified in this section. Persons who operate a facility with CEMS shall calculate the annual CF_{4} and C_{2}F_{6} emissions as specified in section 5.B.1.
5.A.7.a The slope method for CF_{4} emissions from anode effects
Calculate the total annual CF_{4} emissions from anode effects using Equation 57.
Equation 57: CF_{4} emissions from anode effects (slope method)
Long description for Equation 57
This equation is used to calculate the total annual CF_{4} emissions due to anode effects using the slope method. For each month "m", the time series slope for the series of pots "Slope_CF4" is multiplied by the anode effect duration "AED" and the production of liquid aluminum "MP". The anode effect duration is derived from the frequency of anode effects and their average duration in minutes. The series of calculations is repeated for each month up to 12 months. The final step involves summing the monthly values to ascertain the annual CF_{4} emissions from anode effects.
Where:
E_{ CF4} = the total annual quantity of CF_{4} emissions from anode effects (tonnes)
Slope _{CF4} = the slope for series of pots j in month “m” (tonnes CF_{4} / tonnes liquid aluminium / anode effect minute / potday)
AED = the anode effect duration in month “m” (anode effect minutes / potday calculated per month and obtained by multiplying the anode effects frequency, in number of anode effects per potday, by the average duration of anode effects, in minutes)
MP = the production of liquid aluminium in month “m” (tonnes)
5.A.7.b The overvoltage coefficient method for CF_{4} emissions from anode effects
Calculate the total annual CF_{4} emissions from anode effects using Equation 58.
Equation 58: CF_{4} emissions from anode effects (overvoltage coefficient method)
Long description for Equation 58
This equation is used to calculate the total annual quantity of CF₄ emissions resulting from anode effects. For each series of pots "j" up to the total number "n", and for each month "m" up to a total of 12 months, the overvoltage coefficient "OVC_CF₄" for CF₄ emissions (tonnes of CF₄ per tonnes of liquid aluminium per millivolt) is multiplied with the anode effect overvoltages "AEO" (in millivolts per pot). This product is then divided by the current efficiency "CE" of the aluminium production process (expressed as a percentage) and subsequently multiplied by the monthly production of liquid aluminium "MP" (in tonnes). The calculation is repeated for every series of pots and every month. Finally, the values across all series of pots and months are summed to determine the total annual CF₄ emissions.
Where:
E_{ CF4} = the total annual quantity of CF_{4} emissions from anode effects (tonnes)
n = number of series of pots
OVC _{CF4} = the overvoltage coefficient (tonnes of CF_{4} / tonnes liquid aluminium/millivolt)
AEO = the anode effect overvoltages in month “m” for series of pots “j” (millivolts / pot)
CE = the current efficiency of the aluminium production process (percentage)
MP = the production of liquid aluminium in month “m” (tonnes)
5.A.7.c Calculation method for C_{2}F_{6} emissions from anode effects
Calculate the total annual C_{2}F_{6} emissions from anode effects using Equation 59.
Equation 59: C_{2}F_{6} emissions from anode effects
Long description for Equation 59
This equation is used to calculate the total annual quantity of C₂F₆ emissions stemming from anode effects. For each month "m" up to a total of 12 months, the total monthly quantity of CF₄ emissions "E_CF₄" (in tonnes) is multiplied by the weight fraction "F" of C₂F₆ to CF₄. This weight fraction can either be determined by the emitter or selected from Table 52 (expressed in kg C₂F₆ per kg CF₄). The calculation is iteratively executed for every month. Subsequently, the values for all months are aggregated to yield the total annual C₂F₆ emissions.
Where:
E_{ C2F6} = the total annual quantity of C_{2}F_{6} emissions (tonnes)
E_{ CF4} = the total quantity of CF_{4} emissions in month “m” (tonnes)
F = the weight fraction of C_{2}F_{6} / CF_{4} determined by the emitter or selected from Table 52 (kg C_{2}F_{6} / kg CF_{4})
5.A.8 Emissions from SF_{6} used as a cover gas
Calculate the total annual emissions from SF_{6} used as a cover gas using Equation 510 if based on the change in inventory or using Equation 511 if based on direct measurement.
Equation 510: SF_{6} emissions used as a cover gas (change in inventory)
Long description for Equation 510
E_{SF6} = (S_{Inv – Begin} – S_{Inv – End}) + (S_{Purchased}  S_{Shipped})
Where:
E _{SF6} = the total annual quantity of SF_{6} emissions used as a cover gas (tonnes)
S_{ InvBegin} = the total annual quantity of SF_{6} in storage at the beginning of the year (tonnes)
S_{ InvEnd} = the total annual quantity of SF_{6} in storage at the end of the year (tonnes)
S_{ Purchased} = the total annual quantity of SF_{6} purchases for the year (tonnes)
S_{ Shipped} = the total annual quantity of SF_{6} shipped out of the facility during the year (tonnes)
Equation 511: SF_{6} emissions used as a cover gas (direct measurement)
Long description for Equation 511
This equation is used to calculate the total annual quantity of SF₆ emissions employed as a cover gas using direct measurement methods. For each month "m" up to 12 months, the total quantity of cover gas entering the electrolysis cells "Q_Input" (in tonnes) is multiplied by the concentration "C_Input" of SF₆ in the cover gas for that month (expressed as tonnes of SF₆ per tonnes of input gas). From this product, the product of the quantity of gas containing SF₆ collected and shipped out "Q_Output" (in tonnes) and its concentration "C_Output" for that month (in tonnes of SF₆ per tonnes of gas collected and shipped out) is subtracted. The calculation is iteratively performed for every month. Eventually, the monthly values are accumulated to determine the annual SF₆ emissions utilized as a cover gas.
Where:
E_{ SF6} = the total annual quantity of SF_{6} emissions used as a cover gas (tonnes)
Q_{ Input} = the total quantity of cover gas entering the electrolysis cells in month “m” (tonnes)
C_{ Input} = the concentration of SF_{6} in the cover gas entering the electrolysis cells in month “m” (tonnes SF_{6} / tonnes input gas)
Q_{ Output} = the quantity of gas containing SF_{6} collected and shipped out of the facility in month “m” (tonnes)
C_{ Output} = the concentration of SF_{6} in the gas collected and shipped out of the facility in month “m” (tonnes SF_{6} /tonnes gas collected and shipped out of the facility)
5.B Sampling, analysis and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
Measure all parameters monthly, subject to the exceptions specified in this section. Where a method provides the option to use a default value versus a measured parameter, a person who operates a facility that currently measures these parameters, shall continue to measure these parameters. Where measured data for a parameter is unavailable, a person shall use the provided default values.
 For emissions of cyclohexanesoluble matter used in Equation 52, a person shall measure the emissions monthly or use International Aluminium Institute factors.
 For the carbon present in dust from Søderberg electrolysis cells used in the calculation in Equation 52, a person shall measure the carbon monthly or use the value of 0.
 For the hydrogen content in pitch used in the calculation in Equation 52 and Equation 55, a person shall measure the content monthly or use the International Aluminium Institute factors.
 For the parameters concerning the use of SF_{6} as a cover gas, a person shall measure the parameters in accordance with paragraph (b).
 In the case of the quantity of calcinated coke, a person shall directly measure that quantity or determine it by multiplying the recovery factor by the quantity of green coke consumed in accordance with Equation 512:
Equation 512: Calcinated coke
Long description for Equation 512
CCP_{M} = RF × CGC
Where:
CCP_{ M} = the calcinated coke produced and measured during the measurement period (tonnes)
RF = the recovery factor determined annually during a measurement period (tonnes calcinated coke / tonnes green coke)
CGC = the consumption of green coke measured during the measurement period (tonnes)
5.B.1.
Persons using CEMS for CF_{4} and C_{2}F_{6} emissions from anode effects must comply with the guidelines in the document “Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories” published by the Intergovernmental Panel on Climate Change.
5.B.2.
Persons using the slope method or the overvoltage coefficient method shall conduct performance tests to calculate the slope or overvoltage coefficients for each technology used in a series of pots using the Protocol for Measurement of Tetrafluoromethane and Hexafluoroethane Emissions from Primary Aluminum Production (PDF) published in April 2008 by the U.S. Environmental Protection Agency (USEPA) and the International Aluminium Institute. The performance tests shall be conducted whenever:
 36 months have passed since the last tests or a series of pots is started up
 a change occurs in the control algorithm that affects the intensity or duration of the anode effects or the nature of the anode effect termination routine, or
 changes occur in the distribution or duration of anode effects: for example when the percentage of manual kills changes or when, over time, the number of anode effects decreases and results in anode effects of shorter duration, or when the algorithm for bridge movements and anode effect overvoltage accounting changes
5.B.3.
The slope or the overvoltage coefficient calculated following the performance tests specified in 5.B.2 shall be used beginning on the date of the change; or the 1st of January immediately following the measurements.
5.B.4.
Persons who use the direct measurement method in Equation 511 to calculate SF_{6} emissions from the consumption of a cover gas shall, measure monthly the quantity of SF_{6} entering the electrolysis cells and the quantity and SF_{6} concentration of any residual gas collected and shipped out of the facility.
5.C Procedures for estimating missing analytical data
Use the methods prescribed in this section to reanalyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period for missing analytical data.
5.C.1.
Whenever sampling, analysis and measurement data required for section 5 for the calculation of emissions is missing, a person shall ensure the data is replaced using the missing data procedures specified below:
 For missing data that concerns carbon content, sulphur content, ash content, hydrogen content, water content, CSM emissions, pitch content, carbon present in skimmed dust from electrolysis cells, volatiles content, data for slope calculations, frequency and duration of anode effects, overvoltage, SF_{6} concentration or data to calculate current efficiency, determine the sampling or measurement rate using Equation 513 and, replace the missing data as specified in paragraphs (b) to (d) of this section.
 If R ≥ 0.9: a person shall replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, a person shall use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: a person shall replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: a person shall replace the missing data by the highest data value sampled or analyzed during the three preceding years.
Equation 513: Sampling Rate
Long description for Equation 513
This equation is used to calculate the sampling or measurement rate used during an observation. For each observation, the quantity of actual samples or measurements obtained by an individual, denoted as "QS_ACT", is divided by the quantity of samples or measurements required for section 5, labeled "QS_REQUIRED". The result of this division gives the sampling or measurement rate "R" expressed as a percentage. The core calculation process divides the actual quantity of samples by the required quantity of samples.
Where:
R = sampling or measurement rate that was used (%)
QS_{ ACT} = quantity of actual samples or measurements obtained by the person
QS_{ REQUIRED} = quantity of samples or measurements required for section 5
5.C.2.
For missing data that concerns net anode consumption, anode paste consumption, packing material consumption, green anode or cathode consumption, quantity of tar recovered, green coke consumption, liquid aluminium production, aluminium hydrate production, baked anode or cathode production, calcinated and undercalcinated coke production, coke dust quantity or SF_{6} quantity, the replacement data must be estimated on the basis of all the data relating to the processes used.
5.C.3.
For all units that monitor and report emissions using CEMS; the missing data backfilling procedures in the CEMS guidance document can be used or Equation 514 to determine CO_{2} concentration, stack gas flow rate, fuel flow rate, HHV, and fuel carbon content.
 If R ≥ 0.9: a person shall replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, a person shall use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: a person shall replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: a person shall replace the missing data by the highest data value sampled or analyzed during the three preceding years.
Equation 514: Sampling rate
Long description for Equation 514
This equation is used to calculate the sampling or measurement rate used during an observation. For each observation, the quantity of actual samples or measurements procured by an individual, labeled as "HS_ACT", is divided by the quantity of samples or measurements required for section 5, denoted "HS_REQUIRED". The resulting value from this division is the sampling or measurement rate "R", expressed in percentage terms. The core calculation process involves dividing the actual quantity of samples by the required quantity of samples.
Where:
R = sampling or measurement rate that was used (%)
HS_{ ACT} = quantity of actual samples or measurements obtained by the person
HS_{ REQUIRED} = quantity of samples or measurements required for section 5
Parameters^{a}  Default factors 

CSM: emissions of cyclohexane soluble matter (kg per tonne aluminium)  Horizontal stud Søderberg: 4.0 Vertical stud Søderberg: 0.5 
Hp: Hydrogen content in pitch (wt %)  3.3 
Technology used  Weight fraction (kg C_{2}F_{6} / kg CF_{4}) 

Centreworked prebaked anodes (CWPB)  0.121 
Sideworked prebaked anodes (SWPB)  0.252 
Vertical stud Søderberg (VSS)  0.053 
Horizontal stud Søderberg (HSS)  0.085 
6 Quantification methods for iron and steel production
6.A Emissions from iron and steel production
If a person subject to the requirements throughout this section is also subject to the OutputBased Pricing System Regulations, methods described in those regulations may be used, where applicable, to quantify the information that the person must report under the applicable schedule in the 2024 and 2025 GHGRP Notice.
The total annual CO_{2} emissions from iron and steel production shall be calculated using the methods specified in this section, depending on the process used. Specific process inputs or outputs that contribute less than 1% of the total mass of carbon into or out of the process do not have to be included in Equation 61 to Equation 610. Persons who operate a facility with CEMS, may calculate the annual CO_{2} emissions from iron and steel production as specified in Equation 611 or using Equation 61 to Equation 610. Where a method provides the option to use a default value versus a measured parameter, a person who operates a facility that currently measures these parameters shall continue to measure these parameters. Where measured data for a parameter is unavailable, a person shall use the provided default values.
6.A.1 Induration Furnace
Calculate the total annual CO_{2} emissions from the induration furnace using either Equation 61 or Equation 62.
Equation 61: CO_{2} from induration furnace using green pellets
Long description for Equation 61
E_{CO2 T }= [(T × C_{T}) – (P × C_{p}) – (R × C_{R})] × 3.664
Where:
E_{ CO2 T} = the total annual quantity of emissions from induration furnace (tonnes)
T = the total annual quantity of green pellets fed to the furnace (tonnes)
C_{ T} = the annual weighted average carbon content of green pellets fed to the furnace (tonnes C / tonnes green pellets)
P = the total annual quantity of fired pellets produced by the furnace (tonnes)
C_{ P} = the annual weighted average carbon content of fired pellets produced by the furnace (tonnes C / tonnes fired pellets)
R = the annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average carbon content of air pollution control residue collected (tonnes C / tonnes residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
Equation 62: CO_{2} from induration furnace using iron ore concentrate
Long description for Equation 62
This equation is used to calculate the total annual quantity of emissions from an induration furnace using iron ore concentrate. For each additive "j", the total annual quantity of the additive consumed by the furnace, labeled as "AD_j", is multiplied by the annual weighted average carbon content of that additive, "C_ADj". The annual quantity of iron ore concentrate fed to the furnace, "IRC", is multiplied by its corresponding annual weighted average carbon content, "C_IRC". The product of the total annual quantity of fired pellets produced by the furnace, "P", and the annual weighted average carbon content of these pellets, "C_p", is subtracted from the sum of the previous products. Then, the product of the annual quantity of air pollution control residue collected, "R", and the annual weighted average carbon content of this residue, "C_R", is subtracted. The resultant value is then multiplied by the conversion factor 3.664 to provide the total emissions.
Where:
E_{ CO2 IP} = the total annual quantity of emissions from induration furnace (tonnes)
n = number of additives
AD_{ j} = the total annual quantity of additive material “j” (e.g. limestone, dolomite, bentonite) consumed by the furnace (tonnes)
C_{AD j} = the annual weighted average carbon content of additive material “j” consumed by the furnace (tonnes C / tonnes additive material)
IRC = the total annual quantity of iron ore concentrate fed to the furnace (tonnes)
C_{ IRC} = the annual weighted average carbon content of iron ore concentrate fed to the furnace (tonnes C / tonnes iron ore concentrate)
P = the total annual quantity of fired pellets produced by the furnace (tonnes)
C_{ P} = the annual weighted average carbon content of fired pellets produced by the furnace (tonnes C / tonnes fired pellets)
R = the annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average carbon content of air pollution control residue collected (tonnes C / tonnes residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
6.A.2 Basic oxygen furnace
Calculate the total annual CO_{2} emissions from the basic oxygen furnace using Equation 63.
Equation 63: CO_{2} from Basic Oxygen Furnace
Long description for Equation 63
This equation is used to calculate the total annual quantity of emissions from a basic oxygen furnace. The annual total quantity of molten iron charged to the furnace, "I", is multiplied by its corresponding weighted average carbon content, "C_I". This is added to the product of the total annual quantity of ferrous scrap charged to the furnace, "Sc", and its respective annual weighted average carbon content, "C_SC". For each nonbiomass flux material "l", the total annual quantity charged to the furnace, "FL_t", is multiplied by its corresponding weighted average carbon content, "C_FLt", and the resulting values are summed. Similarly, for each nonbiomass carbonaceous material "m", the total quantity consumed by the furnace, "CARi", is multiplied by its respective weighted average carbon content, "C_CAR i", and summed. The product of the total annual quantity of slag produced by the furnace, "ST", and its weighted average carbon content, "C_ST", is subtracted. Subsequently, the products of the annual quantity of ferrous residue, "BOG", and its carbon content, "C_BOG", as well as the annual quantity of air pollution control residue, "R", and its carbon content, "C_R", are subtracted. The final value is multiplied by the conversion factor 3.664 to determine the total emissions.
Where:
E_{ CO2 BOF} = the total annual quantity of emissions from basic oxygen furnace (tonnes)
n = number of flux materials
m = number of carbonaceous materials
I = the total annual quantity of molten iron charged to furnace (tonnes)
C_{ I} = the annual weighted average carbon content of molten iron charged to furnace (tonnes of C / tonnes of molten iron)
SC = the total annual quantity of ferrous scrap charged to furnace (tonnes)
C_{ SC} = the annual weighted average carbon content of ferrous scrap charged to furnace (tonnes C / tonnes ferrous scrap)
FL_{ t} = the total annual quantity of nonbiomass flux material “t” (e.g. limestone, dolomite, bentonite) charged to the furnace (tonnes)
C_{ FL t} = the annual weighted average carbon content of nonbiomass flux material “t” charged to the furnace (tonnes C / flux material)
CAR_{ i} = the total annual quantity of nonbiomass carbonaceous material “i” (e.g. coal, coke) consumed by the furnace (tonnes)
C_{ CAR i} = the annual weighted average carbon content of nonbiomass carbonaceous material “i” consumed by the furnace (tonnes C / tonnes carbonaceous material)
ST = the total annual quantity of molten raw steel produced by the furnace (tonnes)
C_{ ST} = the annual weighted average carbon content of molten raw steel produced by the furnace (tonnes C / tonnes molten raw steel)
SL = the total annual quantity of slag produced by the furnace (tonnes)
C_{ SL} = the annual weighted average carbon content of slag produced by the furnace (tonnes C / tonnes slag)
BOG = the total annual quantity of furnace gas transferred off site (tonnes)
C_{ BOG} = the annual weighted average carbon content of furnace gas transferred off site (tonnes C / tonnes furnace gas transferred)
R = the annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average carbon content of air pollution control residue collected (tonnes C / tonnes residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
6.A.3 Coke oven battery
All emissions related to coke oven batteries are to be allocated, by greenhouse gas (CO_{2}, CH_{4} and N_{2}O), to Stationary fuel combustion and Flaring emissions source categories, as appropriate.
Where coke oven details are sufficiently known to calculate all associated emissions using section 2 of this document, facilities shall do so. Otherwise:
 calculate the total annual CO_{2} emissions from the coke oven battery using Equation 64, and
 calculate total annual CH_{4} and N_{2}O emissions from the coke oven battery using section 2 (note that the high Global Warming Potentials for CH_{4} and N_{2}O are such that they are significantly more potent GHGs than CO_{2})
Equation 64: CO_{2} from coke oven battery
Long description for Equation 64
This equation is used to calculate the total annual quantity of emissions from coke production. The total annual quantity of nonbiomass coking coal charged to a battery, "C_C", is multiplied by its respective weighted average carbon content, "C_CC". For each nonbiomass carbonaceous material "i", other than coking coal, the total annual quantity charged to the battery, "OM_i", is multiplied by its corresponding carbon content, "C_OMi", and summed. The product of the total annual quantity of coke produced, "CO", and its corresponding weighted average carbon content, "C_CO", is subtracted. This is followed by subtracting the products of the total annual quantity of byproduct from nonbiomass byproduct coke oven battery, "BY", its carbon content, "C_BY", the total quantity of coke oven gas transferred offsite, "COG", and its carbon content, "C_COG". Lastly, the product of the annual quantity of air pollution control residue collected, "R", and its carbon content, "C_R", is subtracted. The final value is multiplied by the conversion factor 3.664 to compute the total emissions.
Where:
E_{ CO2 COKE} = the total annual quantity of emissions from coke production (tonnes)
C_{C} = the total annual quantity of nonbiomass coking coal charged to battery (tonnes)
C_{ CC} = the annual weighted average carbon content of nonbiomass coking coal charged to battery (tonnes of C / tonnes of coking coal)
OM_{i} = the total annual quantity of nonbiomass carbonaceous material “I” other than coking coal, such as natural gas and fuel oil, charged to battery (tonnes)
C_{OMi} = the annual weighted average carbon content of nonbiomass carbonaceous material “i” other than coking coal, charged to battery (tonnes of C / tonnes of process material)
n = number of nonbiomass carbonaceous materials, other than coking coal, charged to battery
CO = the total annual quantity of coke produced (tonnes)
C_{ CO} = the annual weighted average carbon content of coke produced (tonnes C / tonnes coke)
BY = the total annual quantity of byproduct, from nonbiomass byproduct coke oven battery (tonnes)
C_{ BY} = the annual weighted average carbon content of nonbiomass byproduct, from byproduct coke oven battery (tonnes C / tonnes byproduct)
COG = the total annual quantity of coke oven gas transferred offsite (tonnes)
C_{ COG} = the annual weighted average carbon content of coke oven gas transferred offsite (tonnes C / tonnes coke oven gas)
R = the annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average carbon content of air pollution control residue collected (tonnes C / tonnes residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
6.A.4 Sinter
Calculate the total annual CO_{2} emissions from sinter production using Equation 65.
Equation 65: CO_{2} from sinter production
Long description for Equation 65
This equation is used to calculate the total annual quantity of emissions from sinter production. For each nonbiomass carbonaceous material "i", the total annual quantity consumed by the furnace, "CAR_i", is multiplied by its respective weighted average carbon content, "C_CAR i", and summed. The product of the total annual quantity of sinter feed material, "FE", and its respective weighted average carbon content, "C_FE", is added. Subsequently, the products of the total annual quantity of sinter production, "S", and its weighted average carbon content, "C_S", and the annual quantity of air pollution control residue collected, "R", and its carbon content, "C_R", are subtracted. The resulting value is multiplied by the conversion factor 3.664 to give the total emissions.
Where:
E_{ CO2 SINTER} = the total annual quantity of emissions from sinter production (tonnes)
n = number of carbonaceous materials
CAR_{ i} = the total annual quantity of nonbiomass carbonaceous material “i” (e.g. coal, coke) consumed by the furnace (tonnes)
C_{ CAR i} = the annual weighted average carbon content of nonbiomass carbonaceous material “i” consumed by the furnace (tonnes C / tonnes carbonaceous material)
FE = the total annual quantity of sinter feed material (tonnes)
C_{ FE} = the annual weighted average carbon content of sinter feed material (tonnes C / tonnes sinter feed)
S = the total annual quantity of sinter production (tonnes)
C_{ S} = the annual weighted average carbon content of sinter production (tonnes C / tonnes sinter production)
R = the annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average carbon content of air pollution control residue collected (tonnes C / tonnes residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
6.A.5 Electric arc furnace
Calculate the total annual CO_{2} emissions from electric arc furnace using Equation 66.
Equation 66: CO_{2} from electric arc furnace
Long description for Equation 66
This equation is used to calculate the total annual quantity of emissions from an electric arc furnace. For each flux material "t" and each carbonaceous material "i", the formula sums the product of the total annual quantity of nonbiomass flux material "FL_t" and its respective carbon content "C_FLt". Simultaneously, the product of the total annual quantity of direct reduced iron "I" and its carbon content "C_I" is added, as is the product of the total annual quantity of ferrous scrap "SC" and its carbon content "C_SC". Additionally, the equation incorporates the product of the total annual quantity of nonbiomass carbon electrodes "EL" and their carbon content "C_EL", and the product of the total annual quantity of nonbiomass carbonaceous material "CAR_i" and its carbon content "C_CARi". From this aggregated sum, the product of slag "SL" and its carbon content "C_SL", and the product of air pollution control residue "R" and its carbon content "C_R", are both subtracted. The result is then multiplied by the conversion factor 3.664 to convert from tonnes of C to tonnes of CO₂. The cumulative values across all materials are combined to yield the annual CO₂ emissions from the electric arc furnace.
