National Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021 (Cth)
National Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021
I, Angus Taylor, Minister for Energy and Emissions Reduction, make the following instrument.
Dated: 15 June 2021
Angus Taylor
Minister for Energy and Emissions Reduction
Contents
1 Name. ...................................................................................................................................... 3
2 Commencement........................................................................................................................ 3
3 Authority.................................................................................................................................. 3
4 Schedules................................................................................................................................. 3
Schedule 1—Amendments 4
National Greenhouse and Energy Reporting (Measurement) Determination 2008 4
1 Name
This is theNational Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021.
2 Commencement
(1) Each provision of this instrument specified in column 1 of the table commences, or is taken to have commenced, in accordance with column 2 of the table. Any other statement in column 2 has effect according to its terms.
| Commencement information | ||
| Column 1 | Column 2 | Column 3 |
| Provisions | Commencement | Date/Details |
| 1. The whole of this instrument | 1 July 2021. | 1 July 2021 |
Note: This table relates only to the provisions of this instrument as originally made. It will not be amended to deal with any later amendments of this instrument.
(2) Any information in column 3 of the table is not part of this instrument. Information may be inserted in this column, or information in it may be edited, in any published version of this instrument.
3 Authority
This instrument is made under subsection 10(3) of the National Greenhouse and Energy Reporting Act 2007.
4 Schedules
Each instrument that is specified in a Schedule to this instrument is amended or repealed as set out in the applicable items in the Schedule concerned, and any other item in a Schedule to this instrument has effect according to its terms.
Schedule 1—Amendments
National Greenhouse and Energy Reporting (Measurement) Determination 2008
[1] At the end of section 1.4
Add:
(3) Data points relevant to the implementation of particular methods are set out in column 3 of the tables in Schedule 4 as ‘matters to be identified’.
Note: Regulations 4.10, 4.11, 4.13, 4.14, 4.15 and 4.17 of the Regulations require these matters to be identified to be included in reports under the Act.
[2] Section 1.8 (subparagraph (d)(i) of the definition of appropriate unit)
Omit “including crude oil condensates,”, substitute “plant condensate”.
[3] Section 1.8
Insert in the appropriate alphabetical position:
captured for enhanced oil recovery: a greenhouse gas is captured for enhanced oil recovery if it is captured and transferred to the holder of an enhanced oil recovery authority for injection into a geological formation, such as a natural reservoir, to further oil or gas production activities and is not captured for permanent storage.
city gate means a distribution hub where gas is reduced in pressure before it enters the lower pressure, smaller diameter, distribution pipeline network.
CO2 stimulation means using carbon dioxide as a fluid in well stimulation treatment which enhances oil and gas production or recovery by increasing the permeability of the formation.
crude oil has the meaning given by the Regulations.
enhanced oil recovery authority means a licence, lease or approval by or under a law of the Commonwealth, State or Territory which authorises the injection of one or more greenhouse gases into one or more geological formations, such as a natural reservoirs, to further oil or gas production activities.
equivalent leak detection standard, means a standard or documented approach that:
(a) has equivalent or higher integrity than the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America or optical gas imaging in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; and
(b) has equivalent or higher sensitivity for detecting leaks than:
(i) 60 grams per hour in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; or
(ii) 10,000 parts per million or greater in accordance with the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America.
Leak Detection and Repair Program or LDAR program means a system of procedures used at a facility to monitor, locate and repair leaking components in order to minimize emissions.
leaker, in relation to a component subject to an LDAR program, means:
(a) if optical gas imaging is used, a leaker is detected at a sensitivity of 60 grams per hour in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; and
(b) if the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America is used, a leaker is detected if 10,000 parts per million or greater is measured consistent with that method; and
(c) if an equivalent leak detection standard is used, a leaker is detected at the sensitivity set for that standard.
Note: Under the definition of equivalent leak detection standard, the sensitivity must be equivalent or higher than the approaches in paragraph (a) or (b).
liquefied natural gas station means the plant and equipment used in the natural gas liquefaction, storage and transfer of liquefied natural gas, and includes:
(a) all onshore or offshore equipment that receives natural gas, liquefies and stores liquefied natural gas, and transfers the liquefied natural gas to a transportation system; and
(b) equipment that receives imported or transported liquefied natural gas, stores liquefied natural gas, re-gasifies liquefied natural gas, and delivers re-gasified natural gas to a natural gas transmission or distribution system.
natural gas distribution pipelines mean pipelines for the conveyance of pipeline natural gas that:
(a) are identified as a distribution pipeline in an access arrangement applicable to the pipeline; or
(b) meet both of the following:
(i) have a maximum design pressure of 1,050 kPa or less; and
(ii) are not natural gas gathering and boosting pipelines.
natural gas liquefaction, storage and transfer means the activity to collect and liquefy natural gas and to store and transfer liquefied natural gas to a transportation system.
natural gas production includes offshore natural gas production and onshore natural gas production.
natural gas processing means one or both of the following activities:
(a) the separation of natural gas liquids or non-methane gases from unprocessed natural gas or coal seam methane;
(b) the separation of natural gas liquids into one or more component mixtures.
Note: The separation includes one or more of the following: forced extraction of natural gas liquids, sulphur and carbon dioxide removal, fractionation of natural gas liquids, or the capture of CO2 separated from natural gas streams.
natural gas storage means the activity to store unprocessed natural gas, coal seam methane or natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas).
natural gas storage station means the plant and equipment used in natural gas storage, and includes:
(a) subsurface storage, such as depleted gas or oil reservoirs that store gas; and
(b) the equipment to undertake natural gas underground storage processes and operations (including compression, dehydration and flow measurement, but excluding natural gas transmission pipelines); and
(c) all the wellheads connected to the compression units located at the station that inject and recover natural gas into and from the underground reservoirs.
natural gas transmission pipeline means a pipeline for the conveyance of pipeline natural gas or plant condensate that:
(a) is licensed as a transmission pipeline under a Commonwealth, State or Territory law; and
(b) has a maximum design pressure exceeding 1,050 kPa; and
(c) is not a natural gas distribution pipeline or a natural gas gathering and boosting pipeline.
oil or gas exploration and development means the activity to explore for oil and gas resources and test, appraise, drill, develop and complete wells for oil and gas resources and includes the following actions:
(a) oil well drilling;
(b) gas well drilling;
(c) drill stem testing;
(e) well appraisals;
(f) development drilling;
(g) well completions;
(h) well workovers associated with the actions in the paragraphs above.
offshore natural gas production means the activity to produce, extract, recover, lift, stabilise, separate or treat unprocessed natural gas, condensate or coal seam methane on offshore submerged lands, including well workovers.
offshore platform includes:
(a) any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses plant and equipment to do either or both of the following:
(i) extract unprocessed natural gas and condensate from the ocean or lake floor;
(ii) transfers such unprocessed natural gas and condensate to storage, transport vessels, or onshore; and
(b) secondary platform structures connected to the platform structure via walkways, and
(c) storage tanks associated with the platform structure; and
(d) floating production and storage offloading equipment; and
(e) submerged wellhead production structures.
offshore platform (shallow water) means an offshore platform standing in less than 200 metres of water.
offshore platform (deep water) means an offshore platform standing in at least 200 metres of water.
onshore natural gas production means the activity to produce, extract, recover, lift, stabilise, separate or treat unprocessed natural gas, condensate or coal seam methane on land, including well workovers.
onshore natural gas wellhead means the gas wellhead.
plant condensate has the meaning given by the Regulations.
pipeline natural gas means natural gas that is suitable for market consumption.
[4] Section 1.8
Repeal the following definitions:
(a) definition of crude oil condensates;
(b) definition of technical guidelines.
[5] Section 1.8 (definition of fugitive emissions)
Repeal the definition, substitute:
fugitive emissions means greenhouse gas emissions that are:
(a) released in connection with, or as a consequence of, the extraction, processing, storage or delivery of fossil fuel; and
(b) not released from the combustion of fuel for the production of useable heat or electricity.
[6] Section 1.8 (definition of natural gas distribution)
Repeal the definition, substitute:
natural gas distribution means the transport of pipeline natural gas over a combination of natural gas distribution pipelines from a city gate to customer delivery points.
[7] Section 1.8 (definition of natural gas transmission)
Repeal the definition, substitute:
natural gas transmission means transmission of natural gas or plant condensate through one or more natural gas transmission pipelines from a natural gas processing station or a natural gas gathering and boosting network to any of the following:
(a) a natural gas distribution network;
(b) another natural gas processing station;
(c) a liquefied natural gas station;
(d) a large industrial facility, such as a power station.
Section 1.8 (definition of well workover)
Repeal the definition, substitute:
well workover means activities performed to restore or increase production which can include any or all of the following processes:
(a) well venting;
(b) tubing maintenance;
(c) air clean out;
(d) hydraulic fracturing and recovery;
(e) well unloading.
[9] Subsection 1.9(4)
Omit “1 July 2014”, substitute “1 January 2020”.
[10] Subsection 1.10(1)
Repeal the subsection, substitute:
(1) A thing mentioned in the column headed ‘Source of emissions’ of the following table is a source.
| Item | Category of source | Source of emissions |
| 1 | Fuel combustion | |
| 1A | Fuel combustion | |
| 2 | Fugitive emissions | |
| 2A | Underground mines | |
| 2B | Open cut mines | |
| 2C | Decommissioned underground mines | |
| 2D | Oil or gas exploration and development—flaring | |
| 2E | Oil or gas exploration and development (other than flaring) | |
| 2F | Crude oil production | |
| 2G | Crude oil transport | |
| 2H | Crude oil refining | |
| 2I | Onshore natural gas production (other than emissions that are vented or flared) | |
| 2J | Offshore natural gas production (other than emissions that are vented or flared) | |
| 2K | Natural gas gathering and boosting (other than emissions that are vented or flared) | |
| 2L | Produced water from oil and gas exploration and development, crude oil production, natural gas production or natural gas gathering and boosting (other than emissions that are vented or flared) | |
| 2M | Natural gas processing (other than emissions that are vented or flared) | |
| 2N | Natural gas transmission (other than flaring) | |
| 2O | Natural gas storage (other than emissions that are vented or flared) | |
| 2P | Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared) | |
| 2Q | Natural gas distribution (other than flaring) | |
| 2R | Onshore natural gas production—venting | |
| 2S | Offshore natural gas production—venting | |
| 2T | Onshore natural gas production—flaring | |
| 2U | Offshore natural gas production—flaring | |
| 2V | Natural gas gathering and boosting—venting | |
| 2W | Natural gas gathering and boosting—flaring | |
| 2X | Natural gas processing—venting | |
| 2Y | Natural gas processing—flaring | |
| 2Z | Natural gas transmission—flaring | |
| 2ZA | Natural gas storage—venting | |
| 2ZB | Natural gas storage—flaring | |
| 2ZC | Natural gas liquefaction, storage and transfer—venting | |
| 2ZE | Natural gas liquefaction, storage and transfer—flaring | |
| 2ZF | Natural gas distribution—flaring | |
| 2ZG | Carbon capture and storage | |
| 2ZH | Enhanced oil recovery | |
| 3 | Industrial processes | |
| 3A | Cement clinker production | |
| 3B | Lime production | |
| 3C | Use of carbonates for the production of a product other than cement clinker, lime or soda ash | |
| 3D | Soda ash use | |
| 3E | Soda ash production | |
| 3F | Ammonia production | |
| 3G | Nitric acid production | |
| 3H | Adipic acid production | |
| 3I | Carbide production | |
| 3J | Chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode | |
| 3JA | Sodium cyanide production | |
| 3JB | Hydrogen production | |
| 3K | Iron, steel or other metal production using an integrated metalworks | |
| 3L | Ferroalloys production | |
| 3M | Aluminium production | |
| 3N | Other metals production | |
| 3O | Emissions of hydrofluorocarbons and sulphur hexafluoride gases | |
| 4 | Waste | |
| 4A | Solid waste disposal on land | |
| 4AA | Biological treatment of solid waste | |
| 4B | Wastewater handling (industrial) | |
| 4C | Wastewater handling (domestic or commercial) | |
| 4D | Waste incineration |
[11] Subsection 2.27(1)
After “subsection (2)”, insert “and (3)”.
