National Greenhouse and Energy Reporting (Measurement) Determination 2008

This Determination is the National Greenhouse and Energy Reporting (Measurement) Determination 2008.

(1) This determination is made under section 10 of the National Greenhouse and Energy Reporting Act 2007. It provides for the measurement of the following:

(a) greenhouse gas emissions arising from the operation of facilities;

(b) the production of energy arising from the operation of facilities;

Note: Facility has the meaning given by section 9 of the Act.

(2) This determination deals with scope 1 emissions and scope 2 emissions.

Note: Scope 1 emission and scope 2 emission have the meaning given by section 10 of the Act (also see, respectively, regulations 2.23 and 2.24 of the Regulations).

(3) There are 4 categories of scope 1 emissions dealt with in this Determination.

Note: This Determination does not deal with emissions released directly from land management.

(4) The categories of scope 1 emissions are:

(a) fuel combustion, which deals with emissions released from fuel combustion (see Chapter 2); and

(b) fugitive emissions from fuels, which deals with emissions mainly released from the extraction, production, processing and distribution of fossil fuels (see Chapter 3); and

(c) industrial processes emissions, which deals with emissions released from the consumption of carbonates and the use of fuels as feedstock or as carbon reductants, and the emission of synthetic gases in particular cases (see Chapter 4); and

(d) waste emissions, which deals with emissions mainly released from the decomposition of organic material in landfill or other facilities, or wastewater handling facilities (see Chapter 5).

(5) Each of the categories has various subcategories.

1.4 Overview—methods for measurement

(1) This Determination provides methods and criteria for the measurement of the matters mentioned in subsection 1.3(1).

(2) For scope 1 emissions or scope 2 emissions:

(a) method 1 (known as the default method) is derived from the National Greenhouse Accounts methods and is based on national average estimates; and

(b) method 2 is generally a facility specific method using industry practices for sampling and Australian or equivalent standards for analysis; and

(c) method 3 is generally the same as method 2 but is based on Australian or equivalent standards for both sampling and analysis; and

(d) method 4 provides for facility specific measurement of emissions by continuous or periodic emissions monitoring.

Note: Method 4, that applies as indicated by provisions of this Determination, is as set out in Part 1.3.

1.5 Overview—energy

Chapter 6 deals with the estimation of the production and consumption of energy.

1.6 Overview—scope 2 emissions

Chapter 7 deals with scope 2 emissions.

1.7 Overview—assessment of uncertainty

Chapter 8 deals with the assessment of uncertainty.

Division 1.1.2—Definitions and interpretation

1.8 Definitions

In this Determination:

2006 IPCC Guidelines means the 2006 IPCC Guidelines for National Greenhouse Gas Inventories published by the IPCC.

ACARP Guidelines means the document entitled Guidelines for the Implementation of NGER Method 2 or 3 for Open Cut Coal Mine Fugitive GHG Emissions Reporting (C20005), published by the Australian Coal Association Research Program in December 2011.

accredited laboratory means a laboratory accredited by the National Association of Testing Authorities or an equivalent member of the International Laboratory Accreditation Cooperation in accordance with AS ISO/IEC 17025:2005, and for the production of calibration gases, accredited to ISO Guide 34:2000.

Act means the National Greenhouse and Energy Reporting Act 2007.

active gas collection means a system of wells and pipes that collect landfill gas through the use of vacuums or pumps.

alternative waste treatment activity means an activity that:

(a) accepts and processes mixed waste using:

(i) mechanical processing; and

(ii) biological or thermal processing; and

(b) extracts recyclable materials from the mixed waste.

alternative waste treatment residue means the material that remains after waste has been processed and organic rich material has been removed by physical screening or sorting by an alternative waste treatment activity that produces compost, soil conditioners or mulch in accordance with:

(a) State or Territory legislation; or

(b) Australian Standard AS 4454:2012.

ANZSIC industry classification and code means an industry classification and code for that classification published in the Australian and New Zealand Standard Industrial Classification (ANZSIC), 2006.

APHA followed by a number means a method of that number issued by the American Public Health Association and, if a date is included, of that date.

API Compendium means the document entitled Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry, published in August 2009 by the American Petroleum Institute.

Note: The API Compendium is available at www.api.org.

applicable State or Territory legislation, for an underground mine, means a law of a State or Territory in which the mine is located that relates to coal mining health and safety, including such a law that prescribes performance‑based objectives, as in force on 1 July 2008.

Note: Applicable State or Territory legislation includes:

 Coal Mine Health and Safety Act 2002 (NSW) and the Coal Mine Health and Safety Regulation 2006 (NSW)

 Coal Mining Safety and Health Act 1999 (Qld) and the Coal Mining Safety and Health Regulation 2001 (Qld).

appropriate standard, for a matter or circumstance, means an Australian standard or an equivalent international standard that is appropriate for the matter or circumstance.

appropriate unit of measurement, in relation to a fuel type, means:

(a) for solid fuels—tonnes; and

(b) for gaseous fuels—metres cubed or gigajoules, except for liquefied natural gas which is kilolitres; and

(d) for liquid fuels of one of the following kinds—tonnes:

(i) crude oil, including crude oil condensates, other natural gas liquids;

(ii) petroleum coke;

(iii) refinery gas and liquids;

(iv) refinery coke;

(v) bitumen:

(vi) waxes;

(vii) carbon black if used as petrochemical feedstock;

(viii) ethylene if used as a petrochemical feedstock;

(ix) petrochemical feedstock mentioned in item 57 of Schedule 1 to the Regulations.

AS or Australian standard followed by a number (for example, AS 4323.1—1995) means a standard of that number issued by Standards Australia Limited and, if a date is included, of that date.

ASTM followed by a number (for example, ASTM D6347/D6347M‑99) means a standard of that number issued by ASTM International and, if a date is included, of that date.

Australian legal unit of measurement has the meaning given by the National Measurement Act 1960.

base of the low gas zone means the part of the low gas zone worked out in accordance with section 3.25A.

basin means a geological basin named in the Australian Geological Provinces Database.

Note: The Australian Geological Provinces Database is available at www.ga.gov.au.

biogenic carbon fuel means energy that is:

(a) derived from plant and animal material, such as wood from forests, residues from agriculture and forestry processes and industrial, human or animal wastes; and

(b) not embedded in the earth for example, like coal oil or natural gas.

biological treatment of solid waste:

(a) means an alternative waste treatment activity consisting of a composting or anaerobic digestion process in which organic matter in solid waste is broken down by microorganisms; but

(b) does not include solid waste disposal in a landfill.

Note: Chapter 5 (waste) deals with solid waste disposal in a landfill as well as the biological treatment of solid waste (whether at a landfill or at a facility elsewhere).

blended fuel means fuel that is a blend of fossil and biogenic carbon fuels.

briquette means an agglomerate formed by compacting a particulate material in a briquette press, with or without added binder material.

calibrated to a measurement requirement, for measuring equipment, means calibrated to a specific characteristic, for example a unit of weight, with the characteristic being traceable to:

(a) a measurement requirement provided for under the National Measurement Act 1960 or any instrument under that Act for that equipment; or

(b) a measurement requirement under an equivalent standard for that characteristic.

captured for permanent storage, in relation to a greenhouse gas, has the meaning given by section 1.19A.

CEM or continuous emissions monitoring means continuous monitoring of emissions in accordance with Part 1.3.

CEN/TS followed by a number (for example, CEN/TS 15403) means a technical specification (TS) of that number issued by the European Committee for Standardization and, if a date is included, of that date.

CO2‑e means carbon dioxide equivalence.

coal seam methane has the same meaning as in the Regulations.

COD or chemical oxygen demand means the total material available for chemical oxidation (both biodegradable and non‑biodegradable) measured in tonnes.

compressed natural gas has the meaning given by the Regulations.

core sample means a cylindrical sample of the whole or part of a strata layer, or series of strata layers, obtained from drilling using a coring barrel with a diameter of between 50 mm and 2 000 mm.

crude oil condensates has the meaning given by the Regulations.

crude oil transport means the transportation of marketable crude oil to heavy oil upgraders and refineries by means that include the following:

(a) pipelines;

(b) marine tankers;

(d) rail cars.

decommissioned underground mine has the meaning given by the Regulations.

detection agent has the same meaning as in the Offshore Petroleum and Greenhouse Gas Storage Act 2006.

documentary standard means a published standard that sets out specifications and procedures designed to ensure that a material or other thing is fit for purpose and consistently performs in the way it was intended by the manufacturer of the material or thing.

domain, of an open cut mine, means an area, volume or coal seam in which the variability of gas content and the variability of gas composition in the open cut mine have a consistent relationship with other geological, geophysical or spatial parameters located in the area, volume or coal seam.

dry wood has the meaning given by the Regulations.

efficiency method has the meaning given by subsection 2.70(2).

EN followed by a number (for example, EN 15403) means a standard of that number issued by the European Committee for Standardization and, if a date is included, of that date.

enclosed composting activity means a semi‑enclosed or enclosed alternative waste or composting technology where the composting process occurs within a reactor that:

(a) has hard walls or doors on all 4 sides; and

(b) sits on a floor; and

energy content factor, for a fuel, means gigajoules of energy per unit of the fuel measured as gross calorific value.

estimator, of fugitive emissions from an open cut mine using method 2 under section 3.21 or method 3 under section 3.26, means:

(a) an individual who has the minimum qualifications of an estimator set out in the ACARP Guidelines; or

(b) individuals who jointly have those minimum qualifications.

extraction area, in relation to an open cut mine, is the area of the mine from which coal is extracted.

feedstock has the meaning given by the Regulations.

ferroalloy has the meaning given by subsection 4.69(2).

flaring means the combustion of fuel for a purpose other than producing energy.

Example: The combustion of methane for the purpose of complying with health, safety and environmental requirements.

fuel means a substance mentioned in column 2 of an item in Schedule 1 to the Regulations other than a substance mentioned in items 58 to 66.

fuel oil has the meaning given by the Regulations.

fugitive emissions has the meaning given by the Clean Energy Regulations 2011.

gas bearing strata is coal and carbonaceous rock strata:

(a) located in an open cut mine; and

(b) that has a relative density of less than 1.95 g/cm3.

gaseous fuel means a fuel mentioned in column 2 of items 17 to 30 of Schedule 1 to the Regulations.

gas stream means the flow of gas subject to monitoring under Part 1.3.

gassy mine means an underground mine that has at least 0.1% methane in the mine’s return ventilation.

Global Warming Potential means, in relation to a greenhouse gas mentioned in column 2 of an item in the table in regulation 2.02 of the Regulations, the value mentioned in column 4 for that item.

GPA followed by a number means a standard of that number issued by the Gas Processors Association and, if a date is included, of that date.

green and air dried wood has the meaning given by the Regulations.

greenhouse gas stream means a stream consisting of a mixture of any or all of the following substances captured for injection into, and captured for permanent storage in, a geological formation:

(a) carbon dioxide, whether in a gaseous or liquid state;

(b) a greenhouse gas other than carbon dioxide, whether in a gaseous or liquid state;

(c) one or more incidental greenhouse gas‑related substances, whether in a gaseous or liquid state, that relate to either or both of the greenhouse gases mentioned in paragraph (a) and (b);

(d) a detection agent, whether in a gaseous or liquid state;

so long as:

(e) the mixture consists overwhelmingly of either or both of the greenhouse gases mentioned in paragraphs (a) and (b); and

(f) if the mixture includes a detection agent—the concentration of the detection agent in the mixture is not more than the concentration prescribed in relation to the detection agent for the purposes of subparagraph (vi) of paragraph (c) of the definition of greenhouse gas substance in section 7 of the Offshore Petroleum and Greenhouse Gas Storage Act 2006.

Note: A greenhouse gas is captured for permanent storage in a geological formation if the gas is captured by, or transferred to, the holder of a licence, lease or approval mentioned in section 1.19A, under a law mentioned in that section, for the purpose of being injected into a geological formation (however described) under the licence, lease or approval.

GST group has the same meaning as in the Fuel Tax Act 2006.

GST joint venture has the same meaning as in the Fuel Tax Act 2006.

GWPmethane means the Global Warming Potential of methane.

higher method has the meaning given by subsection 1.18(5).

hydrofluorocarbons has the meaning given by section 4.99.

ideal gas law means the state of a hypothetical ideal gas in which the amount of gas is determined by its pressure, volume and temperature.

IEC followed by a number (for example, IEC 17025:2005) means a standard of that number issued by the International Electrotechnical Commission and, if a date is included, of that date.

incidental, for an emission, has the meaning given by subregulation 4.27(5) of the Regulations.

incidental greenhouse gas‑related substance, in relation to a greenhouse gas that is captured from a particular source material, means:

(a) any substance that is incidentally derived from the source material; or

(b) any substance that is incidentally derived from the capture; or

(c) if the captured greenhouse gas, whether in a pure form or in a mixture with other substances, is transported—any substance that is incidentally derived from the transportation; or

(d) if the captured greenhouse gas, whether in a pure form or in a mixture with other substances, is injected into a part of a geological formation—any substance that is incidentally derived from the injection; or

(e) if the captured greenhouse gas, whether in a pure form or in a mixture with other substances, is stored in a part of a geological formation—any substance that is incidentally derived from the storage.

independent expert, in relation to an operator of a landfill, means a person who:

(a) is independent of the operator of the landfill; and

(b) has relevant expertise in estimating or monitoring landfill surface gas.

inert waste means waste materials that contain no more than a negligible volume of degradable organic carbon and includes the following waste:

(a) concrete;

(b) metal;

(d) glass;

(e) asbestos concrete;

(f) soil.

integrated metalworks has the meaning given by subsection 4.64(2).

invoice includes delivery record.

IPCC is short for Intergovernmental Panel on Climate Change established by the World Meteorological Organization and the United Nations Environment Programme.

ISO followed by a number (for example, ISO 10396:2007) means a standard of that number issued by the International Organization of Standardization and, if a date is included, of that date.

legacy emissions has the same meaning as in the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015.

legacy waste means waste deposited at a landfill before 1 July 2016.

liquefied natural gas has the same meaning as in the Regulations.

liquefied petroleum gas has the same meaning as in the Regulations.

liquid fuel means a fuel mentioned in column 2 of items 31 to 54 of Schedule 1 to the Regulations.

lower method has the meaning given by subsection 1.18(6).

low gas zone means the part of the gas bearing strata of an open cut mine:

(a) that is located immediately below the original surface of the mine and above the base of the low gas zone; and

(b) the area of which is worked out by working out the base of the low gas zone.

main electricity grid has the meaning given by subsection 7.2(4).

marketable crude oil includes:

(a) conventional crude oil; and

(b) heavy crude oil; and

(d) bitumen.

method means a method specified in this determination for estimating emissions released from the operation of a facility in relation to a source.

municipal materials has the meaning given by the Regulations.

municipal solid waste class I means waste from domestic premises, council collections and other municipal sources where:

(a) the collection of organic waste on a regular basis in a dedicated bin is not provided to residents of the municipality as a standard practice; or

(b) the collection of organic waste on a regular basis in a dedicated bin provided to residents of the municipality cannot be confirmed as standard practice.

municipal solid waste class II means waste from domestic premises, council collections and other municipal sources where a bin dedicated for garden waste is:

(a) provided to residents of the municipality as a standard practice; and

(b) collected on a regular basis.

N/A means not available.

National Greenhouse Accounts means the set of national greenhouse gas inventories, including the National Inventory Report 2005, submitted by the Australian government to meet its reporting commitments under the United Nations Framework Convention on Climate Change and the 1997 Kyoto Protocol to that Convention.

natural gas has the meaning given by the Regulations.

natural gas distribution is distribution of natural gas through low‑pressure pipelines with pressure of 1 050 kilopascals or less.

natural gas gathering and boosting means the activity to collect unprocessed natural gas or coal seam methane from gas wellheads and to compress, dehydrate, sweeten, or transport the gas through natural gas gathering and boosting pipelines to a natural gas processing station, a natural gas transmission pipeline or a natural gas distribution pipeline.

natural gas gathering and boosting pipeline means a pipeline for the conveyance of gas that:

(a) contains unprocessed natural gas or coal seam methane; and

(b) pertains to the activity of natural gas gathering and boosting.

Note: Such pipelines can operates at high or low pressures

natural gas gathering and boosting station means one or more pieces of plant and equipment used in natural gas gathering and boosting at a single location that operates as a unit in the natural gas gathering and boosting activity. The plant and equipment may include any of the following:

(a) compressors;

(b) generators;

(d) storage vessels;

(e) acid gas removal units;

(f) engines;

(g) boilers;

(h) heaters;

(i) flares;

(j) separation and processing equipment;

(k) associated storage or measurement vessels;

(l) equipment on, or associated with, an enhanced oil recovery well pad using CO2 or gas injection.

Note: The single location that operates as a unit will generally be known as a facility, station or node for operational purposes. It is not expected that stations will be defined differently for operational purposes and emissions accounting purposes.

natural gas processing station means the plant and equipment used in the natural gas processing in a single location, and includes:

(a) liquids recovery plant and equipment where the separation of natural gas liquids or non-methane gases from unprocessed natural gas or coal seam methane occurs; and

(b) liquids recovery plant and equipment where the separation of natural gas liquids into one or more component mixtures occur; and

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 unprocessed natural gas and coal seam methane streams.

natural gas liquids has the meaning given by the Regulations.

natural gas processing station means the plant and equipment used in the natural gas processing in a single location, and includes:

(a) liquids recovery plant and equipment where the separation of natural gas liquids or non-methane gases from unprocessed natural gas or coal seam methane occurs; and

(b) liquids recovery plant and equipment where the separation of natural gas liquids into one or more component mixtures occur; and

natural gas transmission is transmission of natural gas through high‑pressure pipelines with pressure greater than 1 050 kilopascals.

non‑gassy mine means an underground mine that has less than 0.1% methane in the mine’s return ventilation.

non‑legacy waste means waste deposited at a landfill on or after 1 July 2016.

open cut mine:

(a) means a mine in which the overburden is removed from coal seams to allow coal extraction by mining that is not underground mining; and

(b) for method 2 in section 3.21 or method 3 in section 3.26—includes a mine of the kind mentioned in paragraph (a):

(i) for which an area has been established but coal production has not commenced; or

(ii) in which coal production has commenced.

PEM or periodic emissions monitoring means periodic monitoring of emissions in accordance with Part 1.3.

Perfluorocarbon protocol means the Protocol for Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6) Emissions from Primary Aluminium Production published by the United States Environmental Protection Agency and the International Aluminium Institute.

petroleum based greases has the meaning given by regulation 1.03 of the Regulations.

petroleum based oils has the meaning given by the Regulations.

petroleum coke has the meaning given by the Regulations.

phytocap means an evapotranspiration landfill capping system that makes use of soil and vegetation to store and release surface water.

post‑mining activities, in relation to a mine, is the handling, stockpiling, processing and transportation of coal extracted from the mine.

primary wastewater treatment plant:

(a) means a treatment facility at which wastewater undergoes physical screening, degritting and sedimentation; and

(b) does not include a treatment facility at which any kind of nitrification or denitrification treatment process occurs.

principal activity, in relation to a facility, means the activity that:

(a) results in the production of a product or service that is produced for sale on the market; and

(b) produces the most value for the facility out of any of the activities forming part of the facility.

produced water means the water that is either:

(a) pumped from coal seams or unprocessed gas reservoirs during natural gas production or natural gas gathering and boosting; or

(b) pumped from wells during crude oil production or oil and gas exploration and development.

pyrolysis of coal means the decomposition of coal by heat.

raw sugar has the meaning given by Chapter 17 of Section IV of Schedule 3 to the Customs Tariff Act 1995.

reductant:

(a) means a reducing agent or substance:

(i) that causes another substance to undergo reduction; and

(ii) that is oxidised while causing the substance to undergo reduction; and

(b) does not include fuels that are combusted only to produce energy.

refinery gases and liquids has the meaning given by the Regulations.

Regulations means the National Greenhouse and Energy Reporting Regulations 2008.

relevant person means a person mentioned in paragraph 1.19A(a), (b), (c), (d), (e) or (f).

run‑of‑mine coal means coal that is produced by mining operations before screening, crushing or preparation of the coal has occurred.

scope 1 emissions has the same meaning as in the Regulations.

scope 2 emissions has the same meaning as in the Regulations.

separate instance of a source has the meaning given by section 1.9A.

separate occurrence of a source has the meaning given by section 1.9B.

shale gas means a substance that:

(a) consists of:

(i) naturally occurring hydrocarbons; or

(ii) a naturally occurring mixture of hydrocarbons and non‑hydrocarbons; and

(b) consists mainly of methane; and

shredder flock means the residual waste generated from the process of scrap metal processing that ends up in landfill.

sludge biogas has the meaning given by the Regulations.

sludge lagoon means a component of a wastewater treatment system that:

(a) is used to stabilise and dry excess or wasted sludge from the liquid or solid phase treatment train of a wastewater treatment plant; and

(b) involves biodegradation of COD in the form of sludge and the use of ambient climatic factors to reduce the moisture content of the sludge.

solid fuel means a fuel mentioned in column 2 of items 1 to 16 of Schedule 1 to the Regulations.

source has the meaning given by section 1.10.

specified taxable fuel has the meaning given by regulation 3.30 of the Clean Energy Regulations 2011.

standard includes a protocol, technical specification or USEPA method.

standard conditions has the meaning given by subsection 2.32(7).

sulphite lyes has the meaning given by the Regulations.

supply means supply by way of sale, exchange or gift.

synthetic gas generating activities has the meaning given by subsections 4.100(1) and (2).

technical guidelines means the document published by the Department and known as the National Greenhouse Energy and Reporting (Measurement) Technical Guidelines 2009.

tight gas means a substance that:

(a) consists of:

(i) naturally occurring hydrocarbons; or

(ii) a naturally occurring mixture of hydrocarbons and non‑hydrocarbons; and

(b) consists mainly of methane; and

uncertainty protocol means the publication known as the GHG protocol guidance on uncertainty assessment in GHG inventories and calculating statistical parameter uncertainty (September 2003) v1.0 issued by the World Resources Institute and the World Business Council for Sustainable Development.

underground mine means a coal mine that allows extraction of coal by mining at depth, after entry by shaft, adit or drift, without the removal of overburden.

