Quantification methods for the Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations (draft for consultation)

Date of publication: November 4, 2024

1. Introduction

This document is referenced in several provisions of the Regulations as the Quantification Methods for the Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations (Quantification Methods).

The Regulations reference the Quantification Methods to specify additional requirements relating to the following:

• Determination of quantities of greenhouse gas (GHG) emissions
• Determination of production
• Determining the quantity of CO₂ storage
• Requirements for continuous emissions monitoring system operation
• Global Warming Potentials

The Quantification Methods would apply beginning in 2026. This early version is available to illustrate the approach and provide an opportunity for comments on the proposed content of the Quantification Methods. The Quantification Methods applicable beginning in 2026 would then be finalized and published prior to the 2026 calendar year.

The approach taken in this document for determining the quantity of GHG emissions is one of harmonization with national reporting methods, where appropriate. Greenhouse Gas Reporting Program, Canada’s Greenhouse Gas Quantification Requirements (GHGRP 2024/2025) methods are required to be used, where an appropriate method exists. In some cases, other methods are referenced such as Alberta’s Greenhouse Gas Quantification Methodologies (AQM) or the Final Essential Requirements of Mandatory Reporting (WCI Method). Where there is no available quantification method, engineering estimates based on but not limited to mass balances, models, process knowledge, and facility-specific data must be used to determine emissions.

The approach taken in this document for determination of production is one of harmonization with reporting requirements in Canadian provinces and territories.

2. General

2.1 For greater certainty

In the event of a conflict between the Regulations and requirements set out in this document, the Regulations prevail to the extent of the conflict.

2.2 Terms

Act means the Canadian Environmental Protection Act, 1999.

Alberta GHG Quantification Methods (AQM) means Version 2.3 of the document titled Alberta Greenhouse Gas Quantification Methodologies, published by the Alberta Government in September 2023.

CEMS Protocols means the document titled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation and other sources, published by the Department of the Environment in 2023.

Directive 017 means the document titled Directive 017: Measurement Requirements for Oil and Gas Operations, published by the Alberta Energy Regulator on March 17, 2022.

Directive PNG017 means the document titled Directive PNG017: Measurement Requirements for Oil and Gas Operations, published by the Government of Saskatchewan in August 2022.

GHG means a substance referred to in any of the items 65 to 70 of Part 2 of Schedule 1 to the Act.

GHGRP 2024/2025 means the document titled Greenhouse Gas Reporting Program, Canada’s Greenhouse Gas Quantification Requirements, version 7.0, published by the Department of Environment in December 2023.

IPCC Guidelines means the document titled 2006 IPCC Guidelines for National Greenhouse Gas Inventories, published by the Institute for Global Environmental Strategies for the Intergovernmental Panel on Climate Change. 

Oil Sands QM means the document titled Quantification of Area Fugitive Emissions at Oil Sands Mines, version 2.2, published in June 2023 by the department of Environment and Parks of the Government of Alberta.

operator means the person who has the charge, management or control of a facility at which industrial activities are carried out.

Regulations means the Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations published for comment [to add link and publication date]

Unit means an assembly comprised of any equipment that is physically connected and that operates together to generate electricity, and

1. must include at least a boiler or combustion engine, and
2. may include duct burners and other combustion devices, heat recovery systems, steam turbines, generators, emission control devices and carbon capture and storage systems.

WCI Method means the document titled Final Essential Requirements of Mandatory Reporting, published on December 17, 2010, and the amendments published in 2012 and 2013 by the Western Climate Initiative. 