[12] Subsection 2.27(2)
Repeal the subsection, substitute:
(2) In applying method 1 under section 2.20, the emission factor EFijoxec is to be one of the following:
(a) obtained by using the equipment type emission factors set out in Volume 2, section 2.3.2.3 of the 2006 IPCC Guidelines corrected to gross calorific values;
(b) estimated based on the manufacturer’s specification for the specific equipment type under relevant operational conditions, including the effect of any supplementary equipment technologies that modify methane emitted to the atmosphere;
(c) if an equipment type (k) in column 2 of the following table is used—the factor in column 3 of the following table for the equipment type in column 2 of the table:
| Item | Equipment type (k) | Emission factor for gas type (j) | |
| CH4 | Units | ||
| 1 | Gas-fired reciprocating engines – 4-stroke lean burn | 13.8 | kg CO2-e /GJ |
| 2 | Gas-fired reciprocating engines – 4-stroke rich burn | 1.2 | kg CO2-e /GJ |
| 3 | Gas-fired reciprocating engines – 2-stroke lean burn | 17.5 | kg CO2-e /GJ |
| 4 | Gas turbines | 0.1 | kg CO2-e /GJ |
(3) If applicable to the facility, the method described in section A.2.2 of Appendix A of the API Compendium may be used as method 2.
Note: In 2021, the API Compendium could be accessed at Subsection 2.45(1) (table items 3 and 4)
Repeal the items, substitute:
3 Crude oil ASTM D 240‑02 (2007)
ASTM D 4809‑06
ASTM D 5291‑02 (2007) ASTM D 1298 – 99 (2005)
ASTM D 5002 – 99 (2005)
4 Plant condensates and other natural gas liquids not covered by another item in this table ASTM D 240‑02 (2007)
ASTM D 4809‑06
ASTM D 5291‑02 (2007) ASTM D 1298 – 99 (2005) [14] Subsection 2.47(3) (table items 3 and 4)
Repeal the items, substitute:
3 Crude oil ISO 3170:2004
ISO 3171:1988
ASTM D 4057 – 06
ASTM D 4177 – 95 (2005)
4 Plant condensates and other natural gas liquids not covered by another item in this table ISO 3170:2004
ISO 3171:1988
ASTM D 4057 – 06
ASTM D 4177 – 95 (2005)
ASTM D1265 – 05
[15] Part 3.3
Repeal the Part, substitute:
Part 3.3—Oil and natural gas—fugitive emissions
Division 3.3.1—Preliminary
3.41 Outline of Part
(1) This Part provides for fugitive emissions from the following:
(a) oil or gas exploration and development (see Division 3.3.2);
(b) crude oil production (see Division 3.3.3);
(c) crude oil transport (see Division 3.3.4);
(d) crude oil refining (see Division 3.3.5);
(e) onshore natural gas production, other than emissions that are vented or flared (see Division 3.3.6A);
(f) offshore natural gas production, other than emissions that are vented or flared (see Division 3.3.6B);
(g) natural gas gathering and boosting, other than emissions that are vented or flared (see Division 3.3.6C);
(h) produced water from oil and gas exploration and development, crude oil production, natural gas production or natural gas gathering and boosting, other than emissions that are vented or flared (see Division 3.3.6D);
(i) natural gas processing, other than emissions that are vented or flared (see Division 3.3.6E);
(j) natural gas transmission, other than emissions that are flared (see Division 3.3.7);
(k) natural gas storage, other than emissions that are vented or flared (see Division 3.3.7A);
(l) natural gas liquefaction, storage and transfer, other than emissions that are vented or flared (see Division 3.3.7B);
(m) natural gas distribution, other than emissions that are flared (see Division 3.3.8);
(n) natural gas production (emissions that are vented or flared) (see Division 3.3.9A);
(o) natural gas gathering and boosting (emissions that are vented or flared) (see Division 3.3.9B);
(p) natural gas processing (emissions that are vented or flared) (see Division 3.3.9C);
(q) natural gas transmission (emissions that are flared) (see Division 3.3.9D);
(r) natural gas storage (emissions that are vented or flared) (see Division 3.3.9E);
(s) natural gas liquefaction, storage or transfer (emissions that are vented or flared) (see Division 3.3.9F);
(t) natural gas distribution (emissions that are flared) (see Division 3.3.9G).
(2) The activities at a facility should be classified in accordance with the relevant definitions to apply the calculations in this Part to comprehensively cover the emissions from the facility, but not count the emissions more than once.
3.41A Interpretation
(1) Terms relating to the oil and gas industry in this Part are to be interpreted:
(a) consistently with their accepted meaning in the oil and gas industry; and
(b) where the term is relevant to methods in the API Compendium—taking into account the meaning and scope of the term in that compendium.
Note: In 2021, the API Compendium could be accessed at (2) If a method in this Part allows for the use of component or equipment emissions factors from the manufacturer of the component or equipment, those factors must not be used if they are likely to result in estimates of emissions inconsistent with the principles in section 1.13.
Division 3.3.2—Oil or gas exploration and development
Subdivision 3.3.2.1—Preliminary
3.42 Application
This Division applies to fugitive emissions from venting or flaring from oil or gas exploration and development activities, including emissions from:
(a) oil well drilling; and
(b) gas well drilling; and
(c) oil well completions; and
(d) gas well completions; and
(e) well workovers; and
(f) well blowouts; and
(g) cold process vents.
Subdivision 3.3.2.2—Oil or gas exploration and development (emissions that are flared)
3.43 Available methods
(1) Subject to section 1.18, for estimating emissions released by oil or gas flaring during the year from the operation of a facility that is constituted by oil or gas exploration and development:
(a) if estimating emissions of carbon dioxide released—one of the following methods must be used:
(i) method 1 under section 3.44;
(ii) method 2 under section 3.45;
(iii) method 3 under section 3.46; and
(b) if estimating emissions of methane released—one of the following methods must be used:
(i) method 1 under section 3.44;
(ii) method 2A under section 3.45A; and
(c) if estimating emissions of nitrous oxide released—one of the following methods must be used:
(i) method 1 under section 3.44;
(ii) method 2A under section 3.45A.
Note: There is no method 4 under paragraph (a) and no method 2, 3 or 4 under paragraph (b) or (c).
(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.
3.44 Method 1—oil or gas exploration and development
(1) Method 1 is:
Eij = Qi ×EFij
where:
Eij is the fugitive emissions of gas type (j) from a fuel type (i) flared in the oil or gas exploration and development during the year measured in CO2‑e tonnes.
Qi is the quantity of fuel type (i) flared in the oil or gas exploration and development during the year measured in tonnes.
Note: This quantity includes all of the fuel type, not just hydrocarbons within the fuel type.
EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of the fuel type (i) flared.
(2) For EFij in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor, for gas type (j), for each fuel type (i) specified in column 2 of that item.
Item Fuel type (i) Emission factor for gas type (j) (tonnes CO2‑e/tonnes of fuel flared) CO2 CH4 N2O 1 Gas 2.80 0.933 0.026 2 Crude oil and liquids 3.20 0.009 0.06 3.45 Method 2—oil or gas exploration and development (flared carbon dioxide emissions)
Combustion of gaseous fuels (flared) emissions
(1) For subparagraph 3.43(1)(a)(ii), method 2 for combustion of gaseous fuels is:
where:
EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in oil or gas exploration and development during the year, measured in CO2‑e tonnes.
Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in oil or gas exploration and development during the year, measured in tonnes in accordance with Division 2.3.3.
EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in oil or gas exploration and development during the year, measured in CO2‑e tonnes per tonne of the fuel type (i) flared, estimated in accordance with Division 2.3.3.
OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.
QCO2 is the quantity of CO2 within fuel type (i) in oil or gas exploration and development during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.
Combustion of liquid fuels (flared) emissions
(2) For subparagraph 3.43(1)(a)(ii), method 2 for combustion of liquid fuels is the same as method 1 under section 3.44, but the carbon dioxide emissions factor EFij must be determined in accordance with method 2 in Division 2.4.3.
3.45A Method 2A—oil or gas exploration and development (flared methane or nitrous oxide emissions)
For subparagraphs 3.43(1)(b)(ii) and (c)(ii), method 2A is:
where:
EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in oil or gas exploration and development during the year, mentioned for the fuel type in the table in subsection 3.44(2) and measured in CO2‑e tonnes per tonne of the fuel type (i) flared.
Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from oil or gas exploration and development during the year, measured in CO2‑e tonnes.
OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.
Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in oil or gas exploration and development during the year, measured in tonnes in accordance with Division 2.3.3 for gaseous fuels or Division 2.4.3 for liquid fuels.
3.46 Method 3—oil or gas exploration and development
Combustion of gaseous fuels (flared) emissions
(1) For subparagraph 3.43(1)(a)(iii), method 3 for the combustion of gaseous fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.3.4.
Combustion of liquid fuels (flared) emissions
(2) For subparagraph 3.43(1)(a)(iii), method 3 for the combustion of liquid fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.4.4.
Subdivision 3.3.2.3—Oil or gas exploration and development—fugitive emissions from system upsets, accidents and deliberate releases
3.46A Available methods
(1) Subject to section 1.18, the methods mentioned in subsections (2) and (3) must be used for estimating fugitive emissions that result from system upsets, accidents and deliberate releases during a reporting year from the operation of a facility that is constituted by oil or gas exploration and development.
(2) To estimate emissions for methane and carbon dioxide that result from deliberate releases from process vents, systems upsets and accidents at a facility during a year, for each oil or gas exploration and development activity one of the following methods must be used:
(a) method 1 under:
(i) section 3.46AB (natural gas well completions); and
(ii) section 3.56B (emissions from system upsets, accidents and deliberate releases from process vents); and
(iii) section 3.85B (cold process vents); and
(iv) section 3.85P (well workovers);
(b) method 4 under:
(i) for emissions of methane and carbon dioxide from natural gas well completions activities, well workovers, cold process vents and well blowouts—section 3.46B; and
(ii) for emissions and activities not mentioned in subparagraph (i)—Part 1.3.
(3) For estimating incidental emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, another method may be used that is consistent with the principles mentioned in section 1.13.
Note: There is no method 2 or 3 for this Subdivision.
Subdivision 3.3.2.3.1—Fugitive emissions that result from deliberate releases from process vents, system upsets and accidents–well completions
3.46AB Method 1—vented emissions from natural gas well completions
(1) Method 1 is:
Eij = Σk Qik ×EFijk × Sij / SDij
where:
Eij is the fugitive emissions of gas type (j), being methane or carbon dioxide, vented from the natural gas exploration and development during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e and estimated by summing up the emissions released from all of the equipment of type (k) specified in column 2 of the table in subsection (2), if the equipment is used in the natural gas exploration and development.