USEPA followed by a reference to a method (for example, Method 3C) means a standard of that description issued by the United States Environmental Protection Agency.

waxes has the meaning given by the Regulations.

well completion means the period that:

(a) begins on the initial gas flow in the well; and

(b) ends on whichever of the following occurs first:

(i) well shut in; or

(ii) continuous gas flow from the well to a flow line or a storage vessel for collection.

well workover means the period that:

(a) begins on the initial gas flow in the well that follows remedial operations to increase the well’s production; and

(b) ends on whichever of the following occurs first:

(i) well shut in; or

(ii) continuous gas flow from the well to a flow line or a storage vessel for collection.

year means a financial year.

Note: The following expressions in this Determination are defined in the Act:

 carbon dioxide equivalence

 consumption of energy (see also regulation 2.26 of the Regulations)

 energy

 facility

 greenhouse gas

 group

 industry sector

 operational control

 potential greenhouse gas emissions

 production of energy (see also regulation 2.25 of the Regulations)

 registered corporation

 scope 1 emission (see also regulation 2.23 of the Regulations)

 scope 2 emission (see also regulation 2.24 of the Regulations).

1.9 Interpretation

(1) In this Determination, a reference to emissions is a reference to emissions of greenhouse gases.

(2) In this Determination, a reference to a gas type (j) is a reference to a greenhouse gas.

(3) In this Determination, a reference to a facility that is constituted by an activity is a reference to the facility being constituted in whole or in part by the activity.

Note: Section 9 of the Act defines a facility as an activity or series of activities.

(4) In this Determination, a reference to a standard, instrument or other writing (other than a Commonwealth Act or Regulations) however described, is a reference to that standard, instrument or other writing as in force on 1 July 2014.

1.9A Meaning of separate instance of a source

If 2 or more different activities of a facility have the same source of emissions, each activity is taken to be a separate instance of the source if the activity is performed by a class of equipment different from that used by another activity.

Example: The combustion of liquefied petroleum gas in the engines of distribution vehicles of the facility operator and the combustion of liquid petroleum fuel in lawn mowers at the facility, although the activities have the same source of emissions, are taken to be a separate instance of the source as the activities are different and the class of equipment used to perform the activities are different.

1.9B Meaning of separate occurrence of a source

(1) If 2 or more things at a facility have the same source of emissions, each thing may be treated as a separate occurrence of the source.

Example: The combustion of unprocessed natural gas in 2 or more gas flares at a facility may be treated as a separate occurrence of the source (natural gas production or processing—flaring).

(2) If a thing at a facility uses 2 or more energy types, each energy type may be treated as a separate occurrence of the source.

Example: The combustion of diesel and petrol in a vehicle at a facility may be treated as a separate occurrence of the source (fuel combustion).

1.10 Meaning of source

(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
2E		Crude oil production
2F		Crude oil transport
2G		Crude oil refining
2H		Natural gas production or processing (other than emissions that are vented or flared)
2I		Natural gas transmission
2J		Natural gas distribution
2K		Natural gas production or processing—flaring
2L		Natural gas production or processing—venting
2M		Carbon capture and storage
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
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
3P		Sodium cyanide production
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

(2) The extent of the source is as provided for in this Determination.

Part 1.2—General

1.11 Purpose of Part

This Part provides for general matters as follows:

(a) Division 1.2.1 provides for the measurement of emissions and energy and also deals with standards;

(b) Division 1.2.2 provides for methods for measuring emissions;

Division 1.2.1—Measurement and standards

1.12 Measurement of emissions and energy

(1) The measurement of emissions released from the operation of a facility is to be done by estimating the emissions in accordance with this Determination.

(2) The measurement of the production and consumption of energy from the operation of a facility is to be done by estimating the production and consumption of energy in accordance with this Determination.

1.13 General principles for measuring emissions and energy

Estimates for this Determination must be prepared in accordance with the following principles:

(a) transparency—emission and energy estimates must be documented and verifiable;

(b) comparability—emission and energy estimates using a particular method and produced by a registered corporation or registered person in an industry sector must be comparable with emission and energy estimates produced by similar corporations or persons in that industry sector using the same method and consistent with the emission and energy estimates published by the Department in the National Greenhouse Accounts;

(c) accuracy—having regard to the availability of reasonable resources by a registered corporation or registered person and the requirements of this Determination, uncertainties in emission and energy estimates must be minimised and any estimates must neither be over nor under estimates of the true values at a 95% confidence level;

(d) completeness—all identifiable emission sources mentioned in section 1.10 must be accounted for and production and consumption of all identifiable fuels and energy commodities listed in Schedule 1 of the Regulations must be accounted for, subject to any applicable reporting thresholds.

1.14 Assessment of uncertainty

The estimate of emissions released from the operation of a facility must include assessment of uncertainty in accordance with Chapter 8.

1.15 Units of measurement

(1) For this Determination, measurements of fuel must be converted as follows:

(a) for solid fuel, to tonnes; and

(b) for liquid fuels, to kilolitres unless otherwise specified; and

(2) For this Determination, emissions of greenhouses gases must be estimated in CO2‑e tonnes.

(3) Measurements of energy content must be converted to gigajoules.

(4) The National Measurement Act 1960, and any instrument made under that Act, must be used for conversions required under this section.

1.16 Rounding of amounts

(1) If:

(a) an amount is worked out under this Determination; and

(b) the number is not a whole number;

then:

(c) the number is to be rounded up to the next whole number if the number at the first decimal place equals or exceeds 5; and

(d) rounded down to the next whole number if the number at the first decimal place is less than 5.

(2) Subsection (1) applies to amounts that are measures of emissions or energy.

1.17 Status of standards

If there is an inconsistency between this Determination and a documentary standard, this Determination prevails to the extent of the inconsistency.

Division 1.2.2—Methods

1.18 Method to be used for a separate occurrence of a source

(1) This section deals with the number of methods that may be used to estimate emissions of a particular greenhouse gas released, in relation to a separate occurrence of a source, from the operation of a facility.

(1A) Subsections (2) and (3) do not apply to a facility if:

(a) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611) and the generating unit used to perform the principal activity:

(i) does not have the capacity to generate, in a reporting year, the amount of electricity mentioned in subparagraph 2.3(3)(b)(i); and

(ii) generates, in a reporting year, less than or equal to the amount of electricity mentioned in subparagraph 2.3(3)(b)(ii); or

(b) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611) and the generating unit used to perform the principal activity:

(i) does not have the capacity to generate, in a reporting year, the amount of electricity mentioned in subparagraph 2.19(3)(b)(i); and

(ii) generates, in a reporting year, less than or equal to the amount of electricity mentioned in subparagraph 2.19(3)(b)(ii).

(2) Subject to subsection (3) and (3A), one method for the separate occurrence of a source must be used for 4 reporting years unless another higher method is used.

(3) If:

(a) at a particular time, a method is being used to estimate emissions in relation to the separate occurrence of a source; and

(b) either:

(i) in the preceding 4 reporting years before that time, only that method has been used to estimate the emissions from the separate occurrence of the source; or

(ii) a registered corporation or registered person certifies in writing that the method used was found to be non‑compliant during an external audit of the separate occurrence of the source;

then a lower method may be used to estimate emissions in relation to the separate occurrence of the source from that time.

(3A) If section 22AA of the Act applies to a person, a lower method may be used to estimate emissions in relation to the source for the purposes of reporting under section 22AA.

(4) In this section, reporting year, in relation to a source from the operation of a facility under the operational control of a registered corporation and entities that are members of the corporation’s group, means a year that the registered corporation is required to provide a report under section 19 of the Act in relation to the facility

(5) Higher method, is:

(a) a prescribed alternative method; or

(b) in relation to a method (the original method) being used to estimate emissions in relation to a separate occurrence of a source, a method for the source with a higher number than the number of the original method.

(6) Lower method, is:

(a) a default method; or

(b) in relation to a method (the original method) being used to estimate emissions in relation to a separate occurrence of a source, a method for the source with a lower number than the number of the original method.

1.18A Conditions—persons preparing report must use same method

(1) This section applies if a person is required, under section 19, 22A, 22AA, 22E, 22G or 22X of the Act (a reporting provision), to provide a report to the Regulator for a reporting year or part of a reporting year (the reporting period).

(2) For paragraph 10(3)(c) of the Act:

(a) the person must, before 31 August in the year immediately following the reporting year, notify any other person required, under a reporting provision, to provide a report to the Regulator for the same facility of the method the person will use in the report; and

(b) each person required to provide a report to the Regulator for the same facility and for the same reporting period must, before 31 October in the year immediately following the reporting year, take all reasonable steps to agree on a method to be used for each report provided to the Regulator for the facility and for the reporting period.

(3) If the persons mentioned in paragraph (2)(b) do not agree on a method before 31 October in the year immediately following the reporting year, each report provided to the Regulator for the facility and for the reporting period must use the method:

(a) that was used in a report provided to the Regulator for the facility for the previous reporting year (if any); and

(b) that will, of all the methods used in a report provided to the Regulator for the facility for the previous reporting year, result in a measurement of the largest amount of emissions for the facility for the reporting year.

(4) In this section, a reference to a method is a reference to a method or available alternative method, including the options (if any) included in the method or available alternative method.

Note 1: Reporting year has the meaning given by the Regulations.

Note 2: An example of available alternative methods is method 2 in section 2.5 and method 2 in section 2.6.

Note 3: An example of options included within a method is paragraphs 3.36(a) and (b), which provide 2 options of ways to measure the size of mine void volume.

Note 4: An example of options included within an available alternative method is the options for identifying the value of the oxidation factor (OFs) in subsection 2.5(3).

1.19 Temporary unavailability of method

(1) The procedure set out in this section applies if, during a reporting year, a method for a separate occurrence of a source cannot be used because of a mechanical or technical failure of equipment or a failure of measurement systems during a period (the down time).

(2) For each day or part of a day during the down time, the estimation of emissions from the separate occurrence of a source must be consistent with the principles in section 1.13.

(3) Subsection (2) only applies for a maximum of 6 weeks in a year. This period does not include down time taken for the calibration of the equipment.

(4) If down time is more than 6 weeks in a year, the registered corporation or registered person must inform the Regulator, in writing, of the following:

(a) the reason why down time is more than 6 weeks;

(b) how the corporation or person plans to minimise down time;

(5) The information mentioned in subsection (4) must be given to the Regulator within 6 weeks after the day when down time exceeds 6 weeks in a year.

(6) The Regulator may require a registered corporation or registered person to use method 1 to estimate emissions during the down time if:

(a) method 2, 3 or 4 has been used to estimate emissions for the separate occurrence of a source; and

(b) down time is more than 6 weeks in a year.

Division 1.2.3—Requirements in relation to carbon capture and storage

1.19A Meaning of captured for permanent storage

For this Determination, a greenhouse gas is captured for permanent storage only if it is captured by, or transferred to:

(a) the registered holder of a greenhouse gas injection licence under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 for the purpose of being injected into an identified greenhouse gas storage formation under the licence in accordance with that Act; or

(b) the holder of an injection and monitoring licence under the Greenhouse Gas Geological Sequestration Act 2008 (Vic) for the purpose of being injected into an underground geological formation under the licence in accordance with that Act; or

(c) the registered holder of a greenhouse gas injection licence under the Offshore Petroleum and Greenhouse Gas Storage Act 2010 (Vic) for the purpose of being injected into an identified greenhouse gas storage formation under the licence in accordance with that Act; or

(d) the holder of a GHG injection and storage lease under the Greenhouse Gas Storage Act 2009 (Qld) for the purpose of being injected into a GHG stream storage site under the lease in accordance with that Act; or

(e) the holder of an approval under the Barrow Island Act 2003 (WA) for the purpose of being injected into an underground reservoir or other subsurface formation in accordance with that Act; or

(f) the holder of a gas storage licence under the Petroleum and Geothermal Energy Act 2000 (SA) for the purpose of being injected into a natural reservoir under the licence in accordance with that Act.

1.19B Deducting greenhouse gas that is captured for permanent storage

(1) If a provision of this Determination provides that an amount of a greenhouse gas that is captured for permanent storage may be deducted in the estimation of emissions under the provision, then the amount of the greenhouse gas may be deducted only if:

(a) the greenhouse gas that is captured for permanent storage is captured by, or transferred to, a relevant person; and

(b) the amount of the greenhouse gas that is captured for permanent storage is estimated in accordance with section 1.19E; and

(2) The certificate must specify:

(a) if the greenhouse gas is captured by the relevant person and is neither transferred to the relevant person nor transferred by the relevant person to another person—the following information:

(i) the amount of the greenhouse gas, measured in CO2‑e tonnes, captured by the relevant person;

(ii) the volume of the greenhouse gas stream containing the captured greenhouse gas;

(iii) the concentration of the greenhouse gas in the stream; or

(b) if the greenhouse gas is transferred to the relevant person—the following information:

(i) the amount of the greenhouse gas, measured in CO2‑e tonnes, that was transferred to the relevant person;

(ii) the volume of the greenhouse gas stream containing the transferred greenhouse gas;

(iii) the concentration of the greenhouse gas in the stream.

(3) The amount of the greenhouse gas that may be deducted is the amount specified in the certificate under paragraph (1)(c).

1.19C Capture from facility with multiple sources jointly generated

If, during the operation of a facility, more than 1 source generates a greenhouse gas, the total amount of the greenhouse gas that may be deducted in relation to the facility is to be attributed:

(a) if it is possible to determine the amount of the greenhouse gas that is captured for permanent storage from each source—to each source from which the greenhouse gas is captured according to the amount captured from the source; or

(b) if it is not possible to determine the amount of the greenhouse gas captured for permanent storage from each source—to the main source that generated the greenhouse gas that is captured during the operation of the facility.

1.19D Capture from a source where multiple fuels consumed

If more than 1 fuel is consumed for a source that generates a greenhouse gas that is captured for permanent storage, the total amount of the greenhouse gas that may be deducted in relation to the source is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed for that source.

1.19E Measure of quantity of captured greenhouse gas

(1) For paragraph 1.19B(1)(b), the amount of a greenhouse gas that is captured must be estimated in accordance with this section.

(2) The volume of the greenhouse gas stream containing the captured greenhouse gas must be estimated:

(a) if the greenhouse gas stream is transferred to a relevant person—using:

(i) criterion A in section 1.19F; or

(ii) criterion AAA in section 1.19G; or

(b) if the greenhouse gas stream is captured by the relevant person and is neither transferred to the relevant person nor transferred by the relevant person to another person—using:

(i) criterion AAA in section 1.19G; or

(ii) criterion BBB in section 1.19GA.

(3) The greenhouse gas stream must be sampled in accordance with ISO 10715:1997, or an equivalent standard.

(4) The concentration of the greenhouse gas in the greenhouse gas stream must be analysed in accordance with the following parts of ISO 6974 or an equivalent standard:

(a) Part 1 (2000);

(b) Part 2 (2001);

(d) Part 4 (2000);

(e) Part 5 (2000);

(f) Part 6 (2002).

(5) The volume of the greenhouse gas stream must be expressed in cubic metres.

(6) The greenhouse gas stream must be analysed for the concentration of the greenhouse gas on at least a monthly basis.

1.19F Volume of greenhouse gas stream—criterion A

(1) For subparagraph 1.19E(2)(a)(i), criterion A is the volume of the greenhouse gas stream that is:

(a) transferred to the relevant person during the year; and

(b) specified in a certificate issued by the relevant person under paragraph 1.19B(1)(c).

(2) The volume specified in the certificate must be accurate and must be evidenced by invoices issued by the relevant person.

1.19G Volume of greenhouse gas stream—criterion AAA

(1) For subparagraphs 1.19E(2)(a)(ii) and (b)(i), criterion AAA is the measurement during the year of the captured greenhouse gas stream from the operation of a facility at the point of capture.

(2) In measuring the quantity of the greenhouse gas stream at the point of capture, the quantity of the greenhouse gas stream must be measured:

(a) using volumetric measurement in accordance with:

(i) for a compressed greenhouse gas stream—section 1.19H; and

(ii) for a super‑compressed greenhouse gas stream—section 1.19I; and

(b) using gas measuring equipment that complies with section 1.19J.

(3) The measurement must be carried out using measuring equipment that:

(a) is in a category specified in column 2 of an item in the table in subsection (4) according to the maximum daily quantity of the greenhouse gas stream captured specified in column 3 for that item from the operation of the facility; and

(b) complies with the transmitter and accuracy requirements for that equipment specified in column 4 for that item, if the requirements are applicable to the measuring equipment being used.

(4) For subsection (3), the table is as follows.

Item	Gas measuring equipment category	Maximum daily quantity of greenhouse gas stream (cubic metres/day)	Transmitter and accuracy requirements (% of range)
1	1	0–50 000	Pressure <±0.25% Diff. pressure <±0.25% Temperature <±0.50%
2	2	50 001–100 000	Pressure <±0.25% Diff. pressure <±0.25% Temperature <±0.50%
3	3	100 001–500 000	Smart transmitters: Pressure <±0.10% Diff. pressure <±0.10% Temperature <±0.25%
4	4	500 001 or more	Smart transmitters: Pressure <±0.10% Diff. pressure <±0.10% Temperature <±0.25%

1.19GA Volume of greenhouse gas stream—criterion BBB

For subparagraph 1.19E(2)(b)(ii), criterion BBB is the estimation of the volume of the captured greenhouse gas stream from the operation of the facility during a year measured in accordance with industry practice, if the equipment used to measure the volume of the captured greenhouse gas stream does not meet the requirements of criterion AAA.

Note: An estimate obtained using industry practice must be considered with the principles in section 1.13.

1.19H Volumetric measurement—compressed greenhouse gas stream

(1) For subparagraph 1.19G(2)(a)(i), volumetric measurement of a compressed greenhouse gas stream must be in cubic metres at standard conditions.

(1A) For this section and subparagraph 1.19G(2)(a)(i), a compressed greenhouse gas stream does not include either of the following:

(a) a super‑compressed greenhouse gas stream;

(b) a greenhouse gas stream that is compressed to a super‑critical state.

(2) The volumetric measurement is to be calculated using a flow computer that measures and analyses flow signals and relative density:

(a) if the greenhouse gas stream is captured by the relevant person and is neither transferred to the relevant person nor transferred by the relevant person to another person—at the point of capture of the greenhouse gas stream; or

(b) if the greenhouse gas stream is transferred to a relevant person—at the point of transfer of the greenhouse gas stream.

(3) The volumetric flow rate must be continuously recorded and integrated using an integration device that is isolated from the flow computer in such a way that if the computer fails, the integration device will retain the last reading, or the previously stored information, that was on the computer immediately before the failure.

(4) Subject to subsection (5), all measurements, calculations and procedures used in determining volume (except for any correction for deviation from the ideal gas law) must be made in accordance with the instructions contained in the following:

(a) for orifice plate measuring systems:

(i) the publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: Natural Gas Applications, published by the American Gas Association in August 1992; or

(ii) Parts 1 to 4 of the publication entitled ANSI/API MPMS Chapter 14.3 Part 2 (R2011) Natural Gas Fluids Measurement: Concentric, Square‑Edged Orifice Meters ‑ Part 2: Specification and Installation Requirements, 4th edition, published by the American Petroleum Institute on 30 April 2000;

(b) for turbine measuring systems—the publication entitled AGA Report No. 7, Measurement of Natural Gas by Turbine Meter (2006), published by the American Gas Association on 1 January 2006;

(c) for positive displacement measuring systems—the publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000.

(5) Measurements, calculations and procedures used in determining volume may also be made in accordance with an equivalent internationally recognised documentary standard or code.

(6) Measurements must comply with Australian legal units of measurement.

1.19I Volumetric measurement—super‑compressed greenhouse gas stream

(1) For subparagraph 1.19G(2)(a)(ii), volumetric measurement of a super‑compressed greenhouse gas stream must be in accordance with this section.

(2) If, in determining volume in relation to the super‑compressed greenhouse gas stream, it is necessary to correct for deviation from the ideal gas law, the correction must be determined using the relevant method contained in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994.

(3) The measuring equipment used must calculate super‑compressibility by:

(a) if the measuring equipment is category 3 or 4 equipment in accordance with column 2 the table in subsection 1.19G(4)—using composition data; or

(b) if the measuring equipment is category 1 or 2 equipment in accordance with column 2 of the table in subsection 1.19G(4)—using an alternative method set out in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994.