3. General rules for determining quantity of greenhouse gases

3.1 Quantity of GHGs

For the purposes of section 18 of the Regulations, the GHG quantification methods are set out in column 3 of the table in section 5 of this document for the industrial activities engaged in at the facility. For the purposes of 18 of the Regulations, where the specified emissions source or GHGs are not listed in column 1 or 2 of the tables in section 5 of this document for the industrial activity, GHGs are to be determined in accordance with:

1. the GHGRP 2024/2025, if that document contains methods applicable to the industrial activity, or,
2. the Alberta GHG Quantification Methods, if that document contains methods applicable to the industrial activity and methods applicable to the industrial activity are not in the GHGRP 2024/2025, or
3. the WCI method, if that document contains methods applicable to the industrial activity and methods applicable to the industrial activity are not in the GHGRP 2024/2025 or the Alberta GHG Quantification Methods, or
4. the IPCC guidelines, if that document contains methods applicable to the industrial activity and methods applicable to the industrial activity are not in the GHGRP 2024/2025, the Alberta GHG Quantification Methods or the WCI Method, or
5. if there is no quantification method applicable to the industrial activity in any of the above-referenced documents, engineering estimates based on but not limited to mass balances, models, process knowledge, and facility-specific data must be used.

When calculating GHGs from stationary fuel combustion using the GHGRP 2024/2025, section 2.A, note #6 from the key notes list does not apply.

3.2 Sampling, analysis and measurement requirements

For the purposes of section 18 of the Regulations, the sampling, analysis and measurement requirements are set out in column 4 of the tables in section 5 of this document for the industrial activities engaged in at the facility.

For the purposes of section 18 of the Regulations, where the sampling, analysis and measurement requirements are not listed in column 4 of the tables in section 5 of this document for the industrial activity, the sampling, analysis, and measurement requirements are specified in the following:

1. the GHGRP 2024/2025, if that document contains sampling, analysis and measurement requirements applicable to the industrial activity, or
2. the Alberta GHG Quantification Methods, if that document contains sampling, analysis and measurement requirements applicable to the industrial activity and sampling, analysis and measurement requirements are not in the GHGRP 2024/2025, or
3. the WCI method, if that document contains sampling, analysis and measurement requirements are applicable to the industrial activity and sampling, analysis and measurement requirements are not in the GHGRP 2024/2025 or the Alberta GHG Quantification Methods, or
4. the IPCC guidelines, if that document contains sampling, analysis and measurement requirements applicable to the industrial activity and sampling, analysis and measurement requirements are not in the GHGRP 2024/2025, the Alberta GHG Quantification Methods or the WCI Method, or
5. if there is no available sampling, analysis and measurement requirement in any of the above-mentioned documents, engineering estimates based on but not limited to mass balances, models, process knowledge, and facility-specific data must be used.

3.3 Missing data

For the purposes of section 18 of the Regulations, the methods for calculating replacement data are set out in column 5 of the tables in section 5 of this document for the industrial activities engaged in at the facility.

For the purposes of section 18 of the Regulations, where methods for calculating replacement data are not listed in column 5 of the tables in section 5 of this document for the industrial activity the methods are specified in the following:

1. the GHGRP 2024/2025, if that document contains methods for calculating replacement data applicable to the industrial activity,
2. the Alberta GHG Quantification Methods, if that document contains methods for calculating replacement data applicable to the industrial activity and methods are not in the GHGRP 2024/2025, or
3. the WCI method, if that document contains methods for calculating replacement data applicable to the industrial activity and methods are not in the Alberta GHG Quantification Methods or the GHGRP 2024/2025, or
4. the IPCC guidelines, if that document contains methods for calculating replacement data applicable to the industrial activity and methods are not in the Alberta GHG Quantification Methods, the GHGRP 2024/2025 or the WCI Method, or
5. if there are no available methods for calculating replacement data in any of the above-referenced documents, engineering estimates based on but not limited to mass balances, models, process knowledge, and facility-specific data must be used.

4. Specific rules for determining quantity of greenhouse gases

4.1 Quantity of CO₂ storage

For the purposes of subsection 17(2) of the Regulations, the variable B, the quantity of CO₂ captured at the facility resulting from carrying out an industrial activity and that is permanently stored during the calendar year in a storage project, is determined using the quantification method described in section 1 of the GHGRP 2024/2025 and multiplied by the factor specified in subsection 19(2) of the Regulations.

