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

This Determination commences on 1 July 2008.

(1) This Determination is made under subsection 10 (3) of the National Greenhouse and Energy Reporting Act 2007. It provides for the measurement of the following arising from the operation of facilities:

(a) greenhouse gas emissions;

(b) the production of energy;

Note For the meaning of facility, see section 9 of the Act.

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

Note Scope 1 and scope 2 emissions are defined in subregulation 2.23 (2) 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 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) Generally:

(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 a facility specific method using industry practices for sampling and Australian or equivalent standards for analysis; and

(c) method 3 is 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.

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.

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 known as the Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, 2004, published by the American Petroleum Institute.

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, 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.

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.

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

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.

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.

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.

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.

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.

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

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.

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 means the release of emissions that occur during the extraction, processing and delivery of fossil fuels.

gas bearing strata is a layer of rock that contains quantities of gas.

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.

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.

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.

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.

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).

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

municipal materials has the meaning given by the Regulations.

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

natural gas liquids has the meaning given by the Regulations.

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.

open cut mine means a mine in which the overburden is removed from coal seams to allow extraction by mining that is not underground mining.

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.

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

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.

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

reductant means a fuel that is used for its chemical properties other than its property as a source of energy.

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

Regulations means the National Greenhouse and Energy Reporting Regulations 2008.

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 meaning given by paragraph 2.23 (2) (a) of the Regulations.

scope 2 emissions has the meaning given by paragraph 2.23 (2) (b) of the Regulations.

Note Regulation 2.23 provides that emissions of greenhouse gases, in relation to a facility, means releases of greenhouse gases as a result of:

(a) activities that constitute the facility (scope 1 emissions); and

(b) activities that generate electricity, heating, cooling or steam that are consumed by the facility but do not form part of the facility (scope 2 emissions).

sludge biogas means the gas derived from the anaerobic fermentation of biomass and solid waste from sewage and animal slurries and combusted to produce heat and electricity.

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.

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.

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.

uncertainty protocol means the publication known as the GHG Uncertainty 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.

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 subregulation 2.23 (4) of the Regulations)

 emission of greenhouse gas (see also subregulation 2.23 (2) of the Regulations)

 energy

 facility

 group

 greenhouse gas

 industry sector

 operational control

 production of energy (see also subregulation 2.23 (3) of the Regulations)

 registered corporation.

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 2009.

1.10 Meaning of source

(1) A thing mentioned in column 3 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
3K		Iron, steel or other metal production using an integrated metalworks
3L		Ferroalloys production
3M		Aluminium production
3N		Other metals production
3O		Emissions of hydrofluorocarbons and sulphur hexafluoride gases
4	Waste
4A		Solid waste disposal on land
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 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

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

1.13 General principles for measuring emissions

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

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

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

(c) accuracy — having regard to the availability of reasonable resources by a registered corporation and the requirements of this Determination, uncertainties in emission 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 within the energy, industrial process and waste sectors as identified by the National Inventory Report must be accounted for.

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 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 source, from the operation of a facility.

(2) Subject to subsection (3), one method for the 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 source; and

(b) in the preceding 4 reporting years before that time, only that method has been used to estimate the emissions from the source;

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

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

(6) Lower method, in relation to a method (the original method) being used to estimate emissions in relation to a source, is a method for the source with a lower number than the number of the original method.

1.19 Temporary unavailability of method

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

(2) For each day or part of a day during the down time, emissions must be calculated based on the average daily emissions estimated for the year.

(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) Use of this procedure for a maximum of 6 weeks in a year is not a change of method for the purposes of section 1.18.

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) 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.

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) 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.

1.28 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 solid fuels.

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 of 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) If the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611), method 1 must not be used for estimating emissions of carbon dioxide for the main fuel combusted from the operation of the facility.

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).

(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:

(a) if the principal activity of the facility is electricity generation — 0.99; or

(b) in any other case — 0.98.

(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).

(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 conveyor.