1.19J Gas measuring equipment—requirements

For paragraph 1.19G(2)(b), gas measuring equipment that is category 3 or 4 equipment in accordance with column 2 of the table in subsection 1.19G(4) must comply with the following requirements:

(a) if the equipment uses flow devices—the requirements relating to flow devices set out in section 1.19K;

(b) if the equipment uses flow computers—the requirement relating to flow computers set out in section 1.19L;

1.19K Flow devices—requirements

(1) If the measuring equipment has flow devices that use orifice measuring systems, the flow devices must be constructed in a manner that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%.

Note: The publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: Natural Gas Applications, published by the American Gas Association in August 1992, sets out a manner that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%.

(2) If the measuring equipment has flow devices that use turbine measuring systems, the flow devices must be installed in a manner that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%.

Note: The publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994, sets out a manner that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%.

(3) If the measuring equipment has flow devices that use positive displacement measuring systems, the flow devices must be installed in a manner that ensures that the maximum uncertainty of flow is ±1.5%.

Note: The publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000, sets out a manner for installation that ensures that the maximum uncertainty of flow is ±1.5%.

(4) If the measuring equipment uses any other type of flow device, the maximum uncertainty of flow measurement must not be greater than ±1.5%.

(5) All flow devices that are used by measuring equipment of a category specified in column 2 of the table in subsection 1.19G(4) must, wherever possible, be calibrated for pressure, differential pressure and temperature in accordance with the requirements specified in column 4 for the category of equipment specified in column 2 for that item. The calibrations must take into account the effects of static pressure and ambient temperature.

1.19L Flow computers—requirements

For paragraph 1.19J(b), the requirement is that the flow computer that is used by the equipment for measuring purposes must record the instantaneous values for all primary measurement inputs and must also record the following outputs:

(a) instantaneous corrected volumetric flow;

(b) cumulative corrected volumetric flow;

(d) for turbine and positive displacement metering systems—cumulative uncorrected volumetric flow;

(e) super‑compressibility factor.

1.19M Gas chromatographs

For paragraph 1.19J(c), the requirements are that gas chromatographs used by the measuring equipment must:

(a) be factory tested and calibrated using a measurement standard produced by gravimetric methods and traceable to Australian legal units of measurement; and

(b) perform gas composition analysis with an accuracy of ±0.25% for calculation of relative density; and

Part 1.3—Method 4—Direct measurement of emissions

Division 1.3.1—Preliminary

1.20 Overview

(1) This Chapter provides for method 4 for a source.

Note: Method 4 as provided for in this Part applies to a source as indicated in the Chapter, Part, Division or Subdivision dealing with the source.

(2) Method 4 requires the direct measurement of emissions released from the source from the operation of a facility during a year by monitoring the gas stream at a site within part of the area (for example, a duct or stack) occupied for the operation of the facility.

(3) Method 4 consists of the following:

(a) method 4 (CEM) as specified in section 1.21 that requires the measurement of emissions using continuous emissions monitoring (CEM);

(b) method 4 (PEM) as specified in section 1.27 that requires the measurement of emissions using periodic emissions monitoring (PEM).

Division 1.3.2—Operation of method 4 (CEM)

Subdivision 1.3.2.1—Method 4 (CEM)

1.21 Method 4 (CEM)—estimation of emissions

(1) To obtain an estimate of the mass of emissions of a gas type (j), being methane, carbon dioxide or nitrous oxide, released at the time of measurement at a monitoring site within the area occupied for the operation of a facility, the following formula must be applied:

where:

Mjct is the mass of emissions in tonnes of gas type (j) released per second.

MMj is the molecular mass of gas type (j) measured in tonnes per kilomole which:

(a) for methane is 16.0410‑3; or

(b) for carbon dioxide is 44.0110‑3; or

Pct is the pressure of the gas stream in kilopascals at the time of measurement.

FRct is the flow rate of the gas stream in cubic metres per second at the time of measurement.

Cjct is the proportion of gas type (j) in the volume of the gas stream at the time of measurement.

Tct is the temperature, in degrees kelvin, of the gas at the time of measurement.

(2) The mass of emissions estimated under subsection (1) must be converted into CO2‑e tonnes.

(3) Data on estimates of the mass emissions rates obtained under subsection (1) during an hour must be converted into a representative and unbiased estimate of mass emissions for that hour.

(4) The estimate of emissions of gas type (j) during a year is the sum of the estimates for each hour of the year worked out under subsection (3).

(5) If method 1 is available for the source, the total mass of emissions for a gas from the source for the year calculated under this section must be reconciled against an estimate for that gas from the facility for the same period calculated using method 1 for that source.

1.21A Emissions from a source where multiple fuels consumed

If more than one fuel is consumed for a source that generates carbon dioxide that is directly measured using method 4 (CEM), the total amount of carbon dioxide is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed for that source.

Subdivision 1.3.2.2—Method 4 (CEM)—use of equipment

1.22 Overview

The following apply to the use of equipment for CEM:

(a) the requirements in section 1.23 about location of the sampling positions for the CEM equipment;

(b) the requirements in section 1.24 about measurement of volumetric flow rates in the gas stream;

(d) the requirements in section 1.26 about frequency of measurement.

1.23 Selection of sampling positions for CEM equipment

For paragraph 1.22(a), the location of sampling positions for the CEM equipment in relation to the gas stream must be selected in accordance with an appropriate standard.

Note: Appropriate standards include:

AS 4323.1—1995 Stationary source emissions ‑ Selection of sampling positions.
AS 4323[1].1—1995 Amdt 1‑1995 Stationary source emissions ‑ Selection of sampling positions.
ISO 10396:2007 Stationary source emissions ‑ Sampling for the automated determination of gas emission concentrations for permanently‑installed monitoring systems.
ISO 10012:2003 Measurement management systems ‑ Requirements for measurement processes and measuring equipment.
USEPA – Method 1 – Sample and Velocity Traverses for Stationary Sources (2000).

1.24 Measurement of flow rates by CEM

For paragraph 1.22(b), the measurement of the volumetric flow rates by CEM of the gas stream must be undertaken in accordance with an appropriate standard.

Note: Appropriate standards include:

ISO 10780:1994 Stationary source emissions—Measurement of velocity and volume flowrate of gas streams in ducts.
ISO 14164:1999 Stationary source emissions—Determination of the volume flowrate of gas streams in ducts ‑ Automated method.
USEPA Method 2 Determination of Stack Gas Velocity and Volumetric flowrate (Type S Pitot tube) (2000).
USEPA Method 2A Direct Measurement of Gas Volume Through Pipes and Small Ducts (2000).

1.25 Measurement of gas concentrations by CEM

For paragraph 1.22(c), the measurement of the concentrations of gas in the gas stream by CEM must be undertaken in accordance with an appropriate standard.

Note: Appropriate standards include:

USEPA Method 3A Determination of oxygen and carbon dioxide concentrations in emissions from stationary sources (instrumental analyzer procedure) (2006).
USEPA Method 3C Determination of carbon dioxide, methane, nitrogen, and oxygen from stationary sources (1996).
ISO 12039:2001 Stationary source emissions—Determination of carbon monoxide, carbon dioxide and oxygen—Performance characteristics and calibration of automated measuring system.

1.26 Frequency of measurement by CEM

(1) For paragraph 1.22(d), measurements by CEM must be taken frequently enough to produce data that is representative and unbiased.

(2) For subsection (1), if part of the CEM equipment is not operating for a period, readings taken during periods when the equipment was operating may be used to estimate data on a pro rata basis for the period that the equipment was not operating.

(3) Frequency of measurement will also be affected by the nature of the equipment.

Example: If the equipment is designed to measure only one substance, for example, carbon dioxide or methane, measurements might be made every minute. However, if the equipment is designed to measure different substances in alternate time periods, measurements might be made much less frequently, for example, every 15 minutes.

(4) The CEM equipment must operate for more than 90% of the period for which it is used to monitor an emission.

(5) In working out the period during which CEM equipment is being used to monitor for the purposes of subsection (4), exclude downtime taken for the calibration of equipment.

Division 1.3.3—Operation of method 4 (PEM)

Subdivision 1.3.3.1—Method 4 (PEM)

1.27 Method 4 (PEM)—estimation of emissions

(1) To obtain an estimate of the mass emissions rate of methane, carbon dioxide or nitrous oxide released at the time of measurement at a monitoring site within the area occupied for the operation of a facility, the formula in subsection 1.21(1) must be applied.

(2) The mass of emissions estimated under the formula must be converted into CO2‑e tonnes.

(3) The average mass emissions rate for the gas measured in CO2‑e tonnes per hour for a year must be calculated from the estimates obtained under subsection (1).

(4) The total mass of emissions of the gas for the year is calculated by multiplying the average emissions rate obtained under subsection (3) by the number of hours during the year when the site was operating.

(5) If method 1 is available for the source, the total mass of emissions of the gas for a year calculated under this section must be reconciled against an estimate for that gas from the site for the same period calculated using method 1 for that source.

1.27A Emissions from a source where multiple fuels consumed

If more than one fuel is consumed for a source that generates carbon dioxide that is directly measured using method 4 (PEM), the total amount of carbon dioxide is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed for that source.

1.28 Calculation of emission factors

(1) Data obtained from periodic emissions monitoring of a gas stream may be used to estimate the average emission factor for the gas per unit of fuel consumed or material produced.

(2) In this section, data means data about:

(a) volumetric flow rates estimated in accordance with section 1.31; or

(b) gas concentrations estimated in accordance with section 1.32; or

(d) material produced, estimated in accordance with Chapters 2 to 7.

Subdivision 1.3.3.2—Method 4 (PEM)—use of equipment

1.29 Overview

The following requirements apply to the use of equipment for PEM:

(a) the requirements in section 1.30 about location of the sampling positions for the PEM equipment;

(b) the requirements in section 1.31 about measurement of volumetric flow rates in a gas stream;

(d) the requirements in section 1.33 about representative data.

1.30 Selection of sampling positions for PEM equipment

For paragraph 1.29(a), the location of sampling positions for PEM equipment must be selected in accordance with an appropriate standard.

Note: Appropriate standards include:

AS 4323.1—1995 Stationary source emissions—Selection of sampling positions.
AS 4323.1‑1995 Amdt 1‑1995 Stationary source emissions—Selection of sampling positions.
ISO 10396:2007 Stationary source emissions—Sampling for the automated determination of gas emission concentrations for permanently‑installed monitoring systems.
ISO 10012:2003 Measurement management systems—Requirements for measurement processes and measuring equipment.
USEPA Method 1 Sample and Velocity Traverses for Stationary Sources (2000).

1.31 Measurement of flow rates by PEM equipment

For paragraph 1.29(b), the measurement of the volumetric flow rates by PEM of the gas stream must be undertaken in accordance with an appropriate standard.

Note: Appropriate standards include:

ISO 10780:1994 Stationary source emissions – Measurement of velocity and volume flowrate of gas streams in ducts.
ISO 14164:1999 Stationary source emissions. Determination of the volume flow rate of gas streams in ducts – automated method.
USEPA Method 2 Determination of stack velocity and volumetric flow rate (Type S Pitot tube) (2000).
USEPA Method 2A Direct measurement of gas volume through pipes and small ducts (2000).

1.32 Measurement of gas concentrations by PEM

For paragraph 1.29(c), the measurement of the concentrations of greenhouse gas in the gas stream by PEM must be undertaken in accordance with an appropriate standard.

Note: Appropriate standards include:

USEPA Method 3A Determination of oxygen and carbon dioxide concentrations in emissions from stationary sources (instrumental analyser procedure) (2006).
USEPA Method 3C Determination of carbon dioxide, methane, nitrogen, and oxygen from stationary sources (1996).
ISO12039:2001 Stationary source emissions – Determination of carbon monoxide, carbon dioxide and oxygen – Performance characteristics and calibration of an automated measuring method.

1.33 Representative data for PEM

(1) For paragraph 1.29(d), sampling by PEM must be undertaken during the year for a sufficient duration to produce representative data that may be reliably extrapolated to provide estimates of emissions across the full range of operating conditions for that year.

(2) Emission estimates using PEM equipment must also be consistent with the principles in section 1.13.

Division 1.3.4—Performance characteristics of equipment

1.34 Performance characteristics of CEM or PEM equipment

(1) The performance characteristics of CEM or PEM equipment must be measured in accordance with this section.

(2) The test procedure specified in an appropriate standard must be used for measuring the performance characteristics of CEM or PEM equipment.

(3) For the calibration of CEM or PEM equipment, the test procedure must be:

(a) undertaken by an accredited laboratory; or

(b) undertaken by a laboratory that meets requirements equivalent to ISO 17025; or

(4) As a minimum requirement, a cylinder of calibration gas must be certified by an accredited laboratory accredited to ISO Guide 34:2000 as being within 2% of the concentration specified on the cylinder label.

Chapter 2—Fuel combustion

Part 2.1—Preliminary

2.1 Outline of Chapter

This Chapter provides for the following matters:

(a) emissions released from the following sources:

(i) the combustion of solid fuels (see Part 2.2);

(ii) the combustion of gaseous fuels (Part 2.3);

(iii) the combustion of liquid fuels (Part 2.4);

(iv) fuel use by certain industries (Part 2.5);

(b) the measurement of fuels in blended fuels (Part 2.6);

Part 2.2—Emissions released from the combustion of solid fuels

Division 2.2.1—Preliminary

2.2 Application

This Part applies to emissions released from the combustion of solid fuel in relation to a separate instance of a source if the amount of solid fuel combusted in relation to the separate instance of the source is more than 1 tonne.

2.3 Available methods for estimating emissions of carbon dioxide, methane and nitrous oxide

(1) Subject to section 1.18, for estimating emissions released from the combustion of a solid fuel consumed from the operation of a facility during a year:

(a) one of the following methods must be used for estimating emissions of carbon dioxide:

(i) subject to subsection (3), method 1 under section 2.4;

(ii) method 2 using an oxidation factor under section 2.5 or an estimated oxidation factor under section 2.6;

(iii) method 3 using an oxidation factor or an estimated oxidation factor under section 2.12;

(iv) method 4 under Part 1.3; and

(b) method 1 under section 2.4 must be used for estimating emissions of methane and nitrous oxide.

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

(3) Method 1 must not be used for estimating emissions of carbon dioxide for the main fuel combusted from the operation of the facility if:

(a) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611); and

(b) the generating unit:

(i) has the capacity to produce 30 megawatts or more of electricity; and

(ii) generates more than 50 000 megawatt hours of electricity in a reporting year.

Note: There is no method 2, 3 or 4 for paragraph (1)(b).

Division 2.2.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide from solid fuels

2.4 Method 1—solid fuels

For subparagraph 2.3(1)(a)(i), method 1 is:

where:

Eij is the emissions of gas type (j), being carbon dioxide, methane or nitrous oxide, released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) measured in tonnes and estimated under Division 2.2.5.

ECi is the energy content factor of fuel type (i) estimated under section 6.5.

EFijoxec is the emission factor for each gas type (j) (which includes the effect of an oxidation factor) released from the combustion of fuel type (i) measured in kilograms of CO2‑e per gigajoule according to source as mentioned in Schedule 1.

Division 2.2.3—Method 2—emissions from solid fuels

Subdivision 2.2.3.1—Method 2—estimating carbon dioxide using default oxidation factor

2.5 Method 2—estimating carbon dioxide using oxidation factor

(1) For subparagraph 2.3(1)(a)(ii), method 2 is:

where:

Eico2 means the emissions of carbon dioxide released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) measured in tonnes and estimated under Division 2.2.5.

ECi is the energy content factor of fuel type (i) estimated under section 6.5.

EFico2oxec is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2‑e per gigajoule as worked out under subsection (2).

γ is the factor 1.861 × 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes.

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.

(2) For EFico2oxec in subsection (1), estimate as follows:

where:

EFico2ox,kg is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2‑e per kilogram of fuel as worked out under subsection (3).

ECi is the energy content factor of fuel type (i) as obtained under subsection (1).

(3) For EFico2ox,kg in subsection (2), work out as follows:

where:

Car is the percentage of carbon in fuel type (i), as received for the facility or as combusted from the operation of the facility, worked out under subsection (4).

OFs, or oxidation factor, is 1.0.

(4) For Car in subsection (3), work out as follows:

where:

Cdaf is the amount of carbon in fuel type (i) as a percentage of the dry ash‑free mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.

Mar is the amount of moisture in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.

Aar is the amount of ash in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.

Subdivision 2.2.3.2—Method 2—estimating carbon dioxide using an estimated oxidation factor

2.6 Method 2—estimating carbon dioxide using an estimated oxidation factor

(1) For subparagraph 2.3(1)(a)(ii), method 2 is:

where:

Eico2 means the emissions of carbon dioxide released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) measured in tonnes and estimated under Division 2.2.5.

ECi is the energy content factor of fuel type (i) estimated under section 6.5.

EFico2oxec is the amount worked out under subsection (2).

γ is the factor 1.861 × 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes.

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.

(2) For EFico2oxec in subsection (1), work out as follows:

where:

EFico2ox,kg is the carbon dioxide emission factor for the type of fuel measured in kilograms of CO2‑e per kilogram of the type of fuel as worked out under subsection (3).

ECi is the energy content factor of fuel type (i) as obtained under subsection (1).

(3) For EFico2ox,kg in subsection (2), estimate as follows:

where:

Car is the percentage of carbon in fuel type (i), as received for the facility or as combusted from the operation of the facility, worked out under subsection (4).

Ca is the amount of carbon in the ash estimated as a percentage of the as‑sampled mass that is the weighted average of fly ash and ash by sampling and analysis in accordance with Subdivision 2.2.3.3.

Aar is the amount of ash in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.

(4) For Car, in subsection (3), estimate as follows:

where:

Cdaf is the amount of carbon in fuel type (i) as a percentage of the dry ash‑free mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.

Mar is the amount of moisture in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.

Aar is the amount of ash in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.

Subdivision 2.2.3.3—Sampling and analysis for method 2 under sections 2.5 and 2.6

2.7 General requirements for sampling solid fuels

(1) A sample of the solid fuel must be derived from a composite of amounts of the solid fuel combusted.

(2) The samples must be collected on enough occasions to produce a representative sample.

(3) The samples must also be free of bias so that any estimates are neither over nor under estimates of the true value.

(4) Bias must be tested in accordance with an appropriate standard (if any).

Note: An appropriate standard for most solid mineral fuels is AS 4264.4—1996 Coal and coke—Sampling—Determination of precision and bias.

(5) The value obtained from the sample must only be used for the delivery period or consignment of the fuel for which it was intended to be representative.

2.8 General requirements for analysis of solid fuels

(1) A standard for analysis of a parameter of a solid fuel, and the minimum frequency of analysis of a solid fuel, is as set out in Schedule 2.

(2) A parameter of a solid fuel may also be analysed in accordance with a standard that is equivalent to a standard set out in Schedule 2.

(3) Analysis must be undertaken by an accredited laboratory that meets the requirements equivalent to those in AS ISO/IEC 17025:2005. However, analysis may be undertaken by an on‑line analyser if:

(a) the analyser is calibrated in accordance with an appropriate standard; and

(b) analysis undertaken to meet the standard is done by a laboratory that meets the requirements equivalent to those in AS ISO/IEC 17025:2005.

Note: An appropriate standard is AS 1038.24—1998, Coal and coke—Analysis and testing, Part 24: Guide to the evaluation of measurements made by on‑line coal analysers.

(4) If a delivery of fuel lasts for a month or less, analysis must be conducted on a delivery basis.

(5) However, if the properties of the fuel do not change significantly between deliveries over a period of a month, analysis may be conducted on a monthly basis.

(6) If a delivery of fuel lasts for more than a month, and the properties of the fuel do not change significantly before the next delivery, analysis of the fuel may be conducted on a delivery basis rather than monthly basis.

2.9 Requirements for analysis of furnace ash and fly ash

For furnace ash and fly ash, analysis of the carbon content must be undertaken in accordance with AS 3583.2—1991 Determination of moisture content and AS 3583.3—1991 Determination of loss on ignition or a standard that is equivalent to those standards.

2.10 Requirements for sampling for carbon in furnace ash

(1) This section applies to furnace ash sampled for its carbon content if the ash is produced from the operation of a facility that is constituted by a plant.

(2) A sample of the ash must be derived from representative operating conditions in the plant.

(3) A sample of ash may be collected:

(a) if contained in a wet extraction system—by using sampling ladles to collect it from sluiceways; or

(b) if contained in a dry extraction system—directly from the conveyer; or

(c) if it is not feasible to use one of the collection methods mentioned in paragraph (a) or (b)—by using another collection method that provides representative ash sampling.

2.11 Sampling for carbon in fly ash

Fly ash must be sampled for its carbon content in accordance with:

(a) a procedure set out in column 2 of an item in the following table, and at a frequency set out in column 3 for that item; or

(b) if it is not feasible to use one of the procedures mentioned in paragraph (a)—another procedure that provides representative ash sampling, at least every two years, or after significant changes in operating conditions.

Item	Procedure	Frequency
1	At the outlet of a boiler air heater or the inlet to a flue gas cleaning plant using the isokinetic sampling method in AS 4323.1—1995 or AS 4323.2—1995, or in a standard that is equivalent to one of those standards	At least every 2 years, or after significant changes in operating conditions
2	By using standard industry ‘cegrit’ extraction equipment	At least every year, or after significant changes in operating conditions
3	By collecting fly ash from: (a) the fly ash collection hoppers of a flue gas cleaning plant; or (b) downstream of fly ash collection hoppers from ash silos or sluiceways	At least once a year, or after significant changes in operating conditions
4	From on‑line carbon in ash analysers using sample extraction probes and infrared analysers	At least every 2 years, or after significant changes in operating conditions

Division 2.2.4—Method 3—Solid fuels

2.12 Method 3—solid fuels using oxidation factor or an estimated oxidation factor

(1) For subparagraph 2.3(1)(a)(iii) and subject to this section, method 3 is the same as method 2 whether using the oxidation factor under section 2.5 or using an estimated oxidation factor under section 2.6.