4.2 Method to determine GHGs from the production of electricity

For the purposes of the determination made under subsection 18(2) of the Regulations, the quantity of GHGs resulting from the production of electricity at a facility is determined as follows:

If the electricity is not generated by a cogeneration unit, the quantity of GHGs is determined for each specified emissions source in column 1 of Table 2 for each GHG in column 2, in accordance with the methods in columns 3 to 5 of Table 2, or, where there is no applicable method for those specified emissions sources in Table 2, in accordance with section 3. For greater certainty, CO₂ emissions from biomass fuel are not included in the quantity of GHG emissions in this category.

If a cogeneration unit is used to generate electricity, the quantity of GHG emissions expressed in carbon dioxide equivalent (CO₂e) tonnes emitted by the unit attributable to the production of electricity by the unit is determined by the formula:

U _total - U _thermal

where

U _total

is the quantity of GHG emissions expressed in CO₂e tonnes emitted by the unit during the calendar year, determined in accordance with the methods in columns 3 to 5 of Table 2 for each specified emissions source in column 1 of Table 2 for each GHG in column 2.

U _thermal

is the quantity of GHG emissions expressed in CO₂e tonnes emitted by the unit attributable to the production of useful thermal energy by the unit during the calendar year, determined by the formula:

H_pnet × b_EI

where

H_pnet

is the net useful thermal energy, expressed in GJ, determined by the formula:

where

t

is the t^th hour, where “t” goes from 1 to x and where x is the total number of hours during which the unit produced useful thermal energy in the calendar year,

i

is the i^th heat stream exiting the unit, where “i” goes from 1 to n and where n is the total number of heat streams exiting the unit,

h_{out_i}

is the average specific enthalpy of the i^th heat stream exiting the unit, expressed in GJ/tonne, during period “t” and must be based on the measurement of the temperature and pressure of that heat stream and determined using a continuous measuring device,

M_{out_i}

is the mass flow of the i^th heat stream exiting the unit, expressed in tonnes, during period “t”, determined using a continuous measuring device,

j

is the j^th heat stream, other than condensate return, entering the unit, where “j” goes from 1 to m and where m is the total number of heat streams entering the unit,

h_{in_j}

is the average specific enthalpy of the j^th heat stream, other than condensate return, entering the unit, expressed in GJ/tonne, during period “t” and must be based on the measurement of the temperature and pressure of that heat stream and determined using a continuous measuring device,

M_{in_j}

is the mass flow of the j^th heat stream, other than condensate return, entering the unit, expressed in tonnes, during period “t” and determined using a continuous measuring device; and

b_EI

is the emission intensity of a reference boiler, set to 0.0556 tonnes of CO₂e/GJ.

4.3 Method to determine quantity of GHGs resulting from the production of thermal energy outside the facility that is supplied to the facility dring the calendar year

For the purposes of the determination of the quantity of GHGs that may be included under element C in the formula under section 17 of the Regulations, the quantity of GHGs resulting from the production of thermal energy outside the facility that is supplied to the facility during the calendar year is determined by the following:

For thermal energy supplied to the facility during the calendar year, generated using a natural gas-fired cogeneration unit:

Q_k x b_EI

Where

b_EI

is the emission intensity of a reference boiler, set to 0.0556 tonnes of CO₂e/GJ,

Q_k

is the quantity of thermal energy produced outside the facility that is supplied to the facility, expressed in GJ during the calendar year, determined using a continuous measuring device; and

For all other thermal energy supplied to the facility during the calendar year, determined by the following formula:

where

E_k

is the total quantity of GHG emissions that results from the thermal energy produced at the originating facility in the calendar year, expressed in tonnes. If biomass fuel is used, this quantity is multiplied by the ratio of heat, as determined in section 4.10, to determine the applicable value;

P_k

is the total quantity of thermal energy produced at the originating facility in a calendar year, expressed in GJ, determined using a continuous measuring device;

Q_k

is the quantity of thermal energy supplied to the facility, expressed in GJ during the calendar year, determined using a continuous measuring device; and

k

is the k^th stream of thermal energy, with “k” going from 1 to n, where n is the number of streams of thermal energy that are supplied to the facility during the calendar year.