Where:
E_{ CO2 EAF} = the total annual quantity of emissions from electric arc furnace (tonnes)
n = number of flux materials
m = number of carbonaceous materials
I = the total annual quantity of direct reduced iron charged to furnace (tonnes)
C_{ I} = the annual weighted average carbon content of direct reduced iron charged to the furnace (tonnes C / tonnes direct reduced iron)
SC = the total annual quantity of ferrous scrap consumed by the furnace (tonnes)
C_{ SC} = the annual weighted average carbon content of ferrous scrap consumed by the furnace (tonnes C / tonnes ferrous scrap)
FL_{ t} = the total annual quantity of nonbiomass flux material “t” (e.g. limestone, dolomite, bentonite) charged to the furnace (tonnes)
C_{ FL t} = the annual weighted average carbon content of nonbiomass flux material “t” charged to the furnace (tonnes C / flux material)
EL = the total annual quantity of nonbiomass carbon electrodes consumed by the furnace (tonnes)
C_{ EL} = the annual weighted average carbon content of nonbiomass carbon electrodes consumed by the furnace (tonnes C / tonnes carbon electrode)
CAR_{ i} = the total annual quantity of nonbiomass carbonaceous material “i” (e.g. coal, coke) consumed by the furnace (tonnes)
C_{ CAR i} = the annual weighted average carbon content of nonbiomass carbonaceous material “i” consumed by the furnace (tonnes C / tonnes carbonaceous material)
ST = the total annual quantity of molten raw steel produced by the furnace (tonnes)
C_{ ST} = the annual weighted average carbon content of molten raw steel produced by the furnace (tonnes C / tonnes molten raw steel)
SL = the total annual quantity of slag produced by the furnace (tonnes)
C_{ SL} = the annual weighted average carbon content of slag produced by the furnace (tonnes C / tonnes slag)
R = the annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average carbon content of air pollution control residue collected (tonnes C / tonnes residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
6.A.6 Argonoxygen decarburization vessels
Calculate the total annual CO_{2} emissions from argonoxygen decarburization vessels using Equation 67. Alternatively, for integrated processes, CO_{2} emissions may be calculated using section 6.A.2 or section 6.A.5, as appropriate.
Equation 67: CO_{2} from argonoxygen decarburization vessels
Long description for Equation 67
E_{CO2 AOD }= [Steel × (C_{In} – C_{Out}) – (R × C_{R})] × 3.664
Where:
E_{ CO2 AOD} = the total annual quantity of emissions from argonoxygen decarburization vessels (tonnes)
Steel = the total annual quantity of molten steel charged to the vessel (tonnes)
C_{ In} = the annual weighted average carbon content of molten steel before decarburization (tonnes C / tonnes molten steel)
C_{ Out} = the annual weighted average carbon content of molten steel after decarburization (tonnes C / tonnes molten steel)
R = the total annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average annual carbon content of air pollution control residue collected or a default value of 0 (tonnes C / tonnes residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
6.A.7 Iron production from direct reduction furnace
Calculate the total annual CO_{2} emissions from the direct reduction furnace using Equation 68.
Equation 68: CO_{2} from direct reduction furnace
Long description for Equation 68
This equation is used to calculate the total annual quantity of CO_{2} emissions from a direct reduction furnace. For each raw material "k", labeled as "RM_k", the total annual consumed quantity other than carbonaceous material and ore is multiplied by its respective carbon content "C RM_k". Similarly, for each carbonaceous material "i", labeled as "CAR_i", its annual consumption is multiplied by its carbon content "C CAR_i". The total annual quantity of iron ore or iron ore pellets, labeled as "Ore", fed to the furnace is multiplied by its carbon content "C Ore". The total annual iron produced, "I", is multiplied by its carbon content "C I", and subtracted. The total annual quantity of nonmetallic material produced, labeled as "NM", is also multiplied by its carbon content "C NM" and subtracted. Furthermore, the total annual quantity of air pollution control residue collected, "R", is multiplied by its carbon content "C R". The resultant value is then multiplied by the conversion factor 3.664 to convert tonnes of carbon to tonnes of CO_{2}. The values from all iterations are summed to yield the final annual CO_{2} emissions from the direct reduction furnace.
Where:
E_{ CO2 DR} = the total annual quantity of emissions from direct reduction furnace (tonnes)
n = number of raw materials, other than carbonaceous materials and ore
m = number of carbonaceous materials
Ore = the total annual quantity of iron ore or iron ore pellets fed to the furnace (tonnes)
C_{ Ore} = the annual weighted average carbon content of iron ore or iron ore pellets fed to the furnace (tonnes C / tonnes iron or iron ore pellets)
RM_{ k} = the total annual consumed raw material “k” other than carbonaceous material and ore (tonnes)
C_{ RM k} =the annual weighted average carbon content of raw material “k” other than carbonaceous material and ore (tonnes C / tonnes raw material)
CAR_{ i} = the total annual quantity of nonbiomass carbonaceous material “i” (e.g. coal, coke) consumed by the furnace (tonnes)
C_{ CAR i} = the annual weighted average carbon content of nonbiomass carbonaceous material “i” consumed by the furnace (tonnes C / tonnes carbonaceous material)
I = the total annual quantity of iron produced by the furnace (tonnes)
C_{ I} = the annual weighted average carbon content of iron produced by the furnace (tonnes C / tonnes iron)
NM = the total annual quantity of nonmetallic material produced by the furnace (tonnes)
C_{ NM} = the annual weighted average carbon content of nonmetallic material produced by the furnace (tonnes C / tonnes nonmetallic material)
R = the total annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average annual carbon content of air pollution control residue collected or a default value of 0 (tonnes C / tonnes residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
6.A.8 Iron production from blast furnace
Calculate the total annual CO_{2} emissions from the blast furnace using Equation 69.
Equation 69: CO_{2} from blast furnace
Long description for Equation 69
This equation is used to calculate the total annual quantity of CO_{2} emissions originating from a blast furnace. For each raw material type "k" up to the total "n", the annual consumed quantity labeled "RM_k" is multiplied by its average carbon content "C_RM_k". Similarly, for every carbonaceous material "i" up to the total "m", the consumed quantity labeled "CAR_i" is multiplied by its average carbon content "C_CAR_i". Additionally, for each flux material "t" up to the total "p", the charged amount "FL_t" is multiplied by its average carbon content "C_FL_t". The annual iron ore or iron ore pellet quantity fed to the furnace, "Ore", is multiplied by its carbon content "C_Ore", while the iron produced by the furnace, "I", is multiplied by its carbon content "C_I". The equation then subtracts the product of the total annual quantity of nonmetallic material "NM" and its carbon content "C_NM". It further subtracts the product of the annual quantity of blast furnace gas transferred offsite "BG" and its carbon content "C_BG", and then subtracts the total annual quantity of air pollution control residue collected "R" multiplied by its carbon content "C_R". The net result of these calculations is then multiplied by the conversion factor 3.664 to convert from tonnes of C to tonnes of CO_{2}. The final value represents the total annual CO_{2} emissions from the blast furnace.
Where:
E_{ CO2 BF} = the total annual quantity of emissions from blast furnace (tonnes)
n = number of raw materials, other than carbonaceous materials and ore
m = number of carbonaceous materials
p = number of flux materials
Ore = the total annual quantity of iron ore or iron ore pellets fed to the furnace (tonnes)
C_{ Ore} = the annual weighted average carbon content of iron ore or iron ore pellets fed to the furnace (tonnes C / tonnes iron or iron ore pellets)
RM_{ k} = the total annual quantity of consumed raw material “k” other than carbonaceous material and ore (tonnes)
C_{ RM k} = the annual average carbon content of raw material “k” other than carbonaceous material and ore (tonnes C / tonnes raw material)
CAR_{ i} = the total annual quantity of nonbiomass carbonaceous material “i” (e.g. coal, coke) consumed by the furnace (tonnes)
C_{ CAR i} = the annual weighted average carbon content of nonbiomass carbonaceous material “i” consumed by the furnace (tonnes C / tonnes carbonaceous material)
FL_{ t} = the total annual quantity of nonbiomass flux material “t” (e.g. limestone, dolomite, bentonite) charged to the furnace (tonnes)
C_{ FL t} = the annual weighted average carbon content of nonbiomass flux material “t” charged to the furnace (tonnes C / flux material)
I = the total annual quantity of iron produced by the furnace (tonnes)
C_{ I} = the annual weighted average carbon content of iron produced by the furnace (tonnes C / tonnes iron)
NM = the total annual quantity of nonmetallic material produced by the furnace (tonnes)
C_{ NM} = the annual weighted average carbon content of nonmetallic material produced by the furnace (tonnes C / tonnes nonmetallic material)
BG = the total annual quantity of blast furnace gas transferred offsite (tonnes)
C_{ BG} = the annual weighted average carbon content of blast furnace gas transferred offsite (tonnes C / tonnes blast furnace gas)
R = the total annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average annual carbon content of air pollution control residue collected or a default value of 0 (tonnes C / tonnes residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
6.A.9 Molten steel production from ladle furnace
Calculate the total annual CO_{2} emissions from the ladle furnace using Equation 610. Alternatively, for integrated processes, CO_{2} emissions may be calculated using section 6.A.2 or section 6.A.5, as appropriate.
Equation 610: CO_{2} from ladle furnace
Long description for Equation 610
This equation is used to calculate the total annual quantity of emissions from a ladle furnace in terms of CO_{2}. The core calculation process involves multiplying the total annual quantity of molten steel fed to the furnace "MS_FED" by its annual weighted average carbon content "C_MS_FED". An iterative addition is then performed for each additive material "j" up to a total of "m" additives, multiplying each additive quantity "AD_j" with its respective annual weighted average carbon content "C_AD_j". The total annual carbon electrodes consumed by the furnace "EL" is multiplied by its carbon content "C_EL". The annual molten steel production "MS_prod" is multiplied by its carbon content "C_MS_prod". Further subtractions are made by multiplying the total annual quantity of slag "SL" and air pollution control residue "R" by their respective carbon contents "C_SL" and "C_R". Another subtraction involves the total annual quantity of other residues "Rp" multiplied by its carbon content "C_Rp". Finally, the resulting value is multiplied by the conversion factor 3.664 to convert tonnes of C to tonnes of CO_{2}. The individual results from these operations are combined to provide the total annual CO_{2} emissions from the ladle furnace.
Where:
E_{ CO2 LF} = the total annual quantity of emissions from ladle furnace (tonnes)
m = number of additives
MS_{ FED} = the total annual quantity of molten steel fed to the furnace (tonnes)
C_{ MS FED} = the annual weighted average carbon content of molten steel fed to the furnace (tonnes C / tonnes molten steel)
AD_{ j} = the total annual quantity of additive material “j” (e.g. limestone, dolomite, bentonite) consumed by the furnace (tonnes)
C_{ AD j} = the annual weighted average carbon content of additive material “j” consumed by the furnace (tonnes C / tonnes additive material)
EL = the total annual carbon electrodes consumed by the furnace (tonnes)
C_{ EL} = the annual weighted average carbon content of carbon electrodes consumed by the furnace (tonnes C / tonnes carbon electrodes)
MS_{ prod} = the total annual quantity of molten steel produced by the furnace (tonnes)
C_{ MS prod} = the annual weighted average carbon content of molten steel produced by the furnace (tonnes C / tonnes molten steel)
SL = the total annual quantity of slag produced by the furnace (tonnes)
C_{ SL} = the annual weighted average carbon content of slag produced by the furnace, or a default value of 0 (tonnes C / tonnes slag)
R = the total annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average carbon content of air pollution control residue collected or a default value of 0 (tonnes C / tonnes residue)
Rp = the total annual quantity of other residue produced (tonnes)
C_{ Rp} = the annual weighted average carbon content of other residue produced or a default value of 0 (tonnes of C / tonnes of residue)
3.664 = conversion factor from tonnes of C to tonnes of CO_{2}
6.A.10 CO_{2} emissions from iron and steel production using CEMS
Persons operating a facility with installed CEMS shall calculate CO_{2} emissions from iron and steel production using Equation 611.
Equation 611: Iron and steel CEMS
Long description for Equation 611
This equation is used to calculate the total annual quantity of CO_{2} emissions from iron and steel production by subtracting the total annual CO_{2} fuel combustion emissions "ECO_{2}FC" from the total annual CO_{2} quantity measured using Continuous Emissions Monitoring Systems (CEMS) "E_CO_{2}CEMS". The CO_{2} fuel combustion emissions are calculated as specified in section 2.
Where:
E_{ CO2} = the total annual quantity of CO_{2} emissions from iron and steel production (tonnes) calculated by subtracting fuel combustion emissions for CO_{2} as specified in section 2 from the total annual CO_{2} quantity measured using CEMS
E_{ CO2 CEMS} = the total annual quantity of CO_{2} emissions from CEMS including fuel combustion and iron and steel production emissions (tonnes)
E_{ CO2 FC} = the total annual CO_{2} fuel combustion emissions, calculated as specified in section 2
6.B CO_{2} emissions from iron and steel powder production
Calculate the total annual CO_{2} emissions from iron and steel powder production using the methods in this section depending on the process used. Specific process inputs or outputs that contribute less than 0.5 % of the total mass of carbon into or out of the process do not have to be included in Equation 612 to Equation 616 by mass balance. Persons operating a facility with CEMS, shall calculate the annual CO_{2} emissions from iron and steel powder production as specified in Equation 617. Where a method provides the option to use a default value versus a measured parameter, persons who operates a facility that currently measures these parameters, shall continue to measure these parameters. Where measured data for a parameter is unavailable, persons shall use the provided default values.
Equation 612: CO_{2} from iron and steel powder production
Equation 612 (See long description below)
This equation is used to calculate the total annual quantity of CO_{2} emissions from iron and steel powder production. The equation adds together four different quantities: the emissions from atomization of molten cast iron "E_CO_{2}A", the emissions from the decarburization of iron powder "E_CO_{2}D", emissions from molten steel grading "E_CO_{2}SG", and emissions from steel powder annealing "E_CO_{2}SA". The sum of these quantities provides the total CO_{2} emissions from the iron and steel powder production process.
Where:
E_{ CO2} = the total annual quantity of CO_{2} emissions from iron and steel powder production (tonnes)
E_{ CO2 A} = the total annual quantity of CO_{2} emissions from the atomization of molten cast iron (tonnes)
E_{ CO2 D} = the total annual quantity of CO_{2} emissions from the decarburization of iron powder (tonnes)
E_{ CO2 SG} = the total annual quantity of CO_{2} emissions from molten steel grading (tonnes)
E_{ CO2 SA} = the total annual quantity of CO_{2} emissions from steel powder annealing
6.B.1 CO_{2} emissions from the atomization of molten cast iron
Calculate the total annual CO_{2} emissions from the atomization of molten cast iron using Equation 613.
Equation 613: CO_{2} from atomization of molten cast iron
Long description for Equation 613
This equation is used to calculate the total annual quantity of CO_{2} emissions from the atomization of molten cast iron. For each material 'k' and byproduct 'j', the product of the total quantity of molten cast iron "MI" and its carbon content "C_MI" is added to the product of the total quantity of other material 'k' "Mk" and its carbon content "C_Mk" and then subtracted from the product of the total annual quantity of atomized cast iron produced "AI" and its carbon content "C_AI". Separately, for each byproduct 'j', the total quantity "BP_j" multiplies its carbon content "C_BPj", or a default value of 0. All these values are summed and multiplied by the conversion factor 3.664, which is the ratio of molecular weights of CO_{2} to carbon, to determine the CO_{2} emissions from the atomization of molten cast iron.
Where:
E_{ CO2 A} = the total annual quantity of CO_{2} emissions from the atomization of molten cast iron (tonnes)
p = number of materials used other than molten cast iron
m = number of byproducts
MI = the total annual quantity of molten cast iron fed into the process (tonnes)
C_{ MI} = the annual weighted average carbon content of molten cast iron fed into the process (tonnes C / tonnes molten cast iron)
M_{ k} = the total annual quantity of other material “k” used in the process (tonnes)
C_{ M k} = the annual weighted average carbon content of other material “k” used in the process (tonnes C / tonnes other material)
AI = the total annual quantity of atomized cast iron production (tonnes)
C_{ AI} = the annual weighted average carbon content of atomized cast iron (tonnes C / tonnes atomized cast iron)
BP_{ j} = the total annual quantity of byproduct “j” (tonnes)
C_{ BP j} = the annual weighted average carbon content of byproduct “j” or a default value of 0 (tonnes C / tonnes byproduct)
3.664 = ratio of molecular weights, CO_{2} to carbon
6.B.2 CO_{2} emissions from the decarburization of iron powder
Calculate the total annual CO_{2} emissions from the decarburization of iron powder using Equation 614.
Equation 614: CO_{2} from decarburization of iron powder
Long description for Equation 614
This equation is used to calculate the total annual quantity of CO_{2} emissions from the decarburization of iron powder. For each byproduct "j", the equation begins by taking the product of the total annual quantity of iron powder fed into the process, labeled as "IP_f", and the annual weighted average carbon content of iron powder fed into the process, labeled as "C_IPf ". From this, the product of the total annual quantity of decarburized iron powder, "IPd", and the annual weighted average carbon content of decarburized powder production, "C_IPd ", is subtracted. Subsequently, the sum of the product of the total annual quantity of byproduct "j", "BP_j", and the annual weighted average carbon content of byproduct "j", "C_BPj ", is subtracted. This entire value is then multiplied by the conversion factor 3.664, which is the ratio of molecular weights of CO_{2} to carbon. The process is iterated for every byproduct up to the total number "m". Then, the values of all byproducts are summed to provide the total annual CO_{2} emissions from the decarburization of iron powder.
Where:
E_{ CO2 D} = the total annual quantity of CO_{2} emissions from the decarburization of iron powder (tonnes)
m = number of byproducts
IP_{ f} = the total annual quantity of iron powder fed into the process (tonnes)
C_{ IP f} = the annual weighted average carbon content of iron powder fed into the process (tonnes C / tonnes iron powder)
IP_{ d} = the total annual quantity of decarburized iron powder (tonnes)
C_{ IP d} = the annual weighted average carbon content of decarburized powder production (tonnes C / tonnes decarburized powder production)
BP_{ j} = the total annual quantity of byproduct “j” (tonnes)
C_{ BP j} = the annual weighted average carbon content of byproduct “j” or a default value of 0 (tonnes C / tonnes byproduct)
3.664 = ratio of molecular weights, CO_{2} to carbon
6.B.3 CO_{2} emissions from steel grading
Calculate the total annual CO_{2} emissions from steel grading using Equation 615.
Equation 615: CO_{2} from steel grading
Long description for Equation 615
This equation is used to calculate the total annual quantity of CO_{2} emissions from steel grading. It incorporates the molten steel fed into the process, labeled "MI_f", multiplied by its annual weighted average carbon content "C_MI f". For each additive "j", labeled "AD_j", the annual quantity is multiplied by the annual weighted average carbon content of the additive "C_AD j". The equation also considers the total annual carbon electrodes consumption "EL" multiplied by their annual weighted average carbon content "C_EL". Likewise, it subtracts the total annual quantity of molten steel production "MS" multiplied by "C_MS" and the total annual quantity of slag production "SL" multiplied by "C SL". Then, the equation subtracts the total annual quantity of air pollution control residue collected "R" multiplied by "C_R" and the total annual quantity of other residue production "Rp" multiplied by "C Rp". Finally, the outcome is multiplied by the conversion factor 3.664, which represents the ratio of molecular weights, CO_{2} to carbon. Then, the values for each additive are summed to provide the annual CO_{2} emissions.
Where:
E_{ CO2 SG} = the total annual quantity of CO_{2} emissions from steel grading (tonnes)
m = number of additives
MI_{ f} = the total annual quantity of molten steel fed into the process (tonnes)
C_{ MI f} = the annual weighted average carbon content of molten steel fed into the process (tonnes C / tonnes
molten steel)
AD_{ j} = the total annual quantity of additive “j” used in the process (tonnes)
C_{ AD j} = the annual weighted average carbon content of additive “j” used in the process (tonnes C / tonnes additive)
EL = the total annual carbon electrodes consumption (tonnes)
C_{ EL} = the annual weighted average carbon content of carbon electrodes consumption (tonnes C / tonnes carbon electrodes)
MS = the total annual quantity of molten steel production (tonnes)
C_{ MS} = the annual weighted average carbon content of molten steel production (tonnes C / tonnes molten steel)
SL = the total annual quantity of slag production (tonnes)
C_{ SL} = the annual weighted average carbon content of slag production, or a default value of 0 (tonnes C / tonnes slag)
R = the total annual quantity of air pollution control residue collected (tonnes)
C_{ R} = the annual weighted average annual carbon content of air pollution control residue collected or a default value of 0 (tonnes C / tonnes residue)
Rp = the total annual quantity of other residue production (tonnes)
C_{ Rp} = the annual weighted average annual carbon content of other residue production or a default value of 0 (tonnes C / tonnes other residue)
3.664 = ratio of molecular weights, CO_{2} to carbon
6.B.4 CO_{2} emissions from steel powder annealing
Calculate the total annual CO_{2} emissions from steel powder annealing using Equation 616.
Equation 616: CO_{2} from steel powder annealing
Long description for Equation 616
This equation is used to calculate the total annual quantity of CO_{2} emissions originating from steel powder annealing. For every byproduct "j", the calculation commences by multiplying the total annual quantity of steel powder fed into the process, labeled "P_a", with its corresponding annual weighted average carbon content, labeled "C_Pa". From this, the multiplication product of the total annual quantity of steel powder production, "SP_p", and its annual weighted average carbon content, "C_SPp", is subtracted. The ensuing result is further reduced by the summation of the products of the total annual quantity of byproduct "j", "BP_j", and its annual weighted average carbon content or a default value of 0, "C_BPj". The entire resultant value is then multiplied by the conversion factor 3.664, representing the ratio of molecular weights of CO_{2} to carbon. This procedure is repeated for every byproduct up to the total "m". Ultimately, the resultant values of all byproducts are accumulated to render the total annual CO_{2} emissions from steel powder annealing.
Where:
E_{ CO2 SA} = the total annual quantity of CO_{2} emissions from steel powder annealing (tonnes)
m = number of byproducts
P_{ a} = the total annual quantity of steel powder fed into the process (tonnes)
C_{ P a} = the annual weighted average carbon content of steel powder fed into the process (tonnes C / tonnes steel powder)
SP_{ p} = the total annual quantity of steel powder production (tonnes)
C_{ SP p} = the annual weighted average carbon content of steel powder production (tonnes C / tonnes steel powder)
BP_{ j} = the total annual quantity of byproduct “j” (tonnes)
C_{ BP j} = the annual weighted average carbon content of byproduct “j” or a default value of 0 (tonnes C / tonnes byproduct)
3.664 = ratio of molecular weights, CO_{2} to carbon
6.B.5 CO_{2} emissions from iron and steel powder production using CEMS
Persons operating a facility with installed CEMS shall calculate CO_{2} emissions from iron and steel production using Equation 617.
Equation 617: CO_{2} from iron and steel powder production – CEMS
Long description for Equation 617
E_{CO2} = E_{CO2 CEMS }– E_{CO2 FC}
Where:
E_{ CO2} = the total annual quantity of CO_{2} emissions from iron and steel powder production (tonnes) calculated by subtracting fuel combustion emissions for CO_{2} as specified in section 2, from the total annual CO_{2} quantity measured using CEMS
E_{ CO2 CEMS} = the total annual quantity of CO_{2} emissions from CEMS including fuel combustion and iron and steel powder production emissions (tonnes)
E_{ CO2 FC} = the total annual CO_{2} fuel combustion emissions, calculated as specified in section 2
6.C Sampling, analysis and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
The annual mass of each material used in sections 6.A and 6.B mass balance methodologies shall be determined using plant instruments used for accounting purposes, including either direct measurement of the quantity of material used in the process or by calculations using process operating information.
6.C.1 Carbon content for materials in iron and steel production
Persons who operate a facility that uses calculations specified in sections 6.A and 6.B shall, for materials that contribute 1% or more of the total carbon in the process, use the data provided by the supplier or determine the carbon content by analyzing a minimum of 3 representative samples per year, using the following analysis methods:
 For iron ore, pellets, and other ironbearing materials, use ASTM E1915.
 For iron and ferrous scrap, use ASTM E1019.
 For coal, coke, and other carbonaceous materials (e.g., electrodes, etc.), use ASTM D5373 or ASTM D7582.