(2) In applying method 2 as mentioned in subsection (1), solid fuels must be sampled in accordance with the appropriate standard mentioned in the table in subsection (3).

(3) A standard for sampling a solid fuel mentioned in column 2 of an item in the following table is as set out in column 3 for that item:

Item	Fuel	Standard
1	Bituminous coal	AS 4264.1—2009
1A	Sub‑bituminous coal	AS 4264.1—2009
1B	Anthracite	AS 4264.1—2009
2	Brown coal	AS 4264.3—1996
3	Coking coal (metallurgical coal)	AS 4264.1—2009
4	Coal briquettes	AS 4264.3—1996
5	Coal coke	AS 4264.2—1996
6	Coal tar
7	Industrial materials and tyres that are derived from fossil fuels, if recycled and combusted to produce heat or electricity	CEN/TS 14778 – 1:2006 CEN/TS 15442:2006
8	Non‑biomass municipal materials, if recycled and combusted to produce heat or electricity	CEN/TS 14778 – 1:2005 CEN/TS 15442:2006
9	Dry wood	CEN/TS 14778 – 1:2005 CEN/TS 15442:2006
10	Green and air dried wood	CEN/TS 14778 – 1:2005 CEN/TS 15442:2006
11	Sulphite lyes	CEN/TS 14778 – 1:2005 CEN/TS 15442:2006
12	Bagasse	CEN/TS 14778 – 1:2005 CEN/TS 15442:2006
13	Primary solid biomass other than items 9 to 12 and 14 to 15	CEN/TS 14778 – 1:2005 CEN/TS 15442:2006
14	Charcoal	CEN/TS 14778 – 1:2005 CEN/TS 15442:2006
15	Biomass municipal and industrial materials, if recycled and combusted to produce heat or electricity	CEN/TS 14778 – 1:2005 CEN/TS 15442:2006

(4) A solid fuel may also be sampled in accordance with a standard that is equivalent to a standard set out in the table in subsection (3).

Note: The analysis is carried out in accordance with the same requirements as for method 2.

Division 2.2.5—Measurement of consumption of solid fuels

2.13 Purpose of Division

This Division sets out how quantities of solid fuels combusted from the operation of a facility are to be estimated for the purpose of working out the emissions released from the combustion of that fuel.

2.14 Criteria for measurement

(1) For the purpose of calculating the amount of solid fuel combusted from the operation of a facility during a year and, in particular, for Qi in sections 2.4, 2.5 and 2.6, the quantity of combustion must be estimated in accordance with this section.

Acquisition involves commercial transaction

(2) If the acquisition of the solid fuel involves a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria:

(a) the amount of the solid fuel delivered for the facility during the year as evidenced by invoices issued by the vendor of the fuel (criterion A);

(b) as provided in section 2.15 (criterion AA);

(3) If, during a year, criterion AA, or criterion AAA using paragraph 2.16(2)(a), is used to estimate the quantity of fuel combusted, then, in each year following that year, only criterion AA, or criterion AAA using paragraph 2.16(2)(a), (respectively) is to be used.

Acquisition does not involve commercial transaction

(4) If the acquisition of the solid fuel does not involve a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria:

(a) as provided in paragraph 2.16(2)(a) (criterion AAA);

(b) as provided in section 2.17 (criterion BBB).

2.15 Indirect measurement at point of consumption—criterion AA

(1) For paragraph 2.14(2)(b), criterion AA is the amount of the solid fuel combusted from the operation of the facility during a year based on amounts delivered for the facility during the year as adjusted for the estimated change in the quantity of the stockpile of the fuel for the facility during the year.

(2) To work out the adjustment for the estimated change in the quantity of the stockpile of the fuel for the facility during the year, one of the following approaches must be used:

(a) the survey approach mentioned in subsection (2C);

(b) the error allowance approach mentioned in subsection (2D).

(2A) The approach selected must be consistent with the principles mentioned in section 1.13.

(2B) The same approach, once selected, must be used for the facility for each year unless:

(a) there has been a material change in the management of the stockpile during the year; and

(b) the change in the management of the stockpile results in the approach selected being less accurate than the alternative approach.

(2C) The survey approach is as follows:

Step 1. Estimate the quantity of solid fuel in the stockpile by:

(a) working out the volume of the solid fuel in the stockpile using aerial or general survey in accordance with industry practice; and

(b) measuring the bulk density of the stockpile in accordance with subregulation (3).

Step 2. Replace the current book quantity with the quantity estimated under step 1.

Step 3. Maintain the book quantity replaced under step 2 by:

(a) adding deliveries made during the year, using:

(i) invoices received for solid fuel delivered to the facility; or

(ii) solid fuel sampling and measurements provided by measuring equipment calibrated to a measurement requirement; and

(b) deducting from the amount calculated under paragraph (a), solid fuel consumed by the facility.

Step 4. Use the book quantity maintained under step 3 to estimate the change in the quantity of the stockpile of the fuel.

(2D) The error allowance approach is as follows:

Step 1. Estimate the quantity of the stockpile by:

(a) working out the volume of the solid fuel in the stockpile using aerial or general survey in accordance with industry practice; and

(b) measuring the bulk density of the stockpile in accordance with subregulation (3).

Step 2. Estimate an error tolerance for the quantity of solid fuel in the stockpile. The error tolerance is an estimate of the uncertainty of the quantity of solid fuel in the stockpile and must be:

(a) based on stockpile management practices at the facility and the uncertainty associated with the energy content and proportion of carbon in the solid fuel; and

(b) consistent with the general principles in section 1.13; and

Step 3. Work out the percentage difference between the current book quantity and the quantity of solid fuel in the stockpile estimated under step 1.

Step 4. If the percentage difference worked out under step 3 is within the error tolerance worked out under step 2, use the book quantity to estimate the change in the quantity of the stockpile of the fuel.

Step 5. If the percentage difference worked out in step 3 is more than the error tolerance worked out in step 2:

(a) adjust the book quantity by the difference between the percentage worked out under step 3 and the error tolerance worked out under step 2; and

(b) use the book quantity adjusted under paragraph (a) to estimate the change in the quantity of the stockpile of the fuel.

(3) The bulk density of the stockpile must be measured in accordance with:

(a) the procedure in ASTM D/6347/D 6347M‑99; or

(b) the following procedure:

Step 1 If the mass of the stockpile:

(a) does not exceed 10% of the annual solid fuel combustion from the operation of a facility—extract a sample from the stockpile using a mechanical auger in accordance with ASTM D 4916‑89; or

(b) exceeds 10% of the annual solid fuel combustion — extract a sample from the stockpile by coring.

Step 2 Weigh the mass of the sample extracted.

Step 3 Measure the volume of the hole from which the sample has been extracted.

Step 4 Divide the mass obtained in step 2 by the volume measured in step 3.

(4) Quantities of solid fuel delivered for the facility must be evidenced by invoices issued by the vendor of the fuel.

(5) In this section:

book quantity means the quantity recorded and maintained by the facility operator as the quantity of solid fuel in the stockpile.

2.16 Direct measurement at point of consumption—criterion AAA

(1) For paragraph 2.14(2)(c), criterion AAA is the measurement during a year of the solid fuel combusted from the operation of the facility.

(2) The measurement must be carried out either:

(a) at the point of combustion using measuring equipment calibrated to a measurement requirement; or

(b) at the point of sale using measuring equipment calibrated to a measurement requirement.

(3) Paragraph (2)(b) only applies if:

(a) the change in the stockpile of the fuel for the facility for the year is less than 1% of total combustion on average for the facility during the year; and

(b) the stockpile of the fuel for the facility at the beginning of the year is less than 5% of total combustion for the year.

2.17 Simplified consumption measurements—criterion BBB

For paragraph 2.14(d), criterion BBB is the estimation of the solid fuel combusted during a year from the operation of the facility in accordance with industry practice if the equipment used to measure combustion of the fuel is not calibrated to a measurement requirement.

Note: An estimate obtained using industry practice must be consistent with the principles in section 1.13.

Part 2.3—Emissions released from the combustion of gaseous fuels

Division 2.3.1—Preliminary

2.18 Application

This Part applies to emissions released from the combustion of gaseous fuels in relation to a separate instance of a source if the amount of gaseous fuel combusted in relation to the separate instance of the source is more than 1000 cubic metres.

2.19 Available methods

(1) Subject to section 1.18, for estimating emissions released from the combustion of a gaseous fuel consumed from the operation of a facility during a year:

(a) one of the following methods must be used for estimating emissions of carbon dioxide:

(i) method 1 under section 2.20;

(ii) method 2 under section 2.21;

(iii) method 3 under section 2.26;

(iv) method 4 under Part 1.3; and

(b) one of the following methods must be used for estimating emissions of methane:

(i) method 1 under section 2.20;

(ii) method 2 under section 2.27; and

Note: The combustion of gaseous fuels releases emissions of carbon dioxide, methane and nitrous oxide. Method 1 is used to estimate emissions of each of these gases. There is no method 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

(3) Method 1 must not be used for estimating emissions of carbon dioxide for the main fuel combusted from the operation of the facility if:

(a) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611); and

(b) the generating unit:

(i) has the capacity to produce 30 megawatts or more of electricity; and

(ii) generates more than 50 000 megawatt hours of electricity in a reporting year.

Division 2.3.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide

2.20 Method 1—emissions of carbon dioxide, methane and nitrous oxide

(1) For subparagraphs 2.19(1)(a)(i) and (b)(i) and paragraph 2.19(1)(c), method 1 for estimating emissions of carbon dioxide, methane and nitrous oxide is:

where:

Eij is the emissions of gas type (j), being carbon dioxide, methane or nitrous oxide, from each gaseous fuel type (i) released from the operation of the facility during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) combusted, whether for stationary energy purposes or transport energy purposes, from the operation of the facility during the year measured in cubic metres or gigajoules and estimated under Division 2.3.6.

ECi is the energy content factor of fuel type (i) estimated under section 6.5.

EFijoxec is the emission factor for each gas type (j) released during the year (which includes the effect of an oxidation factor) measured in kilograms CO2‑e per gigajoule of fuel type (i) according to source as mentioned in:

(a) for stationary energy purposes—Part 2 of Schedule 1; and

(b) for transport energy purposes—Division 4.1 of Schedule 1.

Note: The combustion of gaseous fuels releases emissions of carbon dioxide, methane and nitrous oxide.

(2) In this section:

stationary energy purposes means purposes for which fuel is combusted that do not involve transport energy purposes.

transport energy purposes includes purposes for which fuel is combusted that consist of any of the following:

(a) transport by vehicles registered for road use;

(b) rail transport;

(d) air transport.

Note: The combustion of gaseous fuels releases emissions of carbon dioxide, methane and nitrous oxide.

Division 2.3.3—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels

Subdivision 2.3.3.1—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels

2.21 Method 2—emissions of carbon dioxide from the combustion of gaseous fuels

(1) For subparagraph 2.19(1)(a)(ii), method 2 for estimating emissions of carbon dioxide is:

where:

EiCO2 is emissions of carbon dioxide released from fuel type (i) combusted from the operation of the facility during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) combusted from the operation of the facility during the year measured in cubic metres or gigajoules and estimated under Division 2.3.6.

ECi is the energy content factor of fuel type (i) estimated under section 6.5.

EFiCO2oxec is the carbon dioxide emission factor for fuel type (i) measured in kilograms CO2‑e per gigajoule and calculated in accordance with section 2.22.

γ is the factor 1.861 × 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes.

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.

2.22 Calculation of emission factors from combustion of gaseous fuel

(1) For section 2.21, the emission factor EFiCO2oxec from the combustion of fuel type (i) must be calculated from information on the composition of each component gas type (y) and must first estimate EFi,CO2,ox,kg in accordance with the following formula:

where:

EFi,CO2,ox,kg is the carbon dioxide emission factor for fuel type (i), incorporating the effects of a default oxidation factor expressed as kilograms of carbon dioxide per kilogram of fuel.

moly%, for each component gas type (y), is that gas type’s share of 1 mole of fuel type (i), or that gas type’s share of the total volume of fuel type (i), expressed as a percentage.

mwy, for each component gas type (y), is the molecular weight of the component gas type (y) measured in kilograms per kilomole.

V is the volume of 1 kilomole of the gas at standard conditions and equal to 23.6444 cubic metres.

dy, total is as set out in subsection (2).

fy for each component gas type (y), is the number of carbon atoms in a molecule of the component gas type (y).

OFg is the oxidation factor 1.0 applicable to gaseous fuels.

(2) For subsection (1), the factor dy, total is worked out using the following formula:

where:

moly%, for each component gas type (y), is that gas type’s share of 1 mole of fuel type (i), or that gas type’s share of the total volume of fuel type (i), expressed as a percentage.

mwy, for each component gas type (y), is the molecular weight of the component gas type (y) measured in kilograms per kilomole.

(3) For subsection (1), the molecular weight and number of carbon atoms in a molecule of each component gas type (y) mentioned in column 2 of an item in the following table is as set out in columns 3 and 4, respectively, for the item:

Item	Component gas y	Molecular Wt (kg/kmole)	Number of carbon atoms in component molecules
1	Methane	16.043	1
2	Ethane	30.070	2
3	Propane	44.097	3
4	Butane	58.123	4
5	Pentane	72.150	5
6	Carbon monoxide	28.016	1
7	Hydrogen	2.016	0
8	Hydrogen sulphide	34.082	0
9	Oxygen	31.999	0
10	Water	18.015	0
11	Nitrogen	28.013	0
12	Argon	39.948	0
13	Carbon dioxide	44.010	1

(4) The carbon dioxide emission factor EFiCO2oxec derived from the calculation in subsection (1) must be expressed in terms of kilograms of carbon dioxide per gigajoule calculated using the following formula:

where:

ECi is the energy content factor of fuel type (i), measured in gigajoules per cubic metre that is:

(a) mentioned in column 3 of Part 2 of Schedule 1; or

(b) estimated by analysis under Subdivision 2.3.3.2.

Ci is the density of fuel type (i) expressed in kilograms of fuel per cubic metre as obtained under subsection 2.24(4).

Subdivision 2.3.3.2—Sampling and analysis

2.23 General requirements for sampling under method 2

(1) A sample of the gaseous fuel must be derived from a composite of amounts of the gaseous fuel combusted.

(2) The samples must be collected on enough occasions to produce a representative sample.

(3) The samples must also be free of bias so that any estimates are neither over nor under estimates of the true value.

(4) Bias must be tested in accordance with an appropriate standard (if any).

(5) The value obtained from the samples must only be used for the delivery period, usage period or consignment of the gaseous fuel for which it was intended to be representative.

2.24 Standards for analysing samples of gaseous fuels

(1) Samples of gaseous fuels of a type mentioned in column 2 of an item in the following table must be analysed in accordance with one of the standards mentioned in:

(a) for analysis of energy content—column 3 for that item; and

(b) for analysis of gas composition—column 4 for that item.

Item	Fuel type	Energy content	Gas Composition
1	Natural gas if distributed in a pipeline	ASTM D 1826—94 (2003) ASTM D 7164—05 ASTM 3588—98 (2003) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) ISO 6976:1995 GPA 2172—96	ASTM D 1945—03 ASTM D 1946—90 (2006) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) GPA 2145 – 03 GPA 2261 – 00
2	Coal seam methane that is captured for combustion	ASTM D 1826—94 (2003) ASTM D 7164—05 ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) ISO 6976:1995 GPA 2172—96	ASTM D 1945—03 ASTM D 1946—90 (2006) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) GPA 2145 – 03 GPA 2261 – 00
3	Coal mine waste gas that is captured for combustion	ASTM D 1826 – 94 (2003) ASTM D 7164 – 05 ASTM 3588—98 (2003) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) ISO 6976:1995 GPA 2172—96	ASTM D 1945 – 03 ASTM D 1946 – 90 (2006) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) GPA 2145 – 03 GPA 2261 – 00
4	Compressed natural gas	ASTM 3588—98 (2003)	N/A
5	Unprocessed natural gas	ASTM D 1826—94 (2003) ASTM D 7164—05 ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) ISO 6976:1995 GPA 2172—96	ASTM D 1945—03 ASTM D 1946—90 (2006) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) GPA 2145 – 03 GPA 2261 – 00
6	Ethane	ASTM D 3588 – 98 (2003) IS0 6976:1995	ASTM D 1945 – 03 ASTM D 1946 – 90 (2006)
7	Coke oven gas	ASTM D 3588—98 (2003) ISO 6976:1995	ASTM D 1945—03 ASTM D 1946—90 (2006)
8	Blast furnace gas	ASTM D 3588—98 (2003) ISO 6976:1995	ASTM D 1945—03 ASTM D 1946—90 (2006)
9	Town gas	ASTM D 1826—94 (2003) ASTM D 7164—05 ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) ISO 6976:1995 GPA 2172—96	ASTM D 1945—03 ASTM D 1946—90 (2006) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) GPA 2145 – 03 GPA 2261 – 00
10	Liquefied natural gas	ISO 6976:1995	ASTM D 1945 – 03 ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002)
11	Landfill biogas that is captured for combustion	ASTM D 1826—94 (2003) ASTM D 7164—05 ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) ISO 6976:1995 GPA 2172—96	ASTM D 1945—03 ASTM D 1946—90 (2006) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) GPA 2145 – 03 GPA 2261 – 00
12	Sludge biogas that is captured for combustion	ASTM D 1826 – 94 (2003) ASTM D 7164 – 05 ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) ISO 6976:1995 GPA 2172—96	ASTM D 1945 – 03 ASTM D 1946 – 90 (2006) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000) part 5 (2000) part 6 (2002) GPA 2145 – 03 GPA 2261 – 00
13	A biogas that is captured for combustion, other than those mentioned in items 11 and 12	ASTM D 1826—94 (2003) ASTM D 7164—05 ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000)	ASTM D 1945—03 ASTM D 1946—90 (2006) ISO 6974 part 1 (2000) part 2 (2001) part 3 (2000) part 4 (2000)
		part 4 (2000) part 5 (2000) part 6 (2002)	part 5 (2000) part 6 (2002) GPA 2145 – 03
		ISO 6976:1995 GPA 2172—96	GPA 2261 – 00

(2) A gaseous fuel mentioned in column 2 of an item in the table in subsection (1) may also be analysed in accordance with a standard that is equivalent to a standard set out in column 3 and 4 of the item.

(3) The analysis must be undertaken:

(a) by an accredited laboratory; or

(b) by a laboratory that meets requirements that are equivalent to the requirements in AS ISO/IEC 17025:2005; or

(i) the online analyser is calibrated in accordance with an appropriate standard; and

(ii) the online analysis is undertaken in accordance with this section.

Note: An example of an appropriate standard is ISO 6975:1997—Natural gas—Extended analysis—Gas‑chromatographic method.

(4) The density of a gaseous fuel mentioned in column 2 of an item in the table in subsection (1) must be analysed in accordance with ISO 6976:1995 or in accordance with a standard that is equivalent to that standard.

2.25 Frequency of analysis

Gaseous fuel of a type mentioned in column 2 of an item in the following table must be analysed for the parameter mentioned in column 3 for that item at least at the frequency mentioned in column 4 for that item.

Item	Fuel	Parameter	Frequency
1	Pipeline quality gases	Gas composition Energy content	Monthly Monthly—if category 1 or 2 gas measuring equipment is used Continuous—if category 3 or 4 gas measuring equipment is used
2	All other gases (including fugitive emissions)	Gas composition Energy content	Monthly, unless the reporting corporation or registered person certifies in writing that such frequency of analysis will cause significant hardship or expense in which case the analysis may be undertaken at a frequency that will allow an unbiased estimate to be obtained

Item

Fuel

Parameter

Frequency

Pipeline quality gases

Gas composition

Energy content

Monthly

Monthly—if category 1 or 2 gas measuring equipment is used

Continuous—if category 3 or 4 gas measuring equipment is used

All other gases (including fugitive emissions)

Gas composition

Energy content

Monthly, unless the reporting corporation or registered person certifies in writing that such frequency of analysis will cause significant hardship or expense in which case the analysis may be undertaken at a frequency that will allow an unbiased estimate to be obtained

Note: The table in section 2.31 sets out the categories of gas measuring equipment.

Division 2.3.4—Method 3—emissions of carbon dioxide released from the combustion of gaseous fuels

2.26 Method 3—emissions of carbon dioxide from the combustion of gaseous fuels

(1) For subparagraph 2.19(1)(a)(iii) and subject to subsection (2), method 3 for estimating emissions of carbon dioxide is the same as method 2 under section 2.21.

(2) In applying method 2 under section 2.21, gaseous fuels must be sampled in accordance with a standard specified in the table in subsection (3).

(3) A standard for sampling a gaseous fuel mentioned column 2 of an item in the following table is the standard specified in column 3 for that item.