Quantification of E_k and P_k

E_k and P_k must either be determined in accordance with the prescribed methods for stationary fuel combustion emissions in Table 2, or the ratio E_k/P_k may be replaced with the applicable default value from Table 1. If biomass fuel is used, multiply the applicable default value by the ratio of heat, as determined in section 4.10, to determine the applicable value.

*Refer to section 4.9 for additional quantification requirements

4.4 Method to determine GHGs resulting from the production of thermal energy that is transferred from the facility during the calendar year

For the purposes of the determination of the quantity of GHGs that may be included under element D in the formula under section 17 of the Regulations, the quantity of GHGs resulting from the production of thermal energy that is transferred from the facility during the calendar year is determined by the following formula:

where

E_k

is the total quantity of GHG emissions that results from the production of thermal energy at the facility, expressed in CO₂e tonnes, in the calendar year. If biomass fuel is used, this quantity is multiplied by the ratio of heat, as determined in subsection 4.10, to determine the applicable value;

P_k

is the quantity of thermal energy produced at the facility, expressed in GJ, in a calendar year, determined using a continuous measuring device;

Q_k

is the quantity of  thermal energy transferred from the facility, expressed in GJ, in a calendar year, determined using a continuous measuring device; and

k

is the k^th stream of thermal energy, with “k” going from 1 to n, where n is the number of streams of thermal energy that are transferred from the unit during the calendar year.

Quantification of E_k and P_k

The quantity for elements E_k and P_k are determined in accordance with the prescribed methods for stationary fuel combustion emissions in Table 2, or, if the thermal energy is produced by a cogeneration unit, a default value of 0.0556 tonnes of CO₂e/GJ must replace E_k/P_k. If biomass fuel is used, multiply the applicable default value by the ratio of heat, as determined in section 4.10, to determine the applicable value.

4.5 Method to determine GHGs resulting from the production of hydrogen outside the facility that is supplied to the facility during the calendar year

For the purposes of the determination of the quantity of GHGs that may be included under element E in the formula under section 17 of the Regulations, the quantity of GHGs resulting from the production of hydrogen outside the facility that is supplied to the facility during the calendar year is determined by the following formula:

where

E_k

is the quantity of GHG emissions that results from hydrogen fuel produced at the originating facility in a calendar year, expressed in CO₂e tonnes;

P_k

is the quantity of hydrogen fuel produced at the originating facility in the calendar year, expressed in tonnes at standard conditions, determined using a continuous measuring device;

Q_k

is the quantity of hydrogen supplied to the facility during the calendar year, expressed in tonnes at standard conditions, determined using a continuous measuring device; and

k

is the k^th stream of hydrogen, with “k” going from 1 to n, where n is the number of streams of hydrogen that are supplied to the facility during the calendar year.

Quantification of E_k and P_k

The quantity for elements E_k and P_k is determined in accordance with the prescribed methods for stationary fuel combustion emissions and industrial process emissions in Table 3, or the ratio E_k/P_k may be replaced with the default value of 11.36 tonnes CO₂/tonne of hydrogen.