 For petroleum liquid based fuels and liquid wastederived fuels, use ASTM D5291 and either ASTM D2502 or ASTM D2503.
 For steel, use any of the following analyses methods:
 ASM CS104 UNS No. G10460
 ISO/TR 153491: 1998
 ISO/TR 153493: 1998
 ASTM E415
 ASTM E1019
 For flux (i.e., limestone or dolomite) and slag, use ASTM C25.
 For steel production byproducts (e.g., blast furnace gas, coke oven gas, coal tar, light oil, sinter off gas, slag dust, etc.); use an online instrument that determines carbon content to ±5%; or any of the other analytical methods listed in this section; or methodologies using plant instruments used for accounting purposes.
6.C.2 Iron and steel powder production
Person who operate a facility that produces iron powder and steel powder shall determine annually the carbon content of each material or product that contributes 0.5% or more of the total carbon in the process, either by using the data provided by the supplier, or by using the following methods:
 For iron or iron powder, a person shall use any of the following analyses methods:
 ASTM E1019
 ASTM E415
 For steel or steel powder, a person shall use any of the following methods:
 ASM CS104 UNS G10460
 ISO/TR 153491
 ISO/TR 153493
 ASTM E415
 For carbon electrodes, a person shall use ASTM D5373.
6.D Procedures for estimating missing analytical data
Use the methods prescribed in this section to reanalyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period for missing analytical data.
6.D.1.
Whenever sampling, analysis and measurement data required for section 6 for the calculation of emissions is missing, a person shall ensure the data is replaced using the missing data procedures specified in this section.
 For missing data that concerns carbon content, temperature, pressure or gas concentration, determine the sampling or measurement rate using Equation 618 and, replace the missing data as specified in paragraphs (b) to (d) of this section.
 If R ≥ 0.9: a person shall replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, a person shall use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: a person shall replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: a person shall replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
Equation 618: Sampling rate
Long description for Equation 618
This equation is used to calculate the sampling or measurement rate as a percentage. For each measurement instance, the actual quantity of samples or measurements obtained by the person, labeled as "QS_ACT", is divided by the quantity of samples or measurements that are required for section 6, labeled as "QS_REQUIRED". The resulting value represents the sampling or measurement rate used in percentage terms.
Where:
R = sampling or measurement rate that was used (%)
QS_{ ACT} = quantity of actual samples or measurements obtained by the person
QS_{ REQUIRED} = quantity of samples or measurements required for section 6
6.D.2.
For missing data that concerns the following in iron and steel production: the quantity of carbonaceous raw material, quantity of ferrous scrap, quantity of molten iron, quantity of coking coal, quantity of flux material, quantity of direct reduced iron pellets, quantity of carbon electrodes, quantity of iron ore or iron ore pellets, production of slag, quantity of greenball pellets, production of fired pellets, production of coke oven gas, production of coke, quantity of air pollution control residue collected, quantity of other coke oven byproducts, the quantity of steel consumption or production, quantity of gas from basic oxygen furnace transferred off site, production of sinter, production of iron or the quantity of nonmetallic byproducts, the replacement data shall be generated from best estimates based on all of the data relating to the processes.
6.D.3.
For missing data that concerns the following in iron and steel powder production: the quantity of molten cast iron, consumption of carbon electrodes, quantity of molten steel, quantity of additive, quantity of iron or steel powder, production of atomized cast iron, quantity of slag, quantity of byproducts, quantity of residue or the quantity of other materials, the replacement data shall be generated from best estimates based on all of the data relating to the processes.
6.D.4.
For all units that monitor and report emissions using CEMS; the missing data backfilling procedures in the CEMS guidance document can be used or Equation 619 to determine CO_{2} concentration, stack gas flow rate, fuel flow rate, HHV, and fuel carbon content.
 If R ≥ 0.9: a person shall replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, a person shall use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: a person shall replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: a person shall replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
Equation 619: Sampling rate
Long description for Equation 619
This equation is used to calculate the sampling or measurement rate in percentage terms. For every instance of measurement, the quantity of actual samples or measurements that have been obtained by an individual, referred to as "HS_ACT", is divided by the quantity of samples or measurements that are mandated for section 6, represented as "HS_REQUIRED". The resulting value represents the sampling or measurement rate used in percentage terms.
Where:
R = sampling or measurement rate that was used (%)
HS_{ ACT} = quantity of actual samples or measurements obtained by the person
HS_{ REQUIRED} = quantity of samples or measurements required for section 6
7 Quantification methods for electricity and heat generation
An electricity and/or heat generating unit is any device that combusts solid, liquid, or gaseous fuel for the purpose of producing electricity and/or useful heat or steam either for sale or for use onsite. This does not include portable or emergency generators with a nameplate capacity less than 50 kW or that generate less than 2 MWh in the reporting year.
Quantify emissions of CO_{2}, CH_{4}, and N_{2}O for each generating unit of electric power, steam, heated air and water.
For generating units without individual meters (or no dedicated tank in the case of diesel and heavy oil) and no CEMS in place, the facility may use a common meter or tank to disaggregate emissions for each unit using an engineering estimation approach that accounts for total emissions, and operating hours and combustion efficiency of each individual unit.
For diesel generating facilities in nonintegrated remote areas (those facilities not connected to the North American power grid), allocate diesel fuel to each generating unit from a common tank based on the proportion of MWh energy delivered by each unit.
7.A CO_{2} emissions from electricity and heat generation
Estimate CO_{2} emissions from fuel combustion using methods outlined in section 2: Quantification methods for fuel combustion and flaring for electricity and/or heat generation (or in the case of fossil fuel electric power generation facilities – NAICS 221112, for each electricity generating unit), with some specific references presented in section 7.A(1) to 7.A(5).
(1) Nonvariable fuels – for generating units combusting nonvariable fuels (Table 21 and Table 22) use quantification methods outlined in section 2.A.1.
(2) Variable fuels – for generating units combusting variable fuels, use quantification methods outlined in section 2.A.2.
(3) Biomass fuels – for generating units combusting biomass fuels, use quantification methods outlined in section 2.A.1 or 2.A.2.d, as applicable.
(4) CEMS – determine CO_{2} emissions using quantification methods outlined in section 2.A.3.
(5) For generating units that combust more than one type of fuel, calculate CO_{2} emissions as follows.
 For units burning only fossil fuels, determine CO_{2} emissions using one of the following methods:
 A CEMS in accordance with section 2.A.3; operators using this method need not report emissions separately for each fossil fuel.
 For units not equipped with a CEMS, calculate the CO_{2} emissions separately for each fuel type (refer to Key Notes box in section 2) using the methods specified in paragraphs (1), (2) and (3) of this section.
 For generating units burning biomassderived fuel with a fossil fuel, determine CO_{2} emissions using one of the following methods:
 A CEMS in accordance with section 2.A.3; determine the portion of the total CO_{2} emissions attributable to the biomassderived fuel and portion of the total CO_{2} emissions attributable to the fossil fuel using the methods specified in 2.A.4.
 For units not equipped with a CEMS, calculate the CO_{2} emissions separately for each fuel type, as specified in section 2, using the methods specified in paragraphs (1), (2) and (3) of this section.
7.B CH_{4} and N_{2}O emissions from electricity and heat generation
Calculate the annual CH_{4} and N_{2}O emissions of electricity and/or heat generating units using the methods specified in section 2.B.
7.C CO_{2} emissions from acid gas scrubbing
Calculate the annual CO_{2} emissions from electricity generating units that use acid gas scrubbers, or add an acid gas reagent to the combustion unit, using Equation 71, if these CO_{2} emissions are not already determined using a CEMS.
Equation 71: Acid gas scrubbing
Long description for Equation 71
This equation is used to calculate the amount of CO_{2} emitted from the sorbent over the course of a reporting year. For each reporting year, the amount of limestone or another sorbent used, symbolized as "S", multiplies the ratio of moles of CO_{2} released upon capturing one mole of acid gas, denoted by "R". This product is then multiplied by the fraction of the molecular weight of carbon dioxide, 44, over the molecular weight of the sorbent, given as "Sorbent_MW". If the sorbent is calcium carbonate, the molecular weight is 100. The final result indicates the CO_{2} emitted from the sorbent for that specific report year, measured in tonnes.
Where:
CO_{2} = CO_{2} emitted from sorbent for the report year (tonnes)
S = limestone or other sorbent used in the report year (tonnes)
R = ratio of moles of CO_{2} released upon capture of one mole of acid gas
44 = molecular weight of carbon dioxide
Sorbent_{MW} = molecular weight of sorbent (if calcium carbonate, 100)
7.D Sampling, analysis, and measurement requirements
(1) CO_{2}, CH_{4} and N_{2}O Emissions from Fuel Combustion.
 Operators using CEMS to estimate CO_{2} emissions from fuel combustion shall comply with the requirements in section 2.A.3.
 Operators using methods other than CEMS shall comply with the applicable fuel sampling, fuel consumption monitoring, heat content monitoring, carbon content monitoring, and calculation methods specified in section 2.D.
(2) CO_{2} Emissions from Acid Gas Scrubbing; measure the amount of limestone or other sorbent used during the reporting year in electricity generating units that use acid gas scrubbers or add an acid gas reagent to the combustion unit.
7.E Procedures for estimating missing data
Whenever a qualityassured value of a required parameter is unavailable (e.g., a CEM system malfunction during unit operations or no required fuel sample taken), a substitute data value for the missing parameter shall be used in the emission calculations.
When data related to sampling is unavailable, use the prescribed methods in section 7.D to reanalyze the original sample, a backup sample or the replacement sample for the same measurement and sampling period; if this is not possible, the missing data should be substituted using the following approach.
(1) For missing sampled or analyzed data (e.g. carbon content, temperature, pressure), determine the sampling or measurement rate using Equation 72 and, replace the missing data as described in paragraphs (A) through (C) follows:
Equation 72: Sampling rate
Long description for Equation 72
This equation is used to calculate the percentage of the sampling or measurement rate utilized. In each case of measurement, the actual quantity of samples or measurements secured by the facility operator, signified as "QS_ACT", is divided by the total quantity of samples or measurements that are necessary, designated "QS_REQUIRED". The resulting value represents the sampling or measurement rate used in percentage terms.
Where:
R = sampling or measurement rate that was used (%)
Q_{S ACT}_{ }= quantity of actual samples or measurements obtained by the facility operator
Q_{S REQUIRED}_{ }= quantity of samples or measurements required
 If R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
(2) For missing data concerning a quantity of raw materials (e.g. sorbent), substitute the data based on the best available estimate of that parameter using all available process data (document and retain records of the procedures used for all such estimates).
(3) For missing parameters regarding CEM systems, determine the replacement data using the missing data backfilling procedures in the CEMS guidance document or use the procedure described in paragraph (1) above.
8 Quantification methods for ammonia production
If a person subject to the requirements throughout this section is also subject to the OutputBased Pricing System Regulations, methods described in those regulations may be used, where applicable, to quantify the information that the person must report under the applicable schedule in the 2024 and 2025 GHGRP Notice.
Ammonia production comprises the following process units:
(1) Ammonia manufacturing processes in which ammonia is manufactured from a fossilbased feedstock produced via steam reforming of a hydrocarbon.
(2) Ammonia manufacturing processes in which ammonia is manufactured through the gasification of solid and liquid raw material.
8.A CO_{2} emissions from ammonia production
Calculate and report the annual gross process CO_{2} emissions from ammonia manufacturing process units using the procedures in either paragraph (1) or (2) of this section. Note that emissions from the waste recycle stream are incorporated in these calculations and are entirely allocated to process emissions, therefore, they should not be double counted as fuel combustion emissions.
(1) Calculate and report under this subpart the gross process CO_{2} emissions using Equation 81 if operating and maintaining a CEMS.
Equation 81: Ammonia production – CEMS
Long description for Equation 81
This equation is used to calculate the total annual quantity of gross CO_{2} emissions for all ammonia production manufacturing process units. For each processing unit, it takes the total annual CO_{2} emissions measured using CEMS, labeled as "E_CO_{2} CEMS," and subtracts the CO_{2} fuel combustion emissions labeled as "E_CO_{2} FC." The result gives the annual gross CO_{2} emissions, "E_CO_{2}."
Where:
E_{ CO2} = the total annual quantity of gross CO_{2} emissions for all ammonia production manufacturing process units (tonnes), calculated by subtracting CO_{2} fuel combustion emissions as specified in section 2 from the total annual CO_{2} quantity measured using CEMS
E_{ CO2 CEMS} = the total annual quantity of CO_{2} emissions from CEMS including fuel combustion and gross ammonia production process emissions (tonnes); if CO_{2} is captured at the facility, ensure the captured amounts are included in this quantity as to appropriately reflect gross emissions (do not deduct any emissions consumed in the production of urea and/or recovered for other uses)
E_{ CO2 FC} = the total annual CO_{2} fuel combustion emissions, calculated as specified in section 2
(2) Calculate and report gross process CO_{2} emissions using the procedures in paragraphs (2)(A) through (2)(D) of this section for each feedstock type (gaseous, liquid, and/or solid), as applicable.
 Calculate, from each ammonia manufacturing unit “k,” the CO_{2} process emissions from each feedstock type (solid, liquid, and/or gaseous) according to Equation 82 of this section:
Equation 82: Feedstock methodology
Long description for Equation 82
This equation is used to calculate the annual CO_{2} emissions from ammonia production in a given processing unit. For each month "m" within a processing unit "k", it multiplies the consumption of feedstock "Feed_m,k" by the weighted average carbon content "CC_m,k." This product is then multiplied by the conversion factor 3.664 x 10^3, which is the ratio of molecular weights of CO_{2} to carbon. The calculation is repeated for every month up to a total of 12. Then, the values of all months are summed to provide the annual CO_{2} emissions for that unit, labeled as "CO_2,k.".
Where:
CO_{2,k}_{ }= annual CO_{2} emissions from ammonia production in processing unit “k” (tonnes)
Feed_{m,k} = consumption of feedstock in month “m” in processing unit “k” (solids in kilograms, liquids in kilolitres, and gases in cubic metres, at 15°C and 101.325 kPa, measured as specified in 8.B.); if a mass flow meter is used, measure the feedstock used in month “m” in processing unit “k” in kg of feedstock
CC_{m,k} = weighted average carbon content in month “m” in processing unit “k”(kilograms of carbon per unit of feedstock), measured as specified in 2.D.4
 the units of carbon content shall be reported based on feedstock type: kilograms (kg) carbon per kilolitres (kl) of feedstock for liquid feedstocks; kilograms (kg) carbon per cubic metre (m^{3}) of feedstock for gaseous feedstocks; and in kilograms carbon (kg) per kilograms (kg) of feedstock for solid feedstocks
 if a mass flow meter is used, measure the carbon content for feedstock used in month “m” in processing unit “k” in kg C per kg feedstock
3.664 = ratio of molecular weights, CO_{2} to carbon
10^{3} = conversion factor from kg to tonnes
 (B) Calculate the annual process CO_{2} emissions for each ammonia processing unit “k” by taking the sum of emissions for all feedstock types, as applicable from Equation 82, using Equation 83.
Equation 83: Total emissions per unit
Long description for Equation 83
E_{CO2K} = CO_{2,G} + CO_{2,S} + CO_{2,L}
Where:
E_{CO2k} = annual CO_{2} emissions from each ammonia processing unit “k” (tonnes)
E_{CO2,G}_{ }= annual CO_{2} emissions arising from gaseous feedstock consumption (tonnes)
E_{CO2,S}_{ }= annual CO_{2} emissions arising from solid feedstock consumption (tonnes)
E_{CO2,L}_{ }= annual CO_{2} emissions arising from liquid feedstock consumption (tonnes)
 (C) Determine the combined (gross) CO_{2} emissions from all ammonia processing units at your facility using Equation 84 of this section.
Equation 84: Gross facility emissions
Long description for Equation 84
This equation is used to calculate the total annual quantity of gross CO_{2} emissions from all ammonia processing units within a facility. For each processing unit "k" from the first to the nth unit, it accumulates the annual CO_{2} emissions "E_CO_{2}k." The values for all processing units are then summed to yield the gross facility emissions, represented by "CO_{2}."
Where:
CO_{2} = total annual quantity of gross CO_{2} emissions from all ammonia processing units (tonnes)
E_{CO2k} = annual CO_{2} emissions from each ammonia processing unit “k” (tonnes)
n = total number of ammonia processing units
 (D) If applicable, determine the CO_{2} consumed in the production of urea using Equation 85.
Equation 85: Urea
Long description for Equation 85
This equation is used to calculate the annual CO_{2} consumed in urea production. For each period, the mass of urea produced, labeled as "M_urea," is multiplied by the molecular weight of CO_{2}, labeled as "MW_CO_{2}," and then divided by the molecular weight of urea, labeled as "MW_urea." This provides the CO_{2} consumption in urea production for the specified period.
Where:
CO_{2urea} = annual CO_{2} consumed in urea production (tonnes)
M_{urea} = mass of urea produced (tonnes)
MW_{CO2} = molecular weight of CO_{2} (tonnes/mol)
MW_{urea} = molecular weight of urea (tonnes/mol)
8.B Sampling, analysis and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
(1) Continuously measure the quantity of gaseous or liquid feedstock consumed using a flow meter; the quantity of solid feedstock consumed can be obtained from company records and aggregated on a monthly basis.
(2) Document the procedures used to ensure the accuracy of the estimates of feedstock consumption.
(3) Determine monthly carbon contents and the average molecular weight of each feedstock consumed from reports from your supplier(s); as an alternative to using supplier information on carbon contents, you can also collect a sample of each feedstock on a monthly basis and analyze the carbon content and molecular weight of the fuel using any of the following methods, as appropriate, listed in paragraphs (3)(A) through (3)(H) of this section, as applicable.
 ASTM D194503 Standard Test Method for Analysis of Natural Gas by Gas Chromatography
 ASTM D194690 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography
 ASTM D250204 (Reapproved 2002) Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils from Viscosity Measurements
 ASTM D250392 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure
 ASTM D323895 (Reapproved 2005) Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the ndM Method
 ASTM D529102 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants
 ASTM D317689 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke
 ASTM D537308 Standard Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal
(4) If CO_{2} from ammonia production is used to produce urea at the same facility, you must determine the quantity of urea produced using methods or plant instruments used for accounting purposes (such as sales records); document the procedures used to ensure the accuracy of the estimates of urea produced.
8.C Procedures for estimating missing data
Whenever a qualityassured value of a required parameter is unavailable (e.g., if a CEM system malfunctioned during unit operations or if a required fuel sample was not taken), a substitute data value for the missing parameter shall be used in the emission calculations.
When data related to sampling is unavailable, use the prescribed methods in section 8.B to reanalyze the original sample, a backup sample or the replacement sample for the same measurement and sampling period; if this is not possible, the missing data should be substituted using the following approach.
(1) For missing sampled or analyzed data (e.g. carbon content, temperature, pressure), determine the sampling or measurement rate using Equation 86 and, replace the missing data as described in paragraphs (A) through (C) follows:
Equation 86: Sampling rate
Long description for Equation 86
This equation is used to calculate the sampling or measurement rate that was used. For a given time frame, the quantity of actual samples or measurements obtained by the facility operator, labeled as "QS_ACT," is divided by the quantity of samples or measurements required, labeled as "Qs_REQUIRED." The result represents the rate at which sampling was done during the specified period.
Where:
R = sampling or measurement rate that was used (%)
Q_{S ACT}_{ }= quantity of actual samples or measurements obtained by the facility operator
Q_{S REQUIRED}_{ }= quantity of samples or measurements required
 If R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
(2) For missing data concerning a quantity of raw materials (e.g. feedstock consumption), substitute the data based on the best available estimate of that parameter using all available process data (document and retain records of the procedures used for all such estimates).
(3) For missing parameters regarding CEM systems, determine the replacement data using the missing data backfilling procedures in the CEMS guidance document or use the procedure described in paragraph (1) above.
9 Quantification methods for nitric acid production
If a person subject to the requirements throughout this section is also subject to the OutputBased Pricing System Regulations, methods described in those regulations may be used, where applicable, to quantify the information that the person must report under the applicable schedule in the 2024 and 2025 GHGRP Notice.
A nitric acid production facility uses one or more trains to produce weak nitric acid (30 to 70 percent in strength), through the catalytic oxidation of ammonia followed by the absorption of nitrogen oxides by water. The absorber tail gas contains unabsorbed nitrogen oxides, including nitrous oxide, emissions of which may be reduced via abatement systems.
For calendar year 2024 reporting only, any person subject to the nitric acid requirements who for logistical reasons cannot fulfill the increased (semiannual) N_{2}O source testing requirements and the new CO_{2} and CH_{4} reporting requirements in Canada’s 2024 Greenhouse Gas Quantification Requirements is permitted to revert to Canada’s 2022 Greenhouse Gas Quantification Requirements for N_{2}O source testing and to disregard the CO_{2} and CH_{4} reporting requirements and quantification requirements.
9.A N_{2}O emissions from nitric acid production
Determine annual N_{2}O process emissions from each nitric acid train according to paragraphs (1), (2) or (3) of this section. Determine total N_{2}O process emissions according to paragraph (4) of this section.
For facilities in Alberta, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used where appropriate. More specifically, it is acceptable to use Alberta equation 816 in place of ECCC Equation 92; Alberta equation 817 in place of ECCC Equation 96; and Alberta equation 818 in place of ECCC Equation 91 in this section.
(1) Calculate and report the process N_{2}O emissions by operating and maintaining CEMS according to the European Commission Guidance Document – The Monitoring and Reporting Regulation – Continuous Emissions Monitoring Systems (CEMS) (PDF), 2021; the CEMS method is a continuous direct measurement of stack flow and N_{2}O concentrations, which is used to determine the mass flow of N_{2}O emissions in the stack.
 For each nitric acid production train, calculate N_{2}O emissions from a CEMS in the reporting period using Equation 91; report emissions per acid train.
Equation 91: N_{2}O CEMS calculation
Long description for Equation 91
This equation is used to calculate the N_{2}O mass emissions from nitric acid production per acid train in the reporting period. For each reporting interval "t", the calculation begins by multiplying the stack gas velocity "Vels,t" by the stack crosssectional area "Area_s". This product is then multiplied by the N_{2}O concentration "C_N2O,t" of the stack gas on a wet basis, which is measured by an insitu gas analyzer. If the analyzer provides the N_{2}O concentration in ppmv, then "C_N2O,t" is equal to ppmv times 10^6. The resulting value is further multiplied by a factor, which is the ratio of the actual pressure of the stack gas volume "P_act,t" multiplied by the standard temperature (288.15 K) to the product of standard pressure (101.325 kPa) and the actual temperature of the stack gas volume "T_act,t". The final product is then multiplied by the ratio of the molecular weight of N_{2}O "MW_N2O" (which is 44.01 kg/kmol) to the standard molar volume at standard conditions (23.645), and this product is further multiplied by the conversion factor 0.001. The calculation is repeated for every reporting interval up to the total number of intervals "T" (e.g., 8,760 hours for a nonleap year). Then, the values of all intervals are summed to provide the N_{2}O emissions for the entire reporting period.
Where:
N_{2}O_{p}_{ }= N_{2}O mass emissions from nitric acid production per acid train in reporting period, p (tonnes N_{2}O)
t = CEMS data reporting interval (hour)
T = number of CEMS data reporting intervals in reporting period (T= 8,760 hours for a nonleap year annual reporting period)
Vel_{s} = stack gas velocity (m/h), measured by continuous ultrasonic flow meter
Area_{s} = stack crosssectional area (m^{2})
C_{N2O, t}_{ }= N_{2}O concentration (wet basis) of stack gas (kmol_{N2O}/kmol_{GAS}), measured by insitu gas analyzer; (If analyzer provides N_{2}O concentration in ppmv, then C_{N2O, t }= ppmv × 10^{6})
MW_{N2O} = molecular weight of N_{2}O = 44.01 kg/kmol
P_{act} = measured actual pressure of stack gas volume (kPa)
T_{act} = measured actual temperature of stack gas volume (K)
288.15 = standard temperature (K)
101.325 = standard pressure (kPa)
23.645 = standard molar volume at standard conditions
0.001 = mass conversion factor: tonnes per kg
(2) For systems with abatement downtime: The N_{2}O Emission Factor Method is used for acid trains that do not measure N_{2}O emissions directly using a CEMS and had abatement downtime when the N_{2}O abatement system was bypassed for a certain period of time during the reporting period.
 This method requires an annual measurement of N_{2}O concentration Upstream of the N_{2}O Abatement technology and N_{2}O concentration in the final stack gas stream (after the N_{2}O abatement system), per acid train, with 3 test runs per stack test.