Item	Gaseous fuel	Standard
1	Natural gas if distributed in a pipeline	ISO 10715:1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003) GPA 2166–05
2	Coal seam methane that is captured for combustion	ISO 10715:1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003) GPA 2166–05
3	Coal mine waste gas that is captured for combustion	ISO 10715:1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003) GPA 2166–05
4	Compressed natural gas	ASTM F 307–02 (2007)
5	Unprocessed natural gas	ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003) GPA 2166–05
6	Ethane	ISO 10715:1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003)
7	Coke oven gas	ISO 10715 ‑1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003)
8	Blast furnace gas	ISO 10715:1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003)
9	Town gas	ISO 10715:1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003) GPA 2166–05
10	Liquefied natural gas	ISO 8943:2007
11	Landfill biogas that is captured for combustion	ISO 10715:1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003) GPA 2166–05
12	Sludge biogas that is captured for combustion	ISO 10715:1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003) GPA 2166–05
13	A biogas that is captured for combustion, other than those mentioned in items 11 and 12	ISO 10715:1997 ASTM D 5287–97 (2002) ASTM F 307–02 (2007) ASTM D 5503–94 (2003) GPA 2166–05

(4) A gaseous fuel mentioned in column 2 of an item in the table in subsection (3) may also be sampled in accordance with a standard that is equivalent to a standard specified in column 3 for that item.

Division 2.3.5—Method 2—emissions of methane from the combustion of gaseous fuels

2.27 Method 2—emissions of methane from the combustion of gaseous fuels

(1) For subparagraph 2.19(1)(b)(ii) and subject to subsection (2), method 2 for estimating emissions of methane is the same as method 1 under section 2.20.

(2) In applying method 1 under section 2.20, the emission factor EFijoxec is to be 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.

Division 2.3.6—Measurement of quantity of gaseous fuels

2.28 Purpose of Division

This Division sets out how quantities of gaseous fuels combusted from the operation of a facility are to be estimated for the purpose of working out the emissions released from the combustion of that fuel.

2.29 Criteria for measurement

(1) For the purposes of calculating the combustion of gaseous fuel from the operation of a facility for a year and, in particular, for Qi in sections 2.20 and 2.21, the combustion must be estimated in accordance with this section.

Acquisition involves commercial transaction

(2) If the acquisition of the gaseous fuel involves a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria:

(a) the amount of the gaseous fuel, expressed in cubic metres or gigajoules, delivered for the facility during the year as evidenced by invoices issued by the vendor of the fuel (criterion A);

(b) as provided in section 2.30 (criterion AA);

(3) If, during a year, criterion AA, or criterion AAA using paragraph 2.31(3)(a), is used to estimate the quantity of fuel combusted, then, in each year following that year, only criterion AA, or criterion AAA using paragraph 2.31(3)(a), (respectively) is to be used.

Acquisition does not involve commercial transaction

(4) If the acquisition of the gaseous fuel does not involve a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria:

(a) as provided in section 2.31 (criterion AAA);

(b) as provided in section 2.38 (criterion BBB).

2.30 Indirect measurement—criterion AA

For paragraph 2.29(2)(b), criterion AA is the amount of a gaseous fuel combusted from the operation of the facility during the year based on amounts delivered during the year (evidenced by invoices) as adjusted for the estimated change in the quantity of the stockpile of the fuel for the facility during the year.

2.31 Direct measurement—criterion AAA

(1) For paragraph 2.29(2)(c), criterion AAA is the measurement during the year of a gaseous fuel combusted from the operation of the facility.

(2) In measuring the quantity of gaseous fuel, the quantities of gas must be measured:

(a) using volumetric measurement in accordance with:

(i) for gases other than super‑compressed gases—section 2.32; and

(ii) for super‑compressed gases—sections 2.32 and 2.33; and

(b) using gas measuring equipment that complies with section 2.34.

(3) The measurement must be either:

(a) carried out at the point of combustion using gas measuring equipment that:

(i) is in a category specified in column 2 of an item in the table in subsection (4) according to the maximum daily quantity of gas combusted from the operation of the facility specified, for the item, in column 3 of the table; and

(ii) complies with the transmitter and accuracy requirements specified, for the item, in column 4 of the table, if the requirements are applicable to the gas measuring equipment being used; or

(b) carried out at the point of sale of the gaseous fuels using measuring equipment that complies with paragraph (a).

(4) For subsection (3), the table is as follows:

Item	Gas measuring equipment category	Maximum daily quantity of gas combusted (GJ/day)	Transmitter and accuracy requirements (% of range)
1	1	0–1750	Pressure <±0.25% Diff. pressure <±0.25% Temperature <±0.50%
2	2	1751–3500	Pressure <±0.25% Diff. pressure <±0.25% Temperature <±0.50%
3	3	3501–17500	Smart transmitters: Pressure <±0.10% Diff. pressure <±0.10% Temperature <±0.25%
4	4	17501 or more	Smart transmitters: Pressure <±0.10% Diff. pressure <±0.10% Temperature <±0.25%

(5) Paragraph (3)(b) only applies if:

(a) the change in the stockpile of the fuel for the facility for the year is less than 1% of total consumption on average for the facility during the year; and

(b) the stockpile of the fuel for the facility at the beginning of the year is less than 5% of total consumption of the fuel from the operation of the facility during the year.

2.32 Volumetric measurement—all natural gases

(1) For subparagraph 2.31(2)(a)(i) and (ii), volumetric measurement must be calculated at standard conditions and expressed in cubic metres.

(2) The volumetric measurement must be calculated using a flow computer that measures and analyses the following at the delivery location of the gaseous fuel:

(a) flow;

(b) relative density;

(3) The volumetric flow rate must be:

(a) continuously recorded; and

(b) continuously integrated using an integration device.

(3A) The integration device must be isolated from the flow computer in such a way that, if the computer fails, the integration device will retain:

(a) the last reading that was on the computer immediately before the failure; or

(b) the previously stored information that was on the computer immediately before the failure.

(4) All measurements, calculations and procedures used in determining volume (except for any correction for deviation from the ideal gas law) must be made in accordance with:

(a) the instructions mentioned in subsection (5); or

(b) an appropriate internationally recognised standard or code.

Note: An example of an internationally recognised equivalent standard is New Zealand standard NZS 5259:2004.

(5) For paragraph (4)(a), the instructions are those mentioned in:

(a) for orifice plate measuring systems:

(b) for turbine measuring systems—the publication entitled AGA Report No. 7, Measurement of Natural Gas by Turbine Meter (2006), published by the American Gas Association on 1 January 2006;

(c) for positive displacement measuring systems—the publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000.

(6) Measurements must comply with Australian legal units of measurement.

(7) Standard conditions means, as measured on a dry gas basis:

(a) air pressure of 101.325 kilopascals; and

(b) air temperature of 15.0 degrees Celsius; and

2.33 Volumetric measurement—super‑compressed gases

(1) For subparagraph 2.31(2)(a)(ii), this section applies in relation to measuring the volume of super‑compressed natural gases.

(2) If it is necessary to correct the volume for deviation from the ideal gas law, the correction must be determined using the relevant method set out in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994.

(3) The measuring equipment used must calculate super‑compressibility by:

(a) if the measuring equipment is category 3 or 4 equipment in accordance with the table in section 2.31—using gas composition data; or

(b) if the measuring equipment is category 1 or 2 equipment in accordance with the table in section 2.31—using an alternative method set out in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994.

2.34 Gas measuring equipment—requirements

For paragraph 2.31(2)(b), gas measuring equipment that is category 3 or 4 equipment in accordance with column 2 of the table in section 2.31 must comply with the following requirements:

(a) if the equipment uses flow devices—the requirements relating to flow devices set out in section 2.35;

(b) if the equipment uses flow computers—the requirement relating to flow computers set out in section 2.36;

2.35 Flow devices—requirements

(1A) This section is made for paragraph 2.34(a).

Note: The publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: Natural Gas Applications, published by the American Gas Association in August 1992, sets out a manner of construction that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%.

Note: The publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994, sets out a manner of installation that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%.

Note: The publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000, sets out a manner of installation that ensures that the maximum uncertainty of flow is ±1.5%.

(4) If the measuring equipment uses any other type of flow device, the maximum uncertainty of flow measurement must not be greater than ±1.5%.

(5) All flow devices that are used by gas measuring equipment in a category specified in column 2 of an item in the table in section 2.31 must, wherever possible, be calibrated for pressure, differential pressure and temperature:

(a) in accordance with the requirements specified, for the item, in column 4 of the table; and

(b) taking into account the effects of static pressure and ambient temperature.

2.36 Flow computers—requirements

For paragraph 2.34(b), the requirement is that the flow computer that is used by the equipment for measuring purposes must record:

(a) the instantaneous values for all primary measurement inputs; and

(b) the following outputs:

(i) instantaneous corrected volumetric flow;

(ii) cumulative corrected volumetric flow;

(iii) for turbine and positive displacement metering systems—instantaneous uncorrected volumetric flow;

(iv) for turbine and positive displacement metering systems—cumulative uncorrected volumetric flow;

(v) super‑compressibility factor.

2.37 Gas chromatographs—requirements

For paragraph 2.34(c), the requirements are that gas chromatographs used by the measuring equipment must:

(a) be factory tested and calibrated using a measurement standard:

(i) produced by gravimetric methods; and

(ii) that uses Australian legal units of measurement; and

(b) perform gas composition analysis with an accuracy of:

(i) ±0.15% for use in calculation of gross calorific value; and

(ii) ±0.25% for calculation of relative density; and

2.38 Simplified consumption measurements—criterion BBB

(1) For paragraph 2.29(4)(b), criterion BBB is the estimation of gaseous fuel in accordance with industry practice if the measuring equipment used to estimate consumption of the fuel does not meet the requirements of criterion AAA.

(2) For sources of landfill gas captured for the purpose of combustion for the production of electricity:

(a) the energy content of the captured landfill gas may be estimated:

(i) if the manufacturer’s specification for the internal combustion engine used to produce the electricity specifies an electrical efficiency factor—by using that factor; or

(ii) if the manufacturer’s specification for the internal combustion engine used to produce the electricity does not specify an electrical efficiency factor—by assuming that measured electricity dispatched for sale (sent out generation) represents 36% of the energy content of all fuel used to produce electricity; and

(b) the quantity of landfill gas captured in cubic metres may be derived from the energy content of the relevant gas set out in Part 2 of Schedule 1.

Part 2.4—Emissions released from the combustion of liquid fuels

Division 2.4.1—Preliminary

2.39 Application

This Part applies to emissions released from:

(a) the combustion of petroleum based oil (other than petroleum based oil used as fuel) or petroleum based grease, in relation to a separate instance of a source, if the total amount of oil and grease combusted in relation to the separate instance of the source is more than 5 kilolitres; and

(b) for a liquid fuel not of the kind mentioned in paragraph (a)—the combustion of liquid fuel in relation to a separate instance of a source, if the total amount of liquid fuel combusted in relation to the separate instance of the source is more than 1 kilolitre.

2.39A Definition of petroleum based oils for Part 2.4

In this Part:

petroleum based oils means petroleum based oils (other than petroleum based oils used as fuel).

Subdivision 2.4.1.1—Liquid fuels—other than petroleum based oils and greases

2.40 Available methods

(1) Subject to section 1.18, for estimating emissions released from the combustion of a liquid fuel, other than petroleum based oils and petroleum based greases, consumed from the operation of a facility during a year:

(a) one of the following methods must be used for estimating emissions of carbon dioxide:

(i) method 1 under section 2.41;

(ii) method 2 under section 2.42;

(iii) method 3 under section 2.47;

(iv) method 4 under Part 1.3; and

(b) one of the following methods must be used for estimating emissions of methane and nitrous oxide:

(i) method 1 under section 2.41;

(ii) method 2 under section 2.48.

(2) Under paragraph (1)(b), the same method must be used for estimating emissions of methane and nitrous oxide.

(3) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

Note: The combustion of liquid fuels releases emissions of carbon dioxide, methane and nitrous oxide. Method 1 may be used to estimate emissions of each of these gases. There is no method 3 or 4 for emissions of methane or nitrous oxide.

Subdivision 2.4.1.2—Liquid fuels—petroleum based oils and greases

2.40A Available methods

(1) Subject to section 1.18, for estimating emissions of carbon dioxide released from the consumption, as lubricants, of petroleum based oils or petroleum based greases, consumed from the operation of a facility during a year, one of the following methods must be used:

(a) method 1 under section 2.48A;

(b) method 2 under section 2.48B;

(2) However, for incidental emissions, another method may be used that is consistent with the principles in section 1.13.

Note: The consumption of petroleum based oils and greases, as lubricants, releases emissions of carbon dioxide. Emissions of methane and nitrous oxide are not estimated directly for this fuel type.

Division 2.4.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide from liquid fuels other than petroleum based oils or greases

2.41 Method 1—emissions of carbon dioxide, methane and nitrous oxide

(1) For subparagraphs 2.40(1)(a)(i) and (b)(i), method 1 for estimating emissions of carbon dioxide, methane and nitrous oxide is:

where:

Qi is the quantity of fuel type (i) combusted from the operation of the facility for:

(a) stationary energy purposes; and

(b) transport energy purposes;

during the year measured in kilolitres and estimated under Division 2.4.6.

ECi is the energy content factor of fuel type (i) estimated under section 6.5.

EFijoxec is the emission factor for each gas type (j) released from the operation of the facility during the year (which includes the effect of an oxidation factor) measured in kilograms CO2‑e per gigajoule of fuel type (i) according to source as mentioned in:

(a) for stationary energy purposes—Part 3 of Schedule 1; and

(b) for transport energy purposes—Division 4.1 of Schedule 1.

(2) In this section:

stationary energy purposes means purposes for which fuel is combusted that do not involve transport energy purposes.

transport energy purposes includes purposes for which fuel is combusted that consist of any of the following:

(a) transport by vehicles registered for road use;

(b) rail transport;

(d) air transport.

Note: The combustion of liquid fuels produces emissions of carbon dioxide, methane and nitrous oxide.

Division 2.4.3—Method 2—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases

Subdivision 2.4.3.1—Method 2—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases

2.42 Method 2—emissions of carbon dioxide from the combustion of liquid fuels

(1) For subparagraph 2.40(1)(a)(ii), method 2 for estimating emissions of carbon dioxide is:

where:

EiCO2 is the emissions of carbon dioxide released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) combusted from the operation of the facility during the year measured in kilolitres .

ECi is the energy content factor of fuel type (i) estimated under section 6.5.

EFiCO2oxec is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2‑e per gigajoule.

γ is the factor 1.861 × 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes.

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.

(2) Method 2 requires liquid fuels to be sampled and analysed in accordance with the requirements in sections 2.44, 2.45 and 2.46.

2.43 Calculation of emission factors from combustion of liquid fuel

(1) For section 2.42, the emission factor EFi,CO2,ox,ec from the combustion of fuel type (i) must allow for oxidation effects and must first estimate EFi,co2,ox,kg in accordance with the following formula:

where:

Ca is the carbon in the fuel expressed as a percentage of the mass of the fuel as received, as sampled, or as combusted, as the case may be.

OFi is the oxidation factor 1.0 applicable to liquid fuels.

Note: 3.664 converts tonnes of carbon to tonnes of carbon dioxide.

(2) The emission factor derived from the calculation in subsection (1), must be expressed in kilograms of carbon dioxide per gigajoule calculated using the following formula:

where:

ECi is the energy content factor of fuel type (i) estimated under subsection 2.42(1).

Ci is the density of the fuel expressed in kilograms of fuel per thousand litres as obtained using a Standard set out in section 2.45.

Subdivision 2.4.3.2—Sampling and analysis

2.44 General requirements for sampling under method 2

(1) A sample of the liquid fuel must be derived from a composite of amounts of the liquid fuel.

(2) The samples must be collected on enough occasions to produce a representative sample.

(3) The samples must also be free of bias so that any estimates are neither over nor under estimates of the true value.

(4) Bias must be tested in accordance with an appropriate standard (if any).

(5) The value obtained from the samples must only be used for the delivery period or consignment of the liquid fuel for which it was intended to be representative.

2.45 Standards for analysing samples of liquid fuels

(1) Samples of liquid fuel of a type mentioned in column 2 of an item in the following table must be analysed in accordance with a standard (if any) mentioned in:

(a) for energy content analysis—column 3 for that item; and

(b) for carbon analysis—column 4 for that item; and

Item	Fuel	Energy Content	Carbon	Density
1	Petroleum based oils (other than petroleum based oils used as fuel)	N/A	ASTM D 5291‑02 (2007)	ASTM D 1298 – 99 (2005)
2	Petroleum based greases	N/A	ASTM D 5291‑02 (2007)	ASTM D 1298 – 99 (2005)
3	Crude oil including crude oil condensates	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	Other natural gas liquids	N/A	N/A	ASTM D 1298 – 99 (2005)
5	Gasoline (other than for use as fuel in an aircraft)	ASTM D 240‑02 (2007) ASTM D 4809‑06	N/A	ASTM D 1298 – 99 (2005)
6	Gasoline for use as fuel in an aircraft	ASTM D 240‑02 (2007) ASTM D 4809‑06	N/A	ASTM D 1298 – 99 (2005)
7	Kerosene (other than for use as fuel in an aircraft)	ASTM D 240‑02 (2007) ASTM D 4809‑06	N/A	ASTM D 1298 – 99 (2005) ASTM D 4052 – 96 (2002) e1
8	Kerosene for use as fuel in an aircraft	ASTM D 240‑02 (2007) ASTM D 4809‑06	N/A	ASTM D 1298 – 99 (2005) ASTM D 4052 – 96 (2002) e1
9	Heating oil	ASTM D 240‑02 (2007) ASTM D 4809‑06	ASTM D 5291‑02 (2007)	ASTM D 1298 – 99 (2005)
10	Diesel oil	ASTM D 240‑02 (2007) ASTM D 4809‑06	ASTM D 5291‑02 (2007)	ASTM D 1298 – 99 (2005)
11	Fuel oil	ASTM D 240‑02 (2007) ASTM D 4809‑06	ASTM D 5291‑02 (2007)	ASTM D 1298 – 99 (2005)
12	Liquefied aromatic hydrocarbons	N/A	N/A	ASTM D 1298 – 99 (2005)
13	Solvents if mineral turpentine or white spirits	N/A	N/A	N/A
14	Liquefied Petroleum Gas	N/A	ISO 7941:1988	ISO 6578:1991 ISO 8973:1997 ASTM D 1657 – 02
15	Naphtha	N/A	N/A	N/A
16	Petroleum coke	N/A	N/A	N/A
17	Refinery gas and liquids	N/A	N/A	N/A
18	Refinery coke	N/A	N/A	N/A
19	Petroleum based products other than: (a) petroleum based oils and petroleum based greases mentioned in items 1and 2 (b) the petroleum based products mentioned in items 3 to 18	N/A	N/A	N/A
20	Biodiesel	N/A	N/A	N/A
21	Ethanol for use as a fuel in an internal combustion engine	N/A	N/A	N/A
22	Biofuels other than those mentioned in items 20 and 21	N/A	N/A	N/A

(2) A liquid fuel of a type mentioned in column 2 of an item in the table in subsection (1) may also be analysed for energy content, carbon and density in accordance with a standard that is equivalent to a standard mentioned in columns 3, 4 and 5 for that item.

(3) Analysis must be undertaken by an accredited laboratory or by a laboratory that meets requirements equivalent to those in AS ISO/IEC 17025:2005.

2.46 Frequency of analysis

Liquid fuel of a type mentioned in column 2 of an item in the following table must be analysed for the parameter mentioned in column 3 for that item at least at the frequency mentioned in column 4 for that item.

Item	Fuel	Parameter	Frequency
1	All types of liquid fuel	Carbon	Quarterly or by delivery of the fuel
2	All types of liquid fuel	Energy	Quarterly or by delivery of the fuel

Division 2.4.4—Method 3—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases

2.47 Method 3—emissions of carbon dioxide from the combustion of liquid fuels

(1) For subparagraph 2.40(1)(a)(iii) and subject to this section, method 3 for estimating emissions of carbon dioxide is the same as method 2 under section 2.42.

(2) In applying method 2 under section 2.42, liquid fuels must be sampled in accordance with a standard specified in the table in subsection (3).

(3) A standard for sampling a liquid fuel of a type mentioned in column 2 of an item in the following table is specified in column 3 for that item.

item	Liquid Fuel	Standard
1	Petroleum based oils (other than petroleum based oils used as fuel)	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06
2	Petroleum based greases
3	Crude oil including crude oil condensates	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)
4	Other natural gas liquids	ASTM D1265 – 05
5	Gasoline (other than for use as fuel in an aircraft)	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)
6	Gasoline for use as fuel in an aircraft	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)
7	Kerosene (other than for use as fuel in an aircraft)	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)
8	Kerosene for use as fuel in an aircraft	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)
9	Heating oil	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)
10	Diesel oil	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)
11	Fuel oil	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)
12	Liquefied aromatic hydrocarbons	ASTM D 4057 – 06
13	Solvents if mineral turpentine or white spirits	ASTM D 4057 – 06
14	Liquefied Petroleum Gas	ASTM D1265 – 05) ISO 4257:2001
15	Naphtha	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06
16	Petroleum coke	ASTM D 4057 – 06
17	Refinery gas and liquids	ASTM D 4057 – 06
18	Refinery coke	ASTM D 4057 – 06
19	Petroleum based products other than: (a) petroleum based oils and petroleum based greases mentioned in items 1 and 2; and (b) the petroleum based products mentioned in items 3 to 18	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06
20	Biodiesel	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)
21	Ethanol for use as a fuel in an internal combustion engine	ASTM D 4057 – 06
22	Biofuels other than those mentioned in items 20 and 21	ISO 3170:2004 ISO 3171:1988 ASTM D 4057 – 06 ASTM D 4177 – 95 (2005)

(4) A liquid fuel may also be sampled in accordance with a standard that is equivalent to a standard set out in the table in subsection (3) in relation to that liquid fuel.