*Refer to section 4.9 for additional quantification requirements

4.6 Method to determine GHGs resulting from the production of hydrogen that is transferred from the facility during the calendar year

For the purposes of the determination of the quantity of GHGs that may be included under element F in the formula under subsection section 17 of the Regulations, the quantity of GHGs resulting from the production of hydrogen that is transferred from the facility during the calendar year is determined by the following formula:

where

E_k

is the quantity of GHG emissions that results from the production of hydrogen fuel at the facility, expressed in CO₂e tonnes, in the calendar year;

P_k

is the quantity of the hydrogen fuel produced at the facility, expressed in tonnes at standard conditions, in the calendar year, determined using a continuous measuring device;

Q_k

is the quantity of hydrogen transferred from the facility, expressed in tonnes at standard conditions, during the calendar year, determined using a continuous measuring device; and

k

is the k^th stream of hydrogen, with “k” going from 1 to n, where n is the number of streams of hydrogen that are transferred from the facility during the calendar year.

Quantification of E_k and P_k

The quantity for elements E_k and P_k is determined in accordance with the prescribed methods for stationary fuel combustion emissions and industrial process emissions in Table 3.

4.7 Method to determine quantity of GHGs resulting from leakage

For the purposes of sections 17 and 18 of the Regulations, GHG emissions from leakage from industrial activities set out in items 1, 5, 6, 7 and 8 of Part 1 of Schedule 1 of the Regulations are to be determined as follows:

1. Where a facility meets the requirements for monitoring and leak detection prescribed in the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector)^{Footnote 1}, GHG emissions are to be quantified using the WCI method, WCI.363(n) or WCI.363(o), if those methods are applicable to the industrial activities engaged in at the facility;
   1. For facilities in Alberta, Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting may be used to determine leakage emissions where appropriate.
2. Where a facility does not meet the requirements for monitoring and leak detection prescribed prescribed in the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector), GHG emissions are to be quantified according to IPCC Chapter 4, section 4.2.2.2 Tier 1 approach with the applicable emission factors set out in in Tables 4.2.4a, 4.2.4b, 4.2.4g, 4.2.4h, and 4.2.4i in Section 4.2.2.3 multiplied by the associated leakage disaggregation factors set out in Annex 4A.2.

For the purposes of element A., the following additional requirements apply:

1. Where WCI.363(x) is prescribed in WCI.363(n) and WCI.363(o), the quantification methods set out in section 3 of this document are to be used instead.
2. Emission factors are to be determined as follows:
   1. if statistically valid facility specific emission factors for a component type are available or can be safely or reasonably developed, they must be used,
   2. if facility specific emissions factors for a component type are not available, an operator must use statistically valid company specific emission factors if they can be safely or reasonably developed,
   3. if statistically valid facility or company specific emission factors for a specific component type cannot be safely and reasonably developed, the estimates in Table 5 below may be used.

For the purposes of sections 17 and 18 of the Regulations, the method for estimating missing analytical data from leakage emissions from industrial activities set out in items 1, 5, 6, 7, and 8 of Part 1 of Schedule 1 of the Regulations is as follows:

1. For a facility referred to in element A., WCI.365 must be followed;
2. For a facility referred to in element B., the method for estimating missing production data in section 7.2 below must be followed.

4.8 Continuous emissions monitoring systems

For the purposes of section 21 of the Regulations, if a continuous emissions monitoring system is used to determine GHGs, the operator for the facility must ensure that the system complies with the requirements of the CEMS Protocols.

For the purposes of section 21, for each calendar year during which an operator of the facility uses a continuous emissions monitoring system, they must comply with the record keeping requirements set out in the CEMS Protocols.

Despite the record keeping requirements set out in the CEMS Protocols, the operator must, in accordance with subsection 42(1) of the Regulations, keep any records for at least 7 years.

For greater certainty, when the operator uses a continuous emissions monitoring system to determine GHGs at a facility, any quantity of GHGs that have not been determined using the continuous emissions monitoring system must be included in the quantity of GHGs from the facility determined in accordance with sections 17 and 18 of the Regulations.