 Use a sitespecific emission factor and production data according to paragraphs (A) through (H) of this section.
 (A) For each nitric acid train, calculate N_{2}O emissions using Equation 92; report emissions per acid train.
Equation 92: Nitric acid emissions
Long description for Equation 92
N_{2}O_{P} = m_{pNA} × GF_{N2O,UOA} × (1 – (DF_{N2O} × AF_{N2O})) × 0.001
Where:
N_{2}O_{p} = N_{2}O mass emissions from nitric acid production, per acid train, in reporting period, p (tonnes N_{2}O)
M_{pNA} = production mass of nitric acid (100% basis), (tonnes nitric acid product) in reporting period
DF_{N2O} = average destruction efficiency of N_{2}O abatement system (%), determined by either:
 manufacturer’s specifications
 documented engineering estimates based on process knowledge, or
 calculated using the direct measurement as shown in Equation 93 if the test personnel can safely access the upstream of the N_{2}O abatement system
GF_{N2O,UOA}_{ }= average N_{2}O generation factor measured Upstream Of the N_{2}O Abatement technology (UOA) (kg N_{2}O per tonne nitric acid), as defined in Equation 94
AF_{N2O} = N_{2}O abatement system operating fraction (%) in the reporting period, as defined in Equation 95
0.001 = mass conversion factor (tonnes/kg)
 (B) Calculate the destruction efficiency by averaging the results of at least two testing campaigns during the reporting year; the result of each testing campaign should be calculated using Equation 93.
Equation 93: Destruction efficiency
Long description for Equation 93
This equation is used to calculate the average abatement system destruction efficiency in a reporting period. For each reporting period, it considers the N₂O concentration "N₂O_UOA" upstream of the N₂O Abatement technology (UOA) and multiplies it with the flow rates "Q_UOA" upstream of the N₂O Abatement technology (UOA). From this product, it subtracts the product of the N₂O concentration "N₂ONAS" from the nitric acid stack (NAS) and the flow rates "Q_NAS" from the nitric acid stack (NAS). The result is then divided by the product of "N₂O_UOA" and "Q_UOA". The final result is multiplied by 100% to yield the destruction efficiency.
Where:
DF_{N2O} = average abatement system destruction efficiency (%) in reporting period
N_{2}O_{UOA} = N_{2}O concentration (ppmv) Upstream Of the N_{2}O Abatement technology (UOA)
Q_{UOA} = flow rates (m^{3}/h) Upstream Of the N_{2}O Abatement technology (UOA)
N_{2}O_{NAS} = N_{2}O concentration (ppmv) from the nitric acid stack (NAS)
Q_{NAS} = flow rates (m^{3}/h) from the nitric acid stack (NAS)
 (C) The trainspecific average N_{2}O generation factor is calculated by averaging the results of at least two testing campaigns during the reporting year; the result of each testing campaign should be calculated based on direct measurement of N_{2}O concentration Upstream Of the N_{2}O Abatement technology (UOA) and using Equation 94:
Equation 94: Sitespecific N_{2}O generation factor (measured upstream of N_{2}O abatement technology)
Long description for Equation 94
This equation is used to calculate the average N₂O Generation Factor upstream of the N₂O Abatement technology per tonne of nitric acid. For each of the "N" measurement test runs during the stack test, the volumetric flow rate of effluent gas "Q_UOA,i" upstream of the N₂O Abatement technology during test run "i" is multiplied by the measured N₂O concentration "C_N2O,UOA,i" from the same test run and the constant conversion factor 1.861 x 10⁻⁶. This product is then divided by the measured nitric acid production rate "PR_NA,i" during test run "i". The values for each of the "N" test runs are summed, and the sum is then divided by "N" to produce the average N₂O Generation Factor.
Where:
GF_{N2O,UOA}_{ }= average N_{2}O Generation Factor Upstream Of the N_{2}O Abatement technology (kg N_{2}O per tonne nitric acid)
N = number of N_{2}O measurement test runs during stack test
Q_{UOA,i}_{ }= volumetric flow rate of effluent gas Upstream Of the N_{2}O Abatement technology during test run “i” (m^{3}/h) at 15°C & 1 atm
C_{N2O,UOA,i}_{ }= measured N_{2}O concentration Upstream Of the N_{2}O Abatement technology in test run “i” (ppmv N_{2}O);
PR_{NA,i}_{ }= measured nitric acid production rate during test run “i” (tonnes nitric acid per hour)
1.861x10^{6} = N_{2}O Density conversion factor (kg/m^{3}∙ppmv1; at 15°C & 1 atm)
 (D) Determine the abatement factor for each N_{2}O abatement technology.
 This factor corrects the N_{2}O equation for any periods during the year when the N_{2}O destruction by the abatement system is not applied.
 For operations having 100% N_{2}O abatement uptime, the default AF_{N2O} = 1.0.
 Calculate the abatement factor for each nitric acid train using Equation 95:
Equation 95: Abatement factor
Long description for Equation 95
This equation is used to calculate the N₂O abatement system operating fraction in the reporting period. For the considered reporting period, it divides the nitric acid production "PR_NA,Abate" when the N₂O abatement system is active by the total nitric acid production "PR_NA,Total" in the reporting period. The result indicates the fraction of time the N₂O abatement system was operational.
Where:
AF_{N2O} = N_{2}O abatement system operating fraction (%) in the reporting period
PR_{NA,Abate}_{ }= nitric acid production when N_{2}O abatement system is operating (tonnes nitric acid) in the reporting period
PR_{NA,Total}_{ }= total nitric acid production (tonnes nitric acid) in the reporting period
 (E) The nitric acid production for the reporting period and the monthly nitric acid production when the N_{2}O abatement system is operating must be determined from measurement systems used for accounting purposes.
 (F) Source testing to determine GF_{N2O,UOA} must be conducted at least twice per year.
 A minimum of three test runs for each stack test and hourly measurement of nitric acid production are required during the stack test and the results averaged.
 Conduct the performance tests for determining GF_{N2O,UOA} when nitric acid production process has changed or abatement equipment is installed or replaced.
 (G) If the N_{2}O abatement system destruction efficiency is determined by direct measurement, tests must occur at least twice annually, using the same N_{2}O concentration methods outlined above.
 (H) For the calculation of AF_{N2O}, the operating time of the N_{2}O abatement system during the reporting period must be determined hourly.
(3) N_{2}O Emission Factor Method for direct stack test: The N_{2}O Emission Factor Method is used for nitric acid production where N_{2}O abatement systems are integrated within the operating process and cannot be bypassed.
 A sitespecific emission factor is developed based on N_{2}O emissions by stack testing on the final Nitric Acid Stack (NAS) and production data according to paragraphs (A) through (D) of this section.
 (A) For each nitric acid train, calculate N_{2}O emissions using Equation 96; report emissions per acid train.
Equation 96: Nitric acid train emissions
Long description for Equation 96
This equation is used to calculate the N₂O mass emissions from nitric acid production for each acid train during the reporting period. For the given reporting period, the production mass of nitric acid "m_p,NA" is multiplied by the average N₂O emission factor "EF_N2O,NAS" (kg N₂O per tonne nitric acid) for the final Nitric Acid Stack (NAS), based on direct stack testing of the final N₂O emission stack. This result is then multiplied by the conversion factor 0.001 to provide the N₂O emissions in tonnes.
Where:
N_{2}O_{p} = N_{2}O mass emissions from nitric acid production, per acid train, in the reporting period, p (tonnes N_{2}O)
m_{PNA} = production mass of nitric acid (100% basis) (tonnes nitric acid product) in reporting period
EF_{N2O,NAS}_{ }= average N_{2}O emission factor (kg N_{2}O per tonne nitric acid) for the final Nitric Acid Stack (NAS) based on the direct stack testing of the final N_{2}O emission stack and calculated in Equation 97
0.001 = mass conversion factor: tonnes per kg
 (B) Determine the N_{2}O emission factor to use in Equation 96 of this section by averaging the results of at least two stack testing campaigns during the reporting year; the result of each stack testing campaign should be calculated using Equation 97.
Equation 97: Sitespecific emission factor
Long description for Equation 97
This equation is used to calculate the sitespecific emission factor for nitrous oxide (N₂O) based on final Nitric Acid Stack (NAS). For each measurement test run "i", the volumetric flow rate of effluent gas at final NAS, labeled as "Q_NAS,i", multiplies with the measured N₂O concentration at NAS during test run "i", labeled as "C_N2O,NAS,i", and then divides by the measured nitric acid production rate during test run "i", labeled as "PR_NA,i". The resulting value is then multiplied by the conversion factor 1.861 x 10^(6). The equation is repeated for every test up to the total number of N₂O measurement test runs "N". Then, the values from all the tests are summed and divided by "N" to provide the average N₂O emission factor based on final Nitric Acid Stack (NAS).
Where:
EF_{N2O,NAS}_{ }= average N_{2}O emission factor based on final Nitric Acid Stack (NAS) (kg N_{2}O per tonne nitric acid) in the reporting period.
N = number of N_{2}O measurement test runs during stack test
Q_{NAS,i}_{ }= volumetric flow rate of effluent gas at final NAS during test run “i” (m^{3}/h) at 15°C & 1 atm
C_{N2O,NAS,i}_{ }= measured N_{2}O concentration at NAS in test run “i” (ppmv N_{2}O)
PR_{NA,i}_{ }= measured nitric acid production rate during test run “i” (tonnes nitric acid per hour)
1.861x10^{6} = N_{2}O Density conversion factor (kg/m^{3}∙ppmv1; at 15°C & 1 atm)
 (C) The nitric acid production for reporting period and the monthly nitric acid production when the N_{2}O abatement system is operating must be determined from measurement systems used for accounting purposes.
 (D) Stack tests to determine EF_{N2O,NAS }must be conducted at least twice per year; a minimum of three test runs for each stack test and hourly measurement of nitric acid production are required during the stack test and the results averaged.
(4) Calculate total facility N_{2}O emissions from production of nitric acid using Equation 98.
 Note that for the GHGRP, the online reporting system in Single Window will perform this calculation appropriately after all nitric acid train emissions have been entered.
 Regulatees under the OutputBased Pricing System Regulations may be required to perform this calculation manually.
Equation 98: Facility emissions
Long description for Equation 98
This equation is used to calculate the total annual quantity of emissions from all nitric acid trains. For each nitric acid train "k", the annual emissions, labeled as "E_GHGk", are summed up. The equation is repeated for every train up to the total number of nitric acid trains "n". Then, the values of all trains are aggregated to provide the total annual emissions from all nitric acid trains for a specific gas "GHG", which can be CO₂, CH₄, or N₂O.
Where:
FacilityEmissions_{GHG} = total annual quantity of emissions from all nitric acid trains (tonnes), from gas “GHG”
E_{GHGk} = annual emissions from each nitric acid train “k” (tonnes), from gas “GHG”
GHG = CO_{2}, CH_{4} or N_{2}O gas
n = total number of nitric acid trains
9.B CO_{2} and CH_{4} emissions from reducing agent use
Determine annual CO_{2} and CH_{4} process emissions from each nitric acid train according to paragraphs (1) or (2) of this section. Determine total CO_{2} and CH_{4} process emissions according to paragraph (3) of this section. Note that for the 2024 calendar year only, if for logistical reasons it is not feasible to obtain values necessary to perform the following calculations, default values of 0 may be reported.
(1) Unreacted fraction of reducing agents method: CO_{2} and CH_{4} process emissions are calculated using the quantities and chemical composition of the reducing agents and by developing an estimate of the fraction of reducing of each reducing agent that does not react in the NO_{x} and/or N_{2}O abatement systems; use sitespecific data according to paragraphs (A) through (B) of this section.
 For each nitric acid train, calculate CO_{2} and CH_{4} emissions using Equation 99 and 910; report emissions per acid train.
Equation 99: Trainspecific CO_{2} emissions based on unreacted fraction of reducing agents
Long description for Equation 99
This equation is used to calculate the trainspecific CO₂ emissions resulting from the use of unreacted reducing agents in nitric acid production NOx and/or N₂O abatement systems. For each reducing agent "i", the annual quantity of the reducing agent used, labeled as "Q_i", multiplies with the difference between 1 and the average fraction of reducing agent "i" that did not react, labeled as "M_s,i", and the average carbon content of reducing agent "i", labeled as "C_c,i". This value is then multiplied by the stoichiometric conversion factor 3.664. The calculation is repeated for every reducing agent up to the total number of reducing agents. All the values are then summed to give the annual CO₂ mass emissions per acid train.
Equation 910: Trainspecific CH_{4} emissions based on unreacted fraction of reducing agents
Long description for Equation 910
This equation is used to calculate the trainspecific CH₄ emissions attributed to unreacted methane in the reducing agents used in nitric acid production NO_{x} and/or N₂O abatement systems. For each reducing agent "i", the annual quantity of the reducing agent, labeled as "Q_i", is multiplied with the average fraction of reducing agent "i" that did not react, labeled as "M_si", and the methane content of the reducing agent "i", labeled as "C_CH4,i". This process is repeated for every reducing agent up to the total number of reducing agents. The resultant values are then aggregated to offer the annual CH₄ emissions per acid train.
Where:
CO_{2p} = annual CO_{2} mass emissions, per acid train, from the use of reducing agents in nitric acid production NO_{x} and/or N_{2}O abatement systems (tonnes CO_{2})
CH_{4p} = annual CH_{4} mass emissions, per acid train, from the unreacted methane in the reducing agents used in nitric acid production NO_{x} and/or N_{2}O abatement systems (tonnes CH_{4})
n = number of reducing agents used in nitric acid production NO_{x} and/or N_{2}O abatement systems in the reporting period
Q_{i} = annual quantity of the reducing agent “i” used in NO_{x} and/or N_{2}O abatement systems (solids in tonnes, liquids in kilolitres, and gases in cubic metres at reference temperature and pressure conditions as used by the facility), determined using the sampling methods in section 9.C
M_{s,i} = average fraction of reducing agent “i” that did not react in the NO_{x} and/or N_{2}O abatement systems, based on engineering estimates, design, or direct CH_{4} stack measurement described in Equation 911, during the reporting period
C_{C,i} = average carbon content of reducing agent “i” used in NO_{x} and/or N_{2}O abatement systems during the reporting period (tonnes C per reported unit of reducing agent, at reference temperature and pressure conditions if the reducing agent is a gas), determined using the sampling methods in section 9.C
C_{CH4,i}_{ }= average methane content of the reducing agent “i” used in NO_{x} and/or N_{2}O abatement systems during the reporting period (tonnes of methane per unit of reducing agent, at reference temperature and pressure conditions if the reducing agent is a gas), determined using the sampling methods in section 9.C
3.664 = stoichiometric conversion factor from C to CO_{2}
 (B) If CH_{4} stack measurements are used to determine M_{s}, then M_{s} should be the average of at least two annual testing campaigns during the reporting year; the M_{s} from each testing campaign should be calculated using Equation 911.
Equation 911: Unreacted fraction of each reducing agent
Long description for Equation 911
This equation is used to calculate the average fraction of reducing agent "t" that did not react in the NO_{x} and/or N_{2}O abatement. For each measurement run "j", the volumetric flow rate of effluent gas at the final NAS, labeled as "Q_NAS,j", is multiplied by the measured CH_{4} concentration at NAS in test run "j", labeled as "C_CH4,NAS,j", and then by the CH_{4} density conversion factor 0.6784 × 10^−9. The numerator of the fraction is the summation of these products for all "j" runs, and it is divided by the measured consumption rate of reducing agent "t" during test run "j", labeled as "Cri,j", multiplied by the average methane content of the reducing agent "t" used in NO_{x} and/or N_{2}O abatement systems during the reporting period, labeled as "C_CH4,i", and further divided by the total number of CH_{4} measurement runs, labeled as "N".
Where:
M_{s,i} = average fraction of reducing agent “i” that did not react in the NO_{x} and/or N_{2}O abatement
N = number of CH_{4} measurement runs during stack test
Q_{NAS,j}_{ }= volumetric flow rate of effluent gas at final NAS during test run “j” (m^{3}/h) at 15°C & 1 atm
C_{CH4,NAS,j} = measured CH_{4} concentration at NAS in test run “j” (ppmv CH_{4}), determined using the sampling methods in section 9.C
CR_{,j,j} = measured consumption rate of reducing agent “i” during test run “j” (units of consumption per hour), using the sampling methods in section 9.C
C_{CH4,i} = average methane content of the reducing agent “i” used in NO_{x} and/or N_{2}O abatement systems during the reporting period (tonnes of methane per unit of reducing agent (at reference temperature and pressure conditions if the reducing agent is a gas), using the sampling methods in section 9.C
0.6784 x 10^{9} = CH_{4} density conversion factor (t/m^{3} * ppmv^{1}; at 15°C & 1 atm)
(2) CH_{4} emission factor and carbon mass balance method: A sitespecific emission factor is developed based on CH_{4} emissions by stack testing on the final Nitric Acid Stack (NAS) and production data, and CO_{2} emissions are calculated using a mass balance of the carbon inputs and outputs according to paragraphs (A) through (C) of this section.
 For each nitric acid train, calculate CH_{4} emissions using Equation 912; report emissions per acid train.
Equation 912: Nitric acid train CH_{4} emissions
Long description for Equation 912
CH_{4p} = m_{pNA} × EF_{CH4,NAS} × 0.001
Where:
CH_{4p} = CH_{4} mass emissions from nitric acid production, per acid train, in the reporting period, p (tonnes CH_{4})
m_{pNA} = production mass of nitric acid (100% basis) (tonnes nitric acid product) in reporting period p, using the methods in section 9.C
EF_{CH4,NAS,avg} = average CH_{4} emission factor (kg CH_{4} per tonne nitric acid) for the final Nitric Acid Stack (NAS) based on the direct stack testing of the final CH_{4} emission stack and calculated in Equation 913
0.001 = mass conversion factor: tonnes per kg
 (B) Determine the CH_{4} emission factor to use in Equation 912 of this section by averaging the results of at least two stack testing campaigns during the reporting year; the result of each stack testing campaign should be calculated using Equation 913.
Equation 913: Trainspecific CH_{4} emission factor
Long description for Equation 913
This equation is used to calculate the average CH_{4} emission factor based on the final Nitric Acid Stack (NAS). For each measurement run "j", the volumetric flow rate of effluent gas at the final NAS, labeled as "Q_NAS,j", is multiplied by the measured CH_{4} concentration at NAS in test run "j", labeled as "C_CH4aNASj", and then by the CH_{4} density conversion factor 0.6784 × 10^−6. The numerator is the summation of these products for all "j" runs, divided by the measured nitric acid production rate during test run "j", labeled as "PR_NA,j", and further divided by the total number of CH_{4} measurement test runs, labeled as "N".
Where:
EF_{CH4,NAS}_{ }= average CH_{4} emission factor based on the final Nitric Acid Stack (NAS) (kg CH_{4} per tonne nitric acid) during the stack test
N = number of CH_{4} measurement test runs during stack test
Q_{NAS,j} = volumetric flow rate of effluent gas at final NAS during test run “j” (m^{3}/h) at 15°C & 1 atm
C_{CH4,NAS,j} = measured CH_{4} concentration at NAS in test run “j” (ppmv CH_{4}), determined using the sampling methods in section 9.C
PR_{NA,j} = measured nitric acid production rate during test run “j” (tonnes nitric acid per hour), determined using the sampling methods in section 9.C
0.6784 x 10^{6} = CH_{4} Density conversion factor (kg/m^{3} * ppmv^{1}; at 15°C & 1 atm)
 (C) For each nitric acid train, calculate CO_{2} emissions using Equation 914. Report emissions per acid train.
Equation 914: Trainspecific CO_{2} from carbon mass balance
Long description for Equation 914
This equation is used to calculate the CH_{4} mass emissions from nitric acid production, per acid train, in the reporting period. For each reducing agent "i", the annual quantity of the reducing agent used in NO_{x} and/or N_{2}O abatement systems, labeled as "Q_i", is multiplied by the average carbon content of reducing agent "i", labeled as "C_Ci". The summation of these products across all agents subtracted by the product of CH_{4} mass emissions from nitric acid production, labeled as "CH4_p", and the stoichiometric conversion factor from CH_{4} to C, 0.7488, is then multiplied by the stoichiometric conversion factor from C to CO_{2}, 3.664, to yield the final CO_{2} emissions in terms of tonnes CO_{2}.
Where:
CO_{2p} = CO_{2} mass emissions from nitric acid production, per acid train, in the reporting period, p (tonnes CO_{2})
n = number of reducing agents used in NO_{x} and/or N_{2}O abatement systems during the reporting period
Q_{i} = annual quantity of the reducing agent “i” used in NO_{x} and/or N_{2}O abatement systems (solids in tonnes, liquids in kilolitres, and gases in cubic metres at reference temperature and pressure conditions as used by the facility), determined using the sampling methods in section 9.C
C_{C,i} = average carbon content of reducing agent “i” used in NO_{x} and/or N_{2}O abatement systems during the reporting period (tonnes C per reported unit of reducing agent, at reference temperature and pressure conditions if the reducing agent is a gas), determined using the sampling methods in section 9.C
CH_{4p}_{ }= CH_{4} mass emissions from nitric acid production, per acid train, in the reporting period, p (tonnes CH_{4}), as calculated in Equation 912
0.7488 = stochiometric conversion factor from CH_{4} to C
3.664 = stochiometric conversion factor from C to CO_{2}
(3) Calculate total facility CO_{2} and CH_{4} emissions from production of nitric acid using Equation 98.
 Note that for the GHGRP, the online reporting system in Single Window will perform this calculation appropriately after all nitric acid train emissions have been entered.
 Regulatees under the OutputBased Pricing System Regulations may be required to perform this calculation manually.
9.C Sampling, analysis, and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
(1) When CH_{4} or N_{2}O source testing methods are used to determine the unreacted fraction of reducing agent (M_{s}), the methane emission factor (EF_{CH4,NAS}), the nitrous oxide generation factor (GF_{N2O,UOA}), the destruction efficiency (DF_{N2O}), or the nitrous oxide emission factor (EF_{N2O,NAS}) at least two tests on different days with three runs per test must be conducted during the reporting year.
 Facilities are encouraged to conduct the stack tests over varying times of the year to facilitate a more accurate average over the course of several reporting years.
(2) The N_{2}O CEMS must comply with all relevant requirements of the European Commission Guidance Document – The Monitoring and Reporting Regulation – Continuous Emissions Monitoring Systems (CEMS) (PDF), 2017.
(3) Measure the N_{2}O and CH_{4} concentrations during the performance tests using one of the methods in paragraphs (3)(A) or (3)(B) of this section.
 EPA Method 320 at 40 CFR part 63, appendix A, Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy
 ASTM D634803 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy
(4) Measure stack gas temperature and pressure continuously using stack instruments.
(5) Determine the production rate(s) (100 percent basis) from each nitric acid train during the performance test according to paragraphs (5)(A) or (5)(B) of this section.
 Direct measurement of production and concentration (such as using flow meters or weigh scales, for production and concentration measurements).
 Existing plant procedures used for accounting purposes (i.e. dedicated tanklevel and acid concentration measurements).
(6) Conduct all performance tests in conjunction with the applicable methods; for each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (6)(A) through (6)(C) of this section.
 Analysis of samples, determination of emissions, and raw data.
 All information and data used to derive the emissions factor(s).
 The production rate during each test and how it was determined.
(7) Determine the annual nitric acid production and the annual nitric acid production during which N_{2}O abatement technology is operating for each train by summing the respective monthly nitric acid production quantities.
(8) Continuously measure the quantity of gaseous or liquid reducing agent consumed using a flow meter; the quantity of solid reducing agent consumed can be obtained from company records and aggregated on a monthly basis.
(9) Document the procedures used to ensure the accuracy of the estimates of reducing agent consumption.
(10) Determine carbon and methane contents of each reducing agent consumed (as applicable) at least semiannually from reports from your supplier(s); as an alternative to using supplier information on carbon and methane contents, you can also collect a sample of each reducing agent on a semiannual or more frequent basis and analyze the carbon and methane contents of the reducing agent using any of the following methods, as appropriate, listed in paragraphs (3)(A) through (3)(H) of this section, as applicable.
(A) ASTM D194503 Standard Test Method for Analysis of Natural Gas by Gas Chromatography
(B) ASTM D194690 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography
(C) ASTM D250204 (Reapproved 2002) Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils from Viscosity Measurements
(D) ASTM D250392 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure
(E) ASTM D323895 (Reapproved 2005) Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the ndM Method
(F) ASTM D529102 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants
(G) ASTM D317689 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke
(H) ASTM D537308 Standard Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal
(11) For calendar year 2024 reporting only, any person subject to the nitric acid requirements who for logistical reasons cannot fulfill the increased (semiannual) N_{2}O source testing requirements and the new CO_{2} and CH_{4} reporting requirements in Canada’s 2024 Greenhouse Gas Quantification Requirements is permitted to revert to Canada’s 2022 Greenhouse Gas Quantification Requirements for N_{2}O source testing and to disregard the CO_{2} and CH_{4} reporting requirements and quantification requirements.