Division 2.4.5—Method 2—emissions of methane and nitrous oxide from liquid fuels other than petroleum based oils or greases

2.48 Method 2—emissions of methane and nitrous oxide from the combustion of liquid fuels

(1) For subparagraph 2.40(1)(b)(ii) and subject to subsection (2), method 2 for estimating emissions of methane and nitrous oxide is the same as method 1 under section 2.41.

(2) In applying method 1 in section 2.41, the emission factor EFijoxec is taken to be the emission factor set out in:

(a) for combustion of fuel by vehicles manufactured after 2004—columns 5 and 6 of the table in Division 4.2 of Part 4 of Schedule 1; and

(b) for combustion of fuel by trucks that meet the design standards mentioned in column 3 of the table in Division 4.3 of Part 4 of Schedule 1—columns 6 and 7 of the table in that Division.

Division 2.4.5A—Methods for estimating emissions of carbon dioxide from petroleum based oils or greases

2.48A Method 1—estimating emissions of carbon dioxide using an estimated oxidation factor

(1) For paragraph 2.40A(1)(a), method 1 for estimating emissions of carbon dioxide from the consumption of petroleum based oils or petroleum based greases using an estimated oxidation factor is:

where:

Epogco2 is the emissions of carbon dioxide released from the consumption of petroleum based oils or petroleum based greases from the operation of the facility during the year measured in CO2‑e tonnes.

Qpog is the quantity of petroleum based oils or petroleum based greases consumed from the operation of the facility, estimated in accordance with Division 2.4.6.

ECpogco2 is the energy content factor of petroleum based oils or petroleum based greases measured in gigajoules per kilolitre as mentioned in Part 3 of Schedule 1.

EFpogco2oxec has the meaning given in subsection (2).

(2) EFpogco2oxec is:

(a) the emission factor for carbon dioxide released from the operation of the facility during the year (which includes the effect of an oxidation factor) measured in kilograms CO2‑e per gigajoule of the petroleum based oils or petroleum based greases as mentioned in Part 3 of Schedule 1; or

(b) to be estimated as follows:

where:

OFpog is the estimated oxidation factor for petroleum based oils or petroleum based greases.

EFpogco2ec is 69.9.

(3) For OFpog in paragraph (2)(b), estimate as follows:

where:

Qpog is the quantity of petroleum based oils or petroleum based greases consumed from the operation of the facility, estimated in accordance with Division 2.4.6.

Oil Transferred Offsitepog is the quantity of oils, derived from petroleum based oils or petroleum based greases, transferred outside the facility, and estimated in accordance with Division 2.4.6.

2.48B Method 2—estimating emissions of carbon dioxide using an estimated oxidation factor

For paragraph 2.40A(1)(b), method 2 is the same as method 1 but the emission factor EFpogco2ec must be determined in accordance with Division 2.4.3.

2.48C Method 3—estimating emissions of carbon dioxide using an estimated oxidation factor

For paragraph 2.40A(1)(c), method 3 is the same as method 1 but the emission factor EFpogco2ec must be determined in accordance with Division 2.4.4.

Division 2.4.6—Measurement of quantity of liquid fuels

2.49 Purpose of Division

This Division sets out how quantities of liquid fuels combusted from the operation of a facility are to be estimated for the purpose of working out the emissions released from the combustion of that fuel.

2.50 Criteria for measurement

(1) For the purpose of calculating the combustion of a liquid fuel from the operation of a facility for a year and, in particular, for Qi in sections 2.41 and 2.42 the combustion must be estimated in accordance with this section.

Acquisition involves commercial transaction

(2) If the acquisition of the liquid fuel involves a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria:

(a) the amount of the liquid fuel delivered for the facility during the year as evidenced by invoices issued by the vendor of the fuel (criterion A);

(b) as provided in section 2.51 (criterion AA);

(3) If, during a year, criterion AA, or criterion AAA using paragraph 2.52(2)(a), is used to estimate the quantity of fuel combusted then, in each year following that year, only criterion AA, or criterion AAA using paragraph 2.52(2)(a), (respectively) may be used.

Acquisition does not involve commercial transaction

(4) If the acquisition of the liquid fuel does not involve a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria:

(a) as provided in paragraph 2.52(2)(a) (criterion AAA);

(b) as provided in section 2.53 (criterion BBB).

2.51 Indirect measurement—criterion AA

For paragraph 2.50(2)(b), criterion AA is the amount of the liquid fuel combusted from the operation of the facility during the year based on amounts delivered during the year (evidenced by invoices) as adjusted for the estimated change in the quantity of the stockpile of the fuel for the facility during the year.

2.52 Direct measurement—criterion AAA

(1) For paragraph 2.50(2)(c), criterion AAA is the measurement during the year of the liquid fuel combusted from the operation of the facility.

(2) The measurement must be carried out:

(a) at the point of combustion at ambient temperatures and converted to standard temperatures, using measuring equipment calibrated to a measurement requirement; or

(b) at ambient temperatures and converted to standard temperatures, at the point of sale of the liquid fuel, using measuring equipment calibrated to a measurement requirement.

(3) Paragraph (2)(b) only applies if:

(a) the change in the stockpile of fuel for the facility for the year is less than 1% of total combustion on average for the facility during the year; and

(b) the stockpile of the fuel for the facility at the beginning of the year is less than 5% of total combustion from the operation of the facility for the year.

2.53 Simplified consumption measurements—criterion BBB

For paragraph 2.50(4)(b), criterion BBB is the estimation of the combustion of a liquid fuel for the year using accepted industry measuring devices or, in the absence of such measuring devices, in accordance with industry practice if the equipment used to measure consumption of the fuel is not calibrated to a measurement requirement.

Part 2.5—Emissions released from fuel use by certain industries

2.54 Application

This Part applies to emissions from petroleum refining, solid fuel transformation (coke ovens) and petrochemical production.

Division 2.5.1—Energy—petroleum refining

2.55 Application

This Division applies to petroleum refining.

2.56 Methods

(1) If:

(a) the operation of a facility is constituted by petroleum refining; and

(b) the refinery combusts fuels for energy;

then the methods for estimating emissions during a year from that combustion are as provided in Parts 2.2, 2.3 and 2.4.

(2) The method for estimating emissions from the production of hydrogen by the petroleum refinery must be in accordance with the method set out in section 5 of the API Compendium.

(3) Fugitive emissions released from the petroleum refinery must be estimated using methods provided for in Chapter 3.

Division 2.5.2—Energy—manufacture of solid fuels

2.57 Application

This Division applies to solid fuel transformation through the pyrolysis of coal or the coal briquette process.

2.58 Methods

(1) One or more of the following methods must be used for estimating emissions during the year from combustion of fuels for energy in the manufacture of solid fuels:

(a) if a facility is constituted by the manufacture of solid fuel using coke ovens as part of an integrated metalworks—the methods provided in Part 4.4 must be used; and

(b) in any other case—one of the following methods must be used:

(i) method 1 under subsection (3);

(ii) method 2 under subsections (4) to (7);

(iii) method 3 under subsections (8) to (10);

(iv) method 4 under Part 1.3.

(2) These emissions are taken to be emissions from fuel combustion.

Method 1

(3) Method 1, based on a carbon mass balance approach, is:

Step 1	Work out the carbon content in fuel types (i) or carbonaceous input material delivered for the activity during the year, measured in tonnes of carbon, as follows:
	where: i means the sum of the carbon content values obtained for all fuel types (i) or carbonaceous input material.
	CCFi is the carbon content factor mentioned in Schedule 3, measured in tonnes of carbon, for each appropriate unit of fuel type (i) or carbonaceous input material consumed during the year from the operation of the activity.
	Qi is the quantity of fuel type (i) or carbonaceous input material delivered for the activity during the year, measured in an appropriate unit and estimated in accordance with criterion A in Divisions 2.2.5, 2.3.6 and 2.4.6.
Step 2	Work out the carbon content in products (p) leaving the activity during the year, measured in tonnes of carbon, as follows:
Step 2	where: p means the sum of the carbon content values obtained for all product types (p). CCFp is the carbon content factor, measured in tonnes of carbon, for each tonne of product type (p) produced during the year. Ap is the quantity of product types (p) produced leaving the activity during the year, measured in tonnes.
Step 3	Work out the carbon content in waste by‑product types (r) leaving the activity, other than as an emission of greenhouse gas, during the year, measured in tonnes of carbon, as follows:
	where: r means the sum of the carbon content values obtained for all waste by‑product types (r).
	CCFr is the carbon content factor, measured in tonnes of carbon, for each tonne of waste by‑product types (r). Yr is the quantity of waste by‑product types (r) leaving the activity during the year, measured in tonnes.
Step 4	Work out the carbon content in the amount of the change in stocks of inputs, products and waste by‑products held within the boundary of the activity during the year, measured in tonnes of carbon, as follows:
Step 4	where: i has the same meaning as in step 1.
	CCFi has the same meaning as in step 1. ΔSqi is the change in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year, measured in tonnes.
	p has the same meaning as in step 2. CCFp has the same meaning as in step 2.
	ΔSap is the change in stocks of product types (p) produced by the activity and held within the boundary of the activity during the year, measured in tonnes.
	r has the same meaning as in step 3. CCFr has the same meaning as in step 3. ΔSyr is the change in stocks of waste by‑product types (r) produced from the operation of the activity and held within the boundary of the activity during the year, measured in tonnes.
Step 5	Work out the emissions of carbon dioxide released from the operation of the activity during the year, measured in CO2‑e tonnes, as follows: (a) add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A); (b) subtract amount A from the amount worked out under step 1 to work out a new amount (amount B); (c) multiply amount B by 3.664 to work out the amount of emissions released from the operation of the activity during the year.

Method 2

(4) Subject to subsections (5) to (7), method 2 is the same as method 1 under subsection (3).

(5) In applying method 1 as method 2, step 4 in subsection (3) is to be omitted and the following step 4 substituted.

Step 4	Work out the carbon content in the amount of the change in stocks of inputs, products and waste by‑products held within the boundary of the activity during the year, measured in tonnes of carbon, as follows:
Step 4	where: i has the same meaning as in step 1. CCFi has the same meaning as in step 1. ΔSqi is the change in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year, measured in tonnes.
	p has the same meaning as in step 2. CCFp has the same meaning as in step 2. ΔSap is the change in stocks of product types (p) produced by the activity and held within the boundary of the activity during the year, measured in tonnes. r has the same meaning as in step 3.
	CCFr has the same meaning as in step 3.
	ΔSyr is the change in stocks of waste by‑product types (r) produced from the operation of the activity and held within the boundary of the activity during the year, measured in tonnes.
	α is the factor for converting the mass of carbon dioxide to a mass of carbon.
	γ is the factor 1.861 × 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes. RCCSCO2 is carbon dioxide captured for permanent storage, measured in cubic metres in accordance with Division 1.2.3.

(6) If a fuel type (i) or carbonaceous input material delivered for the activity during the year accounts for more than 5% of total carbon input for the activity, based on a calculation using the factors specified in Schedule 3, sampling and analysis of fuel type (i) or carbonaceous input material must be carried out to determine its carbon content.

(7) The sampling and analysis is to be carried out using the sampling and analysis provided for in Divisions 2.2.3, 2.3.3 and 2.4.3 that apply to the combustion of solid, gaseous and liquid fuels.

Method 3

(8) Subject to subsections (9) and (10), method 3 is the same as method 2 under subsections (4) to (7).

(9) If a fuel type (i) or carbonaceous input material delivered for the activity during the year accounts for more than 5% of total carbon input for the activity, based on a calculation using the factors specified in Schedule 3, sampling and analysis of fuel type (i) or carbonaceous input material must be carried out to determine its carbon content.

(10) The sampling and analysis is to be carried out using the methods set out in Divisions 2.2.4, 2.3.4 and 2.4.4 that apply to the combustion of solid, gaseous and liquid fuels.

Division 2.5.3—Energy—petrochemical production

2.59 Application

This Division applies to petrochemical production (where fuel is consumed as a feedstock).

2.60 Available methods

(1) Subject to section 1.18 one of the following methods must be used for estimating emissions released during a year from the operation of a facility that is constituted by an activity that is petrochemical production:

(a) method 1 under section 2.61;

(b) method 2 under section 2.62;

(d) method 4 under Part 1.3.

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

2.61 Method 1—petrochemical production

Method 1, based on a carbon mass balance approach, is:

Step 1	Calculate the carbon content in all fuel types (i) delivered for the activity during the year as follows:
	where: i means sum the carbon content values obtained for all fuel types (i). CCFi is the carbon content factor measured in tonnes of carbon for each tonne of fuel type (i) as mentioned in Schedule 3 consumed in the operation of the activity. Qi is the quantity of fuel type (i) delivered for the activity during the year measured in tonnes and estimated in accordance with criterion A in Divisions 2.2.5, 2.3.6 and 2.4.6.
Step 2	Calculate the carbon content in products (p) leaving the activity during the year as follows:
	where: p means sum the carbon content values obtained for all product types (p).
	CCFp is the carbon content factor measured in tonnes of carbon for each tonne of product (p).
	Ap is the quantity of products produced (p) leaving the activity during the year measured in tonnes.
Step3	Calculate the carbon content in waste by‑products (r) leaving the activity, other than as an emission of greenhouse gas, during the year as follows:
	where: r means sum the carbon content values obtained for all waste by‑product types (r). CCFr is the carbon content factor measured in tonnes of carbon for each tonne of waste by‑product (r). Yr is the quantity of waste by‑product (r) leaving the activity during the year measured in tonnes.
Step 4	Calculate the carbon content in the amount of the increase in stocks of inputs, products and waste by‑products held within the boundary of the activity during the year as follows:
	where: i has the same meaning as in step 1. CCFi has the same meaning as in step 1. ΔSqi is the increase in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year measured in tonnes. p has the same meaning as in step 2. CCFp has the same meaning as in step 2. ΔSap is the increase in stocks of products produced (p) by the activity and held within the boundary of the activity during the year measured in tonnes.
	r has the same meaning as in step 3. CCFr has the same meaning as in step 3. ΔSyr is the increase in stocks of waste by‑products (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes.
Step 5	Calculate the emissions of carbon dioxide released from the activity during the year measured in CO2‑e tonnes as follows: (a) add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A) (b) subtract amount A from the amount worked out under step 1 to work out a new amount (amount B); (c) multiply amount B by 3.664 to work out the amount of emissions released from the activity during a year.

2.62 Method 2—petrochemical production

(1) Subject to subsections (2) and (3), method 2 is the same as method 1 under section 2.61 but sampling and analysis of fuel types (i) is used to determine carbon content of the fuel.

(2) The sampling and analysis is to be carried out using the methods set out in Divisions 2.2.3, 2.3.3 and 2.4.3 that apply to the combustion of solid, liquid or gaseous fuels.

(3) In applying method 1 as method 2, step 4 in section 2.61 is to be omitted and the following step 4 substituted:

Step 4	Calculate the carbon content in the amount of the increase in stocks of inputs, products and waste by‑products held within the boundary of the activity during the year as follows:
Step 4
	where: i has the same meaning as in step 1. CCFi has the same meaning as in step 1.
	ΔSqi is the increase in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year measured in tonnes.
	p has the same meaning as in step 2.
	CCFp has the same meaning as in step 2.
	ΔSap is the increase in stocks of products produced (p) by the activity and held within the boundary of the activity during the year measured in tonnes.
	r has the same meaning as in step 3. CCFr has the same meaning as in step 3.ΔSyr is the increase in stocks of waste by‑products (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes.
	α is the factor for converting the mass of carbon dioxide to a mass of carbon.
	γ is the factor 1.861 x 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes. RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.

2.63 Method 3—petrochemical production

(1) Subject to subsections (2) and (3), method 3 is the same as method 1 in section 2.61 but the sampling and analysis of fuel types (i) is used to determine carbon content of the fuel.

(2) The sampling and analysis is to be carried out using the methods set out in Divisions 2.2.4, 2.3.4 and 2.4.4 that apply to the combustion of solid, liquid or gaseous fuels.

(3) In applying method 1 as method 3, step 4 in section 2.61 is to be omitted and the following step 4 substituted.

Step 4	Calculate the carbon content in the amount of the increase in stocks of inputs, products and waste by‑products held within the boundary of the activity during the year as follows:

	where: i has the same meaning as in step 1. CCFi has the same meaning as in step 1. ΔSqi is the increase in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year measured in tonnes. p has the same meaning as in step 2. CCFp has the same meaning as in step 2. ΔSap is the increase in stocks of products produced (p) by the activity and held within the boundary of the activity during the year measured in tonnes.
	r has the same meaning as in step 3. CCFr has the same meaning as in step 3. ΔSyr is the increase in stocks of waste by‑products (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes.
	α is the factor for converting the mass of carbon dioxide to a mass of carbon.
	γ is the factor 1.861 x 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes. RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.

Part 2.6—Blended fuels

2.64 Purpose

This Part sets out how to determine the amounts of each kind of fuel that is in a blended fuel.

2.65 Application

This Part sets out how to determine the amount of each fuel type (i) that is in a blended fuel if that blended fuel is a solid fuel or a liquid fuel.

2.66 Blended solid fuels

(1) In determining the amounts of each kind of fuel that is in a blended solid fuel, a person may adopt the outcome of the sampling and analysis done by the manufacturer of the fuel if:

(a) the sampling has been done in accordance with subsections 2.12(3) and (4); and

(b) the analysis has been done in accordance with one of the following standards or a standard that is equivalent to one of those standards:

(i) CEN/TS15440:2006;

(ii) ASTM D6866—10.

(2) The person may use his or her own sampling and analysis of the fuel if the sampling and analysis complies with the requirements of paragraphs (1)(a) and (b).

2.67 Blended liquid fuels

The person may adopt the manufacturer’s determination of each kind of fuel that is in a blended liquid fuel or adopt the analysis arrived at after doing both of the following:

(a) sampling the fuel in accordance with a standard mentioned in subsections 2.47(3) and (4);

(b) analysing the fuel in accordance with ASTM: D6866—10 or a standard that is equivalent to that standard.

Part 2.7—Estimation of energy for certain purposes

2.68 Amount of energy consumed without combustion

For paragraph 4.22(1)(b) of the Regulations:

(a) the energy is to be measured:

(i) for solid fuel—in tonnes estimated under Division 2.2.5; or

(ii) for gaseous fuel—in cubic metres estimated under Division 2.3.6; or

(iii) for liquid fuel—in kilolitres estimated under Division 2.4.6; and

(iv) for electricity—in kilowatt hours:

(A) worked out using the evidence mentioned in paragraph 6.5(2)(a); or

(B) if the evidence mentioned in paragraph 6.5(2)(a) is unavailable—estimated in accordance with paragraph 6.5(2)(b).

(b) the reporting threshold is:

(i) for solid fuel—20 tonnes; or

(ii) for gaseous fuel—13 000 cubic metres; or

(iii) for liquid fuel—15 kilolitres; or

(iv) for electricity consumed from a generating unit at the facility—that each generating unit has a maximum capacity to produce at least 0.5 megawatts of electricity and produces over 100 000 kilowatt hours of electricity in a reporting year; or

(v) for electricity consumed that was not generated by a generating unit at the facility—20 000 kilowatt hours.

Example: A fuel is consumed without combustion when it is used as a solvent or a flocculent, or as an ingredient in the manufacture of products such as paints, solvents or explosives.

2.69 Apportionment of fuel consumed as carbon reductant or feedstock and energy

(1) This section applies, other than for Division 2.5.3, if:

(a) a fuel type as provided for in a method is consumed from the operation of a facility as either a reductant or a feedstock; and

(b) the fuel is combusted for energy; and

(c) the equipment used to measure the amount of the fuel for the relevant purpose was not calibrated to a measurement requirement.

Note: Division 2.5.3 deals with petrochemicals. For petrochemicals, all fuels, whether used as a feedstock, a reductant or combusted as energy are reported as energy.

(2) The amount of the fuel type consumed as a reductant or a feedstock may be estimated:

(a) in accordance with industry measuring devices or industry practice; or

(b) if it is not practicable to estimate as provided for in paragraph (a)—to be the whole of the amount of the consumption of that fuel type from the operation of the facility.

(3) The amount of the fuel type combusted for energy may be estimated as the difference between the total amount of the fuel type consumed from the operation of the facility and the estimated amount worked out under subsection (2).

2.70 Amount of energy consumed in a cogeneration process

(1) For subregulation 4.23(3) of the Regulations and subject to subsection (3), the method is the efficiency method.

(2) The efficiency method is as described in the publication entitled Allocation of Emissions from a Combined Heat and Power (CHP) Plant Guide to calculation worksheets (September 2006) v1.0 issued by the World Resource Institute and World Business Council for Sustainable Development.

(3) Where heat is to be used mainly for producing mechanical work, the work potential method may be used.

(4) The work potential method is as described in the publication entitled Allocation of Emissions from a Combined Heat and Power (CHP) Plant Guide to calculation worksheets (September 2006) v1.0 issued by the World Resource Institute and World Business Council for Sustainable Development.