Qik is the total of the number of well completion events for equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the natural gas exploration and development.
Note: Consistent with subsection 3.41(2), a well completion event should be reported for a single reporting year and not separately in two consecutive years.
EFijk is the emission factor for gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per well completion event using equipment type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the natural gas exploration and development.
Sij is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed natural gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.
SDij is the default share of gas type (j) in the unprocessed natural gas (i), for methane SD is 0.832 and for carbon dioxide SD is 0.0345.
(2) For EFijk mentioned in subsection (1), column 3 of an item in the following table specifies the emission factor for methane for an equipment of type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide for an equipment of type (k) specified in column 2 of that item:
Item Equipment type (k) Emission factor for gas type (j) CH4 CO2 1 Well completion without hydraulic fracturing 5.5 1.1 × 10-2 tonnes CO2‑e per well completion event 2 Well completion with hydraulic fracturing and venting (no flaring) 1031 4.2 tonnes CO2‑e per well completion event 3 Well completion with hydraulic fracturing with capture (no flaring) 90.8 0.37 tonnes CO2‑e per well completion event 4 Well completion with hydraulic fracturing and flaring 136.6 0.56 tonnes CO2‑e per well completion event 3.46B Method 4—vented emissions from natural gas well completions, well workovers, cold process vents and well blowouts
Method 4 is, for natural gas well completion activities, well workovers, cold process vents and well blowouts, as described in section 5.7.1 of the API Compendium.
Division 3.3.3—Crude oil production
Subdivision 3.3.3.1—Preliminary
3.47 Application
(1) This Division applies to fugitive emissions from crude oil production activities, including emissions from flaring, from:
(a) an oil wellhead; and
(b) well servicing; and
(c) oil sands mining; and
(d) shale oil mining; and
(e) the transportation of untreated production to treating or extraction plants; and
(f) activities at extraction plants or heavy oil upgrading plants, and gas reinjection systems; and
(g) activities at upgrading plants and associated gas reinjection systems.
(2) For paragraph (1)(e), untreated production includes:
(a) well effluent; and
(b) emulsion; and
(c) oil shale; and
(d) oil sands.
Subdivision 3.3.3.2—Crude oil production (non‑flared)—fugitive leak emissions of methane
3.48 Available methods
(1) Subject to section 1.18, for estimating fugitive emissions of methane, other than fugitive emissions of methane specified in subsection (1A), during a year from the operation of a facility that is constituted by crude oil production, one of the following methods must be used:
(a) method 1 under section 3.49;
(b) method 2 under section 3.50;
(c) method 3 under section 3.51.
Note: There is no method 4 for this Division.
(1A) For subsection (1), the following fugitive emissions of methane are specified:
(a) fugitive emissions from oil or gas flaring;
(b) fugitive emissions that result from system upsets, accidents or deliberate releases from process vents.
(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.
3.49 Method 1—crude oil production (non‑flared) emissions of methane
(1) Method 1 is:
where:
Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2‑e tonnes.
Σk is the total emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from all of the equipment of type (k) specified in column 2 of the table in subsection (2), if the equipment is used in the crude oil production.
Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the crude oil production.
EFijk is the emission factor for methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the crude oil production.
Qi is the total quantity of crude oil (i) measured in tonnes that passes through the crude oil production.
EF(l) ij is 1.6 × 10‑3, which is the emission factor for methane (j) from general leaks in the crude oil production, measured in CO2‑e tonnes per tonne of crude oil that passes through the crude oil production.
(2) For EFijk mentioned in subsection (1), column 3 of an item in the following table specifies the emission factor for an equipment of type (k) specified in column 2 of that item:
Item Equipment type (k) Emission factor for gas type (j) (tonnes CO2‑e/tonnes fuel throughput) CH4 1 Internal floating tank 1.12 × 10-6 2 Fixed roof tank 5.60 × 10-6 3 Floating tank 4.27 × 10-6 (3) For EF(l) ij in subsection (1), general leaks in the crude oil production comprise the emissions (other than vent emissions) from equipment listed in sections 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production.
3.50 Method 2—crude oil production (non‑flared) emissions of methane
(1) Method 2 is:
where:
Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2‑e tonnes.
Σk is the total emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment type is used in the crude oil production.
Qik is the total of the quantities of crude oil that pass through each equipment type (k), or the number of equipment units of type (k), listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production, measured in tonnes.
EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium as determined under subsection (2), if the equipment is used in the crude oil production.
(2) For EFijk, the emission factors for methane (j), as crude oil passes through an equipment type (k), are:
(a) as listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, for the equipment type; or
(b) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors.
3.51 Method 3—crude oil production (non-flared) emissions of methane
(1) Method 3 is:
Eij = ∑k (EFijk × Tik × Nk)
where:
Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2‑e tonnes.
Σk is the total emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil production.
EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per component-hour that passes through each component type (k) listed in section 6.1.3 of the API Compendium as determined under subsection (2), if the component is used in the crude oil production.
Tik is the average hours of operation during the year of the components of each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil production, measured in hours per year.
Nk is the total number of each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil production, measured in components.
(2) For EFijk, the emission factors for methane (j), as crude oil passes through a component type (k), are:
(a) column 3 of an item in the following table, which specifies the emission factor for a component of type (k) specified in column 2 of that item:
Item Component type (k) Emission factor for gas type (j) (tonnes CO2‑e/component-hour) CH4 1 Valves – heavy crude production 3.64 × 10-7 2 Valves – light crude production 3.70 × 10-5 3 Connectors – heavy crude production 2.23 × 10-7 4 Connectors – light crude production 4.59 × 10-6 5 Flanges – heavy crude production 6.13 × 10-7 6 Flanges – light crude production 2.15 × 10-6 7 Open-ended lines – heavy crude production 4.34 × 10-6 8 Open-ended lines – light crude production 3.39 × 10-5 9 Pump Seals – light crude production 8.90 × 10-6 10 Others – heavy crude production 1.96 × 10-6 11 Others – light crude production 2.10 × 10-4 Note: API Publication 4615 defines light crude as oil with an API gravity of 20 or more, and heavy crude as oil with an API gravity of less than 20.
(b) if the manufacturer of the component supplies component‑specific emission factors for the component type—those factors.
Subdivision 3.3.3.3—Crude oil production (flared)—fugitive emissions of carbon dioxide, methane and nitrous oxide
3.52 Available methods
(1) Subject to section 1.18, for estimating emissions released by oil or gas flaring during a year from the operation of a facility that is constituted by crude oil production:
(a) if estimating emissions of carbon dioxide released—one of the following methods must be used:
(i) method 1 under section 3.53;
(ii) method 2 under section 3.54;
(iii) method 3 under section 3.55; and
(b) if estimating emissions of methane released—one of the following methods must be used:
(i) method 1 under section 3.53;
(ii) method 2A under section 3.54A; and
(c) if estimating emissions of nitrous oxide released—one of the following methods must be used:
(i) method 1 under section 3.53;
(ii) method 2A under section 3.54A.
Note: There is no method 4 under paragraph (a) and no method 2, 3 or 4 under paragraph (b) or (c).
(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.
3.53 Method 1—crude oil production (flared) emissions
(1) For subparagraph 3.52(a)(i), method 1 is:
where:
Eij is the emissions of gas type (j) measured in CO2‑e tonnes from a fuel type (i) flared in crude oil production during the year.
Qi is the quantity of fuel type (i) measured in tonnes flared in crude oil production during the year.
Note: This quantity includes all of the fuel type, not just hydrocarbons within the fuel type.
EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of the fuel type (i) flared.
(2) For EFij mentioned in subsection (1), columns 3, 4 and 5 of an item in following table specify the emission factor for each fuel type (i) specified in column 2 of that item.
| Item | Fuel type (i) | Emission factor for gas type (j) (tonnes CO2‑e/tonnes of fuel flared) | ||
| CO2 | CH4 | N2O | ||
| 1 | Gas | 2.80 | 0.933 | 0.026 |
| 2 | Crude oil and liquids | 3.20 | 0.009 | 0.06 |
3.54 Method 2—crude oil production
Combustion of gaseous fuels (flared) emissions of carbon dioxide
(1) For subparagraph 3.52(1)(a)(ii), method 2 for combustion of gaseous fuels is:
where:
EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in crude oil production during the year, measured in CO2‑e tonnes.
Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in tonnes in accordance with Division 2.3.3.
EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in CO2‑e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3.
OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.
QCO2 is the quantity of CO2 within the fuel type (i) in crude oil production during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.
Combustion of liquid fuels (flared) emissions of carbon dioxide
(2) For subparagraph 3.51(1)(a)(ii), method 2 for combustion of liquid fuels is the same as method 1, but the carbon dioxide emissions factor EFh must be determined in accordance with method 2 in Division 2.4.3.
3.54A Method 2A—crude oil production (flared methane or nitrous oxide emissions)
For subparagraphs 3.52(1)(b)(ii) and (c)(ii), method 2A is:
where:
EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in crude oil production during the year, mentioned for the fuel type in the table in subsection 3.53(2) and measured in CO2‑e tonnes per tonne of the fuel type (i) flared.
Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from crude oil production during the year, measured in CO2‑e tonnes.
OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.
Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in tonnes in accordance with Division 2.3.3 for gaseous fuels or Division 2.4.3 for liquid fuels.
3.55 Method 3—crude oil production
Combustion of gaseous fuels (flared) emissions of carbon dioxide
(1) For subparagraph 3.52(1)(a)(iii), method 3 for the combustion of gaseous fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.3.4.
Combustion of liquid fuels (flared) emissions of carbon dioxide
(2) For subparagraph 3.52(1)(a)(iii), method 3 for the combustion of liquid fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.4.4.
Subdivision 3.3.3.4—Crude oil production (non‑flared)—fugitive vent emissions of methane and carbon dioxide
3.56A Available methods
(1) Subject to section 1.18, the methods mentioned in subsections (2) and (3) must be used for estimating fugitive emissions that result from system upsets, accidents and deliberate releases from process vents during a year from the operation of a facility that is constituted by crude oil production.
(2) To estimate emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, one of the following methods must be used:
(a) method 1 under section 3.56B;
(b) method 4 under Part 1.3.
(3) For estimating incidental emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, another method may be used that is consistent with the principles mentioned in section 1.13.
Note: There is no method 2 or 3 for this Subdivision.
Note: Methods to estimate vented emissions from condensate storage tanks are available at section 3.85D.
3.56B Method 1—emissions from system upsets, accidents and deliberate releases from process vents
(1) Method 1 is, for a process mentioned in column 2 of an item in the following table, as described in the section of the API Compendium mentioned in column 3 for the item.
| Item | Emission process | API Compendium section |
| 1 | Gas treatment processes | Section 5.1 |
| 2 | Cold process vents | Section 5.3 |
| 3 | Storage tanks - vented emissions | Section 5.4 |
| 4 | Other venting sources—gas driven pneumatic devices | Section 5.6.1 |
| 5 | Other venting sources—gas driven chemical injection pumps | Section 5.6.2 |
| 6 | Non‑routine activities—production related non‑routine emissions | Section 5.7.1 and 5.7.2 |
(2) However, emissions from well workovers may use method 1 under section 3.85P (as if that method referred to crude oil production instead of natural gas production).
Division 3.3.4—Crude oil transport
3.57 Application
This Division applies to fugitive emissions from crude oil transport activities, other than emissions that are flared.