9.D Procedures for estimating missing data
Whenever a qualityassured value of a required parameter is unavailable (e.g., if a CEM system malfunctioned during unit operations or if a required fuel sample was not taken), a substitute data value for the missing parameter shall be used in the emission calculations.
When data related to sampling is unavailable, use the prescribed methods in section (E) to reanalyze the original sample, a backup sample or the replacement sample for the same measurement and sampling period; if this is not possible, the missing data should be substituted using the following approach.
(1) For missing sampled or analyzed data (e.g. carbon content, temperature, pressure), determine the sampling or measurement rate using Equation 915 and, replace the missing data as described in paragraphs (A) through (C) follows:
Equation 915: Sampling rate
Long description for Equation 915
This equation is used to calculate the sampling or measurement rate utilized by a facility. For each period of measurement, the equation takes the "Quantity of actual samples or measurements obtained by the facility operator," labeled as 'QS_ACT', and divides it by the "Quantity of samples or measurements required," labeled as 'QS_REQUIRED'. The resulting quotient gives the percentage rate at which sampling or measurements were taken. This equation does not factor in any specific conversion or iteration processes and is a straightforward ratio determination of actual samples to required samples.
Where:
R = sampling or measurement rate that was used (%)
Q_{S ACT}_{ }= quantity of actual samples or measurements obtained by the facility operator
Q_{S REQUIRED}_{ }= quantity of samples or measurements required
 If R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
(2) For missing data concerning a quantity of raw materials (e.g. nitric acid production), substitute the data based on the best available estimate of that parameter using all available process data; document and retain records of the procedures used for all such estimates.
(3) For missing parameters regarding CEM systems, determine the replacement data using the missing data backfilling procedures in the CEMS guidance document or the European Commission Guidance Document – The Monitoring and Reporting Regulation – Continuous Emissions Monitoring Systems (CEMS) (PDF), 2017; alternatively, use the procedure described in paragraph (1) above.
10 Quantification methods for hydrogen production
If a person subject to the requirements throughout this section is also subject to the OutputBased Pricing System Regulations, methods described in those regulations may be used, where applicable, to quantify the information that the person must report under the applicable schedule in the 2024 and 2025 GHGRP Notice.
Hydrogen production occurs at bitumen upgraders, petroleum refineries, chemical plants and fertilizer plants, where needed for purification or synthesis of substances. In addition, standalone industrial gas producers also manufacture hydrogen. The produced hydrogen can be both, used onsite and transferred offsite.
For ammonia production, the quantification methods in section 8 incorporate emissions associated with hydrogen production.
10.A CO_{2} emissions from hydrogen production
Two main processes can transform hydrocarbons into hydrogen gas, both of which result in CO_{2} emissions as a byproduct:
 steam reforming of methane, followed by shift reactions
 partial oxidation of hydrocarbons into synthesis gas (“syngas”)
As per IPCC guidelines ^{Footnote 4} (PDF), if the hydrogen production is associated with production or processing of fossil fuels (e.g. at a petroleum refinery, upgrading operation), then the CO_{2} emissions are attributed to the energy sector and categorised as fugitive – venting emissions source category. Otherwise, CO_{2} emissions from hydrogen production are attributed to the appropriate key category in the Industrial Process and Product Use sector, example Ammonia. Note that this is solely related to allocation by source category; emissions are not quantified or treated in any different manner otherwise.
If the syngas produced from partial oxidation is combusted to generate useful heat or work, attribute the GHG emissions from that combustion to the fuel combustion emissions source category. Otherwise, attribute emissions from syngas combustion to the fugitive – flaring emissions source category.
Calculate annual CO_{2} emissions from hydrogen production as specified in paragraph (1) or (2) of this section. Note that emissions from the waste recycle stream from a steam methane reformer are incorporated in these calculations and are entirely allocated to fugitive process vents or process emissions, therefore, they should not be double counted as fuel combustion emissions.
For facilities in Alberta, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used where appropriate. More specifically, it is acceptable to use Alberta equations 81, 81a, 82, 83, 84a, or 84b to calculate emissions from hydrogen production.
(1) Determine gross hydrogen production CO_{2} emissions using Equation 101, if operating and maintaining a CEMS.
Equation 101: Hydrogen production – CEMS
Long description for Equation 101
E_{CO2} = E_{CO2 CEMS} – E_{CO2 FC}
Where:
E_{ CO2} = the total annual quantity of gross hydrogen production related CO_{2} emissions (tonnes), calculated by subtracting CO_{2} fuel combustion emissions as specified in section 2 from the total annual CO_{2} quantity measured using CEMS
E_{ CO2 CEMS} = the total annual quantity of CO_{2} emissions from CEMS including fuel combustion and gross hydrogen production emissions (tonnes); if CO_{2} is captured at the facility, ensure that it is included in this amount as to appropriately reflect gross emissions (do not deduct any recovered emissions).
E_{ CO2 FC} = the total annual CO_{2} fuel combustion emissions, calculated as specified in section 2
(2) Determine gross CO_{2} emissions from hydrogen production using the feedstock methodology specified by Equation 102; this methodology uses the mass or volume and the carbon content of the feedstock.
Equation 102: Feedstock methodology
Long description for Equation 102
This equation is used to calculate the annual CO_{2} emissions from hydrogen production based on feedstock consumption. For each month "m", the equation multiplies the consumption of feedstock, labeled as 'Feed_m', by its weighted average carbon content for that month, labeled as 'CC_m'. This product is then further multiplied by the ratio of molecular weights of CO_{2} to carbon, 44/12, and by a conversion factor of 10^3. The calculation is repeated for every month up to the total of 12 months in a year. Then, the values of all months are summed to provide the annual CO_{2} emissions. This equation accounts for the different types of feedstock (solid, liquid, gas) and their specific carbon contents, with reference to specific conditions and measurements mentioned in the equation's specifics.
Where:
CO_{2} = annual CO_{2} emissions from hydrogen production (tonnes)
Feed_{ m} = consumption of feedstock in month “m” (solids in kilograms, liquids in kilolitres, and gases in cubic metres, at 15°C and 101.325 kPa, measured as specified in 10.B, or specific to petroleum refineries at dry reference conditions (25°C, 101.325 kPa and 0% moisture (dRm^{3}/period), if applicable); if a mass flow meter is used, measure the feedstock used in month “m” as kg of feedstock
CC_{ m} = weighted average carbon content in month “m” (kilograms of carbon per unit of feedstock), measured as specified in 2.D.4.
 the units of carbon content shall be reported based on feedstock type: kilograms (kg) carbon per kilolitres (kl) of feedstock for liquid feedstocks; kilograms (kg) carbon per cubic metre (m^{3}) of feedstock for gaseous feedstocks; and in kilograms carbon (kg) per kilograms (kg) of feedstock for solid feedstocks
 if a mass flow meter is used, measure the carbon content for feedstock used in month “m” in kg C per kg feedstock
44 / 12 = ratio of molecular weights, CO_{2} to carbon
10^{3} = conversion factor from kilograms to tonnes
10.B Sampling, analysis and measurement requirements
Measure consumption of feedstock and hydrogen production daily. Conduct sampling and analysis of feedstock, or use results received from fuel suppliers, at the following frequencies:
(1) Monthly for natural gas feedstock not mixed with another feedstock prior to consumption.
(2) Daily for all other feedstock, with a weighted average calculated for each month.
Collect samples at a location in the feedstock handling system that is representative of the feedstock consumed in the hydrogen production process.
Quantify the carbon content of the feedstock, as applicable, as specified in section 2.D.4 “Fuel carbon content monitoring requirements.”
10.C Procedures for estimating missing data
Whenever a qualityassured value of a required parameter is unavailable (e.g., a CEM system malfunction during unit operations or no required fuel sample taken), a substitute data value for the missing parameter shall be used in the emission calculations.
When data related to sampling is unavailable, use the prescribed methods in section 10.B to reanalyze the original sample, a backup sample or the replacement sample for the same measurement and sampling period; if this is not possible, the missing data should be substituted using the following approach.
(1) For missing sampled or analyzed data (e.g. carbon content, temperature, pressure), determine the sampling or measurement rate using Equation 103 and, replace the missing data as described in paragraphs (A) through (C) follows:
Equation 103: Sampling rate
Long description for Equation 103
This equation is used to calculate the sampling or measurement rate utilized by a facility. For each period of measurement, the equation takes the "Quantity of actual samples or measurements obtained by the facility operator," labeled as 'QS_ACT', and divides it by the "Quantity of samples or measurements required," labeled as 'QS_REQUIRED'. The resulting quotient gives the percentage rate at which sampling or measurements were taken. This equation does not factor in any specific conversion or iteration processes and is a straightforward ratio determination of actual samples to required samples.
Where:
R = sampling or measurement rate that was used (%)
Q_{S ACT}_{ }= quantity of actual samples or measurements obtained by the facility operator
Q_{S REQUIRED}_{ }= quantity of samples or measurements required
 If R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
(2) For missing data concerning a quantity of raw materials (e.g. gas flow rate, volume of hydrogen), substitute the data based on the best available estimate of that parameter using all available process data; document and retain records of the procedures used for all such estimates.
(3) For missing parameters regarding CEM systems, determine the replacement data using the missing data backfilling procedures in the CEMS guidance document or use the procedure described in paragraph (1) above.
11 Quantification methods for petroleum refining
If a person subject to the requirements throughout this section is also subject to the OutputBased Pricing System Regulations, methods described in those regulations may be used, where applicable, to quantify the information that the person must report under the applicable schedule in the 2024 and 2025 GHGRP Notice.
This section provides quantification methods for the following sources at petroleum refineries: catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; coke calcining units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; and sulphur recovery plants.
For crude oil charged to refineries, use sampling, analysis and measurement methods for liquid fuels in section 2.D to report volumes and weighted average annual, HHV and carbon content.
Methodologies for estimating emissions from fuel combustion and flares, and hydrogen plants (i.e., hydrogen plants that are owned or under the direct control of the refinery owner and operator) are covered in section 2 and section 10 of this document, respectively.
Calculate GHG emissions using the methods in sections 11.A through 11.M. If a CEMS measures CO_{2} emissions from process vents, asphalt production, sulphur recovery, or other control devices then the operator may calculate the CO_{2} emissions from these processes using the CEMS as specified in section 2.A.3.
When the flue gas from two or more processes or stationary combustion sources are discharged through a common stack or duct before exiting to the atmosphere and if CEMS as specified in 2.A.3 are used to continuously monitor the CO_{2} emissions, report the combined emissions from the processes or stationary combustion sources sharing the common stack or duct. This is in lieu of separately reporting the GHG emission from individual processes or stationary combustion sources.
11.A Fugitive emissions from catalyst regeneration
Calculate the CO_{2}, CH_{4}, and N_{2}O process emissions resulting from catalyst regeneration using the methods in paragraph (1), (2) and (3), respectively.
CO_{2} emissions
(1) Use the methods in paragraphs (A) through (C). For units equipped with CEMS, calculate fugitive CO_{2} emissions resulting from catalyst regeneration using CEMS in accordance with 2.A.3.
 (A) Calculate fugitive CO_{2} emissions from the continuous regeneration of catalyst material in fluid catalytic cracking units (FCCU) and fluid cokers using paragraphs (i) to (iii) or alternatively using paragraph (iv) of this section.
 (i) Calculate fugitive CO_{2} emissions:
Equation 111: Continuous regeneration emissions
Long description for Equation 111
This equation is used to calculate the annual mass of CO_{2} emissions. For each hour of operation "i", labeled as 'n', the hourly mass of coke burn 'CR_i' is multiplied by the carbon fraction in coke burned 'CF'. The resultant value is then multiplied by the ratio of molecular weights between CO_{2} and carbon, 3.664. This product is further multiplied by the conversion factor 10^3 to adjust the units. The calculation is repeated for every hour up to the total number of operational hours in the reporting year. Then, the values of all hours are summed to provide the annual CO_{2} emissions in tonnes.
Where:
CO_{2} = annual mass of CO_{2} emissions (tonnes)
n = number of hours of operation in the reporting year
CR_{i} = hourly mass of coke burn, for period i (kg)
CF = carbon fraction in coke burned, measured as specified in section 11.N.1 and 2.D.4 or by engineering estimation, refer to Appendix A for detail
3.664 = ratio of molecular weights, CO_{2} to carbon
10^{3} = conversion factor from kilograms to tonnes
 (ii) Calculate the hourly mass of coke burn using Equation 112 or from facility measurement or engineering estimate:
Equation 112: Hourly coke burn
Long description for Equation 112
This equation is used to calculate the hourly mass of coke burned for a specific period "i", labeled as "CRi". For each period "i", the calculation begins by multiplying the volumetric flow rate of exhaust gas, labeled as "Qr", with the CO_{2} concentration, "%CO_{2}", and adds this result to the product of the volumetric flow rate of exhaust gas "Qr" and the CO concentration, "%CO". This sum is then multiplied by the factor "K1". Additionally, the volumetric flow rate of air to the regenerator, labeled as "Qa", is multiplied by the half of the CO concentration, "%CO/2", and added to the product of "Qa" and the O_{2} concentration, "%O2". This result is multiplied by the factor "K2". Furthermore, the volumetric flow rate of O_{2} enriched air to the regenerator, labeled as "Qoxy", is multiplied by the O_{2} concentration in the O_{2} enriched air stream, labeled as "%Ooxy", and this product is multiplied by the factor "K3". The results of these three core calculations are then summed to provide the hourly coke burn for the period "i". Material balance and conversion factors, "K1", "K2", and "K3", can be derived from Table 111 or obtained from facility measurements or engineering estimates.
Where:
CR_{i} = hourly mass of coke burn for period i (kg)
K_{1}, K_{2}, K_{3} = material balance and conversion factors (K_{1}, K_{2}, and K_{3} from Table 111 or from facility measurement or engineering estimate)
Q_{r} = volumetric flow rate of exhaust gas before entering the emission control system from Equation 113 (dRm^{3}/min) at dry reference condition (101.325 kPa, 25°C and 0% moisture)
Q_{a} = volumetric flow rate of air to regenerator as determined from control room instrumentation, at reference temperature and pressure conditions used in variable Q_{r} (dRm^{3}/min)
%CO_{2} = CO_{2} concentration in regenerator exhaust, percent by volume—dry basis, 0% moisture
%CO = CO concentration in regenerator exhaust, percent by volume—dry basis. When no auxiliary fuel is burned and a continuous CO monitor is not required, assume %CO to be zero
% O_{2} = O_{2} concentration in regenerator exhaust, percent by volume—dry basis, 0% moisture
Q_{oxy} = volumetric flow rate of O_{2} enriched air to regenerator as determined from control room instrumentation at reference temperature and pressure conditions used in variable Q_{r} (dRm^{3}/min)
%O_{oxy} = O_{2} concentration in O_{2} enriched air stream inlet to regenerator, percent by volume—dry basis, 0% moisture
 (iii) Either continuously monitor the volumetric flow rate of exhaust gas from the FCCU regenerator or fluid coking unit burner prior to the combustion of other fossil fuels or calculate the volumetric flow rate of this exhaust gas stream using Equation 113 of this section.
Equation 113: Volumetric flow rate
Long description for Equation 113
This equation is used to calculate the volumetric flow rate of exhaust gas from the regenerator before entering the emission control system. For the exhaust gas rate labeled as "Q_r", the numerator multiplies the volumetric flow rate of air to the regenerator "Q_a" by 79 and adds the result to the product of the subtraction of the oxygen concentration in the oxygenenriched air stream "%O_oxy" from 100 and the volumetric flow rate of O_{2} enriched air "Q_oxy". The denominator subtracts the concentrations of carbon dioxide "%CO_{2}", carbon monoxide "%CO", and oxygen "%O2" in the regenerator exhaust from 100. The final value of "Q_r" is obtained by dividing the numerator by the denominator.
Where:
Q_{r} = volumetric flow rate of exhaust gas from regenerator before entering the emission control system, dRm^{3}/min (101.325 kPa , 25°C and 0% moisture)
Q_{a} = volumetric flow rate of air to regenerator, as determined from control room instrumentation at dry reference conditions used for Q_{r} (dRm^{3}/min)
O_{oxy}_{ }= oxygen concentration in oxygen enriched air stream, percent by volume—dry basis, 0% moisture
Q_{oxy} = volumetric flow rate of O_{2} enriched air to regenerator as determined from catalytic cracking unit control room instrumentation at dry reference conditions used for Q_{r} (dRm^{3}/min)
%CO_{2}_{ }= carbon dioxide concentration in regenerator exhaust, percent by volume—dry basis, 0% moisture
%CO = CO concentration in regenerator exhaust, percent by volume—dry basis. When no auxiliary fuel is burned and a continuous CO monitor is not required, assume %CO to be zero
%O_{2} = O_{2} concentration in regenerator exhaust, percent by volume—dry basis, 0% moisture
 (iv) Alternatively, calculate process CO_{2} emissions from the continuous regeneration of catalyst material in fluid catalytic cracking units (FCCU) and fluid cokers using Equation 114 and Equation 113.
Equation 114: Alternative catalyst regeneration
Long description for Equation 114
This equation is used to calculate the annual mass of CO_{2} emissions from alternative catalyst regeneration. For each period 'p', the equation takes into account the volumetric flow of exhaust gas labeled as "Qr," the average hourly CO_{2} concentration in regenerator exhaust "%CO_{2}", and the average hourly CO concentration "%CO." When no postcombustion device is in use, the %CO value is assumed to be zero. The product of these factors is then divided by 100% to give a proportion. This result is then multiplied by the molecular weight of CO_{2} "MWCO_{2}" and divided by the molar volume conversion factor "MVC." The MVC is calculated using the reference temperature and reference pressure, with the provided formula. The outcome is then multiplied by the conversion factor 10^3 to convert the values from kilograms to tonnes. The equation is repeated for every period up to the total 'n'. Finally, the values of all periods are summed to provide the annual CO_{2} emissions.
Where:
CO_{2} = annual mass of CO_{2} emissions (tonnes)
Q_{r} = volumetric flow of exhaust gas before entering the emission control system using Equation 113, dRm^{3}/hr (101.325 kPa , 25°C and 0% moisture)
%CO_{2} = average hourly CO_{2} concentration in regenerator exhaust, per cent by volume—dry basis, 0% moisture
%CO = average hourly CO concentration in regenerator exhaust, per cent by volume—dry basis. When there is no postcombustion device, assume %CO to be zero
MW_{CO2} = molecular weight of CO_{2} (44 kg/kgmole)
MVC = molar volume conversion factor at the same reference conditions as the above Q_{r}
(dRm^{3}/kgmole) = 8.3145 * [273.16 + reference temperature in °C]/[reference pressure in kilopascal]
10^{3} = conversion factor from kilograms to tonnes
n = number of hours of operation in the report year
%O_{2} = O_{2} concentration in regenerator exhaust, percent by volume—dry basis, 0% moisture
Q_{oxy} = volumetric flow rate of O_{2} enriched air to regenerator as determined from control room instrumentation used for Q_{r}, dRm^{3}/min
%O_{oxy} = O_{2} concentration in O_{2} enriched air stream inlet to regenerator, percent by volume—dry basis, 0% moisture
Material balance and conversion factors  (kg min)/(hr dRm^{3}%)  (lb min)/(hr dscf %) 

K_{1}  0.2982  0.0186 
K_{2}  2.0880  0.1303 
K_{3}  0.0994  0.0062 
 (B) Calculate process CO_{2} emissions resulting from continuous catalyst regeneration in operations other than FCCUs and fluid cokers (e.g. catalytic reforming) using Equation 115.
Equation 115: Continuous regeneration (other) emissions
Long description for Equation 115
CO_{2} = CC_{irc} × (CF_{spent} – CF_{regen}) × H × 3.664
Where:
CO_{2} = annual mass of CO_{2} emissions (tonnes)
CC_{irc} = average catalyst regeneration rate (tonnes/hr)
CF_{spent}_{ }= weight carbon fraction of spent catalyst
CF_{regen} = weight carbon fraction of regenerated catalyst (default = 0)
H = annual hours regenerator was operational (hr)
3.664 = ratio of molecular weights, CO_{2} to carbon
 (C) Calculate process CO_{2} emissions resulting from periodic catalyst regeneration using Equation 116
Equation 116: Periodic regeneration emissions
Long description for Equation 116
This equation is used to calculate the annual mass of CO_{2} emissions. For each regeneration cycle "n," the coke burnoff quantity per regeneration cycle is represented as "CB_Q_n." This value is multiplied by the carbon content of coke, labeled "CC," and then multiplied by the ratio of molecular weights of CO_{2} to carbon, which is 3.664. The resultant value is then multiplied by the conversion factor 10^3 to convert kilograms to tonnes. This calculation is repeated for every regeneration cycle up to the total 'n'. Finally, the values for all cycles are summed to provide the annual CO_{2} emissions.
Where:
CO_{2} = annual mass of CO_{2} emissions (tonnes)
CB_{Q} = coke burnoff quantity per regeneration cycle from engineering estimates (kg)
n = number of regeneration cycles in the calendar year
CC = carbon content of coke (kg C/kg coke) based on measurement as specified in section 2.D.4
3.664 = ratio of molecular weights, CO_{2} to carbon
10^{3} = conversion factor from kilograms to tonnes
CH_{4} Emissions
(2) Calculate CH_{4} emissions using either unit specific measurement data, a unit specific emission factor based on a source test of the unit, or Equation 117 of this section.
Equation 117: Catalyst regeneration – CH_{4}
Long description for Equation 117
This equation is used to calculate the annual mass of CH_{4} emissions. It begins by referencing the annual emissions of CO_{2} from coke burnoff, represented as "CO_{2}." This CO_{2} value is multiplied by the default CH_{4} emission factor for petroleum coke, labeled "EmF_2," and then divided by the default CO_{2} emission factor for petroleum coke, labeled "EmF_1." The result of this calculation gives the annual CH_{4} emissions from coke burnoff.
Where:
CH_{4} = annual mass of CH_{4} emissions from coke burnoff (tonnes)
CO_{2} = annual emissions of CO_{2} from coke burnoff calculated in paragraph (1) of this section, as applicable (tonnes)
EmF_{1} = default CO_{2} emission factor for petroleum coke (97 kg CO_{2}/GJ)
EmF_{2} = default CH_{4} emission factor for petroleum coke (2.8 x 10^{3} kg CH_{4}/GJ)
N_{2}O emissions
(3) Calculate N_{2}O emissions using either unit specific measurement data, a unitspecific emission factor based on a source test of the unit, or Equation 118 of this section.
Equation 118: Catalyst regeneration – N_{2}O
Long description for Equation 118
This equation is used to calculate the annual mass of N_{2}O emissions. Similar to the CH_{4} calculation, it references the annual emissions of CO_{2} from coke burnoff, labeled "CO_{2}." This CO_{2} value is multiplied by the default N_{2}O emission factor for petroleum coke, labeled "EmF_3," and is then divided by the default CO_{2} emission factor for petroleum coke, labeled "EmF_1." The result provides the annual N_{2}O emissions from coke burnoff.
Where:
N_{2}O = annual mass of N_{2}O emissions from coke burnoff (tonnes)
CO_{2} = annual emissions of CO_{2} from coke burnoff calculated in paragraph (1) of this section, as applicable (tonnes)
EmF_{1} = default CO_{2} emission factor for petroleum coke (97 kg CO_{2}/GJ)
EmF_{3} = default N_{2}O emission factor for petroleum coke (5.7 x 10^{4} kg N_{2}O/GJ)
11.B Emissions from fugitive process vents
Guidance for calculating vented emissions associated with hydrogen production can be found in section 10.A Hydrogen Production of this document. Calculate other fugitive emissions of CO_{2}, CH_{4}, and N_{2}O from fugitive process vents using Equation 119. Report for each process vent that contains greater than 2 percent by volume CO_{2} or greater than 0.5 percent by volume of CH_{4} or greater than 0.01 percent by volume (100 parts per million) of N_{2}O.