2.71 Apportionment of energy consumed for electricity, transport and for stationary energy

Subject to section 2.70, the amount of fuel type (i) consumed by a reporting corporation or registered person that is apportioned between electricity generation, transport (excluding international bunker fuels) and other stationary energy purposes may be determined using the records of the corporation or registered person if the records are based on the measurement equipment used by the corporation or the registered person to measure consumption of the fuel types.

Chapter 3—Fugitive emissions

Part 3.1—Preliminary

3.1 Outline of Chapter

This Chapter provides for fugitive emissions from the following:

(a) coal mining (see Part 3.2);

(b) oil and natural gas (see Part 3.3);

Part 3.2—Coal mining—fugitive emissions

Division 3.2.1—Preliminary

3.2 Outline of Part

This Part provides for fugitive emissions from coal mining, as follows:

(a) underground mining activities (see Division 3.2.2);

(b) open cut mining activities (see Division 3.2.3);

Division 3.2.2—Underground mines

Subdivision 3.2.2.1—Preliminary

3.3 Application

This Division applies to fugitive emissions from underground mining activities (other than decommissioned underground mines).

3.4 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 underground mining activities (other than decommissioned underground mines) the methods as set out in this section must be used.

Methane from extraction of coal

(2) Method 4 under section 3.6 must be used for estimating fugitive emissions of methane that result from the extraction of coal from the underground mine.

Note: There is no method 1, 2 or 3 for subsection (2).

Carbon dioxide from extraction of coal

(3) Method 4 under section 3.6 must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the underground mine.

Note: There is no method 1, 2 or 3 for subsection (3).

Flaring

(4) For estimating emissions released from coal mine waste gas flared from the underground mine:

(a) one of the following methods must be used for estimating emissions of carbon dioxide released:

(i) method 1 under section 3.14;

(ii) method 2 under section 3.15;

(iii) method 3 under section 3.16; and

(b) one of the following methods must be used for estimating emissions of methane released:

(i) method 1 under section 3.14;

(ii) method 2 under section 3.15A; and

(i) method 1 under section 3.14;

(ii) method 2 under section 3.15A.

Note: The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 under section 3.14 or method 2 under section 3.15A is a reference to these gases. The same formula in Method 1 is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide and no method 3 or 4 for emissions of methane or nitrous oxide.

Venting or other fugitive release before extraction of coal

(5) Method 4 under Part 1.3 must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, that result from venting or other fugitive release of gas from the underground mine before coal is extracted from the mine.

Note: There is no method 1, 2 or 3 for subsection (5).

Post‑mining activities

(6) Method 1 under section 3.17 must be used for estimating fugitive emissions of methane that result from post‑mining activities related to a gassy mine.

Note: There is no method 2, 3 or 4 for subsection (6).

(7) However, for incidental emissions, another method may be used that is consistent with the principles in section 1.13.

Subdivision 3.2.2.2—Fugitive emissions from extraction of coal

3.5 Method 1—extraction of coal

For subsection 3.32(1), method 1 is:

where:

Ej is the fugitive emissions of methane (j) that result from the extraction of coal from the mine during the year measured in CO2‑e tonnes.

Q is the quantity of run‑of‑mine coal extracted from the mine during the year measured in tonnes.

EFj is the emission factor for methane (j), measured in CO2‑e tonnes per tonne of run‑of‑mine coal extracted from the mine, as follows:

(a) for a gassy mine—0.407;

(b) for a non‑gassy mine—0.011.

3.6 Method 4—extraction of coal

(1) For subsections 3.4(2) and (3), method 4 is:

where:

Ej is the fugitive emissions of gas type (j) that result from the extraction of coal from the mine during the year, measured in CO2‑e tonnes.

CO2‑e j gen, total is the total mass of gas type (j) generated from the mine during the year before capture and flaring is undertaken at the mine, measured in CO2‑e tonnes and estimated using the direct measurement of emissions in accordance with subsection (2).

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes, being:

(a) for methane—6.784 × 10‑4 × GWPmethane; and

(b) for carbon dioxide—1.861 × 10‑3.

Qij,cap is the quantity of gas type (j) in coal mine waste gas type (i) captured for combustion from the mine and used during the year, measured in cubic metres and estimated in accordance with Division 2.3.6.

Qij,flared is the quantity of gas type (j) in coal mine waste gas type (i) flared from the mine during the year, measured in cubic metres and estimated in accordance with Division 2.3.6.

Qijtr is the quantity of gas type (j) in coal mine waste gas type (i) transferred out of the mining activities during the year measured in cubic metres.

(2) The direct measurement of emissions released from the extraction of coal from an underground mine during a year by monitoring the gas stream at the underground mine may be undertaken by one of the following:

(a) continuous emissions monitoring (CEM) in accordance with Part 1.3;

(b) periodic emissions monitoring (PEM) in accordance with sections 3.7 to 3.13.

Note: Any estimates of emissions must be consistent with the principles in section 1.13.

(3) For Qijtr in subsection (1), the quantity of gas type (j) must be estimated in accordance with Division 2.3.6 as if a reference in that Division to quantities of gaseous fuels combusted from the operation of a facility was a reference to quantities of gaseous fuels transferred out of the operation of a facility.

3.7 Estimation of emissions

(1) To obtain an estimate of the mass emissions rate of gas (j), being methane and carbon dioxide, at the time of measurement at the underground mine, the formula in subsection 1.21(1) must be applied.

(2) The mass of emissions estimated under the formula must be converted into CO2‑e tonnes.

(3) The average mass emission rate for gas type (j) measured in CO2–e tonnes per hour for a year must be calculated from the estimates obtained under subsections (1) and (2).

(4) The total mass of emissions of gas type (j) from the underground mine for the year is calculated by multiplying the average emissions rate obtained under subsection (3) by the number of hours during the year.

3.8 Overview—use of equipment

The following requirements apply to the use of PEM equipment:

(a) the requirements in section 3.9 about location of the sampling positions for the PEM equipment;

(b) the requirements in section 3.10 about measurement of volumetric flow rates in a gas stream;

(d) the requirements in section 3.12 about representative data.

(e) the requirements in section 3.13 about performance characteristics of equipment.

3.9 Selection of sampling positions for PEM

For paragraph 3.8(a), an appropriate standard or applicable State or Territory legislation must be complied with for the location of sampling positions for PEM equipment.

Note: Appropriate standards include:

 AS 4323.1—1995/Amdt 1‑1995, Stationary source emissions—Selection of sampling positions

 USEPA Method 1—Sample and velocity traverses for stationary sources (2000)

3.10 Measurement of volumetric flow rates by PEM

For paragraph 3.8(b), the measurement of the volumetric flow rates by PEM of the gas stream must be undertaken in accordance with an appropriate standard or applicable State or Territory legislation.

Note: Appropriate standards include:

 ISO 14164:1999 Stationary source emissions. Determination of the volume flowrate of gas streams in ducts – automated method

 ISO 10780:1994 Stationary source emissions. Measurement of velocity and volume flowrate of gas streams in ducts

 USEPA Method 2—Determination of stack gas velocity and volumetric flow rate (Type S Pitot tube) (2000)

 USEPA Method 2A—Direct measurement of gas volume through pipes and small ducts (2000).

3.11 Measurement of concentrations by PEM

For paragraph 3.8(c), the measurement of the concentrations of gas type (j) in the gas stream by PEM must be undertaken in accordance with an appropriate standard or applicable State or Territory legislation.

Note: Appropriate standards include USEPA—Method 3C—Determination of carbon dioxide, methane, nitrogen and oxygen from stationary sources (1996).

3.12 Representative data for PEM

(1) For paragraph 3.8(d), sampling by PEM must be undertaken during the year for a sufficient duration to produce representative data that may be reliably extrapolated to provide estimates of emissions across the full range of operating conditions for that year.

(2) Emission estimates of PEM equipment must also be consistent with the principles in section 1.13.

3.13 Performance characteristics of equipment

For paragraph 3.8(e), the performance characteristics of PEM equipment must be consistent with an appropriate standard or applicable State or Territory legislation.

Note: The performance characteristics of PEM equipment includes calibration.

Subdivision 3.2.2.3—Emissions released from coal mine waste gas flared

3.14 Method 1—coal mine waste gas flared

For subparagraph 3.4(4)(a)(i) and paragraphs 3.4(4)(b) and (c), method 1 is:

where:

E(fl)ij is the emissions of gas type (j) released from coal mine waste gas (i) flared from the mine during the year, measured in CO2‑e tonnes.

Qi,flared is the quantity of coal mine waste gas (i) flared from the mine during the year, measured in cubic metres and estimated under Division 2.3.6.

ECi is the energy content factor of coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in gigajoules per cubic metre.

EFij is the emission factor for gas type (j) and coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in CO2‑e kilograms per gigajoule.

OFif is 0.98, which is the destruction efficiency of coal mine waste gas (i) flared.

3.15 Method 2—emissions of carbon dioxide from coal mine waste gas flared

For subparagraph 3.4(4)(a)(ii), method 2 is:

where:

EiCO2 is the emissions of CO2 released from coal mine waste gas (i) flared from the mine during the year, measured in CO2‑e tonnes.

ECi is the energy content factor of the methane (k) within coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in gigajoules per cubic metre.

EFk is the emission factor for the methane (k) within the fuel type from the mine during the year, measured in kilograms of CO2‑e per gigajoule, estimated in accordance with Division 2.3.3.

OFi is 0.98, which is the destruction efficiency of coal mine waste gas (i) flared.

Qk is the quantity of methane (k) within the fuel type from the mine during the year, measured in cubic metres in accordance with Division 2.3.6.

QCO2 is the quantity of carbon dioxide within the coal mine waste gas emitted from the mine during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.

3.15A Method 2—emissions of methane and nitrous oxide from coal mine waste gas flared

For subparagraphs 3.4(4)(b)(ii) and (c)(ii), method 2 is:

where:

Eij is the emissions of gas type (j), being methane or nitrous oxide, released from coal mine waste gas (i) flared from the mine during the year, measured in CO2‑e tonnes.

ECi is the energy content factor of methane (k) within coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in gigajoules per cubic metre.

EFkj is the emission factor of gas type (j), being methane or nitrous oxide, for the quantity of methane (k) within coal mine waste gas (i) flared, mentioned in item 19 of Schedule 1 and measured in kilograms of CO2‑e per gigajoule.

OFi is 0.98, which is the destruction efficiency of coal mine waste gas (i) flared.

Qk is the quantity of methane (k) within the coal mine waste gas (i) flared from the mine during the year, measured in cubic metres in accordance with Division 2.3.3.

3.16 Method 3—coal mine waste gas flared

(1) For subparagraph 3.4(4)(a)(iii), method 3 is the same as method 2 under section 3.15.

(2) In applying method 2 under section 3.15, the facility specific emission factor EFk must be determined in accordance with the procedure for determining EFiCO2oxec in Division 2.3.4.

Subdivision 3.2.2.4—Fugitive emissions from post‑mining activities

3.17 Method 1—post‑mining activities related to gassy mines

(1) For subsection 3.4(6), method 1 is the same as method 1 under section 3.5.

(2) In applying method 1 under section 3.5, EFj is taken to be 0.019, which is the emission factor for methane (j), measured in CO2‑e tonnes per tonne of run‑of‑mine coal extracted from the mine.

Division 3.2.3—Open cut mines

Subdivision 3.2.3.1—Preliminary

3.18 Application

This Division applies to fugitive emissions from open cut mining activities.

3.19 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 an open cut mine the methods as set out in this section must be used.

Methane from extraction of coal

(2) Subject to subsection (7), one of the following methods must be used for estimating fugitive emissions of methane that result from the extraction of coal from the mine:

(a) method 1 under section 3.20;

(b) method 2 under section 3.21;

Note: There is no method 4 for subsection (2).

Carbon dioxide from extraction of coal

(3) If method 2 under section 3.21 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the open cut mine.

(4) If method 3 under section 3.26 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the open cut mine.

Note: There is no method 1 or 4 for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from an open cut mine.

Flaring

(5) For estimating emissions released from coal mine waste gas flared from the open cut mine:

(a) one of the following methods must be used for estimating emissions of carbon dioxide released:

(i) method 1 under section 3.27;

(ii) method 2 under section 3.28;

(iii) method 3 under section 3.29; and

(b) method 1 under section 3.27 must be used for estimating emissions of methane released; and

Note: The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 2, 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.

Venting or other fugitive release before extraction of coal

(6) Method 4 under Part 1.3 must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, that result from venting or other fugitive release of gas from the mine before coal is extracted from the mine.

Note: There is no method 1, 2 or 3 for subsection (6).

(7) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

Subdivision 3.2.3.2—Fugitive emissions from extraction of coal

3.20 Method 1—extraction of coal

For paragraph 3.19(2)(a), method 1 is:

where:

Ej is the fugitive emissions of methane (j) that result from the extraction of coal from the mine during the year measured in CO2‑e tonnes.

Q is the quantity of run‑of‑mine coal extracted from the mine during the year measured in tonnes.

EFj is the emission factor for methane (j), measured in CO2‑e tonnes per tonne of run‑of‑mine coal extracted from the mine, taken to be the following:

(a) for a mine in New South Wales—0.061;

(b) for a mine in Victoria—0.0003;

(d) for a mine in Western Australia—0.023;

(e) for a mine in South Australia—0.0003;

(f) for a mine in Tasmania—0.019.

3.21 Method 2—extraction of coal

(1) For paragraph 3.19(2)(b) and subsection 3.19(3), method 2 is:

where:

Ej is the fugitive emissions of gas type (j) that result from the extraction of coal from the mine during the year, measured in CO2‑e tonnes.

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes, as follows:

(a) for methane—6.784 × 10‑4 × GWPmethane;

(b) for carbon dioxide—1.861 × 10‑3.

∑z (Sj,z) is the total of gas type (j) in all gas bearing strata (z) under the extraction area of the mine during the year, measured in cubic metres, where the gas in each strata is estimated under section 3.22.

(2) Method 2 requires each gas in a gas bearing strata to be sampled and analysed in accordance with the requirements in sections 3.24, 3.25 and 3.25A.

3.22 Total gas contained by gas bearing strata

(1) For method 2 under subsection 3.21(1), Sj,z for gas type (j) contained in a gas bearing strata (z) under the extraction area of the mine during the year, measured in cubic metres, is:

where:

Mz is the mass of the gas bearing strata (z) under the extraction area of the mine during the year, measured in tonnes.

βz is the proportion of the gas content of the gas bearing strata (z) that is released by extracting coal from the extraction area of the mine during the year, as follows:

(a) if the gas bearing strata is at or above the pit floor—1;

(b) in any other case—as estimated under section 3.23.

GCjz is the content of gas type (j) contained by the gas bearing strata (z) before gas capture, flaring or venting is undertaken at the extraction area of the mine during the year, measured in cubic metres per tonne of gas bearing strata at standard conditions.

∑Qij,cap,z is the total quantity of gas type (j) in coal mine waste gas (i) captured for combustion from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres.

∑Qij,flared,z is the total quantity of gas type (j) in coal mine waste gas (i) flared from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres.

∑Qijtr is the total quantity of gas type (j) in coal mine waste gas (i) transferred out of the mining activities at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres.

∑Ej,vented,z is the total emissions of gas type (j) vented from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres and estimated under subsection 3.19 (6).

(2) For ∑Qij,cap,z, ∑Qij,flared,z and ∑Qijtr in subsection (1), the quantity of gas type (j) must be estimated in accordance with Division 2.3.6 as if a reference in that Division to quantities of gaseous fuels combusted from the operation of a facility was a reference to the following:

(a) for ∑Qij,cap,z—quantities of gaseous fuels captured from the operation of a facility;

(b) for ∑tQij,flared,z—quantities of gaseous fuels flared from the operation of a facility;

(3) In subsection (1), ∑Qijtr applies to carbon dioxide only if the carbon dioxide is captured for permanent storage.

Note: Division 1.2.3 contains a number of requirements in relation to deductions of carbon dioxide captured for permanent storage.

(4) For GCjz in subsection (1), the content of gas type (j) contained by the gas bearing strata (z) must be estimated in accordance with sections 3.24, 3.25, 3.25A and 3.25B.

3.23 Estimate of proportion of gas content released below pit floor

For paragraph (b) of the factor βz in subsection 3.22(1), estimate βz using one of the following equations:

(a) equation 1:

;

(b) equation 2:

where:

x is the depth in metres of the floor of the gas bearing strata (z) measured from ground level.

h is the depth in metres of the pit floor of the mine measured from ground level.

dh is 20, being representative of the depth in metres of the gas bearing strata below the pit floor that releases gas.

3.24 General requirements for sampling

(1) Core samples of a gas bearing strata must be collected to produce estimates of gas content that are representative of the gas bearing strata in the extraction area of the mine during the year.

(2) The sampling process must also be free of bias so that any estimates are neither over nor under estimates of the true value.

(3) Bias must be tested in accordance with an appropriate standard (if any).

(4) The value obtained from the samples must only be used for the open cut mine from which it was intended to be representative.

(5) Sampling must be carried out in accordance with:

(a) the minimum requirements for data collection and gas testing mentioned in section 2 of the ACARP Guidelines; and

(b) the data validation, analysis and interpretation processes mentioned in section 3 of the ACARP Guidelines.

3.25 General requirements for analysis of gas and gas bearing strata

Analysis of a gas and a gas bearing strata, including the mass and gas content of the strata, must be done in accordance with:

(a) the minimum requirements for data collection and gas testing mentioned in section 2 of the ACARP Guidelines; and

(b) the data validation, analysis and interpretation processes mentioned in section 3 of the ACARP Guidelines; and

(c) the method of applying the gas distribution model to develop an emissions estimate for an open cut mine mentioned in section 4 of the ACARP Guidelines.

3.25A Method of working out base of the low gas zone

(1) The estimator must:

(a) take all reasonable steps to ensure that samples of gas taken from the gas bearing strata of the open cut mine are taken in accordance with the minimum requirements for data collection and gas testing mentioned in section 2 of the ACARP Guidelines; and

(b) take all reasonable steps to ensure that samples of gas taken from boreholes are taken in accordance with the requirements for:

(i) the number of boreholes mentioned in sections 2 and 3 of the ACARP Guidelines; and

(ii) borehole spacing mentioned in section 2 of the ACARP Guidelines; and

(iii) sample selection mentioned in section 2 of the ACARP Guidelines; and

(d) if the base of the low gas zone worked out in accordance with subsection (2) varies, in a vertical plane, within:

(i) a range of 20 metres between boreholes located in the same domain of the open cut mine—work out the base of the low gas zone using the method mentioned in subsection (3); or

(ii) a range of greater than 20 metres between boreholes located in the same domain of the open cut mine—the method mentioned in subsection (4).

Preliminary method of working out base of low gas zone

(2) For paragraph (1)(c), the method is that the estimator must perform the following steps:

Step 1

For each borehole, identify the depth at which:

(a) the results of greater than 3 consecutive samples taken in the borehole indicate that the gas content of the gas bearing strata is greater than 0.5 m3/t; or

(b) the results of 3 consecutive samples taken in the borehole indicate that the methane composition of the gas bearing strata is greater than 50% of total gas composition by volume.

Step 2

If paragraph (a) or (b) of step 1 applies, identify, for each borehole, the depth of the top of the gas bearing strata at which the first of the 3 consecutive samples in the borehole was taken.

Note The depth of the top of the gas bearing strata worked out under step 2 is the same as the depth of the base of the low gas zone.

Method of working out base of low gas zone for subparagraph (1)(d)(i)

(3) For subparagraph (1)(d)(i), the method is that the estimator must work out the average depth at which step 2 of the method in subsection (2) applies.

Method of working out base of low gas zone for subparagraph (1)(d)(ii)

(4) For subparagraph (1)(d)(ii), the method is that the estimator must construct a 3‑dimensional model of the surface of the low gas zone using a triangulation algorithm or a gridding algorithm.

3.25B Further requirements for estimator

(1) This section applies if:

(a) the estimator constructs a 3‑dimensional model of the surface of the base of the low gas zone in accordance with the method mentioned in subsection 3.25A(4); and

(b) the 3‑dimensional model of the surface of the low gas zone is extrapolated beyond the area modelled directly from boreholes in the domain.

(2) The estimator must:

(a) ensure that the extrapolated surface:

(i) applies the same geological modelling rules that were applied in the generation of the surface of the base of the low gas zone from the boreholes; and

(ii) represents the base of the low gas zone in relation to the geological structures located within the domain; and

(iii) is generated using a modelling methodology that is consistent with the geological model used to estimate the coal resource; and

(iv) the geological model used to estimate the coal resource meets the minimum requirements and the standard of quality mentioned in section 1 of the ACARP Guidelines.

(b) make and retain a record:

(i) of the data and assumptions incorporated into the generation of the 3‑dimensional surface; and

(ii) that demonstrates that the delineation of the 3‑dimensional surface complies with sections 1.13 and 3.24.

3.25C Default gas content for gas bearing strata in low gas zone

A default gas content of 0.00023 tonnes of carbon dioxide per tonne of gas bearing strata must be assigned to all gas bearing strata located in the low gas zone.

3.25D Requirements for estimating total gas contained in gas bearing strata

(1) The total gas contained in gas bearing strata for an open cut coal mine must be estimated in accordance with the emissions estimation process mentioned in section 1 of the ACARP Guidelines.

(2) The gas distribution model used for estimating emissions must be applied in accordance with section 4.1 of the ACARP Guidelines; and

(3) The modelling bias must be assessed in accordance with section 4.2 of the ACARP Guidelines.