3.58 Available methods
(1) Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane released during a year from the operation of a facility that is constituted by crude oil transport:
(a) method 1 under section 3.59;
(b) method 2 under section 3.60.
Note: There is no method 3 or 4 for this Division.
(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.
3.59 Method 1—crude oil transport
Method 1 is:
where:
Eij is the fugitive emissions of methane (j) from the crude oil transport during the year measured in CO2‑e tonnes.
Qi is the quantity of crude oil (i) measured in tonnes and transported during the year.
EFij is the emission factor for gas type (j), being methane, which is 9.74 × 10‑4 tonnes CO2‑e per tonnes of crude oil transported during the year.
3.60 Method 2—fugitive emissions from crude oil transport
(1) Method 2 is:
Eij = ∑k (Qik × EFijk)
where:
Eij is the fugitive emissions of gas type (j), being methane, from the crude oil transport during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane, measured in tonnes of CO2‑e and estimated by summing up the emissions from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport.
Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport.
EFijk is the emission factor of gas type (j), being methane, measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium as determined under subsection (2), if the equipment is used in the crude oil transport.
(2) For EFijk, the emission factors for gas type (j), being methane, as crude oil passes through equipment type (k), are:
(a) as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or
(b) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors.
Division 3.3.5—Crude oil refining
3.62 Application
This Division applies to fugitive emissions from crude oil refining activities, including emissions from flaring at petroleum refineries.
3.63 Available methods
(1) Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by crude oil refining the methods as set out in this section must be used.
Crude oil refining and storage tanks
(2) One of the following methods must be used for estimating fugitive emissions of methane that result from crude oil refining and from storage tanks for crude oil:
(a) method 1 under section 3.64;
(b) method 2 under section 3.65;
(c) method 3 under section 3.66.
Note: There is no method 4 for subsection (2).
Process vents, system upsets and accidents
(3) One of the following methods must be used for estimating fugitive emissions of each type of gas, being carbon dioxide, methane and nitrous oxide, that result from deliberate releases from process vents, system upsets and accidents:
(a) method 1 under section 3.67;
(b) method 4 under section 3.68.
Note: There is no method 2 or 3 for subsection (3).
Flaring
(4) For estimating emissions released from gas flared from crude oil refining:
(a) one of the following methods must be used for estimating emissions of carbon dioxide released:
(i) method 1 under section 3.69;
(ii) method 2 under section 3.70;
(iii) method 3 under section 3.71; and
(b) if estimating emissions of methane released—one of the following methods must be used:
(i) method 1 under section 3.69;
(ii) method 2A under section 3.70A; and
(c) if estimating emissions of nitrous oxide released—one of the following methods must be used:
(i) method 1 under section 3.69;
(ii) method 2A under section 3.70A.
Note: The flaring of gas from crude oil refining releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 under section 3.69 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide and no method 2, 3 or 4 for emissions of nitrous oxide or methane.
(5) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.
Subdivision 3.3.5.1—Fugitive emissions from crude oil refining and from storage tanks for crude oil
3.64 Method 1—crude oil refining and storage tanks for crude oil
Method 1 is:
where:
Eij is the fugitive emissions of gas type (j), being methane or carbon dioxide, from fuel type (i) being crude oil refined or stored in tanks during the year measured in CO2‑e tonnes.
∑i is the sum of emissions of gas type (j), being methane or carbon dioxide, released during refining and from storage tanks during the year.
Qi is the quantity of crude oil (i) refined or stored in tanks during the year measured in tonnes.
EFij is the emission factor for gas type (j), being methane or carbon dioxide, being 9.47 × 10‑4 tonnes CO2‑e per tonne of crude oil refined and 1.73 × 10‑4 tonnes CO2‑e per tonne of crude oil stored in tanks.
3.65 Method 2—crude oil refining and storage tanks for crude oil
(1) Method 2 is:
where:
Eij is the fugitive emissions of gas type (j), being methane, from the crude oil refining and from storage tanks during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane, measured in tonnes of CO2‑e estimated by summing up the emissions released from each equipment types (k) listed in sections 5 and 6.1.2 of the API Compendium as determined under subsection (2), if the equipment is used in the crude oil refining and in the storage tanks.
Qik is the total of the quantities of crude oil (i) measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.
EFijk is the emission factor for gas type (j), being methane, measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.
(2) For EFijk, the emission factors for gas type (j), being methane, as the crude oil passes through an equipment type (k) are:
(a) as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or
(b) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors.
3.66 Method 3—crude oil refining and storage tanks for crude oil
(1) Method 3 is:
Eij = ∑k (Qik × EFijk)
where:
Eij is the fugitive emissions of gas type (j), being methane, from the crude oil refining and from storage tanks during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane, measured in tonnes of CO2‑e and estimated by summing up the emissions released from each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil refining and from storage tanks.
Qik is the total of the quantities of crude oil (i) that pass through each component type (k), or the number of components of each component type (k), listed in section 6.1.3 of the API Compendium , if the component is used in the crude oil refining and from storage tanks, measured in tonnes.
EFijk is the emission factor of gas type (j), being methane, measured in tonnes of CO2‑e per tonne of crude oil that passes through each component type (k) listed in section 6.1.3 of the API Compendium as determined under subsection (2), if the component is used in the crude oil refining and from storage tanks.
(2) For EFijk, the emission factors for gas type (j), being methane or carbon dioxide, as crude oil passes through a component type (k), are:
(a) as listed in section 6.1.3 of the API Compendium, for the component type; or
(b) if the manufacturer of the component supplies component‑specific emission factors for the component type—those factors.
Subdivision 3.3.5.2—Fugitive emissions from deliberate releases from process vents, system upsets and accidents
3.67 Method 1—fugitive emissions from deliberate releases from process vents, system upsets and accidents
Method 1 is:
where:
Ei is the fugitive emissions of carbon dioxide during the year from deliberate releases from process vents, system upsets and accidents in the crude oil refining measured in CO2‑e tonnes.
Qi is the quantity of refinery coke (i) burnt to restore the activity of the catalyst of the crude oil refinery (and not used for energy) during the year measured in tonnes.
CCFi is the carbon content factor for refinery coke (i) as mentioned in Schedule 3.
3.664 is the conversion factor to convert an amount of carbon in tonnes to an amount of carbon dioxide in tonnes.
3.68 Method 4—deliberate releases from process vents, system upsets and accidents
(1) Method 4 is:
(a) is as set out in Part 1.3; or
(b) uses the process calculation approach in section 5.2 of the API Compendium.
(2) For paragraph (1)(b), all carbon monoxide is taken to fully oxidise to carbon dioxide and must be included in the calculation.
Subdivision 3.3.5.3—Fugitive emissions released from gas flared from the oil refinery
3.69 Method 1—gas flared from crude oil refining
(1) Method 1 is:
where:
Eij is the emissions of gas type (j) released from the gas flared in the crude oil refining during the year measured in CO2‑e tonnes.
Qi is the quantity of gas for the fuel type (i) flared during the year measured in tonnes.
Note: This quantity includes all of the fuel type, not just hydrocarbons within the fuel type.
EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of gas type (j) flared in the crude oil refining during the year.
(2) For EFij in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor for gas type (j) for the fuel type (i) specified in column 2 of that item:
| Item | fuel type (i) | Emission factor of gas type (j) (tonnes CO2‑e/tonnes fuel flared) | ||
| CO2 | CH4 | N2O | ||
| 1 | Gas | 2.7 | 0.133 | 0.026 |
| 2 | Crude oil and liquids | 3.2 | 0.009 | 0.06 |
3.70 Method 2—gas flared from crude oil refining
For subparagraph 3.63(4)(a)(ii), method 2 is:
where:
EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in crude oil refining during the year, measured in CO2‑e tonnes.
Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, measured in tonnes in accordance with Division 2.3.3.
EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in the crude oil refining during the year, measured in CO2‑e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3.
OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.
QCO2 is the quantity of CO2 within the fuel type (i) in the crude oil refining during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.
3.70A Method 2A—crude oil refining (flared methane or nitrous oxide emissions)
For subparagraphs 3.63(4)(b)(ii) and (c)(ii), method 2A is:
where:
EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, mentioned for the fuel type in the table in subsection 3.69(2) and measured in CO2‑e tonnes per tonne of the fuel type (i) flared.
Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from crude oil refining during the year, measured in CO2‑e tonnes.
OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.
Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, measured in tonnes in accordance with Division 2.3.3.
3.71 Method 3—gas flared from crude oil refining
For subparagraph 3.63(4)(a)(iii), method 3 is the same as method 2 under section 3.70, but the emission factor EFij must be determined in accordance with method 3 for the consumption of gaseous fuels as specified in Division 2.3.4.
Division 3.3.6A—Onshore natural gas production (other than emissions that are vented or flared)
3.72 Application
This Division applies to fugitive emissions from onshore natural gas production activities, other than emissions that are vented or flared, including emissions from onshore natural gas wellheads.
Subdivision 3.3.6A.1—Onshore natural gas production, other than emissions that are vented or flared—wellheads
3.73 Available methods
(1) Subject to section 1.18 and subsections (3) and (4), one of the following methods must be used for estimating fugitive emissions of methane and carbon dioxide (other than emissions that are vented or flared) released during a year from the operation of a facility that is constituted by onshore natural gas production:
(a) method 1 under section 3.73A;
(b) method 2 under section 3.73B;
(c) method 3 under section 3.73C.
Note: There is no method 4 for this Division.
(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.
(3) If method 2 is used for a facility, all other available methods 2 must be used in Divisions 3.3.6B, 3.3.6C, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.
(4) If method 3 is used for a facility, all other available methods 3 must be used in Divisions 3.3.6B, 3.3.6C, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.
3.73A Method 1—onshore natural gas production, other than emissions that are vented or flared—wellheads
(1) Method 1 is:
Eij = Σk (Qik ×EFijk × Sij / SDij)
where:
Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the onshore natural gas production during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) specified in column 2 of an item in the table in subsection (2), if the equipment is used in the onshore natural gas production.
Qik is the total of the quantities of unprocessed natural gas (i) that pass through each equipment type (k) specified in column 2 of the table in subsection (2), during the year measured in tonnes in accordance with Division 2.3.6.
EFijk is the emission factor for gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes per tonne of unprocessed natural gas (i) that passes through each equipment type (k), if the equipment is used in the onshore natural gas production during the year.
Note: Consistent with subsection 3.41(2), emissions associated with any piece of equipment included in this definition should not be counted under this section if those emissions are also counted as equipment emissions under another section within this Part.
Sij is the measured share of each gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.
SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.98 and for carbon dioxide SD is 0.02.
(2) For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for gas type (j) being methane for an equipment type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for an equipment type (k) specified in column 2 of that item:
| Item | Equipment type (k) | Emission factor for gas type (j) | ||
| CH4 | CO2 | Units | ||
| 1 | Onshore natural gas wellheads | 1.32 × 10-3 | 2.60 × 10-6 | tonnes CO2-e/t gas throughput |
3.73B Method 2—onshore natural gas production, other than emissions that are vented or flared—wellheads
(1) Method 2 is:
Eij = Σk (Tik ×Nik ×EFijk) × Sij/SDij
where:
Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the onshore natural gas production during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) specified in column 2 of an item in the table in subsection (2), if the equipment is used in the onshore natural gas production.
Tik is the average hours of operation during the year of the equipment of each equipment type (k), if the equipment is used in the onshore natural gas production during the year.