Equation 119: Process vent emissions
Long description for Equation 119
This equation is used to calculate the annual mass of emissions of a specific gas "x", where "x" can be CO_{2}, N_{2}O, or CH_{4}. For each venting event labeled as "i" up to the total number of events "n", the average volumetric flow rate is represented by "VRi". The molar fraction of the gas type "x" during the venting event "i" is denoted by "Fxi". The molecular weight of the specific gas "x" is labeled "MWx", and "MVC" stands for the molar volume conversion factor at dry reference conditions. This conversion factor is further defined as 8.3145 multiplied by the sum of 273.16 and the reference temperature in °C, divided by the reference pressure in kilopascals. The time duration of the venting event "i" is represented by "VTi". The core calculation involves multiplying the average volumetric flow rate "VRi" by the molar fraction "Fxi", the molecular weight "MWx", and the duration "VTi". This product is then divided by "MVC" and finally multiplied by the conversion factor 10^3 to convert kilograms to tonnes. This process is repeated for every venting event up to the total "n". Lastly, the values from all events are summed to provide the annual emissions of the gas.
Where:
E_{x} = annual mass of emissions of gas “x” (tonnes), where x = CO_{2}, N_{2}O, or CH_{4}
VR_{i} = average volumetric flow rate for venting event “i” from measurement data, process knowledge or engineering estimates (dRm^{3}/unit time); if a mass flow meter is used, measure the flow rate in kg/unit time and replace the term “MW_{x}/MVC” with “1”
F_{xi} = molar fraction by type of gas “x” in vent stream during event “i” from measurement data, process knowledge or engineering estimates
MW_{x} = molecular weight of gas “x” (kg/kgmole)
MVC = molar volume conversion factor at dry reference conditions as used for VR_{i} (dRm^{3}/kgmole)
= 8.3145 * [273.16 + reference temperature in °C]/[reference pressure in kilopascal]
VT_{i} = time duration of venting event “I” in same units of time as VR_{i}
n = number of venting events in report year
10^{3} = conversion factor from kilograms to tonnes
11.C Fugitive emissions from asphalt production
Calculate CO_{2} and CH_{4} fugitive emissions from asphalt blowing activities using either process vent method specified in paragraph 11.B or applicable provisions in paragraphs (1) and (2) of this section.
(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled by vapor scrubbing, calculate CO_{2} and CH_{4} emissions using Equation 1110 and Equation 1111 of this section, respectively.
Equation 1110: Uncontrolled asphalt emissions – CO_{2}
Long description for Equation 1110
CO_{2} = (Q_{AB} × EF_{AB,CO2})
Where:
CO_{2} = annual mass of CO_{2} emissions from uncontrolled asphalt blowing (tonnes)
Q_{AB} = annual quantity of asphalt blown (million barrels, million bbl)
EF_{AB},_{CO2} = emission factor for CO_{2} from uncontrolled asphalt blowing from facilityspecific test data (tonnes CO_{2}/million bbl asphalt blown); default = 1,100
Equation 1111: Uncontrolled asphalt emissions – CH_{4}
Long description for Equation 1111
CH_{4} = (Q_{AB} × EF_{AB,CH4})
Where:
CH_{4} = annual mass of CH_{4} emissions from uncontrolled asphalt blowing (tonnes)
Q_{AB} = annual quantity of asphalt blown (million bbl)
EF_{AB},_{CH4} = emission factor for CH_{4} from uncontrolled asphalt blowing from facilityspecific test data (tonnes CH_{4}/million bbl asphalt blown); default = 580
(2) For asphalt blowing operations controlled by thermal oxidizer or flare, calculate CO_{2} and CH_{4} emissions using Equation 1112 and Equation 1113 of this section, provided these emissions are not already included in the flaring emissions specified in paragraph 11.E of this section (and quantified by methods outlined in section 2.C).
Equation 1112: Controlled asphalt emissions – CO_{2}
Long description for Equation 1112
CO_{2} = 0.98 × (Q_{AB} × CEF_{AB} × 3.664)
Where:
CO_{2} = annual mass of CO_{2} emissions from controlled asphalt blowing (tonnes)
0.98 = assumed combustion efficiency of thermal oxidizer or flare, if facility factor is unavailable
Q_{AB} = annual quantity of asphalt blown (million bbl)
CEF_{AB} = carbon emission factor from asphalt blowing from facilityspecific test data (tonnes C/million bbl asphalt blown), default = 2,750
3.664 = ratio of molecular weights, CO_{2} to carbon
Equation 1113: Controlled asphalt emissions – CH_{4}
Long description for Equation 1113
CH_{4} = 0.02 × (Q_{AB} × EF_{AB,CH4})
Where:
CH_{4} = annual mass of CH_{4} emissions from controlled asphalt blowing (tonnes)
0.02 = fraction of methane not combusted in thermal oxidizer or flare based on assumed 98% combustion efficiency
Q_{AB} = annual quantity of asphalt blown (million bbl)
EF_{AB},_{CH4} = emission factor for CH_{4} from uncontrolled asphalt blowing from facilityspecific test data (tonnes CH_{4}/million bbl asphalt blown), default = 580
11.D Fugitive emissions from sulphur recovery
Calculate CO_{2} process emissions from Sulphur recovery units (SRUs) using Equation 1114. For the molar fraction (MF) of CO_{2} in the sour gas, use either a default factor of 0.20 or a source specific molar fraction value. If a source specific value is used, document and provide the methodology.
Equation 1114: Sulphur recovery emissions
Long description for Equation 1114
This equation is used to calculate the annual mass of CO_{2} emissions from sulphur recovery processes. For each measurement year, it considers the volumetric flow rate of acid gas to the Sulphur Recovery Unit (SRU), labeled as "FR", and the molecular weight of CO_{2}, labeled as "MW_CO_{2}", which has a defined value of 44 kg/kgmole. The molar volume conversion factor "MVC" is calculated at the same reference conditions as the "FR" variable, and it can be determined using the reference temperature and pressure with the provided formula. The mole fraction (%) of CO_{2} in sour gas, labeled as "MF", is based on measurement or engineering estimate with a default value of 20%. The core calculation multiplies "FR", "MW_CO_{2}", and "MF", then divides by "MVC", and finally multiplies by the conversion factor 10^3 to convert the result into tonnes.
Where:
CO_{2} = annual mass of CO_{2} emissions (tonnes)
FR = volumetric flow rate of acid gas to SRU, dRm^{3}/year; if a mass flow meter is used, measure the acid gas flow in kg per year and replace the term “MW_{CO2}/MVC” with “1”
MW_{CO2} = molecular weight of CO_{2} (44 kg/kgmole)
MVC = molar volume conversion factor at the same reference conditions as the FR variable (dRm^{3}/kgmole)
= 8.3145 * [273.16 + reference temperature in °C]/[reference pressure in kilopascal]
MF = molar fraction (%) of CO_{2} in sour gas based on measurement or engineering estimate (default MF = 20% expressed as 0.20)
10^{3}^{ }= conversion factor from kilograms to tonnes
11.E Flaring emissions from flares and other control devices
Calculate CO_{2}, CH_{4} and N_{2}O emissions resulting from the combustion of flare pilot and hydrocarbons routed to the flare using the appropriate method(s) specified in section 2.C.
11.F Fugitive emissions from storage tanks
For storage tanks other than those that meet the descriptions in paragraph (3) of this section, calculate CH_{4} emissions using the applicable methods in paragraphs (1) and (2).
(1) For storage tanks, not processing unstabilized crude oil. Calculate CH_{4} emissions from storage tanks having a vaporphase methane concentration of 0.5 volume percent or more using, tankspecific methane composition data (from measurement data or product knowledge) and estimation methods provided in section 7.1 of the AP42  Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources, including TANKS Model (Version 4.09D), or Equation 1115 of this section.
Equation 1115: Storage tanks emissions
Long description for Equation 1115
CH_{4} = (0.1 × Q_{ref})
Where:
CH_{4} = annual mass of CH_{4} emissions from storage tanks (tonnes)
0.1 = default emission factor for storage tanks (tonnes CH_{4}/millionbbl)
Q_{Ref} = annual quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (millionbbl)
(2) For storage tanks that process unstabilized crude oil, calculate CH_{4} emissions using either, tankspecific methane composition data (from measurement data or product knowledge) and direct measurement of the gas generation rate, or Equation 1116 of this section.
Equation 1116: Storage tanks – unstabilized crude oil
Long description for Equation 1116
This equation is used to calculate the annual mass of CH_{4} emissions from storage tanks storing unstabilized crude oil. The equation starts by multiplying the annual quantity of unstabilized crude oil received at the facility "Qun" by the pressure differential from the previous storage pressure to atmospheric pressure "ΔP" and by the correlation equation factor of 995,000 (scf gas per million bbl per psi). This result is then multiplied by the mole fraction of CH_{4} in vent gas from the unstabilized crude oil storage tank "MFCH4", which is obtained from facility measurements. If measurement data is not available, a default value of 0.27 is used for MFCH4. The resulting value is further multiplied by the molecular weight of CH_{4}, which is 16 (kg/kgmole). Finally, this value is divided by the molar volume conversion "MVCi" (849.5 scf/kgmole, 101.325 kPa, 20°C) and then multiplied by the conversion factor of 10^3 to obtain the desired quantity in tonnes.
Where:
CH_{4} = annual mass of CH_{4} emissions from storage tanks (tonnes)
Qun = annual quantity of unstabilized crude oil received at the facility (million bbl)
ΔP = pressure differential from the previous storage pressure to atmospheric pressure (pounds per square inch, psi)
MF_{CH4} = mole fraction of CH_{4} in vent gas from the unstabilized crude oil storage tank from facility measurements (kgmole CH_{4}/kgmole gas); use 0.27 as a default if measurement data are not available
995,000 = correlation equation factor (scf gas per million bbl per psi)
16 = molecular weight of CH_{4} (kg/kgmole)
MVCi = molar volume conversion (849.5 scf/kgmole, 101.325 kPa, 20°C)
10^{3} = conversion factor from kilograms to tonnes
(3) You do not need to calculate annual CH_{4} emissions from storage tanks that meet any of the following descriptions:
 units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships
 pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere
 bottoms receivers or sumps
 vessels storing wastewater
 reactor vessels associated with a manufacturing process unit
11.G Fugitive emissions from industrial wastewater processing
Emissions from industrial wastewater may be determined using direct measurement (see sampling measurement in section 11.N.7) or calculation methods presented in paragraphs (1), (2) and (3) of this section.
(1) Calculate only the fossil based (nonbiogenic) CO_{2} emissions from wastewater treatment using Equation 1117a. Note that consideration must be given to the source of organics in the wastewater (biogenic vs nonbiogenic).
Equation 1117a and 1117b: Industrial wastewater CO_{2} emissions
Equation 1117a
Long description for Equation 1117a
This equation is used to calculate the CO_{2} emissions from industrial wastewater that originate from fossil sources. The calculation is achieved by multiplying the total nonbiogenic CO_{2} emissions, represented as "CO_2,total", by the fraction of nonbiogenic organics entering wastewater treatment, denoted as "FossilFrac". It's essential to note that the "CO_{2},total" captures both biogenic and nonbiogenic CO_{2} emissions, while "FossilFrac" signifies the fraction of nonbiogenic organic substances that are present during wastewater treatment.
Equation 1117b
Long description for Equation 1117b
This equation is used to calculate the total nonbiogenic CO_{2} emissions in industrial wastewater. The operation starts with the volume of wastewater labeled "Q", which is then multiplied by the average quantity of organics in wastewater represented as "Organics_qave". This product is further multiplied by one subtracted by the fraction of organics in wastewater removed as sludge, "FracOrganics_removedassludge". This is further adjusted by subtracting the methane correction factor "MCF" from one and multiplying this result by the product. The final computation multiplies the result by the maximum methane producing capacity "BO_CO_{2}", and incorporates a conversion factor of 10^3 to yield the total CO_{2} emissions.
(2) Calculate CH_{4} emissions from wastewater treatment (such as anaerobic reactor, digester, or lagoon) using Equation 1118.
Equation 1118: Industrial wastewater CH_{4} emissions
Long description for Equation 1118
This equation is used to calculate the methane emissions originating from industrial wastewater. The procedure involves multiplying the volume of wastewater, denoted "Q", by the average amount of organics present in it, termed "Organics_qave". The product is adjusted by taking the initial amount and then multiplying it by the remaining fraction after accounting for the organics in wastewater removed as sludge, calculated as "1  FracOrganics_removedassludge", and then by the remaining fraction after accounting for the organics in wastewater that remain in the effluent discharge, calculated as "1  FracOrganics_effluent". This intermediate result is then multiplied by the maximum potential methane production "BO_CH4", and subsequently by the methane correction factor "MCF". To finalize, the total is multiplied by the conversion factor 10^3 and the methane recovery from wastewater treatment “R” is subtracted from the total to present the CH_{4} emissions from industrial wastewater.
Where:
CO_{2} = annual mass of nonbiogenic CO_{2} emissions (tonnes)
CO_{2,total} = annual mass of CO_{2} emissions (tonnes); this includes both the biogenic and nonbiogenic CO_{2} emissions as calculated using Equation 1117b
FossilFrac = fraction of nonbiogenic organics entering wastewater treatment
 this is based on the proportion of Organics_{qave} that are of biogenic origin and those that are of fossil origin; the fraction of nonbiogenic organics should be determined by considering the source of organics and determining the nonbiogenic portion using facilityspecific data (e.g., company records) and engineering estimates
 for example, organics introduced to wastewater such as pulp and paper or food processing may be considered to be of biogenic origin, whereas organics introduced to wastewater from sources such as petroleum refining, plastics manufacturing or methanol additions for denitrification may be considered nonbiogenic
CH_{4} = annual mass of CH_{4} emissions (tonnes)
Q = annual volume of wastewater treated (m^{3})
Organics_{qave} = average of quarterly determinations of organics in wastewater, measured as either chemical oxygen demand (COD) or biological oxygen demand (BOD) of the wastewater (kg/m^{3}), as specified in section 11.N.7
 organics mean any carbonbased substances suspended or dissolved in wastewater, measurable as the BOD or COD of the wastewater; it does not include inorganic carbon (carbon dioxide, carbonate, bicarbonate)
 the emission factors (Bo, MCF) are derived based on the BOD or COD measure of wastewater (IPCC 2019 Refinement,^{Footnote 5} Volume 5, Chapter 6)
FracOrganics_{removedassludge} = fraction of organics in wastewater removed as sludge
 this is the proportion of organics, measured as fiveday biological oxygen demand (BOD) of wastewater or chemical oxygen demand (COD) of wastewater that is removed from water as sludge
 organics in the wastewater that are removed as sludge do not contribute to GHG emissions during the wastewater treatment stage (emissions from handling or further treatment of sludge such as anaerobic digestion should be calculated and reported separately from wastewater, under the “waste” emission source category)
 the fraction of organics removed as sludge may be estimated using Table 114
 alternatively, if the information to determine the dry mass of sludge is available, Equation 1119 and Equation 1120 and Table 115 may be used to estimate the BOD removed as sludge in order to calculate the fraction of organics in wastewater removed as sludge
FracOrganics_{effluent} = fraction of organics in wastewater remaining in the effluent discharge
 default: 0; organics remaining in the effluent won’t contribute to greenhouse gas emissions directly from the treatment process (emissions do occur from the receiving water body, but must be determined separately)
 for many advanced treatment technologies the organics remaining in effluent is sufficiently low that this term can be left at the default value (zero)
 for some technology or pretreatment systems, the amount of organics remaining in the effluent may be appreciable
 the fraction should be estimated on a quarterly bases (Organics_{Effluentqave} / Organics_{qave})
Bo_{CH4} = methane generation capacity; this is the theoretical maximum amount of methane that could be produced.
 the parameter must match the organics (see Table 113 for default values.
 industryspecific Bo_{CH4} may be used, if appropriate)
Bo_{CO2}_{ }= CO_{2} generation capacity; this is the theoretical maximum amount of CO_{2 }that could be produced, if all consumable organics, measured are consumed.
 the parameter must match the organics measurement
 see Table 113 for default values. Industryspecific Bo_{CO2} may be used, if appropriate
MCF = methane correction factor (fraction of methane generation capacity, Bo_{CH4}, that is realized with a given treatment technology or discharge pathway) from Table 112 or facilityspecific (if using a facilityspecific MCF, document how it was derived)
R = methane recovery from wastewater treatment (tonnes)
10^{3} = conversion factor from kilograms to tonnes
Type of treatment and discharge pathway or system 
Comments  Default MCF  Range 

Untreated sea, river and lake discharge 
Rivers with high organic loading may turn anaerobic, yielding higher emissions than the default, however this is not considered here 
0.11 
0 – 0.2 
Aerobic treatment plant, including aerated lagoons, aerated secondary activated sludge and primary treatment (treated) 
Well maintained and not overloaded. Some CH_{4} may be emitted from settling basins. Some advanced biological nutrient removal may yield MCF values of 0.03. 
0 
0 – 0.1 
Aerobic treatment plant (treated) 
Not well maintained, or overloaded 
0.3 
0.2 – 0.4 
Anaerobic reactor / anaerobic wastewater treatment (treated) 
CH_{4} recovery must be accounted separately 
0.8 
0.8 – 1.0 
Shallow anaerobic lagoon, nonaerated, or facultative lagoon (treated) 
Depth less than 2 Meters 
0.2 
0 – 0.3 
Anaerobic or nonaerated, deep lagoon (treated) 
Depth more than 2 Meters 
0.8 
0.8 – 1.0 
Septic tank (treated) 
With or without land dispersal field 
0.5 
0.4 – 0.72 
The emission factor for CH_{4} is MCF ^{*} BoCH_{4}. For CH_{4} generation capacity (BoCH_{4}) in kg CH_{4}/kg COD, use default factor of 0.25 kg CH_{4}/kg COD or 0.60 kg CH_{4}/kg BOD. 
Organics Measurement Method  Anaerobic Treatment – BoCH_{4}  Anaerobic Treatment – BoCO_{2}  Aerobic Treatment – BoCO_{2} 

COD (kg GHG/kg COD)  0.25  0.69  1.375 
BOD (kg GHG/kg BOD)  0.6  1.65  3.3 
Table adapted from Doorn et al., 1997: M. Doorn, R. Strait, W. Barnard, B. Eklund, 1997. Estimates of Global Greenhouse Gas Emissions from Industrial and Domestic Wastewater. E.H. Pechan & Associates, Radian International. EPA Contract No. 68D40100, Report No. EPA600/R97091.September 1997. 
Type of treatment and discharge pathway or system 
Default fraction of influent BOD or COD removed as sludge 

Primary only  0.40 
Secondary treatment (with or without a primary clarification stage) 
0.34 
Secondary with advanced biological nutrient removal  0.44 
Lagoon (any kind)  0.009 
Septic  0.25 
No treatment  0 
Equation 1119: Alternate method to determine FracOrganic_{sremovedassludge}
Long description for Equation 1119
This equation is used to calculate the fraction of organics in wastewater removed as sludge. For each type of organic measurement, either as fiveday biological oxygen demand (BOD) or chemical oxygen demand (COD), the mass of organics removed as sludge, labeled "SludgeBOD_mass" for BOD and "SludgeCOD_mass" for COD, is divided by the product of the annual volume of wastewater treated, "Q", and the average of quarterly determinations of organics in wastewater. The organics, labeled either "Organics_BOD" for BOD or "Organics_COD" for COD, are any carbonbased substances suspended or dissolved in wastewater and can be measurable as the BOD or COD of the wastewater, excluding inorganic carbon.
Equation 1120: Alternate method to determine FracOrganics_{removedassludge}
Long description for Equation 1120
SludgeBOD_{mass} = DrySludge_{mass} × K_{rem,BOD}
OR
SludgeCOD_{mass} = DrySludge_{mass} × K_{rem,COD}
Where:
FracOrganics_{removedassludge} = fraction of organics in wastewater removed as sludge; this is the proportion of organics, measured as fiveday biological oxygen demand (BOD) of wastewater or chemical oxygen demand (COD) of wastewater that is removed from water as sludge
SludgeBOD_{mass} = the mass of BOD removed from wastewater as sludge (kg BOD)
SludgeCOD_{mass} = the mass of COD removed from wastewater as sludge (kg COD)
Q = annual volume of wastewater treated (m^{3})
Organics = average of quarterly determinations of organics in wastewater, measured as either chemical oxygen demand (COD) or biological oxygen demand (BOD) of the wastewater (kg/m^{3}), as specified in section 11.N.7; organics mean any carbonbased substances suspended or dissolved in wastewater, measurable as the BOD or COD of the wastewater—it does not include inorganic carbon (carbon dioxide, carbonate, bicarbonate)
DrySludge_{mass}_{ }= dry weight of sludge solids, or total suspended solids of the sludge (kg)
K_{rem} = mass of BOD or COD per mass of sludge (kg BOD or kg COD/ kg dry mass sludge), obtained according to treatment type from Table 115
Treatment type  K_{rem} (kg BOD/kg dry mass sludge) – Default  K_{rem} (kg BOD/kg dry mass sludge) – Range  K_{rem} (kg COD/kg dry mass sludge) – Default  K_{rem} (kg COD/kg dry mass sludge) – Range 

Mechanical treatment plants (primary sedimentation sludge)  0.5  0.40.6  1.20  0.961.44 
Aerobic treatment plants with primary treatment (mixed primary and secondary sludge, untreated or treated aerobically)  0.8  0.650.95  1.92  1.562.28 
Aerobic treatment plants with primary treatment and anaerobic sludge digestion (mixed primary and secondary sludge, treated anaerobically)  1.0  0.81.2  2.40  1.922.88 
Aerobic wastewater treatment plants without separate primary treatment  1.16  1.01.5  2.78  2.43.6 
Adapted from IPCC 2019, 2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Calvo Buendia, E., Tanabe, K., Kranjc, A., Baasansuren, J., Fukuda, M., Ngarize S., Osako, A., Pyrozhenko, Y., Shermanau, P. and Federici, S. (eds). Published: IPCC, Switzerland. (Volume 5, Chapter 6, Table 6.6A) 
(3) Calculate N_{2}O emissions from wastewater treatment using Equation 1121.
Equation 1121: Industrial wastewater N_{2}O emissions
Long description for Equation 1121
N_{2}O = Q × N_{qave} × EF_{N2ON }× 1.571 × 10^{3}
Where:
N_{2}O = annual mass of N_{2}O emissions (tonnes)
Q = annual volume of wastewater treated (m^{3})
N_{qave} = average of quarterly determinations of N in wastewater stream (kg N/m^{3})
EF_{N2ON} = emission factor for N_{2}ON (mass of nitrogen in N_{2}O) from wastewater treatment. See Table 116 for default values; if using a facilityspecific emission factor, document how it was derived
1.571 = stochiometric conversion factor from N_{2}ON to N_{2}O, 44/28 (kg N_{2}O N to kg N_{2}O)
10^{3} = conversion factor from kilograms to tonnes
Type of treatment and discharge pathway or system 
Default EF (kg N_{2}ON/kg N) 

Centralised, aerobic treatment plant (primary, secondary or tertiary treatment) 
0.016 
Lagoon (any kind)  0 
Centralized anaerobic treatment plant  0 
Septic tank with land dispersal field  0.0045 
Septic tank (without dispersal field)  0 
Untreated  0.005 
11.H Fugitive emissions from oilwater separators
Calculate CH_{4} emissions from oilwater separators using Equation 1122. For the CF_{NMHC} conversion factor, use either a default factor of 0.6 or species specific conversion factors determined by analysis. Document and provide sampling and analysis methodology.
Equation 1122: Oilwater separators emissions
Long description for Equation 1122
CH_{4} = EF_{sep} × V_{water} × CF_{NMHC} × 10^{3}
Where:
CH_{4} = annual mass of CH_{4} emissions (tonnes)
EF_{sep} = NMHC (nonmethane hydrocarbon) emission factor (kg/m^{3}) from Table 117
V_{water} = annual volume of wastewater treated by the separator (m^{3})
CF_{NMHC} = NMHC to CH_{4} conversion factor
10^{3} = conversion factor from kilograms to tonnes
Separator type  Emission factor (EF_{sep})^{a} kg NMHC/m^{3} wastewater treated 

Gravity type – uncovered  1.11 x 10^{1} 
Gravity type – covered  3.30 x 10^{3} 
Gravity type – covered and connected to destruction device  0 
DAF^{b} or IAF^{c} – uncovered  4.00 x 10^{3d} 
DAF or IAF – covered  1.20 x 10^{4d} 
DAF or IAF – covered and connected to a destruction device  0 
a. EFs do not include ethane 
11.I Fugitive emissions from equipment leaks
Calculate CH_{4} emissions using the method specified in either paragraph (1) or (2) of this section.
(1) When possible, use processspecific methane composition data (from measurement data or process knowledge) and any of the emission estimation procedures provided in the Protocol for Equipment Leak Emissions Estimates (EPA453/R95017, NTIS PB96175401).