4.9 Additional quantification requirements for various specified emission sources

4.10 Ratio of heat

For the purposes of subsections 4.2, 4.3 and 4.4, the ratio of heat from the combustion of fossil fuels during a calendar year is

1. equal to 1 when the thermal energy is produced from the combustion of only fossil fuels;
2. determined by the following formula if the thermal energy is produced from the combustion of both fossil fuels and biomass:

HF / (HF + B)

where

HF

is determined by the formula

The summation of the products of QF_i and HHV_i for each fossil fuel type “i”

where

QF_i

is the quantity of fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the calendar year, determined in accordance with the following:

1. for a solid fuel, the mass of the fuel combusted, on a wet or dry basis, expressed in tonnes and measured in accordance with section 2.D.2 of the GHGRP 2024/2025;
2. for a liquid fuel, the volume of the fuel combusted, expressed in kiloliter and measured in accordance with section 2.D.2 of the GHGRP 2024/2025; and
3. for a gaseous fuel, the volume of the fuel combusted, expressed in standard cubic metres and measured in accordance with section 2.D.2 of the GHGRP 2024/2025,

HHV_i

is the higher heating value of the fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the calendar year, determined in accordance with sections 2.D.1 and 2.D.3 of GHGRP 2024/2025, and

i

is the i^th fossil fuel type combusted in the facility during the calendar year, where “i” goes from 1 to n and where n is the number of types of fossil fuels combusted.

B

is determined by the formula

The summation of the products of QBB_k and HHV_k for each biomass fuel type “k”

where

QBB_k

is the quantity of biomass fuel type “k” combusted in the facility for the generation of thermal energy during the calendar year, determined in accordance with the following:

1. for a solid fuel, the mass of the fuel combusted, on a wet or dry basis, expressed in tonnes and measured in accordance with section 2.D.2 of the GHGRP 2024/2025;
2. for a liquid fuel, the volume of the fuel combusted, expressed in kiloliter and measured in accordance with section 2.D.2 of the GHGRP 2024/2025; and
3. for a gaseous fuel, the volume of the fuel combusted, expressed in standard cubic metres and measured in accordance with section 2.D.2 of the GHGRP 2024/2025,

HHV_k

is the higher heating value for biomass fuel type “k” combusted in the facility for the generation of thermal energy during the calendar year, determined in accordance with sections 2.D.1 and 2.D.3 of GHGRP 2024/2025, and

k

is the k^th biomass fuel type combusted in the facility during the calendar year, where “k” goes from 1 to m and where m is the number of types of biomass fuels combusted.

Default ratio of heat

Despite paragraph (b), if, for any reason beyond the control of the operator of a facility, the data required to determine the ratio of heat from the combustion of fossil fuels is missing for a given period during the calendar year, 1 can be used as the ratio of heat from the combustion of fossil fuels for the fuel combusted during this period.

5. Quantification methods for GHGs from industrial activities

Item 1 of schedule 1 of part 1 of the regulations

Quantification of GHGs from Certain Specified Emission Sources for:

- Bitumen and other crude oil production activities, other than extraction of bitumen through thermal in situ recovery or from surface mining

*Refer to section 4.9 for additional quantification requirements

Items 2 and 3 of schedule 1 of part 1 of the regulations

Quantification of GHGs from Certain Specified Emission Sources for:

- Thermal in situ recovery of bitumen from oil sand deposits; and

- Surface mining of oil sands and extraction of bitumen

*Refer to section 4.9 for additional quantification requirements

Item 4 of schedule 1 of part 1 of the regulations

Quantification of GHGs from Certain Specified Emission Sources for:

- Upgrading of bitumen or heavy oil to produce synthetic crude oil

*Refer to section 4.9 for additional quantification requirements

Items 5, 6 and 7 of schedule 1 of part 1 of the regulations

Quantification of GHGs from Certain Specified Emission Sources for:

- Extraction of natural gas and natural gas condensates;

- Compression of natural gas between production wells, gas processing facilities or re-injection sites; and

- Processing of natural gas or natural gas condensates into marketable natural gas and into natural gas liquids

*Refer to section 4.9 for additional quantification requirements

Item 8 of schedule 1 of part 1 of the regulations

Quantification of GHGs from Certain Specified Emission Sources for:

- Production of liquified natural gas

*Refer to section 4.9 for additional quantification requirements

6. Global warming potentials

For the purposes of subsection 18(1) of the Regulations, the global warming potentials are set out in the table below.