Nik is the total number of equipment units of each equipment type (k), if the equipment type is used in the onshore natural gas production during the year.
EFijk is the emission factor of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per equipment type (k) – hour as determined under subsection (2), if the equipment is used in the onshore natural gas production.
Note: Consistent with subsection 3.41(2), emissions associated with any piece of equipment included in this definition should not be counted under this section if those emissions are also counted as equipment emissions under another section within this Part.
Sij is the measured share of each gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.
SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.788 and for carbon dioxide SD is 0.02.
(2) For EFijk in subsection (1):
(a) column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for an equipment type (k) specified in column 2 of that item:
| Item | Equipment type (k) | Emission factor for gas type (j) | |||
| CH4 | CO2 | Units | |||
| 1 | Gas wellheads | 5.04 × 10-4 | 1.25 × 10-6 | tonnes CO2-e /equipment - hour | |
| 2 | Gas separators | 1.24 × 10-3 | 3.08 × 10-6 | tonnes CO2-e /equipment - hour | |
| 3 | Gas heaters | 1.29 × 10-3 | 3.20 × 10-6 | tonnes CO2-e /equipment - hour | |
| 4 | Reciprocating compressor | 4.60 × 10-2 | 1.14 × 10-4 | tonnes CO2-e /equipment - hour | |
| 5 | Screw compressor | 2.88 × 10-2 | 7.15 × 10-5 | tonnes CO2-e /equipment - hour | |
| 6 | Metering installation and associated piping | 9.86 × 10-4 | 2.45 × 10-6 | tonnes CO2-e /equipment - hour | |
| 7 | Dehydrators | 2.00 × 10-3 | 4.96 × 10-6 | tonnes CO2-e /equipment - hour | |
(b) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors are the relevant emissions factors.
3.73C Method 3—onshore natural gas production, other than emissions that are vented or flared—wellheads
(1) Method 3 is:
Eij = ∑k (Tik × Nik ×EFijk ) × Sij /SDij
where:
Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the onshore natural gas production during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e and estimated by summing up the emissions released from each component type (k), if the component type is used in the onshore natural gas production during the year.
EFijk is the emission factor of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per component-hour for each component type (k) as determined under subsection (2) or (3), if the component is used in the onshore natural gas production during the year.
Note: Consistent with subsection 3.41(2), emissions associated with any components included in this definition should not be counted under this section if those emissions are also counted as component emissions under another section within this Part.
Nik is the total number of components of each component type (k) if the component type is used in the onshore natural gas production during the year.
Tik is:
(a) if subsection (2) applies—the average hours of operation during the year of the component of each component type (k), if the component is used in the onshore natural gas production;
(b) if subsection (3) applies—an engineering estimate of the number of hours in the year the component type (k) was operational as a leaker or non leaker based on the best available data and subsection (4).
Sij is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.
SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.788 and for carbon dioxide SD is 0.02.
(2) Unless subsection (3) is elected and used for all components under this method, EFijk, the emission factors for methane or carbon dioxide (j), for component type (k), are:
(a) column 3 of an item in the following table specifies the emission factor for methane (j) for a component type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for a component type (k) specified in column 2 of that item:
| Item | Component type (k) | Emission factor for gas type (j) | ||
| CH4 | CO2 | Units | ||
| 1 | Valves – gas production | 7.36 × 10-5 | 1.83 × 10-7 | tonnes CO2-e /component - hour |
| 2 | Connectors – gas production | 8.99 × 10-6 | 2.23 × 10-8 | tonnes CO2-e / component - hour |
| 3 | Flanges – gas production | 3.30 × 10-6 | 8.22 × 10-9 | tonnes CO2-e / component - hour |
| 4 | Open-ended lines – gas production | 1.92 × 10-5 | 4.78 × 10-8 | tonnes CO2-e / component - hour |
| 5 | Pump Seals – gas production | 5.46 × 10-6 | 1.36 × 10-8 | tonnes CO2-e / component - hour |
| 6 | Others – gas production | 2.57 × 10-4 | 6.40 × 10-7 | tonnes CO2-e / component - hour |
Note: These component types are listed in section 6.1.3 of the API Compendium.
(b) if the manufacturer of the component supplies component‑specific emission factors for the component type—those factors.
(3) If an LDAR program has been carried out at the facility in relation to onshore natural gas production components in accordance with subsection (4) and this subsection elected for all components under this method, EFijk, the emission factors for methane or carbon dioxide (j), for component type (k), are:
(a) column 3 of an item in the following table specifies the emission factor for methane (j) for a component and leaker/non-leaker type (k) specified in column 2 of that item; and
(b) column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for a component and leaker/non-leaker type (k) specified in column 2 of that item:
| Item | Component and leaker/non leaker type (k) | Emission factor for gas type (j) | ||
| CH4 | CO2 | Units | ||
| 1 | Valves—non leaker | 7.56 × 10-6 | 1.88 × 10-8 | tonnes CO2-e /component - hour |
| 2 | Values—leaker | 5.60 × 10-3 | 1.39 × 10-5 | tonnes CO2-e / component - hour |
| 3 | Pumps—non leaker | 4.20 × 10-6 | 1.04 × 10-8 | tonnes CO2-e / component - hour |
| 4 | Pumps—leaker | 9.80 × 10-3 | 2.44 × 10-5 | tonnes CO2-e / component - hour |
| 5 | Flanges—non leaker | 3.92 × 10-7 | 9.75 × 10-10 | tonnes CO2-e / component - hour |
| 6 | Flanges—leaker | 3.36 × 10-3 | 8.36 × 10-6 | tonnes CO2-e / component - hour |
| 7 | Other—non leaker | 2.27 × 10-6 | 5.64 × 10-9 | tonnes CO2-e / component - hour |
| 8 | Other—leaker | 5.88 × 10-3 | 1.46 × 10-5 | tonnes CO2-e / component - hour |
(4) For subsection (3), the LDAR program must survey each component used in onshore gas production at the facility at least once in a reporting year in accordance with:
(a) paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America using optical gas imaging with a sensitivity of 60 grams per hour; or
(b) the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America where a leaker is detected if 10,000 parts per million or greater is measured consistent with that method; or
(c) an equivalent leak detection standard.
(5) To determine whether a component is a leaker or non leaker at a period of time:
(a) if a leak is detected in a survey the component is assumed to leak from the later of the beginning of the reporting year or last survey where it was a non leaker; and
(b) after a leak is detected in a survey the component is assumed to leak until the earlier of the end of the reporting year or the next survey where it is a non leaker.
Division 3.3.6B—Offshore natural gas production (other than emissions that are vented or flared)
3.73D Application
This Division applies to fugitive emissions from offshore natural gas production activities, other than emissions that are vented or flared, including emissions from:
(a) a gas wellhead through to the inlet of gas processing plants; and
(b) a gas wellhead through to the tie‑in points on gas transmission systems, if processing of natural gas is not required.
Subdivision 3.3.6B.1—Offshore natural gas production, other than emissions that are vented or flared—offshore platforms
3.73E Available methods
(1) Subject to section 1.18 and subsections (3) and (4), one of the following methods must be used for estimating fugitive emissions of methane and carbon dioxide (other than emissions that are vented or flared) released during a year from the operation of a facility that is constituted by offshore natural gas production:
(a) method 1 under section 3.73F;
(b) method 2 under section 3.73G;
(c) method 3 under section 3.73H.
Note: There is no method 4 for this Division.
(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.
(3) If method 2 is used for a facility, all other available methods 2 must be used in Divisions 3.3.6A, 3.3.6C, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.
(4) If method 3 is used for a facility all other available methods 3 must be used in Divisions 3.3.6A, 3.3.6C, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.
3.73F Method 1—offshore natural gas production (other than emissions that are vented or flared)
(1) Method 1 is:
Eij = ∑k (Qik ×EFijk) × Sij/SDij
where:
Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the offshore natural gas production during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) specified in column 2 of an item in the table in subsection (2), if the equipment is used in the offshore natural gas production.
Qik is the number of platforms of each equipment type (k) specified in column 2 of the table in subsection (2), during the year.
EFijk is the emission factor for gas type (j) measured in CO2‑e tonnes per platform during the year as determined under subsection (2), if the equipment is used in the offshore natural gas production.
Note: Consistent with subsection 3.41(2), emissions associated with any piece of equipment included in this definition should not be counted under this section if those emissions are also counted as equipment emissions under another section within this Part.
Sij is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.
SDij is the default share of gas type (j) in the unprocessed gas (i) where methane SD is 0.832 and carbon dioxide SD is 0.035.
(2) For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for an equipment type (k) specified in column 2 of that item:
| Item | Equipment type (k) | emission factor for gas type (j) | ||
| CH4 | CO2 | Units | ||
| 1 | Offshore platforms (shallow water) | 1,747.1 | 7.10 | tonnes CO2-e /platform |
| 2 | Offshore platforms (deep water) | 18,422.6 | 75.0 | tonnes CO2-e/ platform |
3.73G Method 2—offshore natural gas production (other than venting and flaring)
(1) Method 2 is:
Eij = ∑k (Tik × Nik ×EFijk) × Sij/SDij
where:
Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the offshore natural gas production during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k), if the equipment is used in the offshore natural gas production.
Tik is the average hours of operation during the year of the equipment of each equipment type (k), if the equipment is used in the offshore natural gas production during the year.
Nik is the total number of equipment units of each equipment type (k), if the equipment type is used in the offshore natural gas production during the year.
EFijk is the emission factor of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per equipment type (k) – hour as determined under subsection (2), if the equipment is used in the offshore natural gas production.
Note: Consistent with subsection 3.41(2), emissions associated with any piece of equipment included in this definition should not be counted under this section if those emissions are also counted as equipment emissions under another section within this Part.
Sij is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.
SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.788 and for carbon dioxide SD is 0.02.
(2) For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for an equipment type (k) specified in column 2 of that item:
| Item | Equipment type (k) | Emission factor for gas type (j) | |||
| CH4 | CO2 | Units | |||
| 1 | Gas wellheads | 5.04 × 10-4 | 1.25 × 10-6 | tonnes CO2-e /equipment - hour | |
| 2 | Gas separators | 1.24 × 10-3 | 3.08 × 10-6 | tonnes CO2-e /equipment - hour | |
| 3 | Gas heaters | 1.29 × 10-3 | 3.20 × 10-6 | tonnes CO2-e /equipment - hour | |
| 4 | Reciprocating compressor | 4.60 × 10-2 | 1.14 × 10-4 | tonnes CO2-e /equipment - hour | |
| 5 | Screw compressor | 2.88 × 10-2 | 7.15 × 10-5 | tonnes CO2-e /equipment - hour | |
| 6 | Metering installation and associated piping | 9.86 × 10-4 | 2.45 × 10-6 | tonnes CO2-e /equipment - hour | |
| 7 | Dehydrators | 2.00 × 10-3 | 4.96 × 10-6 | tonnes CO2-e /equipment - hour | |
| 8 | Gathering pipelines | 7.45 × 10-4 | 1.85 × 10-6 | tonnes CO2-e /kilometre - hour | |
3.73H Method 3—offshore natural gas production (other than emissions that are vented or flared)
(1) Method 3 is:
Eij = ∑k (Tik × Nik ×EFijk) × Sij /SDij
where:
Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the offshore natural gas production during the year measured in CO2‑e tonnes.
Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e and estimated by summing up the emissions released from each component type (k), if the component type is used in the offshore natural gas production.
EFijk is the emission factor of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per component-hour for each component type (k) as determined under subsection (2) or (3), if the component is used in the offshore natural gas production.
Note: Consistent with subsection 3.41(2), emissions associated with any components included in this definition should not be counted under this section if those emissions are also counted as component emissions under another section within this Part.
Tik is:
(a) if subsection (2) applies—the average hours of operation during the year of the component of each component type (k), if the component is used in the offshore natural gas production; and
(b) if subsection (3) applies—an engineering estimate of the number of hours in the year the component type (k) was operational as a leaker or non leaker based on the best available data and subsection (4).
| Item | Method | Matters to be identified |
| 1 | Method 1, 2 and 3 for the source, as set out in sections 3.76, 3.77 and 3.78 | (a) the terajoules of natural gas transmission throughput (b) kilometres of pipeline length |
Source 2O—Natural gas storage (other than emissions that are vented or flared)
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.78C | number of storage stations |
| 2 | Method 2 for the source, as set out in section 3.78D | (a) number of storage stations (b) number of equipment units of each equipment type (c) average hours of operation of each equipment type (d) total emissions for each gas type (CO2-e) for each equipment type |
| 3 | Method 3 for the source, as set out in section 3.78E | (a) number of storage stations (b) number of components of each type (by leaker or non-leaker if LDAR factors are elected) (c) average hours of operation of each component type (by leaker or non-leaker if LDAR factors are elected) (d) total emissions for each gas type (CO2-e) for each component type (by leaker or non-leaker if LDAR factors are elected) (e) if LDAR factors are elected—the standard used to detect leakers |
Source 2P—Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)
| Item | Method | Matters to be identified |
| 1 | Method 1, and 2 for the source, as set out in sections 3.78H and 3.78I | (a) the tonnes of natural gas liquefied (b) number of liquefied natural gas stations |
| 3 | Method 3 for the source, as set out in section 3.78J | (a) the tonnes of natural gas liquefied (b) number of liquefied natural gas stations (c) number of components of each type (by leaker or non-leaker if LDAR factors are elected) (d) average hours of operation of each component type (by leaker or non-leaker if LDAR factors are elected) (e) total emissions for each gas type (CO2-e) for each component type (by leaker or non-leaker if LDAR factors are elected) (f) if LDAR factors are elected—the standard used to detect leakers |
Source 2Q—Natural gas distribution (other than flaring)
| Item | Method | Matters to be identified |
| 1 | Methods 1 and 2 for the source, as set out in sections 3.81 and 3.82 | (a) terajoules of utility sales (b) location of the natural gas distribution |
| 3 | Method 3 for the source, as set out in section 3.82A | (a) terajoules of utility sales (b) location of the natural gas distribution (c) the facility specific unaccounted for gas factor as a percentage (d) whether the facility specific unaccounted for gas factor is the percentage calculated or determined for the reporting year or for a previous period |
Source 2R—Onshore natural gas production—venting
| Item | Method | Matters to be identified |
| 1 | Methods 1 and 4 for the source, as set out in section 3.85, 3.85B, 3.85D, 3.85F, 3.85H, 3.85L, 3.85N, 3.85P, 3.85Q, 3.85S and Part 1.3 | (a) the tonnes and megajoules of vented gas related to gas treatment processes (b) the tonnes and megajoules of vented gas related to cold process vents (c) the tonnes and megajoules of vented gas related to gas blanketed tanks (d) the tonnes and megajoules of vented gas related to condensate storage tanks (e) the tonnes and megajoules of vented gas related to gas driven pneumatic devices (f) the tonnes and megajoules of vented gas related to gas driven chemical injection pumps (g) the tonnes and megajoules of vented gas related to well blowouts (h) the tonnes and megajoules of vented gas related to carbon dioxide stimulation (i) the tonnes and megajoules of vented gas related to well workovers (j) the tonnes and megajoules of vented gas related to vessel blowdowns, compressor starts and compressor blowdowns (k) number of well workovers without hydraulic fracturing (l) number of well workovers with hydraulic fracturing and venting (no flaring) (m) number of well workovers with hydraulic fracturing with capture (no flaring) (n) number of well workovers with hydraulic fracturing with flaring |
Source 2S—Offshore natural gas production—venting
| Item | Method | Matters to be identified |
| 1 | Methods 1 and 4 for the source, as set out in sections 3.85, 3.85B, 3.85D, 3.85F, 3.85H, 3.85L, 3.85N, 3.85P, 3.85Q, 3.85S and Part 1.3 | (a) the tonnes and megajoules of vented gas related to gas treatment processes (b) the tonnes and megajoules of vented gas related to cold process vents (c) the tonnes and megajoules of vented gas related to gas blanketed tanks (d) the tonnes and megajoules of vented gas related to condensate storage tanks (e) the tonnes and megajoules of vented gas related to gas driven pneumatic devices (f) the tonnes and megajoules of vented gas related to gas driven chemical injection pumps (g) the tonnes and megajoules of vented gas related to well blowouts (h) the tonnes and megajoules of vented gas related to carbon dioxide stimulation (i) the tonnes and megajoules of vented gas related to well workovers (j) the tonnes and megajoules of vented gas related to vessel blowdowns, compressor starts and compressor blowdowns (k) number of well workovers without hydraulic fracturing (l) number of well workovers with hydraulic fracturing and venting (no flaring) (m) number of well workovers with hydraulic fracturing with capture (no flaring) (n) number of well workovers with hydraulic fracturing with flaring |
Source 2T—Onshore natural gas production—flaring
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.86 | (a) the tonnes of flared gas (b) the tonnes of flared crude oil and liquids |
| 2 | Methods 2, 2A and 3 for the source, as set out in sections 3.87, 3.87A and 3.88 | (a) the tonnes and megajoules of flared gas (hydrocarbon component) (b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component) |
Source 2U—Offshore natural gas production—flaring
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.86 | (a) the tonnes of flared gas (b) the tonnes of flared crude oil and liquids |
| 2 | Methods 2, 2A and 3 for the source, as set out in sections 3.87, 3.87A and 3.88 | (a) the tonnes and megajoules of flared gas (hydrocarbon component) (b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component) |
Source 2V—Natural gas gathering and boosting—venting
| Item | Method | Matters to be identified |
| 1 | Methods 1 for the source, as set out in section 3.88C | (a) the tonnes and megajoules of vented gas for each gas type |
Source 2W—Natural gas gathering and boosting—flaring
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.86 | (a) the tonnes of flared gas (b) the tonnes of flared crude oil and liquids |
| 2 | Methods 2, 2A and 3 for the source, as set out in sections 3.87, 3.87A and 3.88 | (a) the tonnes and megajoules of flared gas (hydrocarbon component) (b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component) |
Source 2X—Natural gas processing—venting
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.88G | (a) the tonnes and megajoules of vented gas for each gas type |
Source 2Y—Natural gas processing—flaring
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.86 | (a) the tonnes of flared gas (b) the tonnes of flared crude oil and liquids |
| 2 | Methods 2, 2A and 3 for the source, as set out in sections 3.87, 3.87A and 3.88 | (a) the tonnes and megajoules of flared gas (hydrocarbon component) (b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component) |
Source 2Z—Natural gas transmission—flaring
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.86 | (a) the tonnes of flared gas (b) the tonnes of flared crude oil and liquids |
| 2 | Methods 2, 2A and 3 for the source, as set out in sections 3.87, 3.87A and 3.88 | (a) the tonnes and megajoules of flared gas (hydrocarbon component) (b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component) |
Source 2ZA—Natural gas storage—venting
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.88M | (a) the tonnes and megajoules of vented gas for each gas type |
Source 2ZB—Natural gas storage—flaring
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.86 | (a) the tonnes of flared gas (b) the tonnes of flared crude oil and liquids |
| 2 | Methods 2, 2A and 3 for the source, as set out in sections 3.87, 3.87A and 3.88 | (a) the tonnes and megajoules of flared gas (hydrocarbon component) (b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component) |
Source 2ZC—Natural gas liquefaction, storage and transfer—venting
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.88Q | (a) the tonnes and megajoules of vented gas for each gas type |
Source 2ZE—Natural gas liquefaction, storage and transfer—flaring
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.86 | (a) the tonnes of flared gas (b) the tonnes of flared crude oil and liquids |
| 2 | Methods 2, 2A and 3 for the source, as set out in sections 3.87, 3.87A and 3.88 | (a) the tonnes and megajoules of flared gas (hydrocarbon component) (b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component) |
Source 2ZF—Natural gas distribution—flaring
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 3.86 | (a) the tonnes of flared gas (b) the tonnes of flared crude oil and liquids |
| 2 | Methods 2, 2A and 3 for the source, as set out in sections 3.87, 3.87A and 3.88 | (a) the tonnes and megajoules of flared gas (hydrocarbon component) (b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component) |
Source 2ZH—Enhanced oil recovery
| Item | Method | Matters to be identified |
| 1 | Method 1, 2 or 3 for the source, as set out sections 3.77, 3.91, 3.92, 3.95, 3.96 and 3.97 | (a) the amount of greenhouse gases captured for enhanced oil recovery (b) the amount of greenhouse gases imported for enhanced oil recovery (c) the amount of greenhouse gases injected at enhanced oil recovery sites (d) the amount of emissions that occurred during the transportation of greenhouse gases to the enhanced oil recovery site (e) the amount of emissions that occurred when greenhouse gases were being injected into the enhanced oil recovery site (f) the type of the source of the greenhouse gases captured for enhanced oil recovery |
Part 3—Mineral products
Source 3A—Cement clinker production
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.4 | (a) the tonnes of clinker produced (b) the tonnes of cement kiln dust produced (c) the degree of calcination of cement kiln dust produced |
| 2 | Methods 2 and 4 for the source, as set out in sections 4.5 and Part 1.3 | (a) the tonnes of clinker produced (b) the tonnes of cement kiln dust produced (c) the facility specific emission factor or factors for clinker production, in tonnes of greenhouse gas emissions of each gas (CO2‑e) per tonne of clinker produced |
| (d) the degree of calcination of cement kiln dust produced | ||
| 3 | Method 3 for the source, as set out in section 4.8 | (a) the tonnes of pure calcium carbonate calcined (b) the tonnes of pure magnesium carbonate calcined |
| (c) the tonnes of pure dolomite calcined (d) the tonnes of cement kiln dust not recycled or lost | ||
| (e) the tonnes of organic matter or other carbon in specific non‑fuel raw material | ||
| (f) the emission factor for kerogen or other carbon‑bearing non‑fuel raw material, in tonnes of emissions (CO2‑e) per tonne of clinker produced | ||
| (g) the degree of calcination of the carbonate in the production of cement clinker during the year (h) the tonnes of any other pure carbonate calcined | ||
| (i) the degree of calcination of cement kiln dust produced |
Source 3B—Lime production