(2) Else, use Equation 1123 of this section.
Equation 1123: Equipment leaks CH_{4}
Long description for Equation 1123
This equation is used to calculate the annual mass of CH₄ emissions from equipment leaks. For each facility, the number of atmospheric crude oil distillation columns, labeled as "N_CD", is multiplied by 0.4. Simultaneously, the cumulative number of various units including catalytic cracking units, coking units (delayed or fluid), hydrocracking, and fullrange distillation columns (including depropanizer and debutanizer distillation columns) at the facility, labeled as "N_PU1", is multiplied by 0.2. The cumulative number of units such as hydrotreating/hydrorefining, catalytic reforming, and visbreaking, labeled as "N_PU2", is multiplied by 0.1. Furthermore, the total number of hydrogen plants at the facility, labeled as "N_H2", is multiplied by 4.3. Lastly, the total number of fuel gas systems at the facility, labeled as "N_FGS", is multiplied by 6. Then, the resultant values of all these multiplications are summed together to provide the annual CH₄ emissions from equipment leaks.
Where:
CH_{4} = annual mass of CH_{4} emissions from equipment leaks (tonnes)
N_{CD} = number of atmospheric crude oil distillation columns at the facility
N_{PU1} = cumulative number of catalytic cracking units, coking units (delayed or fluid), hydrocracking, and fullrange distillation columns (including depropanizer and debutanizer distillation columns) at the facility
N_{PU2} = cumulative number of, hydrotreating/hydrorefining, catalytic reforming, and visbreaking, units at the facility
N_{H2} = total number of hydrogen plants at the facility
N_{FGS} = total number of fuel gas systems at the facility
11.J Fugitive emissions from coke calcining
Calculate GHG emissions according to the applicable provisions in paragraphs (1) through (3) of this section.
(1) If a CEMS measures CO_{2} emissions according to section 2.A.3, calculate and report CO_{2} emissions for coke calcining using the CEMS Calculation Methodology specified in that section; if the coke calcining unit is not equipped with CEMS follow the requirements of paragraph (2) of this section.
(2) Calculate the CO_{2} emissions from the coke calcining unit using Equation 1124 of this section.
Equation 1124: Coke calcining CO_{2} emissions
Long description for Equation 1124
CO_{2} = 3.664 × (M_{in} × CC_{GC} – (M_{out} + M_{dust}) × CC_{MPC})
Where:
CO_{2} = annual mass of CO_{2} emissions (tonnes)
M_{in} = annual mass of green coke fed to the coke calcining unit from facility records (tonnes)
CC_{GC} = average mass fraction carbon content of green coke from facility measurement data (tonnes carbon/tonnes green coke)
M_{out} = annual mass of marketable petroleum coke produced by the coke calcining unit from facility records (tonnes)
M_{dust} = annual mass of petroleum coke dust collected in the dust collection system of the coke calcining unit from facility records (tonnes)
CC_{MPC} = average mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (tonnes carbon/tonnes petroleum coke)
3.664 = ratio of molecular weights, carbon dioxide to carbon
(3) For all coke calcining units, use the CO_{2} emissions from the coke calcining unit calculated in paragraphs (1) or (2), as applicable, and calculate CH_{4} and N_{2}O using the following methods:
 Calculate CH_{4} emissions using either unit specific measurement data, a unit specific emission factor based on a source test of the unit, or Equation 1125 of this section.
Equation 1125: Coke calcining CH_{4} emissions
Long description for Equation 1125
This equation is used to calculate the annual mass of CH₄ emissions from coke calcining. The operational details involve dividing the annual mass of CO₂ emissions, labeled as "CO₂," by the default CO₂ emission factor for petroleum coke, labeled as "EmF_1" and found to be 97 kg CO₂/GJ. This quotient is then multiplied by the default CH₄ emission factor for petroleum coke, labeled as "EmF_2" and having a value of 2.8 × 10^3 kg CH₄/GJ. The resulting value provides the annual CH₄ emissions from coke calcining.
Where:
CH_{4} = annual mass of CH_{4} emissions (tonnes)
CO_{2} = annual mass of CO_{2} calculated in paragraphs (1) and (2) of this section, as applicable (tonnes)
EmF_{1} = default CO_{2} emission factor for petroleum coke (97 kg CO_{2}/GJ)
EmF_{2} = default CH_{4} emission factor for petroleum coke (2.8 x 10^{3} kg CH_{4}/GJ)
(B) Calculate N_{2}O emissions using either unit specific measurement data, a unitspecific emission factor based on a source test of the unit, or Equation 1126 of this section.
Equation 1126: Coke calcining N_{2}O emissions
Long description for Equation 1126
This equation is used to calculate the annual mass of N₂O emissions from coke calcining. The core calculation involves dividing the annual mass of CO₂ emissions, labeled as "CO₂," by the default CO₂ emission factor for petroleum coke, labeled as "EmF_1" and having a value of 97 kg CO₂/GJ. The quotient is then multiplied by the default N₂O emission factor for petroleum coke, labeled as "EmF_3" and equal to 5.7 × 10^4 kg N₂O/GJ. This product represents the annual N₂O emissions resulting from coke calcining.
Where:
N_{2}O = annual mass of N_{2}O emissions (tonnes)
CO_{2} = annual mass of CO_{2} from paragraphs (1) and (2) of this section, as applicable (tonnes)
EmF_{1} = default CO_{2} emission factor for petroleum coke (97 kg CO_{2}/GJ)
EmF_{3} = default N_{2}O emission factor for petroleum coke (5.7 x 10^{4} kg N_{2}O /GJ)
11.K Fugitive emissions from uncontrolled blowdown systems
For uncontrolled blowdown systems, use the methods for fugitive process vents in section 11.B.
11.L Fugitive emissions from crude oil, intermediate or product loading operations
Calculate CH_{4} emissions from loading operations using productspecific, vaporphase methane composition data (from measurement data or process knowledge) and the emission estimation procedures provided in section 5.2 of the AP42  Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources, if the equilibrium vaporphase concentration of methane is 0.5 volume percent or more.
For loading operations where the equilibrium vaporphase concentration of methane is less than 0.5 volume percent, assume zero methane emissions.
11.M Fugitive emissions from delayed coking units
Calculate the CH_{4} emissions from the depressurization of the coking unit vessel (i.e., the “coke drum”) to the atmosphere, using either of the methods provided in paragraphs (1) or (2) and provided no water or steam is added to the vessel after venting to atmosphere. Use the method in paragraph (1) of this section if you add water or steam to the vessel after venting to atmosphere.
(1) In addition to the process vent calculations from section 11.B, also calculate the CH_{4} emissions from the subsequent opening of the vessel for coke cutting operations using Equation 1127 of this section; for coke drums or vessels of different dimensions, use Equation 1127 for each set of coke drums or vessels of the same size and sum the resultant emissions across each set of coke drums or vessels to calculate the CH_{4} emissions for all delayed coking units.
Equation 1127: Delayed coking unit emissions
Long description for Equation 1127
This equation is used to calculate the annual mass of CH_{4} emissions from the delayed coking unit vessel opening. For each vessel opening, it considers the cumulative number of vessel openings "N" for all delayed coking unit vessels of the same dimensions during the year and multiplies this with the height of the coking unit vessel "H". This product is then multiplied by the gauge pressure of the coking vessel when opened to the atmosphere "P_CV", added to the assumed atmospheric pressure of 101.325 kilopascals, and divided by the same assumed atmospheric pressure. The result is then multiplied by the volumetric void fraction of the coking vessel "f_void" prior to steaming based on engineering judgment, and by the square of the diameter of the coking unit vessel "D" times π (pi) divided by 4. This intermediate result is then multiplied by the molecular weight of CH_{4}, which is 16, and divided by the molar volume factor "MVC", calculated using the formula 8.3145 multiplied by [273.16 plus reference temperature in °C] and divided by the reference pressure in kilopascals. The product is finally multiplied by the average mole fraction of methane in the coking vessel gas "MF_CH4" based on the analysis of at least two samples per year and multiplied by the conversion factor 10^3 to convert kilograms to tonnes. The values of all periods are summed to provide the annual CH_{4} emissions.
Where:
CH_{4} = annual mass of CH_{4} emissions from the delayed coking unit vessel opening (tonnes)
N = cumulative number of vessel openings for all delayed coking unit vessels of the same dimensions during the year
H = height of coking unit vessel (metres)
P_{CV} = gauge pressure of the coking vessel when opened to the atmosphere prior to coke cutting or, if the alternative method provided in paragraph (2) of this section is used, gauge pressure of the coking vessel when depressurization gases are first routed to the atmosphere (kilopascals)
101.325 = assumed atmospheric pressure (kilopascals)
f_{void} = volumetric void fraction of coking vessel prior to steaming based on engineering judgement, at dry reference temperature and pressure (dRm^{3} gas/m^{3} of vessel)
D = diameter of coking unit vessel (metres)
16 = molecular weight of CH_{4} (kg/kgmole)
MVC = molar volume factor at the same reference conditions as the coking vessel (dRm^{3}/kgmole)
= 8.3145 * [273.16 + reference temperature in °C]/[reference pressure in kilopascal]
MF_{CH4} = average mole fraction of methane in coking vessel gas based on the analysis of at least two samples per year, collected at least four months apart (kgmole CH_{4}/kgmole gas, wet basis)
10^{3} = conversion factor from kilograms to tonnes
(2) Calculate the CH_{4} emissions from the depressurization vent and subsequent opening of the vessel for coke cutting operations using Equation 1127 of this section and the pressure of the coking vessel when the depressurization gases are first routed to the atmosphere; for coke drums or vessels of different dimensions, use Equation 1127 for each set of coke drums or vessels of the same size and sum the resultant emissions across each set of coke drums or vessels to calculate the CH_{4} emissions for all delayed coking units.
11.N Sampling, analysis, and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
Perform sampling, analysis, and measurement, when required according to the methodology chosen in the appropriate paragraphs above, in accordance with 11.N.1 to 11.N.9. Note that where the option to use process data and engineering estimates is provided and chosen, a description of the methodology and supporting information shall be provided.
11.N.1 Catalyst regeneration
For FCCUs and fluid coking units, measure the following parameters:
(1) The daily oxygen concentration in the oxygen enriched air stream inlet to the regenerator.
(2) Continuous measurements of the volumetric flow rate of air and oxygen enriched air entering the regenerator.
(3) Weekly periodic measurements of the CO_{2}, CO and O_{2} concentrations in the regenerator exhaust gas (or continuous measurements if the equipment necessary to make continuous measurements is already in place).
(4) Daily determinations of the carbon content of the coke burned.
(5) The number of hours of operation.
(6) Use the measured daily or weekly values to derive the minute or hourly parameters as required by the corresponding equations.
11.N.2 Fugitive process vents
Measure the following parameters for each process vent.
(1) The vent flow rate for each venting event from measurement data, process knowledge or engineering estimates.
(2) The molar fraction of CO_{2}, N_{2}O, and CH_{4} in the vent gas stream during each venting event from measurement data, process knowledge or engineering estimates.
(3) The duration of each venting event.
11.N.3 Asphalt production
Measure the annual mass of asphalt blown.
11.N.4 Sulphur recovery
Measure the volumetric flow rate of acid gas to the SRU. When using a source specific molar fraction value based on measurements, instead of the default factor or engineering estimates, conduct an annual test of the molar fraction value.
11.N.5 Flares and other control devices
Refer to section 2.D.7.
11.N.6 Storage tanks
Determine the annual throughput of crude oil, naphtha, distillate oil, asphalt, and gas oil for each storage tank using company records or applicable plant instruments.
11.N.7 Wastewater treatment
Measure the following parameters.
(1) Collect samples representing wastewater influent to the wastewater treatment process, following all preliminary and primary treatment steps (e.g., after grit removal, primary clarification, oilwater separation, dissolved air flotation or similar solids and oil separation processes).
 Collect and analyze samples for COD or BOD_{5} concentration weekly.
 Note that for the 2024 calendar year only, if weekly sampling is not feasible, samples may be collected and analyzed quarterly.
(2) Measure the flow of wastewater entering the wastewater treatment process weekly.
 The flow measurement location must correspond to the location used to collect samples analyzed for COD or BOD_{5 }concentration.
 Note that for the 2024 calendar year only, if weekly measurement of flow rate is not feasible, measurement may be taken quarterly.
(3) The quarterly nitrogen content of the influent wastewater.
If measuring the CH_{4} or N_{2}O emissions directly:
CH_{4} emission measurements taken from settling basins, lagoons, activated sludge tanks, nitrification/denitrification equipment and any other relevant locations where CH_{4} emissions may occur from the wastewater. Samples must be taken at least quarterly.
N_{2}O emission measurements taken from settling basins, lagoons, activated sludge tanks and any nitrification/denitrification equipment. N_{2}O emissions are highly variable temporally, on daily, weekly and annual scales (Daelman et al. 2013; Daelman M., De Baets, B., van Loosdrecht M., Volcke, E., 2013 Influence of sampling strategies on the estimated nitrous oxide emission from wastewater treatment plants. Water Research 47, 31203130. http://dx.doi.org/10.1016/j.watres.2013.03.016). Sampling strategies must collect enough data to cover the variability. Minimum number of samples vary according to sampling method:
 Online monitoring, 24 hour online: minimum 25 days, randomly selected throughout the year.
 Online monitoring, 7 day online: minimum 10 weeks, randomly selected throughout year.
 Weekly grab sample: minimum 50 weeks.
 Random grab sample: minimum 30 samples, randomly selected days and times throughout the year.
11.N.8 Oilwater separators
Measure the daily volume of wastewater treated by the oilwater separators.
11.N.9 Coke calcining
Determine the mass of petroleum coke as required using measurement equipment used for accounting purposes. Determine the carbon content of petroleum coke using any one of the following methods:
(1) ASTM D317689 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke
(2) ASTM D529102 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants
(3) ASTM D537308 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal
11.O Procedures for estimating missing data
Whenever a qualityassured value of a required parameter is unavailable (e.g., if a CEM system malfunctioned during unit operations or a required fuel sample not taken), a substitute data value for the missing parameter shall be used in the emission calculations.
When data related to sampling is unavailable, use the prescribed methods in section 11.N to reanalyze the original sample, a backup sample or the replacement sample for the same measurement and sampling period; if this is not possible, the missing data should be substituted using the following approach.
(1) For missing sampled or analyzed data (e.g. carbon content, temperature, pressure, etc), determine the sampling or measurement rate using Equation 1128 and, replace the missing data as described in paragraphs (A) through (C) follows:
Equation 1128: Sampling rate
Long description for Equation 1128
This equation is used to calculate the sampling or measurement rate that was used in percentage terms. It divides the quantity of actual samples or measurements obtained by the facility operator "QS_ACT" by the quantity of samples or measurements required "QS_REQUIRED". The resulting value gives the sampling or measurement rate "R" as a percentage.
Where:
R = sampling or measurement rate that was used (%)
Q_{S ACT}_{ }= quantity of actual samples or measurements obtained by the facility operator
Q_{S REQUIRED}_{ }= quantity of samples or measurements required
 If R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
(2) For missing data concerning other parameters (e.g. coke burn, volumetric flow rate, number of hours of operation, quantity of wastewater, etc) substitute the data based on the best available estimate of that parameter using all available process data; document and retain records of the procedures used for all such estimates.
(3) For missing parameters regarding CEM systems, determine the replacement data using the missing data backfilling procedures in the CEMS guidance document or use the procedure described in paragraph (1) above.
12 Quantification methods for pulp and paper production
If a person subject to the requirements throughout this section is also subject to the OutputBased Pricing System Regulations, methods described in those regulations may be used, where applicable, to quantify the information that the person must report under the applicable schedule in the 2024 and 2025 GHGRP Notice.
The methodology for pulp and paper production applies to those facilities primarily engaged in manufacturing pulp, paper and paper products. The manufacture of pulp involves separating the cellulose fibres from other materials in fibre sources (e.g. wood). Paper manufacturing involves matting fibres into a sheet. Converted paper products produced from paper are also considered here.
12.A Emissions from pulp and paper production
Calculate emissions from each unit (i.e., kraft or soda chemical recovery furnace, sulfite chemical recovery combustion unit, standalone semichemical recovery combustion unit, or kraft or soda pulp mill lime kiln) as specified under paragraphs 12.A.1 and 12.A.2 of this section. Calculate emissions from wastewater according to section 12.A.3.
12.A.1 Fuel combustion and electricity/heat emissions
(1) If generating electricity or useful heat or steam, calculate associated emissions as specified in section 7 (Quantification Methods for Electricity and Heat Generation).
(2) Calculate CO_{2, }CH_{4} and N_{2}O emissions from fuel combustion following methodologies specified in section 2 (Quantification Methods for Fuel Combustion).
12.A.2 Process emissions (makeup chemical use)
For makeup chemical use, CO_{2} process emissions may be obtained using either of the methods in paragraphs (1) or (2).
(1) If operating and maintaining a CEMS, Equation 121 may be used. For Alberta facilities, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used where appropriate; more specifically, Alberta equation 812 may be used in place of ECCC Equation 121 in this section.
Equation 121: Makeup chemical use – CEMS
Long description for Equation 121
E_{CO2} = E_{CO2 CEMS} – E_{CO2 FC}
Where:
E_{ CO2} = the total annual quantity of CO_{2} process emissions (tonnes), calculated by subtracting CO_{2} fuel combustion emissions as specified in section 2 from the total annual CO_{2} quantity measured using CEMS
E_{ CO2 CEMS} = the total annual quantity of CO_{2} emissions from CEMS including fuel combustion and process emissions (tonnes)
E_{ CO2 FC} = the total annual CO_{2} fuel combustion emissions, calculated as specified in section 2
(2) Use Equation 122 or Equation 123 to calculate process emissions from the use of carbonates; for Alberta facilities, Alberta Greenhouse Gas Quantification Methodologies (AEP 2021) may be used where appropriate; more specifically, Alberta equation 811 may be used in this section or Alberta equation 810 may be used in place of ECCC Equation 123.
Equation 122: Makeup chemical use – carbon content
Long description for Equation 122
This equation is used to calculate the annual CO_{2} emissions from the consumption of carbonates. For each carbonate input material type 'k' and each carbonate output material type 'j', the annual quantity of input carbonate type "k" used, labeled as 'P_k', is multiplied by its corresponding annual weighted average carbon content, labeled as 'CC_k'. Similarly, the annual quantity of output carbonate type "j", labeled as 'P_j', is multiplied by its respective annual weighted average carbon content, labeled as 'CC_j'. The sum of products for all input materials is then subtracted from the sum of products for all output materials. This resultant value is then multiplied by the stoichiometric conversion factor 3.664 to convert carbon to CO_{2}. This calculation is iterative over all carbonate input material types up to the total 'n' and all output material types up to the total 'm'. The values from all these iterations are summed to provide the total annual CO_{2} emissions from the consumption of carbonates.
Where:
CO_{2} = annual CO_{2} emissions from consumption of carbonates
n = number of carbonate input material types
m = number of carbonate output material types
P_{k} = annual quantity of input carbonate type “k” used (tonnes)
P_{ j} = annual quantity of output carbonate type “j” (tonnes) A default value of 0 may be used
CC_{ k} = annual weighted average carbon content for material “k” (tonnes of carbon per tonne of material k), measured as specified in 12.B
CC_{ j} = annual weighted average carbon content for material “j” (tonnes of carbon per tonne of material j), measured as specified in 12.B
3.664 = stoichiometric conversion factor from C to CO_{2}
Equation 123: Makeup chemical use – Emission factor
Long description for Equation 123
This equation is used to calculate the annual CO₂ emissions from the consumption of carbonates. For each carbonate type "k", it multiplies the annual quantity of input carbonate type "P_k", by its specific CO₂ emission factor "EF_k" (default values for which can be found in Table 121), and by the weight fraction of calcination achieved for the carbonate type "F_k". If one assumes 100% calcination, a value of 1.0 may be used for "F_k". The values obtained for each carbonate type are then summed to yield the total annual CO₂ emissions.
Where:
CO_{2} = annual CO_{2} emissions from consumption of carbonates
n = number of carbonate types
P_{ k} = annual quantity of input carbonate type “k” used (tonnes)
EF_{ k} = emission factor for the input carbonate type “k” (Table 121 provides default values for certain types of carbonates)
F_{k}_{ }= weight fraction of calcination achieved for the carbonate type “k” (a value of 1.0 may be used if assuming 100% calcination)
Mineral name – Carbonate  CO_{2} emission factor (tonnes CO_{2}/tonne carbonate) 

Calcite or aragonite – CaCO_{3}  0.43971 
Magnesite – MgCO_{3}  0.52197 
Dolomite – CaMg(CO_{3})_{2}  0.47732 
Siderite – FeCO_{3}  0.37987 
Ankerite – Ca(Fe,Mg,Mn)(CO_{3})_{2}  0.47572 
Rhodochrosite – MnCO_{3}  0.38286 
Sodium carbonate or soda ash – Na_{2}CO_{3}  0.41492 
Source: Adapted from 2006 IPCC Guidelines for National Greenhouse Gas Inventories. Intergovernmental Panel on Climate Change National Greenhouse Gas Inventories Programme. 
12.A.3 Wastewater emissions
Calculate CO_{2}, CH_{4 }and N_{2}O emissions from wastewater using the methodology specified in section 11.G.
12.B Sampling, analysis, and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
(1) The annual mass of carbonate input material (e.g., limestone and dolomite) and process output material (for Equation 122) or carbonate inputs (for Equation 123) shall be determined by summing the monthly mass for the material determined for each month of the calendar year.
 The monthly mass may be determined using facility instruments, procedures, or records used for accounting purposes, including either direct measurement of the quantity of the material consumed or by calculations using process operating information.
(2) For Equation 122, obtain carbon content from supplier information or by collecting and analyzing at least three representative samples of the material each year using ASTM C2506 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime.”
(3) For Equation 123, rather than assuming a calcination fraction of 1.0, the facility may determine, on an annual basis, the calcination fraction for each carbonate consumed using the most appropriate method published by a consensusbased standards organization, if such a method exists.
 If no appropriate method is published by a consensusbased standards organization, use industry standard methods, noting where such methods are used and what methods are used.
12.C Procedures for estimating missing data
Whenever a qualityassured value of a required parameter is unavailable (e.g., if a CEM system malfunctioned during unit operations or if a required fuel sample was not taken), a substitute data value for the missing parameter shall be used in the emission calculations.
When data related to sampling is unavailable, use the prescribed methods in section 12.B to reanalyze the original sample, a backup sample or the replacement sample for the same measurement and sampling period; if this is not possible, the missing data should be substituted using the following approach.
(1) For missing sampled or analyzed data (e.g. carbon content, temperature, pressure), determine the sampling or measurement rate using Equation 124 and, replace the missing data as described in paragraphs (A) through (C) follows:
Equation 124: Sampling Rate
Long description for Equation 124
This equation is used to calculate the sampling or measurement rate that was employed. The main variables include the quantity of actual samples or measurements obtained by the facility operator, labeled as "QS_ACT", and the quantity of samples or measurements required, denoted as "QS_REQUIRED". The core calculation involves dividing "QS_ACT" by "QS_REQUIRED" to determine the sampling rate "R", expressed as a percentage.
Where:
R = sampling or measurement rate that was used (%)
Q_{S ACT}_{ }= quantity of actual samples or measurements obtained by the facility operator
Q_{S REQUIRED}_{ }= quantity of samples or measurements required
 If R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
(2) For missing data concerning a quantity of raw materials (e.g. mass of carbon containing inputs), substitute the data based on the best available estimate of that parameter using all available process data (e.g., electrical load, steam production, operating hours, etc.); document and retain records of the procedures used for all such estimates.
(3) For missing parameters regarding CEM systems, determine the replacement data using the missing data backfilling procedures in the CEMS guidance document or use the procedure described in paragraph (1) above.
13 Quantification methods for base metal production
If a person subject to the requirements throughout this section is also subject to the OutputBased Pricing System Regulations, methods described in those regulations may be used, where applicable, to quantify the information that the person must report under the applicable schedule in the 2024 and 2025 GHGRP Notice.
Base metal production considered in this section includes lead, zinc, copper, nickel, and cobalt production. Aluminum and iron and steel production are considered in sections 5 and 6, respectively.
Several processes involved in the production (smelting and/or refining) of base metals may generate CO_{2} emissions. Processrelated activities may include the use of carbonates as flux reagents (e.g., limestone [CaCO_{3}] or dolomite [CaCO_{3} MgCO_{3}]) to assist in the removal of impurities from the metal ore concentrate; the use of carbon feedstock (e.g. metallurgical coke) as a reducing agent to extract metals or for slag cleaning; and carbon electrode consumption in electric furnaces. The raw metal ore may also represent a source of CO_{2 }emissions.