(4) The gas distribution model must be applied to the geology model in accordance with section 4.3 of the ACARP Guidelines.

3.26 Method 3—extraction of coal

(1) For paragraph 3.19(2)(c) and subsection 3.19(4), method 3 is the same as method 2 under section 3.21

(2) In applying method 2 under section 3.21 a sample of gas bearing strata must be collected in accordance with an appropriate standard, including:

(a) AS 2617—1996 Sampling from coal seams or an equivalent standard; and

(b) AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits or an equivalent standard.

Subdivision 3.2.3.3—Emissions released from coal mine waste gas flared

3.27 Method 1—coal mine waste gas flared

(1) For subparagraph 3.19(5)(a)(i) and paragraph 3.19(5)(b) and paragraph (5)(c), method 1 is the same as method 1 under section 3.14.

(2) In applying method 1 under section 3.14, a reference to an underground mine is taken to be a reference to an open cut mine.

3.28 Method 2—coal mine waste gas flared

For subparagraph 3.19(5)(a)(ii), method 2 is the same as method 2 under section 3.15.

3.29 Method 3—coal mine waste gas flared

For subparagraph 3.19(5)(a)(iii), method 3 is the same as method 3 under section 3.16.

Division 3.2.4—Decommissioned underground mines

Subdivision 3.2.4.1—Preliminary

3.30 Application

This Division applies to fugitive emissions from decommissioned underground mines from the time that they became a decommissioned underground coal mine, other than mines which have been a decommissioned underground coal mine for a continuous period of 20 years or more.

3.31 Available methods

(1) Subject to sections 1.18 and 3.30, for estimating emissions released during a year from the operation of a facility that is constituted by a decommissioned underground mine the methods as set out in this section must be used.

Methane from decommissioned mines

(2) One of the following methods must be used for estimating fugitive emissions of methane that result from the mine:

(a) subject to subsection (6), method 1 under section 3.32;

(b) method 4 under section 3.37.

Note: There is no method 2 or 3 for subsection (2).

Carbon dioxide from decommissioned mines

(3) If method 4 under section 3.37 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the mine.

Note: There is no method 1, 2 or 3 for subsection (3).

Flaring

(4) For estimating emissions released from coal mine waste gas flared from the mine:

(a) one of the following methods must be used for estimating emissions of carbon dioxide released:

(i) method 1 under section 3.38;

(ii) method 2 under section 3.39;

(iii) method 3 under section 3.40; and

(b) method 1 under section 3.38 must be used for estimating emissions of methane released.

(5) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

(6) If coal mine waste gas from the decommissioned underground mine is captured during the year, method 1 in subsection (2) must not be used.

Subdivision 3.2.4.2—Fugitive emissions from decommissioned underground mines

3.32 Method 1—decommissioned underground mines

(1) For paragraph 3.31(2)(a), method 1 is:

where:

Edm is the fugitive emissions of methane from the mine during the year measured in CO2‑e tonnes.

Etdm is the emissions from the mine for the last 12 month period before the mine became a decommissioned underground coal mine, measured in CO2‑e tonnes and estimated under section 3.6.

EFdm is the emission factor for the mine calculated under section 3.33.

Fdm is the proportion of the mine flooded at the end of the year, as estimated under section 3.34, and must not be greater than 1.

(2) However, if, under subsection (1), the estimated emissions in CO2‑e tonnes for the mine during the year is less than 0.02  Etdm, the estimated emissions for the mine during the year is taken to be 0.02  Etdm.

3.33 Emission factor for decommissioned underground mines

For section 3.32, EFdm is the integral under the curve of:

for the period between T and T-N,

where:

A is:

(a) for a gassy mine—; or

(b) for a non‑gassy mine—.

T is the number of whole months since the mine became a decommissioned underground coal mine, at the end of the reporting year.

N is:

(a) if T is less than 12—the value for T; or

(b) if T is 12 or greater—12.

b is:

(a) for a gassy mine—‑1.45; or

(b) for a non‑gassy mine—‑1.01.

C is:

(a) for a gassy mine—0.024; or

(b) for a non‑gassy mine—0.088.

3.34 Measurement of proportion of mine that is flooded

For subsection 3.32(1), Fdm is:

where:

MWI is the rate of water flow into the mine in cubic metres per year as measured under section 3.35.

MVV is the mine void volume in cubic metres as measured under section 3.36.

months is the number of whole months since the mine became a decommissioned underground coal mine, at the end of the reporting year.

3.35 Water flow into mine

For MWI in section 3.34, the rate of water flow into the mine must be measured by:

(a) using water flow rates for the mine estimated in accordance with an appropriate standard; or

(b) using the following average water flow rates:

(i) for a mine in the southern coalfield of New South Wales—913 000 cubic metres per year; or

(ii) for a mine in the Newcastle, Hunter, Western or Gunnedah coalfields in New South Wales—450 000 cubic metres per year; or

(iii) for a mine in Queensland—74 000 cubic metres per year.

Note: An appropriate standard includes AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits.

3.36 Size of mine void volume

For MVV in section 3.34, the size of the mine void volume must be measured by:

(a) using mine void volumes for the mine estimated in accordance with industry practice; or

(b) dividing the total amount of run‑of‑mine coal extracted from the mine before the mine was decommissioned by 1.425.

3.37 Method 4—decommissioned underground mines

(1) For paragraph 3.31(2)(b) and subsection 3.31(3), method 4 is the same as method 4 in section 3.6.

(2) In applying method 4 under section 3.6, a reference to an underground mine is taken to be a reference to a decommissioned underground mine.

Subdivision 3.2.4.3—Fugitive emissions from coal mine waste gas flared

3.38 Method 1—coal mine waste gas flared

(1) For subparagraph 3.31(4)(a)(i) and paragraphs 3.31(4)(b) and (4)(c), method 1 is the same as method 1 under section 3.14.

(2) In applying method 1 under section 3.14, a reference to an underground mine is taken to be a reference to a decommissioned underground mine.

3.39 Method 2—coal mine waste gas flared

For subparagraph 3.31(4)(a)(ii), method 2 is the same as method 2 under section 3.15.

3.40 Method 3—coal mine waste gas flared

For subparagraph 3.31(4)(a)(iii), method 3 is the same as method 3 under section 3.16.

Part 3.3—Oil and natural gas—fugitive emissions

Division 3.3.1—Preliminary

3.40A Definition of natural gas for Part 3.3

In this Part:

natural gas includes the following:

(a) shale gas;

(b) tight gas;

3.41 Outline of Part

This Part provides for fugitive emissions from the following:

(a) oil or gas exploration (see Division 3.3.2);

(b) crude oil production (see Division 3.3.3);

(d) crude oil refining (see Division 3.3.5);

(e) natural gas production or processing, other than emissions that are vented or flared (see Division 3.3.6);

(f) natural gas transmission (see Division 3.3.7);

(g) natural gas distribution (see Division 3.3.8);

(h) natural gas production or processing (emissions that are vented or flared) (see Division 3.3.9).

Division 3.3.2—Oil or gas exploration

Subdivision 3.3.2.1—Preliminary

3.42 Application

This Division applies to fugitive emissions from venting or flaring from oil or gas exploration activities, including emissions from:

(a) oil well drilling; and

(b) gas well drilling; and

(d) well completions; and

(e) wellworkovers.

Subdivision 3.3.2.2—Oil or gas exploration (flared) emissions

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:

(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

(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

(1) Method 1 is:

where:

Eij is the fugitive emissions of gas type (j) from a fuel type (i) flared in the oil or gas exploration during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) flared in the oil or gas exploration during the year measured in tonnes.

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)
	Fuel type (i)	CO2	CH4	N2O
1	Unprocessed gas flared	2.8	0.933	0.026
2	Crude oil	3.2	0.009	0.06

3.45 Method 2—oil or gas exploration (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 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 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 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 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 (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 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 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 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

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—fugitive emissions from system upsets, accidents and deliberate releases from process vents

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 from process vents during a reporting year from the operation of a facility that is constituted by oil or gas exploration.

(2) To estimate emissions that result from deliberate releases from process vents, systems upsets and accidents at a facility during a year, for each oil or gas exploration activity one of the following methods must be used:

(a) method 1 under section 3.84;

(b) method 4 under:

(i) for emissions of methane and carbon dioxide from natural gas well completions or well workover activities—section 3.46B; or

(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.

3.46B Method 4—vented emissions from well completions and well workovers

Vented volume measured for all wells and well types in a basin

(1) For subparagraph 3.46A(2)(b)(i), where vented volume is measured for all wells and well types (horizontal or vertical) in a basin, method 4 is:

where:

Emj is total emissions for gas type (j), being methane and carbon dioxide from all well completions and well workovers during a year in a basin, measured in CO2‑e tonnes.

ESp is the volume of methane vented during a well completion or well workover from strata for each well (p) in cubic metres at standard conditions, worked out in accordance with subsection (2).

VIGGj,p is the volume of gas type (j) in cubic metres at standard conditions, being methane and carbon dioxide, injected into the well during well completion or well workover, worked out in accordance with subsection (3).

W is the total number of well completions and well workovers in the basin during a year.

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions to CO2‑e tonnes, being:

(a) for methane—6.784 × 10‑4 × GWPmethane; and

(b) for carbon dioxide—1.861 × 10‑3.

Z is the total number of greenhouse gas types.

(2) For subsection (1), the factor ESp is worked out using the formula:

where:

FVp is the flow volume of each well (p) in cubic metres at standard conditions, measured using a digital or analog recording flow metre on the vent line to measure flowback during the well completion or well workover, estimated in accordance with Division 2.3.6.

VIp is the volume of injected gas in cubic metres at standard conditions that is injected into the well during the well completion or well workover, estimated in accordance with Division 2.3.6.

(3) For subsection (1), VIGGj,p is worked out using the following formula:

where:

molj,p%, for each gas type (j), being methane and carbon dioxide, is the gas type’s share of one mole of VIp expressed as a percentage, estimated in accordance with Division 2.3.3.

VIp is the volume of injected gas in cubic metres at standard conditions that is injected into the well during the well completion or well workover, estimated in accordance with Division 2.3.6.

Vented volume measured for a sample of wells and well types in a basin

(4) For subparagraph 3.46A(2)(b)(i), where vented volume is measured for a sample of wells and well types (horizontal or vertical) in a basin, method 4 is:

where:

Emj is total emissions for gas type (j), being methane and carbon dioxide from all well completions and well workovers during a year in a basin, measured in CO2‑e tonnes.

EVp is the volume of methane flowback during a well completion or well workover from strata for each well (p) in cubic metres at standard conditions, worked out in accordance with subsection (5).

SGj,p is the volume of gas type (j), being methane and carbon dioxide, in cubic metres at standard conditions that is captured or flared for each well (p) during the well completion or well workover, estimated in accordance with:

(a) for the volume of the gas—Division 2.3.6; and

(b) for the gas composition—Division 2.3.3.

VIGGj,p is the volume of gas type (j), being methane and carbon dioxide, injected into each well (p) during the well completion or well workover, worked out in accordance with subsection (6).

W is the total number of well completions and well workovers during a year in the basin.

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions to CO2‑e tonnes, being:

(a) for methane—6.784 × 10‑4 × GWPmethane; and

(b) for carbon dioxide—1.861 × 10‑3.

Z is the total number of greenhouse gas types.

(5) For subsection (4), the factor EVp is worked out using the following formula:

where:

FRMbt is the ratio of flowback during well completions and well workovers to the 30 day production rate for the basin (b) and the well type combination (t), as worked out in accordance with subsection (7).

PRp is the first 30 days average production flow rate in cubic metres per hour at each well (p), estimated in accordance with Division 2.3.6.

Tp is the total number of hours for the reporting year of flowback for the well completion or well workover for each well (p) and well type (horizontal or vertical) in a basin.

VIp is the volume of injected gas in cubic metres at standard conditions that is injected into the well during the well completion or well workover, estimated in accordance with Division 2.3.6.

(6) For subsection (4), VIGGj,p is worked out using the following formula:

where:

molj,p%, for each gas type (j), being methane and carbon dioxide, is the gas type’s share of one mole of VIp expressed as a percentage, estimated in accordance with Division 2.3.6.

VIp is the volume of injected gas in cubic metres at standard conditions that is injected into the well during the well completion or well workover, estimated in accordance with Division 2.3.6.

(7) For subsection (5), the factor FRMbt is worked out using the following formula:

where:

FRp(bt) is the average flow rate for flowback during well completions and well workovers in cubic metres per hour at standard conditions for each basin (b) and well type combination (t), determined using a digital or analog recording flow metre on the vent line to measure flowback during the well completion or well workover, estimated in accordance with Division 2.3.6.

N is the number of measured well completions or well workovers in the basin.

PRp(bt) is the first 30 days production flow rate in cubic metres per hour for each well (p) and well type (t) measured in a basin (b), estimated in accordance with Division 2.3.6.

(8) For subsection (7), the sampling requirements for the number of well completions or well workovers performed during a year for each basin and well type (horizontal or vertical) are as follows:

(a) if one to 5 well completions or workovers are performed during a year, all wells are to be measured;

(b) if 6 to 50 well completions or workovers are performed during a year, a minimum of 5 wells are to be measured;

(c) if more than 50 well completions or workovers are performed during a year, a minimum of 10% of wells are to be measured.

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

(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 produced water disposal systems associated with the those plants; and

(g) activities at upgrading plants and associated gas reinjection systems and produced water disposal systems.

(2) For paragraph (1)(e), untreated production includes:

(a) well effluent; and

(b) emulsion; 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;

Note: There is no method 3 or 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 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 1.60 x 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)
	Equipment type (k)	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 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, 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.

Subdivision 3.3.3.3—Crude oil production (flared)—fugitive emissions of carbon dioxide, methane and nitrous oxide

3.51 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 3.52;

(ii) method 2 under section 3.53;

(iii) method 3 under section 3.54; and

(b) if estimating emissions of methane released—one of the following methods must be used:

(i) method 1 under section 3.52;

(ii) method 2A under section 3.53A; and

(i) method 1 under section 3.52;

(ii) method 2A under section 3.53A.

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.

3.52 Method 1—crude oil production (flared) emissions

(1) For subparagraph 3.51(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.

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)
	Fuel type (i)	CO2	CH4	N2O
1	Unprocessed gas flared	2.8	0.933	0.026
2	Crude oil	3.2	0.009	0.060

3.53 Method 2—crude oil production

Combustion of gaseous fuels (flared) emissions of carbon dioxide

(1) For subparagraph 3.51(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.

3.53A Method 2A—crude oil production (flared methane or nitrous oxide emissions)

For subparagraphs 3.51(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 3.52(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.

3.54 Method 3—crude oil production

Combustion of gaseous fuels (flared) emissions of carbon dioxide

(1) For subparagraph 3.51(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 3.51(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 3.84;

(b) method 4 under Part 1.3.

Note: There is no method 2 or 3 for this Subdivision.

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 methane (j), which is 9.74 x 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:

where:

Eij is the fugitive emissions of methane (j) from the crude oil transport during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) 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 methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes though 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.

(2) For EFijk, the emission factors for methane (j), 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

3.61 Application

This Division applies to fugitive emissions from crude oil refining activities, including emissions from flaring at petroleum refineries.

3.62 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 3.63;

(b) method 2 under section 3.64.

Note: There is no method 3 or 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 3.65;

(b) method 4 under section 3.66.

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 3.67;

(ii) method 2 under section 3.68;

(iii) method 3 under section 3.69; and

(b) if estimating emissions of methane released—one of the following methods must be used:

(i) method 1 under section 3.67;

(ii) method 2A under section 3.68A; and

(i) method 1 under section 3.67;

(ii) method 2A under section 3.68A.

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 3.67 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

3.63 Method 1—crude oil refining and storage tanks for crude oil

Method 1 is:

where:

Eij is the fugitive emissions of methane (j) 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 methane (j) 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 methane (j) being 9.47 x 10‑4 tonnes CO2‑e per tonne of crude oil refined and 1.73 x 10‑4 tonnes CO2‑e per tonne of crude oil stored in tanks.

3.64 Method 2—crude oil refining and storage tanks for crude oil

(1) Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil refining and from storage tanks during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) 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, if the equipment is used in the crude oil refining and in the storage tanks.

EFijk is the emission factor for methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes though 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 methane (j) 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.

Subdivision 3.3.5.2—Fugitive emissions from deliberate releases from process vents, system upsets and accidents

3.65 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.

3.66 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

3.67 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 type (i) flared during the year measured in tonnes.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of gas type (i) 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)
	fuel type (i)	CO2	CH4	N2O
1	gas	2.7	0.133	0.026

3.68 Method 2—gas flared from crude oil refining

For subparagraph 3.62(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.

3.68A Method 2A—crude oil refining (flared methane or nitrous oxide emissions)

For subparagraphs 3.62(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 3.67(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.

3.69 Method 3—gas flared from crude oil refining

For subparagraph 3.62(4)(a)(iii), method 3 is the same as method 2 under section 3.68, 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 3.3.6—Natural gas production or processing, other than emissions that are vented or flared

3.70 Application

This Division applies to fugitive emissions from natural gas production or processing 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; and

(d) well servicing; and

(e) gas gathering; and

(f) gas processing and associated waste water disposal and acid gas disposal activities.

3.71 Available methods

(1) Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane (other than emissions that are vented or flared) released during a year from the operation of a facility that is constituted by natural gas production and processing:

(a) method 1 under section 3.72;

(b) method 2 under section 3.73.

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.

3.72 Method 1—natural gas production and processing (other than emissions that are vented or flared)

(1) Method 1 is:

where:

Eij is the fugitive emissions of methane (j) (other than emissions that are vented or flared) from the natural gas production and processing during the year measured in CO2‑e tonnes.

Σk is the total emissions of methane (j), 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 natural gas production and processing.

Qik is the total of the quantities of natural gas that pass through each equipment type (k), or the number of equipment units of type (k) specified in column 2 of the table in subsection (2), measured in tonnes.

EFijk is the emission factor for methane (j) measured in CO2‑e tonnes per tonne of natural gas that passes through each equipment type (k) during the year if the equipment is used in the natural gas production and processing.

Qi is the total quantity of natural gas (i) that passes through the natural gas production and processing measured in tonnes.

EF(l) ij is 1.60 x 10‑3, which is the emission factor for methane (j) from general leaks in the natural gas production and processing, measured in CO2‑e tonnes per tonne of natural gas that passes through the natural gas production and processing.

(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:

Item	Equipment type (k)	Emission factor for methane (j) (tonnes CO2‑e/tonnes fuel throughput)
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 natural gas production and processing 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 natural gas production and processing.

3.73 Method 2—natural gas production and processing (other than venting and flaring)

(1) Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the natural gas production and processing during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) measured in CO2‑e tonnes 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 is used in the natural gas production and processing.

Qik is the total of the quantities of natural gas measured in tonnes that pass 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, if the equipment is used in the natural gas production and processing.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of natural gas 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, if the equipment is used in the natural gas production and processing.

(2) For EFijk, the emission factors for methane (j) as the natural gas passes through the equipment types (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.

Division 3.3.7—Natural gas transmission

3.74 Application

This Division applies to fugitive emissions from natural gas transmission activities.

3.75 Available methods

(1) Subject to section 1.18 and subsection (2), one of the following methods must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, released from the operation of a facility that is constituted by natural gas transmission through a system of pipelines during a year:

(a) method 1 under section 3.76;

(b) method 2 under section 3.77.

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.

3.76 Method 1—natural gas transmission

Method 1 is:

where:

Eij is the fugitive emissions of gas type (j) from natural gas transmission through a system of pipelines of length (i) during the year measured in CO2‑e tonnes.

Qi is the length of the system of pipelines (i) measured in kilometres.

EFij is the emission factor for gas type (j), which is 0.02 for carbon dioxide and 11.6 for methane, measured in tonnes of CO2‑e emissions per kilometre of pipeline (i).

3.77 Method 2—natural gas transmission

(1) Method 2 is:

where:

Ej is the fugitive emissions of gas type (j) measured in CO2‑e tonnes from the natural gas transmission through the system of pipelines during the year.

Σk is the total of emissions of gas type (j) measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas transmission.

Qk is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) or the number of equipment units of type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas transmission.

EFjk is the emission factor of gas type (j) measured in CO2‑e tonnes for each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, where the equipment is used in the natural gas transmission.

(2) For EFjk, the emission factors for a gas type (j) as the natural gas passes through the equipment type (k) are:

(a) as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

(b) as listed in that Compendium for the equipment type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s sections 5 and 6.1.2, and the requirements of Division 2.3.3; or

(c) as listed in that Compendium for the equipment type with emission factors adjusted for variations in the type of equipment material estimated in accordance with the results of published research for the crude oil industry and the principles of section 1.13; or

(d) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors; or

(e) estimated using the engineering calculation approach in accordance with sections 5 and 6.1.2 of the API Compendium.

Note: The API Compendium is available at www.api.org.

Division 3.3.8—Natural gas distribution

3.78 Application

This Division applies to fugitive emissions from natural gas distribution activities.

3.79 Available methods

(1) Subject to section 1.18 and subsections (2) and (3), one of the following methods must be used for estimating fugitive emissions (other than emissions that are flared) of each gas type, being carbon dioxide and methane, released during a year from the operation of a facility that is constituted by natural gas distribution through a system of pipelines:

(a) method 1 under section 3.80;

(b) method 2 under section 3.81;

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)