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.13 | (a) the tonnes of commercial lime produced (b) the tonnes of in‑house lime produced (c) the tonnes of dolomitic lime produced (d) the tonnes of magnesian lime produced; |
| (e) the tonnes of lime kiln dust produced (f) the degree of calcination of lime kiln dust produced | ||
| 2 | Method 2, 3 and 4 for the source, as set out in sections 4.14, 4.17 and Part 1.3 | (a) the tonnes of lime produced (b) the tonnes of lime kiln dust produced (c) the degree of calcination of lime kiln dust produced |
| (d) the emission factor for lime production at each facility, in tonnes of emissions (CO2‑e) per tonne of lime |
Source 3C—Use of carbonate for production of mineral product (other than cement, clinker, lime or soda ash)
| Item | Method | Matters to be identified |
| 1 | Methods 1 or 1A for the source, as set out in section 4.22 or 4.22A | (a) the tonnes of limestone calcined (b) the tonnes of dolomite calcined (c) the tonnes of magnesium carbonate calcined (d) the degree of calcination of the carbonate during the year |
| (e) the tonnes of any other raw carbonate calcined | ||
| 2 | Methods 3 or 3A for the source, as set out in section 4.23 and 4.23A | (a) the tonnes of pure calcium carbonate calcined (b) the tonnes of pure dolomite calcined (c) the tonnes of pure magnesium carbonate calcined |
| (d) the degree of calcination of the carbonate during the year (e) the tonnes of any other pure carbonate calcined | ||
| 3 | Method 4 for the source, as set out in Part 1.3 | the tonnes of each pure carbonate calcined |
Source 3D—Soda ash use
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.29 | the tonnes of soda ash consumed |
Source 3E—Soda ash production
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.31 | (a) the tonnes of limestone consumed (b) the tonnes of dolomite consumed (c) the tonnes of magnesium carbonate consumed |
| (d) the tonnes of soda ash produced (e) the tonnes of sodium bicarbonate produced (f) the tonnes of soda ash used for brine purification | ||
| (g) the tonnes of solid waste by‑product containing carbon produced (h) the average carbon content factor of solid waste by‑products, in tonnes of carbon per tonne of solid waste by‑product | ||
| (i) the change in stock containing carbon, in tonnes (j) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock | ||
| 2 | Methods 2, 3 and 4 for the source, as set out in sections 4.32, 4.33 and Part 1.3 | (a) the facility specific carbon content factor for soda ash production for each fuel type consumed, or each carbonaceous input material type consumed, in tonnes of carbon per: (i) tonne of fuel or carbonaceous input material; or |
| (ii) cubic metre of fuel or carbonaceous input material; or (iii) kilolitre of fuel or carbonaceous input material | ||
| (b) the tonnes of pure calcium carbonate consumed (c) the tonnes of pure dolomite consumed (d) the tonnes of pure magnesium carbonate consumed | ||
| (e) the tonnes of soda ash produced (f) the tonnes of sodium bicarbonate produced (g) the tonnes of soda ash used for brine purification | ||
| (h) the tonnes of solid waste by‑product containing carbon produced (i) the average carbon content factor of solid waste by‑products, in tonnes of carbon per tonne of solid waste by‑product | ||
| (j) the change in stock containing carbon, in tonnes (k) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock |
Part 4—Chemical products
Source 3F—Ammonia production
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.42 | (a) the tonnes of ammonia produced (b) the tonnes of carbon dioxide recovered and transferred from the facility (c) the tonnes of carbon dioxide recovered and used for urea production |
| 2 | Methods 2, 3 and 4 for the source, as set out in sections 4.43, 4.44 and Part 1.3 | (a) the tonnes of ammonia produced (b) the tonnes of carbon dioxide recovered and transferred from the facility (c) the facility specific emission factor or factors for each fuel type consumed, in kilograms of CO2‑e per gigajoule |
| (d) the tonnes of carbon dioxide recovered and used for urea production |
Source 3G—Nitric acid production
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.47 | (a) the tonnes of nitric acid production (b) the emission factor of the plant type, in tonnes of emissions (CO2‑e) per tonne of nitric acid produced |
| 2 | Methods 2 and 4 for the source, as set out in section 4.48 and Part 1.3 | (a) the tonnes of nitric acid produced (b) the facility specific emission factor or factors, in tonnes of emissions (CO2‑e) per tonne of nitric acid produced |
Source 3H—Adipic acid production
| Item | Method | Matters to be identified |
| 1 | The method set out in section 4.50 | the tonnes of adipic acid produced |
Source 3I—Carbide production
| Item | Method | Matters to be identified |
| 1 | The method set out in section 4.52 | the tonnes of carbide produced |
Source 3J—Chemical or mineral production (other than carbide production) using carbon reductant or carbon anode
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.55 | (a) the tonnes of chemical or mineral products containing carbon produced (b) the carbon content of the chemical or mineral products containing carbon produced, in tonnes of carbon per tonne of output |
| (c) the tonnes of solid waste by‑products containing carbon produced | ||
| (d) the average carbon content factor of solid waste by‑products, in tonnes of carbon per tonne of solid waste by‑product | ||
| (e) the change in stock containing carbon, in tonnes (f) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock | ||
| (g) the tonnes of pure calcium carbonate consumed (h) the tonnes of pure dolomite consumed (i) the tonnes of pure magnesium carbonate consumed | ||
| (j) the tonnes of any other pure carbonate consumed | ||
| 2 | Methods 2, 3 and 4 for the source, as set out in sections 4.56, 4.57 and Part 1.3 | (a) the tonnes of chemical or mineral products containing carbon produced (b) the carbon content of the chemical or mineral products containing carbon produced, in tonnes of carbon per tonne of output |
| (c) the tonnes of solid waste by‑products containing carbon produced | ||
| (d) the average carbon content factor of solid waste by‑products, in tonnes of carbon per tonne of solid waste by‑product | ||
| (e) the change in stock containing carbon, in tonnes (f) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock | ||
| (g) the facility specific carbon content factor for each fuel type consumed, or each carbonaceous input material consumed, in tonnes of carbon per: (i) tonne of fuel or carbonaceous input material; or | ||
| (ii) cubic metre of fuel or carbonaceous input material; or | ||
| (iii) kilolitre of fuel or carbonaceous input material | ||
| (h) the tonnes of pure calcium carbonate consumed (i) the tonnes of pure dolomite consumed | ||
| (j) the tonnes of pure magnesium carbonate consumed (k) the tonnes of any other pure carbonate consumed |
Source 6—Hydrogen production
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.62 | (a) the tonnes of hydrogen produced from fossil fuel feedstocks (b) the tonnes of hydrogen produced from electrolysers (c) the amount of electricity consumed for hydrogen production from electrolysers (d) the tonnes of carbon dioxide recovered and transferred from the facility |
| 2 | Methods 2, 3 and 4 for the source, as set out in sections 4.62A, 4.62B and Part 1.3 | (a) the tonnes of hydrogen produced from fossil fuel feedstocks (b) the tonnes of hydrogen produced from electrolysers (c) the amount of electricity consumed for hydrogen production from electrolysers (d) the tonnes of carbon dioxide recovered and transferred from the facility |
Part 5—Metal products
Source 3K—Iron, steel or other metal production using integrated metalworks
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.66 | (a) the tonnes of iron produced for sale (b) the carbon content of the iron produced for sale, in tonnes of carbon per tonne of output (c) the tonnes of crude steel produced |
| (d) the carbon content factor of the crude steel, in tonnes of carbon per tonne of output | ||
| (e) the tonnes of solid waste by‑product containing carbon produced | ||
| (f) the average carbon content factor of solid waste by‑products containing carbon, in tonnes of carbon per tonne of waste by‑product | ||
| (g) the change in stock containing carbon, in tonnes (h) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock | ||
| (i) the tonnes of coke transferred beyond the boundary of the activity | ||
| (j) the tonnes of coal tar transferred beyond the boundary of the activity | ||
| (k) the tonnes of pure calcium carbonate consumed (l) the tonnes of pure dolomite consumed | ||
| (m) the tonnes of pure magnesium carbonate consumed (n) the tonnes of any other pure carbonate consumed | ||
| 2 | Methods 2, 3 and 4 for the source, as set out in sections 4.67, 4.68 and Part 1.3 | (a) the tonnes of iron produced for sale (b) the carbon content of the iron produced for sale, in tonnes of carbon per tonne of output (c) the tonnes of crude steel produced (d) the carbon content factor of the crude steel, in tonnes of carbon per tonne of output |
| (e) the facility specific carbon content factor for each fuel type consumed, or each carbonaceous input material consumed, in tonnes of carbon per: (i) tonne of fuel or carbonaceous input material; or | ||
| (ii) cubic metre of fuel or carbonaceous input material; or (iii) kilolitre of fuel or carbonaceous input material | ||
| (f) tonnes of solid waste by‑product containing carbon produced | ||
| (g) the average carbon content factor of solid waste by‑products containing carbon, in tonnes of carbon per tonne of waste by‑product | ||
| (h) the change in stock containing carbon, in tonnes | ||
| (i) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock | ||
| (j) the tonnes of coke transferred beyond the boundary of the activity | ||
| (k) the tonnes of coal tar transferred beyond the boundary of the activity | ||
| (l) the tonnes of pure calcium carbonate consumed | ||
| (m) the tonnes of pure dolomite consumed (n) the tonnes of pure magnesium carbonate consumed | ||
| (o) the tonnes of any other pure carbonate consumed |
Source 3L—Ferroalloys production
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.71 | (a) the tonnes of ferroalloys containing carbon produced (b) the carbon content factor of the ferroalloy produced, in tonnes of carbon per tonne of output |
| (c) the tonnes of solid waste by‑products containing carbon produced | ||
| (d) the average carbon content factor of solid waste by‑products, in tonnes of carbon per tonne of solid waste by‑product | ||
| (e) the change in stock containing carbon, in tonnes (f) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock | ||
| (g) the tonnes of pure calcium carbonate consumed (h) the tonnes of pure dolomite consumed | ||
| (i) the tonnes of pure magnesium carbonate consumed | ||
| (j) the tonnes of any other pure carbonate consumed | ||
| 2 | Methods 2, 3 and 4 for the source, as set out in sections 4.72, 4.73 and Part 1.3 | (a) the tonnes of ferroalloy containing carbon produced (b) the carbon content factor of the ferroalloy produced, in tonnes of carbon per tonne of output |
| (c) the tonnes of solid waste by‑products containing carbon produced (d) the average carbon content factor of solid waste by‑products, in tonnes of carbon per tonne of solid waste by‑product | ||
| (e) the change in stock containing carbon, in tonnes (f) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock | ||
| (g) the facility specific carbon content factor for each fuel type consumed, or each carbonaceous input material consumed, in tonnes of carbon per: (i) tonne of fuel or carbonaceous input material; or (ii) cubic metre of fuel or carbonaceous input material; or (iii) kilolitre of fuel or carbonaceous input material | ||
| (h) the tonnes of pure calcium carbonate consumed (i) the tonnes of pure dolomite consumed | ||
| (j) the tonnes of pure magnesium carbonate consumed (k) the tonnes of any other pure carbonate consumed |
Source 3M—Aluminium production
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.76 | the amount of primary aluminium produced, in tonnes |
| 2 | Methods 2, 3 and 4 for the source, as set out in sections 4.77, 4.78 and Part 1.3 | (a) the facility specific emission factor or factors for each fuel type consumed, in kilograms of CO2‑e per gigajoule (b) the facility specific carbon tetrafluoride emission factor or factors, in tonnes of CO2‑e emitted per tonne of aluminium production |