It is important to distinguish between fuels used for combustion and fuels used as reducing agents; only emissions from fuels used as reducing agents should be included as industrial process emissions. Guidance for emissions from fuels used for combustion is provided in section 2.
13.A Calculation of CO_{2} emissions
Calculate total CO_{2} emissions as specified under paragraphs (1) or (2) of this section.
(1) Determine facility process CO_{2} emissions using Equation 131 if operating and maintaining a CEMS.
Equation 131: Base metal – CEMS
Long description for Equation 131
This equation is used to calculate the total annual quantity of CO_{2} process emissions for base metal production. The key variables consist of the total annual quantity of CO_{2} emissions from CEMS, including both fuel combustion and process emissions, represented by "E_CO_{2}_CEMS", and the total annual CO_{2} fuel combustion emissions, designated as "E_CO_{2}_FC". The principal operation involves subtracting "E_CO_{2}_FC" from "E_CO_{2}_CEMS" to yield the quantity "E_CO_{2}".
Where:
E_{ CO2} = the total annual quantity of CO_{2} process emissions for base metal production (tonnes), calculated by subtracting CO_{2} fuel combustion emissions as specified in section 2 from the total annual CO_{2} quantity measured using CEMS
E_{ CO2 CEMS} = the total annual quantity of CO_{2} emissions from CEMS including fuel combustion and process emissions (tonnes)
E_{ CO2 FC} = the total annual CO_{2} fuel combustion emissions, calculated as specified in section 2
(2) If not using CEMS, calculate total CO_{2} emissions using Equation 132; this is a general equation used to determine CO_{2} emissions based on a mass balance approach considering carbon content of input and output process materials.
 CO_{2} emissions from each material and process shall be used to determine total CO_{2} emissions.
 Specific materials that in aggregate contribute less than 0.5% of the total carbon into the process may be excluded from the calculation.
Equation 132: Base metal process CO_{2} emissions
Long description for Equation 132
This equation is used to calculate the annual CO_{2} emissions from metal production. The main variables encompass the number of carboncontaining process input materials, indicated as "n", and the number of process output materials, denoted as "m". For each input material "i", the annual quantity used is represented by "M_i", and it is multiplied by its corresponding annual weighted average carbon content, "CC_i". Similarly, for each output material "j", its annual quantity "P_j" is multiplied by its respective annual weighted average carbon content, "CC_j". The sum of products for input materials is subtracted by the sum of products for the output materials. The result of this subtraction is then multiplied by the stoichiometric conversion factor 3.664 to convert carbon to CO_{2}. The resulting value represents the annual CO_{2} emissions from the metal production process.
Where:
CO_{2} = annual CO_{2} emissions from metal production
n = number of carboncontaining process input materials
m = number of process output materials
M_{ i} = annual quantity of carboncontaining process input material “i” used, including wastebased reducing agents (tonnes)
P_{ j} = annual quantity of process output material “j” (tonnes)
CC_{ i} = annual weighted average carbon content for material “i” (for example, reductants and carbonates) (kilograms of carbon per tonne of material i), measured as specified in section 13.B
CC_{ j} = annual weighted average carbon content for material “j” (for example, reductants and carbonates) (kilograms of carbon per tonne of material j), measured as specified in section 13.B
3.664 = stoichiometric conversion factor from C to CO_{2}
13.B Sampling, analysis, and measurement requirements
Sampling, analysis and measurement activities must be conducted as described throughout this section. If any of the prescribed standards have been withdrawn, and there is no replacement provided by the standards organization or no alternative presented within these requirements, an appropriate alternative standard may be used. In this case, the facility operator must provide documentation with the GHG report that a) identifies the alternative standard used and describes its appropriateness, and b) includes a copy of the alternative standard or, if the standard is copyrighted, information on how to access a copy (e.g., website link).
The annual mass of each solid carboncontaining input material consumed shall be determined by summing the monthly mass for the material determined for each month of the calendar year. The monthly mass may be determined using facility instruments, procedures, or records used for accounting purposes, including either direct measurement of the quantity of the material consumed or by calculations using process operating information.
The average carbon content of each material consumed shall be determined as specified under paragraph (1) or (2) of this section.
(1) Obtain carbon content by collecting and analyzing at least three representative samples of the material each year using one of the following methods:
 For carbonate flux reagents (e.g., limestone and dolomite), use ASTM C2506 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime.”
 For metalbearing materials, use ASTM E194104 “Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys.”
 For solid carbonaceous reducing agents and carbon electrodes, use ASTM D537308 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal.”
 For liquid reducing agents, use the methods described in (i) through (iv), as appropriate:
 ASTM D250204 (reapproved 2002) “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils from Viscosity Measurements”
 ASTM D250392 (reapproved 2002) “Standard Test Method for Relative Molecular Mass (Relative Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure”
 ASTM D323895 (reapproved 2005) “Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the ndM Method”
 ASTM D529102 (reapproved 2007) “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”
 For gaseous reducing agents, use one of the methods described in subparagraph (i) or (ii):
 ASTM D194503 “Standard Test Method for Analysis of Natural Gas by Gas Chromatography”
 ASTM D194690 “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”
 For wastebased carboncontaining material, use one of the methods described in subparagraph (i) or (ii):
 Determine carbon content by operating the smelting furnace both with and without the waste reducing agents while keeping the composition of other material introduced constant; to ensure representativeness of wastebased carboncontaining material variability, the specific testing plan (e.g. number of test runs, other process variables to keep constant, timing of runs) for these trials must be documented.
 Use an average carbon content value from samples analyzed by a Leco instrument for percent carbon. Monthly composites of ewaste need to be riffled, ground to no less than 2 mm, split and then analyzed.
(2) Obtain carbon contents of the material, including carbon electrodes from the vendor or supplier.
13.C Procedures for estimating missing data
Whenever a qualityassured value of a required parameter is unavailable (e.g., if a CEM system malfunctioned during unit operations or if a required fuel sample was not taken), a substitute data value for the missing parameter shall be used in the emission calculations.
When data related to sampling is unavailable, use the prescribed methods in section 13.B to reanalyze the original sample, a backup sample or the replacement sample for the same measurement and sampling period; if this is not possible, the missing data should be substituted using the following approach.
(1) For missing sampled or analyzed data (e.g. carbon content, temperature, pressure), determine the sampling or measurement rate using Equation 133 and, replace the missing data as described in paragraphs (A) through (C) follows:
Equation 133: Sampling rate
Long description for Equation 133
This equation is used to calculate the sampling or measurement rate used. The principal variables encompass the quantity of actual samples or measurements secured by the facility operator, denoted as "QS_ACT", and the amount of samples or measurements required, indicated as "QS_REQUIRED". The fundamental calculation consists of dividing "QS_ACT" by "QS_REQUIRED" to determine the sampling rate "R", expressed in percentage terms.
Where:
R = sampling or measurement rate that was used (%)
Q_{S ACT}_{ }= quantity of actual samples or measurements obtained by the facility operator
Q_{S REQUIRED}_{ }= quantity of samples or measurements required
 If R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the missing data period; if no data is available from before the missing data period, use the first available data from after the missing data period.
 If 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the reporting period for which the calculation is made.
 If R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years.
(2) For missing data concerning a quantity of raw materials (e.g. mass of carbon containing inputs), substitute the data based on the best available estimate of that parameter using all available process data (e.g., electrical load, steam production, operating hours, etc.); document and retain records of the procedures used for all such estimates.
(3) For missing parameters regarding CEM systems, determine the replacement data using the missing data backfilling procedures in the CEMS guidance document or use the procedure described in paragraph (1) above.
Appendix A: Documentation
Documentation – General record keeping
Where facility specific method(s) differ from the Quantification Requirements, supporting documentation is required for consideration and assessment. This allows a facility to account for the uniqueness of their operational conditions and circumstances.
In general, documentation of a specific method, sampling and measurement approach for an emission source, by greenhouse gases, should include but not be limited to the following:
 Overview of the emissions by source and by greenhouse gas, where applicable.
 Description of issue(s) with the Quantification Requirements’ method (including emission factor(s), other input parameters, sampling and measurement approaches) that prevents the generation of representative emissions estimates for specific facility emission sources.
 Description of facility specific method applied.
 Source of the data used to derive any facility specific input variable(s) or parameter(s) used to estimate emissions and an explanation of why these provide better facility estimates.
 Any other additional information to support the approach used, including sampling and measurement protocol(s), summary of measurement results (when available), sample calculations, and result(s) along with uncertainty estimates (when available).
14 Equations, figures, and tables
1 Quantification methods for carbon capture, utilization, transport and storage
Figure 11: Illustration of CCUTS site and metering points
Equation 11: Capture – mass flow
Equation 12: Capture – Volumetric flow
Equation 13: Transport – Mass flow
Equation 14: Transport – Volumetric flow
Equation 15: Injection – Mass flow
Equation 16: Injection – Volumetric flow
2 Quantification methods for fuel combustion and flaring
Equation 21: Energybased emissions equation
Equation 22: Volume or massbased emissions equation
Table 21: CO_{2} emission factors for ethane, propane and butane
Table 22: CO_{2} emission factors for diesel, gasoline, ethanol and biodiesel
Equation 23: Onsite transportation by equipment type – HHV
Equation 24: Onsite transportation by equipment type – EF
Equation 25: Onsite transportation
Equation 26: Solid fuels
Equation 27: Liquid fuels
Equation 28: All gaseous fuels
Equation 29: Natural gas
Table 23: Regional slope and intercept for use in Equation 29
Equation 210: Ideal gas equation
Equation 211: Biomass fuels
Table 24: CO_{2} emission factors for biomass
Equation 212: CH_{4} and N_{2}O HHV methods, in energy units
Equation 213: CH_{4} and N_{2}O HHV value methods, in physical units
Equation 214: CH_{4} and N_{2}O CEM methods
Table 25: CH_{4} and N_{2}O emission factors for natural gas
Table 26: CH_{4} and N_{2}O emission factors for ethane, propane and butane
Table 27: CH_{4} and N_{2}O emission factors for refined petroleum products and biofuels
Table 28: CH_{4} and N_{2}O Emission Factors for Coal, Coke and Coke Oven Gas
Table 29: CH_{4} and N_{2}O emission factors for petroleum coke
Table 210: CH_{4} and N_{2}O emission factors for still gas
Table 211: CH_{4} and N_{2}O emission factors for industrial waste fuel used by cement plants
Table 212: CH_{4} and N_{2}O emission factors for biomass fuels
Equation 215: Onsite transportation by type of equipment in energy units
Equation 216: Onsite transportation by type of equipment in physical units
Equation 217: Onsite transportation
Equation 218: CH_{4} and N_{2}O biomass method
Equation 219: CO_{2} from flaring – CC
Equation 220: CO_{2} from flaring – HHV
Equation 221: CO_{2} from flaring – Alternative
Equation 222: CH_{4} from flaring
Equation 223: N_{2}O from flaring
Equation 224: Flaring – Other
Equation 225: Fuel consumption
Table 213: Fuel oil default density values
Equation 226: HHV
Equation 227: Annual carbon content
Equation 228: Sampling rate
Equation 229: Sampling rate
3 Quantification methods for lime production
Equation 31: CO_{2} from lime production
Equation 32: Lime emission factor
Equation 33: Byproduct emission factor
Equation 34: CEMS
Equation 35: Sampling rate
Equation 36: Sampling rate
4 Quantification methods for cement production
Equation 41: CO_{2} emissions from cement production
Equation 42: CO_{2} emissions from cement production
Equation 43: Monthly clinker emission factor
Equation 44: Quarterly CKD emission factor
Equation 45: Organic carbon oxidation emissions
Equation 46: CEMS
Equation 47: Sampling rate
Equation 48: Sampling rate
5 Quantification methods for aluminium production
Equation 51: Prebaked anode consumption
Equation 52: Anode consumption from Søderberg electrolysis cells
Equation 53: Anode and cathode baking
Equation 54: Packing material
Equation 55: Coking of pitch or other binding agent
Equation 56: Green coke calcination
Equation 57: CF_{4} emissions from anode effects (slope method)
Equation 58: CF_{4} emissions from anode effects (overvoltage coefficient method)
Equation 59: C_{2}F_{6} emissions from anode effects
Equation 510: SF_{6} emissions used as a cover gas (change in inventory)
Equation 511: SF_{6} emissions used as a cover gas (direct measurement)
Equation 512: Calcinated coke
Equation 513: Sampling Rate
Equation 514: Sampling rate
Table 51: Default factors for parameters used to quantify CO_{2} emissions
Table 52: C_{2}F_{6} / CF_{4} weight fractions based on the technology used
6 Quantification methods for iron and steel production
Equation 61: CO_{2} from induration furnace using green pellets
Equation 62: CO_{2} from induration furnace using iron ore concentrate
Equation 63: CO_{2} from Basic Oxygen Furnace
Equation 64: CO_{2} from coke oven battery
Equation 65: CO_{2} from sinter production
Equation 66: CO_{2} from electric arc furnace
Equation 67: CO_{2} from argonoxygen decarburization vessels
Equation 68: CO_{2} from direct reduction furnace
Equation 69: CO_{2} from blast furnace
Equation 610: CO_{2} from ladle furnace
Equation 611: Iron and steel CEMS
Equation 612: CO_{2} from iron and steel powder production
Equation 613: CO_{2} from atomization of molten cast iron
Equation 614: CO_{2} from decarburization of iron powder
Equation 615: CO_{2} from steel grading
Equation 616: CO_{2} from steel powder annealing
Equation 617: CO_{2} from iron and steel powder production – CEMS
Equation 618: Sampling rate
Equation 619: Sampling rate
7 Quantification methods for electricity and heat generation
Equation 71: Acid gas scrubbing
Equation 72: Sampling rate
8 Quantification methods for ammonia production
Equation 81: Ammonia production – CEMS
Equation 82: Feedstock methodology
Equation 83: Total emissions per unit
Equation 84: Gross facility emissions
Equation 85: Urea
Equation 86: Sampling rate
9 Quantification methods for nitric acid production
Equation 91: N_{2}O CEMS calculation
Equation 92: Nitric acid emissions
Equation 93: Destruction efficiency
Equation 94: Sitespecific N_{2}O generation factor (measured upstream of N_{2}O abatement technology)
Equation 95: Abatement factor
Equation 96: Nitric acid train emissions
Equation 97: Sitespecific emission factor
Equation 98: Facility emissions
Equation 99: Trainspecific CO_{2} emissions based on unreacted fraction of reducing agents
Equation 910: Trainspecific CO_{2} emissions based on unreacted fraction of reducing agents
Equation 911: Unreacted fraction of each reducing agent
Equation 912: Nitric acid train CH_{4} emissions
Equation 913: Trainspecific CH_{4} emission factor
Equation 914: Trainspecific CO_{2} from carbon mass balance
Equation 915: Sampling rate
10 Quantification methods for hydrogen production
Equation 101: Hydrogen production – CEMS
Equation 102: Feedstock methodology
Equation 103: Sampling rate
11 Quantification methods for petroleum refining
Equation 111: Continuous regeneration emissions
Equation 112: Hourly coke burn
Equation 113: Volumetric flow rate
Equation 114: Alternative catalyst regeneration
Table 111: Coke burn rate material balance and conversion factors, dry reference condition
Equation 115: Continuous regeneration (other) emissions
Equation 116: Periodic regeneration emissions
Equation 117: Catalyst regeneration – CH_{4}
Equation 118: Catalyst regeneration – N_{2}O
Equation 119: Process vent emissions
Equation 1110: Uncontrolled asphalt emissions – CO_{2}
Equation 1111: Uncontrolled asphalt emissions – CH_{4}
Equation 1112: Controlled asphalt emissions – CO_{2}
Equation 1113: Controlled asphalt emissions – CH_{4}
Equation 1114: Sulphur recovery emissions
Equation 1115: Storage tanks emissions
Equation 1116: Storage tanks – unstabilized crude oil
Equation 1117a and 1117b: Industrial wastewater CO_{2} emissions
Equation 1118: Industrial wastewater CH_{4} emissions
Table 112: Default MCF values for industrial wastewater
Table 113: Bo values for BOD or COD
Table 114: Default fraction of BOD or COD removed as sludge for type of treatment
Equation 1119: Alternate method to determine FracOrganics_{removedassludge}
Equation 1120: Alternate method to determine FracOrganics_{removedassludge}
Table 115: Alternate approach to determine removal of organic component from wastewater as sludge
Equation 1121: Industrial wastewater N_{2}O emissions
Table 116: Default N_{2}O emission factors (Based on IPCC 2019 guideline refinements)
Equation 1122: Oilwater separators emissions
Table 117: Emission factors for oil/water separators
Equation 1123: Equipment leaks CH_{4}
Equation 1124: Coke calcining CO_{2} emissions
Equation 1125: Coke calcining CH_{4} emissions
Equation 1126: Coke calcining N_{2}O emissions
Equation 1127: Delayed coking unit emissions
Equation 1128: Sampling rate
12 Quantification methods for pulp and paper production
Equation 121: Makeup chemical use – CEMS
Equation 122: Makeup chemical use – carbon content
Equation 123: Makeup chemical use – emission factor
Table 121: CO_{2} default emissions factors for common carbonates
Equation 124: Sampling Rate
13 Quantification methods for base metal production
Equation 131: Base metal – CEMS
Equation 132: Base metal process CO_{2} emissions
Equation 133: Sampling rate
Appendix A: Documentation
14 Equations, figures, and tables
15 References
15.A General
[AEP] Alberta Environment and Parks. 2021. Alberta Greenhouse Gas Quantification Methodologies.
[AER] Alberta Energy Regulator. 2016. Directive 017: Measurement Requirements for Oil and Gas Operations.
[API] American Petroleum Institute. 2009. Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry.
[ASME] American Society of Mechanical Engineers. Performance Test Codes.
BioMer. 2005. Biodiesel Demonstration and Assessment for Tour Boats in the Old Port of Montreal and Lachine Canal National Historic Site. Final Report.
[CAPP] Canadian Association of Petroleum Producers. 1999. CH_{4} and VOC Emissions from the Canadian Upstream Oil and Gas Industry. Vols. 1 and 2. Prepared for the Canadian Association of Petroleum Producers. Calgary (AB): Clearstone Engineering. Publication Nos. 19990009 and 19990010.
[ECCC] Environment and Climate Change Canada. 2017a. National Inventory Report (19902015).
[ECCC] Environment and Climate Change Canada. 2017b. Updated CO_{2} Emission Factors for Gasoline and Diesel Fuel. Unpublished report prepared by Tobin S, Pollutant Inventories and Reporting Division, Environment and Climate Change Canada. Gatineau (QC).
[ECCC] Environment and Climate Change Canada. 2021. DRAFT Carbon Dioxide Emission Factors for Coal Combustion in Canada. Unpublished Report. Pollutant Inventories and Reporting Division, Environment and Climate Change Canada. Gatineau (QC).
[ECCC] Environment and Climate Change Canada. 2023. Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation and other sources.
European Commission. Guidance Document. The Monitoring and Reporting Regulation – Continuous Emissions Monitoring Systems (CEMS). MRR Guidance Document No. 7. October, 2021.
[GPA] Gas Producers Association. 2000. GPA Standard 2261. Analysis of Natural Gas and Similar Gaseous Mixtures by Gas Chromatography.
Griffin B. 2020. Personal communication (email from Griffin B to Tracey K, Senior Program Engineer, PIRD dated Sept 25, 2020). Canadian Emissions and Energy Data Centre.
Haynes WM. 2016. CRC Handbook of Chemistry and Physics, 97th Edition. ISBN 9781498754286.
[IAI] International Aluminium Institute. 2006. The Aluminium Sector Greenhouse Gas Protocol (Addendum to the WRI/WBCSD Greenhouse Gas Protocol).
[IPCC] Intergovernmental Panel on Climate Change. 2000. Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories. Intergovernmental Panel on Climate Change National Greenhouse Gas Inventories Programme.
[IPCC] Intergovernmental Panel on Climate Change. 2006. 2006 IPCC Guidelines for National Greenhouse Gas Inventories. Intergovernmental Panel on Climate Change National Greenhouse Gas Inventories Programme.
McCann TJ. 2000. 1998 Fossil Fuel and Derivative Factors: CO_{2} per Unit of Fuel, Heating Values. Prepared by T.J. McCann and Associates for Environment and Climate Change Canada.
[NCASI] National Council for Air and stream Improvement. 2010. ICFPA/NCASI Spreadsheets for Calculating GHG Emissions from Pulp and Paper Manufacturing. Version 3.2. [revised 2010 March; cited 2010 Dec 3].
[NCASI] National Council for Air and Stream Improvement. 2012. Methane (CH_{4}) and Nitrous Oxide (N_{2}O) Emissions from BiomassFired Boilers and Recovery Furnaces. Technical Bulletin No. 998. Research Tirancle Park, N.C.: National Council for Air and Stream Improvement, Inc.
[NLA] National Lime Association. 2008. CO_{2} Emissions Calculation Protocol for the Lime Industry English Units Version.
Oak Leaf Environmental. 2017. Memorandum, Recommended NonRoad CH_{4} and N_{2}O Emission Rates (Revision 2). Prepared by Oak Leaf Environmental Inc. for Environment and Climate Change Canada. Dexter, MI (USA).
[Sask ECON] Saskatchewan Ministry of the Economy. 2017. Directive PNG017: Measurement Requirements for Oil and Gas Operations.
SGA Energy. 2000. Emission Factors and Uncertainties for CH_{4} & N_{2}O from Fuel Combustion. Unpublished report prepared by SGA Energy Limited for the Greenhouse Gas Division, Environment and Climate Change Canada.
Statistics Canada. 2017. Report on Energy Supply and Demand in Canada, 2015, preliminary edition. Catalogue No. 57003X.
[U.S. EPA and IAI] United States Environmental Protection Agency and the International Aluminium Institute. 2008. Protocol for Measurement of Tetrafluoromethane (CF_{4}) and Hexafluoroethane (C_{2}F_{6}) Emissions from Primary Aluminum Production.
[U.S. EPA] United States Environmental Protection Agency. 1996. Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources, AP 42, 5th Edition, Supplement B.
[U.S. EPA] United States Environmental Protection Agency. 2003. Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources, AP 42, 5th Edition.
15.B Technical testing and analysis standards
ASM CS104 UNS G10460: Carbon steel of medium carbon content
ASTM C25: Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime
ASTM C114: Standard Test Methods for Chemical Analysis of Hydraulic Cement
ASTM D70: Standard Test Method for Density of SemiSolid Asphalt Binder (Pycnometer Method)
ASTM D240: Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter
ASTM D1298: Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method
ASTM D1826: Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter
ASTM D1945: Standard Test Method for Analysis of Natural Gas by Gas Chromatography
ASTM D1946: Standard Practice for Analysis of Reformed Gas by Gas Chromatography
ASTM D2013 / D2013M: Standard Practice for Preparing Coal Samples for Analysis
ASTM D2163: Standard Test Method for Determination of Hydrocarbons in Liquefied Petroleum (LP) Gases and Propane/Propene Mixtures by Gas Chromatography
ASTM D2234 / D2234M: Standard Practice for Collection of a Gross Sample of Coal
ASTM D2502: Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils from Viscosity Measurements
ASTM D2503: Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure
ASTM D3238: Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the ndM Method
ASTM D4809: Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method)
ASTM D4891: Standard Test Method for Heating Value of Gases in Natural Gas and Flare Gases Range by Stoichiometric Combustion
ASTM D5291: Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants
ASTM D5373: Standard Test Methods for Determination of Carbon, Hydrogen and Nitrogen in Analysis Samples of Coal and Carbon in Analysis Samples of Coal and Coke
ASTM D5468: Standard Test Method for Gross Calorific and Ash Value of Waste Materials
ASTM D5865 / D5865M: Standard Test Method for Gross Calorific Value of Coal and Coke
ASTM D6866: Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis
ASTM D7459: Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and FossilDerived Carbon Dioxide Emitted from Stationary Emissions Sources
ASTM D7582: Standard Test Methods for Proximate Analysis of Coal and Coke by Macro Thermogravimetric Analysis
ASTM E415: Standard Test Method for Analysis of Carbon and LowAlloy Steel by Spark Atomic Emission Spectrometry
ASTM E1019: Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques
ASTM E1915: Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials for Carbon, Sulfur, and AcidBase Characteristics
ISO/TR 153491:1998: Unalloyed steel – Determination of low carbon content – Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation)
ISO/TR 153493: Unalloyed steel – Determination of low carbon content – Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating)
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