* From Part 2 of Schedule 1 to CEPA

**From Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (2013)

Note: For molecular formulae in this Schedule, “n” and “x” refer to the number of atoms.

7. Quantification of production for industrial activities

For the purposes of section 16 of the Regulations, the production from each industrial activity set out in Part 1 of Schedule 1 of the Regulations, must be determined in accordance with requirements in:

1. the document titled BC Measurement Guideline for Upstream Oil and Gas Operations, published by the British Columbia Energy Regulator on October 25, 2023, as listed in Table 7, if the facility is located in British Columbia;
2. the document titled Directive PNG017: Measurement Requirements for Oil and Gas Operations, published by the Government of Saskatchewan in August 2022, as listed in Table 7, if the facility is located in Manitoba or Saskatchewan;
3. the document titled Directive 017: Measurement Requirements for Oil and Gas Operations, published by the Alberta Energy Regulator on March 17, 2022, as listed in Table 7, if the facility is located in Alberta;
4. the document titled Oil, Gas and Salt Resources of Ontario Provincial Operating Standards, version 3.0, published by the Ministry of the Environment, Conservation and Parks on July 1, 2023, as listed in Table 7, if the facility is located in Ontario;
5. the document titled Guidelines Respecting Monthly Production Reporting for Producing Fields, published by the Canada-Newfoundland and Labrador Offshore Petroleum Board in September 2011, as listed in Table 7, if the facility is located in Newfoundland & Labrador;
6. the document titled The Reporting and Reduction of Greenhouse Gas Emissions Standard, published by the New Brunswick Department of Environment and Local Government in August 2022 as listed in Table 7, if the facility is located in New Brunswick; and

Facilities regulated under the Canada Oil and Gas Operations Act (i.e., facilities located in the Northwest Territories) must follow a production quantification method that fulfills the obligations pursuant to section 85 of the Canada Oil and Gas Drilling and Production Regulations.

* Whenever sampling, measurement, financial, purchase records, accounting records, or any other data required for the determination of a production parameter is missing, the operator shall ensure that the data is replaced using the following missing data procedures:

(1) Determine the sampling or measurement rate using the equation below:

R_p=Q_Pact/Q_Prequired

Where:

R_p = valid production record that was used, expressed as a percentage

Q_PAct = Quantity of valid production records obtained by the operator

Q_PRequired = Quantity of production records required

(i) Replace the missing data as follows,

(A) If R ≥ 0.9: replace the missing data by the arithmetic mean of the production record from immediately before and after the missing data period. If no data is available from before the missing data period, the operator shall use the first available data from after the missing data period;

(B) If 0.75 ≤ R < 0.9: replace the missing data by the lowest production record value during the reporting period for which the calculation is made; and

(C) If R < 0.75: replace the missing data by the lowest production record value sampled or analyzed during the 3 preceding years.

7.1 Specific production quantification rules

7.1.1 Integrated oil sands mines and upgraders

For the purposes of section 16 of the Regulations, the operator of a facility with industrial activities set out in items 2 through 4, column 1 of Part 1 of Schedule 1 of the Regulations must report the total quantity of bitumen extracted even if it is not delivered outside the facility but upgraded to synthetic crude oil at the same facility.

7.1.2 Extraction of natural gas and natural gas condensates

For the purposes of section 16 of the Regulations, the operator of a facility with an industrial activity set out in item 5, column 1 of Part 1 of Schedule 1 of the Regulations must report the combined quantity, in one thousand cubic metres of natural gas equivalent (1000 m³ NGE) produced, of natural gas and natural gas condensates extracted, including associated gas.