| (c) the facility specific hexafluoroethane emission factor or factors, in tonnes of CO2‑e emitted per tonne of aluminium production | ||
| (d) the amount of primary aluminium produced, in tonnes |
Source 3N—Production of other metals
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 4.94 | (a) the tonnes of other metals produced (b) the carbon content of the other metals produced, in tonnes of carbon per tonne of output |
| (c) the tonnes of solid waste by‑products containing carbon produced | ||
| (d) the average carbon content factor of solid waste by‑products, in tonnes of carbon per tonne of solid waste by‑product | ||
| (e) the change in stock containing carbon, in tonnes (f) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock | ||
| (g) the tonnes of pure calcium carbonate limestone consumed (h) the tonnes of pure dolomite consumed | ||
| (i) the tonnes of pure magnesium carbonate consumed (j) the tonnes of any other pure carbonate consumed | ||
| 2 | Methods 2, 3 and 4 for the source, as set out in sections 4.95, 4.96 and Part 1.3 | (a) the tonnes of other metal produced (b) the carbon content factor of the other metal, in tonnes of carbon per tonne of output (c) the tonnes of solid waste by‑products containing carbon produced |
| (d) the average carbon content factor of solid waste by‑products, in tonnes of carbon per tonne of solid waste by‑product | ||
| (e) the change in stock containing carbon, in tonnes (f) the carbon content factor of the change in stock, in tonnes of carbon per tonne of stock | ||
| (g) the facility specific carbon content factor for each fuel type consumed, or each carbonaceous input material consumed, in tonnes of carbon per: | ||
| (i) tonne of fuel or carbonaceous input material; or (ii) cubic metre of fuel or carbonaceous input material; or (iii) kilolitre of fuel or carbonaceous input material | ||
| (h) the tonnes of pure calcium carbonate consumed (i) the tonnes of pure dolomite consumed | ||
| (j) the tonnes of pure magnesium carbonate consumed (k) the tonnes of any other pure carbonate consumed |
Part 6—Waste
Source 4A—Solid waste disposal on land
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in sections 5.4 and 5.22 | (a) the location of the landfill facility by State or Territory or by landfill classification specified in the Determination (b) the number of years in operation |
| (c) the average annual amount (in tonnes) of disposal of solid waste over the lifetime of the landfill facility prior to the first year of reporting | ||
| (d) the total tonnes of waste entering the landfill | ||
| (e) the tonnes of waste entering the landfill from each of the following: (i) municipal sources; (ii) commercial and industrial sources; (iii) construction and demolition sources; | ||
| (iv) alternative waste treatment facilities; (v) shredder flock; (vi) inert waste (f) the tonnes of waste received at the landfill facility for each of the following: (i) transfer to an external recycling or biological treatment facility; | ||
| (ii) recycling or biological treatment onsite; | ||
| (iii) construction purposes, daily cover purposes, intermediate cover purposes or final capping and cover purposes (inert waste only) | ||
| (g) the percentages of each waste mix type entering the landfill in each of the following: (i) municipal solid waste; (ii) commercial and industrial waste; (iii) construction and demolition waste; (iv) shredder flock | ||
| (h) the opening stock of degradable organic carbon, in tonnes | ||
| (i) if the total amount of scope 1 emissions from the operation of the facility during the year is more than 100 000 tonnes CO2‑e—the following matters: (i) the legacy emissions from decomposition of waste; (ii) the emissions, other than legacy emissions, from decomposition of waste; (iii) the tonnes of methane (CO2‑e) captured for combustion that are legacy emissions; (iv) the tonnes of methane (CO2‑e) captured for combustion that are not legacy emissions; (v) the tonnes of methane (CO2‑e) captured and transferred offsite that are legacy emissions; (vi) the tonnes of methane (CO2‑e) captured and transferred offsite that are not legacy emissions; (vii) the tonnes of methane (CO2‑e) flared that are legacy emissions; (viii) the tonnes of methane (CO2‑e) flared that are not legacy emissions; | ||
| (j) if the total amount of scope 1 emissions from the operation of the facility during the year is 100 000 tonnes CO2‑e or less—the following matters: (i) the emissions from decomposition of waste; (ii) the tonnes of methane (CO2‑e) captured for combustion; (iii) the tonnes of methane (CO2‑e) captured and transferred offsite; (iv) the tonnes of methane (CO2‑e) flared; | ||
| (n) the tonnes of waste treated by each of the following methods: (i) composting; (ii) anaerobic digestion | ||
| (o) the tonnes of methane (CO2‑e) captured from each of the following: (i) composting; (ii) anaerobic digestion | ||
| 2 | Methods 2, 3 and 4 for the source, as set out in sections 5.15, 5.18 and 5.22AA | (a) the location of the landfill facility by State or Territory (b) the number of years in operation (c) the average annual amount (in tonnes) of disposal of solid waste over the lifetime of the landfill facility prior to the first year of reporting |
| (d) the total tonnes of waste entering the landfill (e) the opening stock of degradable organic carbon, in tonnes | ||
| (f) the tonnes of waste entering the landfill from each of the following: (i) municipal sources; (ii) commercial and industrial sources; (iii) construction and demolition sources; (iv) alternative waste treatment facilities; (v) shredder flock; (vi) inert waste | ||
| (g) the percentages of each waste mix type entering the landfill in each of the following: (i) municipal solid waste; (ii) commercial and industrial waste; (iii) construction and demolition waste | ||
| (h) the tonnes of waste received at the landfill facility for each of the following: (i) transfer to an external recycling or biological treatment facility; (ii) recycling or biological treatment onsite; | ||
| (iii) construction purposes, daily cover purposes, intermediate cover purposes or final capping and cover purposes (inert waste only) | ||
| (i) the facility specific k value for each of the following waste mix types: (i) food; (ii) paper and cardboard; (iii) garden and green; (iv) wood; (v) textiles; (vi) sludge; (vii) nappies; (viii) rubber and leather; (ix) alternative waste treatment residues | ||
| (j) if the total amount of scope 1 emissions from the operation of the facility during the year is more than 100 000 tonnes CO2‑e—the following matters: (i) the legacy emissions from decomposition of waste; (ii) the emissions, other than legacy emissions, from decomposition of waste; (iii) the tonnes of methane (CO2‑e) captured for combustion that are legacy emissions; (iv) the tonnes of methane (CO2‑e) captured for combustion that are not legacy emissions; (v) the tonnes of methane (CO2‑e) captured and transferred offsite that are legacy emissions; (vi) the tonnes of methane (CO2‑e) captured and transferred offsite that are not legacy emissions; (vii) the tonnes of methane (CO2‑e) flared that are legacy emissions; (viii) the tonnes of methane (CO2‑e) flared that are not legacy emissions; | ||
| (k) if the total amount of scope 1 emissions from the operation of the facility during the year is 100 000 tonnes CO2‑e or less—the following matters: (i) the emissions from decomposition of waste; (ii) the tonnes of methane (CO2‑e) captured for combustion; (iii) the tonnes of methane (CO2‑e) captured and transferred offsite; (iv) the tonnes of methane (CO2‑e) flared; | ||
| (o) the tonnes of waste treated by each of the following methods: (i) composting; (ii) anaerobic digestion (p) the tonnes of methane (CO2‑e) captured from each of the following: (i) composting; (ii) anaerobic digestion |
Source 4B—Wastewater handling—industrial
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in sections 5.25 and 5.31 | (a) the tonnes of commodity produced (b) the fraction of wastewater anaerobically treated |
| (c) the fraction of COD removed as sludge | ||
| (d) the fraction of COD in sludge anaerobically treated on site (e) the tonnes of COD in sludge transferred off site and disposed of at a landfill facility | ||
| (f) the tonnes of COD in sludge transferred off site and disposed of at a site other than a landfill facility (g) the tonnes of COD in effluent leaving the site (h) the tonnes of methane (CO2‑e) captured for production of electricity on site | ||
| (i) the tonnes of methane (CO2‑e) captured and transferred off site (j) the tonnes of methane (CO2‑e) flared | ||
| 2 | Methods 2 and 3 for the source, as set out in sections 5.26, 5.30, 5.32 and 5.36 | (a) the tonnes of commodity produced (b) the tonnes of COD measured entering the treatment site (c) the fraction of wastewater anaerobically treated |
| (d) the tonnes of COD removed as sludge | ||
| (e) the fraction of COD in sludge anaerobically treated on site | ||
| (f) the tonnes of COD in sludge transferred off site and disposed of at a landfill facility (g) the tonnes of COD in sludge transferred off site and disposed of at a site other than a landfill facility | ||
| (h) the tonnes of COD in effluent leaving the site (i) the tonnes of emissions (CO2‑e) generated (j) the tonnes of methane (CO2‑e) captured for production of electricity on site | ||
| (k) the tonnes of methane (CO2‑e) captured and transferred off site (l) the tonnes of methane (CO2‑e) flared |
Source 4C—Wastewater handling—domestic or commercial
| Item | Method | Matters to be identified |
| 1 | Method 1 for the source, as set out in section 5.42 | (a) the population served by the wastewater treatment plant (b) the fraction of COD in wastewater anaerobically treated |
| (c) the tonnes of COD removed as sludge | ||
| (d) the fraction of COD in sludge anaerobically treated on site (e) the tonnes of COD in sludge transferred off site and disposed of at a landfill facility | ||
| (f) the tonnes of COD in sludge transferred off site and disposed of at a site other than a landfill facility | ||
| (g) the tonnes of methane (CO2‑e) captured for combustion on site | ||
| (h) the tonnes of methane (CO2‑e) captured and transferred off site (i) the tonnes of methane (CO2‑e) flared | ||
| (j) the tonnes of COD in effluent leaving the site (k) the tonnes of nitrogen in sludge transferred out of the plant and disposed of at a landfill facility (l) the tonnes of nitrogen in sludge transferred out of the plant and disposed of at a site other than a landfill facility | ||
| (m) the tonnes of nitrogen in effluent leaving the plant into enclosed waters (n) the tonnes of nitrogen in effluent leaving the plant into estuarine waters (o) the tonnes of nitrogen in effluent leaving the plant into open coastal waters | ||
| 2 | Methods 2 and 3 for the source, as set out in sections 5.43 and 5.47 | (a) the population served by the wastewater treatment plant (b) the tonnes of COD measured entering treatment facility (c) the fraction of COD in wastewater anaerobically treated |
| (d) the tonnes of COD removed as sludge (e) the fraction of COD in sludge anaerobically treated | ||
| (f) the tonnes of methane (CO2‑e) generated from the decomposition of COD | ||
| (g) the tonnes of methane (CO2‑e) captured for combustion on site (h) the tonnes of methane (CO2‑e) captured and transferred off site (i) the tonnes of methane (CO2‑e) flared | ||
| (j) the tonnes of COD in effluent leaving the site | ||
| (k) the tonnes of COD in sludge transferred offsite and disposed of at a landfill facility | ||
| (l) the tonnes of COD in sludge transferred offsite to a site other than a landfill facility | ||
| (m) the tonnes of nitrogen in influent entering the plant | ||
| (n) the tonnes of nitrogen in sludge transferred out of the plant and disposed of at a landfill facility | ||
| (o) the tonnes of nitrogen in sludge transferred out of the plant and disposed of at a site other than a landfill facility | ||
| (p) the tonnes of nitrogen in effluent leaving the plant into enclosed waters | ||
| (q) the tonnes of nitrogen in effluent leaving the plant into estuarine waters | ||
| (r) the tonnes of nitrogen in effluent leaving the plant into open coastal waters |
Source 4D—Waste incineration
| Item | Method | Matters to be identified |
| 1 | Methods 1 and 4 for the source, as set out in section 5.53 and Part 1.3 | the tonnes of waste incinerated |
0
0
0