1. Gas volumes must be measured in 1000 m³ at 15°C and 101.325 kPa (kilopascals)
2. Natural gas condensate volumes must be measured in cubic metres (m³) at 15°C and at equilibrium pressure and converted into the equivalent volume of natural gas in 1000 m³ using the following conversion factor:

7.1.3 Compression of natural gas between production wells, natural gas processing facilities or re-injection sites

7.1.3.1 Production in MWh of brake power

For the purposes of section 16 of the Regulations, facilities with an industrial activity set out in item 6, column 1 of Part 1 of Schedule 1 of the Regulations, production must be reported in the units described, i.e., in megawatt hours, equal to the sum of the amounts determined by the following formula for each of the drivers operated by the facility:

P_x × L_x× H_x

where

P_x

is the rated brake power of driver “x”, expressed in megawatts;

L_x

is the actual annual average percent load of driver “x”, or, if the actual annual average percent load is unavailable, the percentage determined by the formula:

rpm_avg /rpm_max

where

rpm_avg

is the actual annual average speed during operation of driver “x”, expressed in revolutions per minute, and

rpm_max

is the maximum rated speed of driver “x”, expressed in revolutions per minute;

H_x

is the number of hours during the calendar year that driver “x” was operated; and

The following definitions apply in this section:

driver means an electric motor, reciprocating engine or turbine used to drive a compressor. 

rated brake power means the maximum brake power of a driver as specified by its manufacturer either on its nameplate or otherwise. 

7.1.3.2 Production in volume of natural gas throughput, expressed in 1000 m³ of natural gas equivalent

For the purposes of section 10(3) of the Regulations, the operator of a facility with an industrial activity set out in item 6, column 1 of Part 1 of Schedule 1 of the Regulations, must determine the production from that activity in volume of natural gas throughput, expressed in 1000 m³ of natural gas equivalent, of natural gas and natural gas condensates delivered.

1. Gas volumes must be measured in 1000 m³ at 15°C and 101.325 kPa (kilopascals)
2. Natural gas condensate volumes must be measured in cubic metres (m³) at 15°C and at equilibrium pressure and converted into the equivalent volume of natural gas in 1000 m³ using the following conversion factor:

7.1.4 Processing of natural gas or natural gas condensates into marketable natural gas and into natural gas liquids

For the purposes of section 16 of the Regulations, the operator of a facility with an industrial activity set out in item 7, column 2 of Part 1 of Schedule 1 of the Regulations must determine the combined quantity, in thousand cubic metres of marketable natural gas and specified natural gas liquids delivered.

1. Gas volumes must be measured in 1000 m³ at a temperature of 15°C and 101.325 kPa (kilopascals).
2. For natural gas liquids, liquids volumes must be measured in cubic metres (m³) at 15°C and at equilibrium pressure and converted into the equivalent volume of natural gas in 1000 m³ using the following conversion factor:

7.2 Quantification of cumulative production

For the purposes of subsection 10(2)(b) of the Regulations, an operator must report the cumulative production from all industrial activities carried out at all facilities of the operator for each calendar year by applying the applicable threshold unit conversion as seen in the table below.

1. Operators must add up the light-oil equivalent volume of all the hydrocarbons delivered from facilities, including oil and gas batteries, gas gathering systems, gas plants, oil sands extraction facilities, and upgraders.
2. Liquids = m³ at 15°C and 101.325 kPa rounded to one decimal place.
3. For operators of gas processing facilities, including fractionation plants and straddle plants, or liquefied natural gas (LNG) facilities that deliver natural gas liquids, the natural gas equivalent (NGE) volume for each product must be determined and then converted to BOE and added to the operator's total. This includes gas volumes previously reported as delivered from batteries.
4. For operators of facilities that deliver liquified natural gas, the LNG delivered must be reported on a tonnage basis and the expected content of natural gas must be converted into BOE.