2.11 Sampling for carbon in fly ash

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

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 specified in AS 4323.1—1995 and AS 4323.2—1995 or in a standard that is equivalent to one of those standards	Every 2 years, and as a function of load
2	By using standard industry ‘cegrit’ extraction equipment	Every year, and as a function of load
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	Once a year
4	From on‑line carbon in ash analysers using sample extraction probes and infrared analysers	Every 2 years, and as a function of load

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	Black coal (other than that used to produce coke)	AS 4264.1—1995
2	Brown coal	AS 4264.3—1996
3	Coking coal (metallurgical coal)	AS 4264.1—1995
4	Brown coal briquettes	AS 4264.3—1996
5	Coke oven 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 (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) The volume of solid fuel in the stockpile may be measured using aerial or general survey in accordance with industry practice.

(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.

2.16 Direct measurement at point of consumption — criterion AAA

(1) For paragraph 2.14 (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 gaseous fuels.

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) If the primary activity of the facility is electricity generation (ANZSIC industry classification and code 2611) method 1 must not be used for estimating emissions of carbon dioxide for the main fuel combusted from the operation of the facility.

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 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 Part 2 of Schedule 1.

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:

Ei,CO2 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.

EFiCO2ox,ec 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.

2.22 Calculation of emission factors from combustion of gaseous fuel

(1) For section 2.21, the emission factor EFi,CO2,ox,ec 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 0.995 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 EFi CO2,ox,ec 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) obtained under section 2.21.

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) 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) 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 by an accredited laboratory or by a laboratory that meets requirements that are equivalent to the requirements in AS ISO/IEC 17025:2005.

(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	Monthly
1	Pipeline quality gases	Energy content	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	Gas composition Energy content	Monthly, unless the reporting corporation 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 at point of consumption — criterion AA

For paragraph 2.29 (1) (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 at point of consumption — criterion AAA

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

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

(a) using volumetric measurement in accordance with:

(i) for gases generally — section 2.32; and

(ii) for supercompressed gases — section 2.33; and

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

(3) The measurement must be either:

(a) carried out using 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 specified in column 3 for that item from the operation of the facility; and

(ii) is in a category specified in column 2 of an item in the table and complies with the transmitter and accuracy requirements for that equipment specified in column 4 for that item; 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 — general

(1) For paragraph 2.31 (2) (a), volumetric measurement must be in cubic metres at standard conditions.

(2) The volumetric measurement is to be calculated using a flow computer that measures and analyses flow signals, relative density and gas composition at the delivery location of the gaseous fuel.

(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 — the publication entitled American Gas Report No. 3 published by the American Gas Association or Parts 1 to 4 of the publication entitled API 14.3 published by the American Petroleum Institute;

(b) for turbine measuring systems — the publication entitled American Gas Association Transmission Measurement Committee Report No. 7 published by the American Gas Association;

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

Note New Zealand standard NZS 5259:1999 is an example of an appropriate internationally recognised code.

(6) Measurements must comply with units of measurement required by or under the National Measurement Act 1960.

(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) This section applies for subparagraph 2.31 (2) (a) (ii).

(2) If, in determining volume in relation to super‑compressed gases, 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 American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility published by the American Gas Association.

(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 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 American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility published by the American Gas Association.

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

(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 American Gas Association Report No. 3, published by the American Gas Association, 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 American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility, published by the American Gas Association, 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 ANSI B109.3—1986 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 section 2.31 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.

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 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.

2.37 Gas chromatographs

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 produced by gravimetric methods and traceable to Australian units of measurement required by or under the National Measurement Act 1960; and

(b) perform gas composition analysis with an accuracy of ±0.15% for use in calculation of gross calorific value and ±0.25% for calculation of relative density; and

2.38 Simplified consumption measurements — criterion BBB

(1) For paragraph 2.29 (1) (d), 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 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 liquid fuels.

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:

(a) transport by vehicles registered for road use; and

(b) rail, marine navigation and 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:

Ei,CO2 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.

EFiCO2ox,ec is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2‑e per gigajoule.

(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 EFiCO2ox,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 0.99 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)
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)
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)
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
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 — column 4 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 2 of the table in Division 4.3 of Part 4 of Schedule 1 — column 4 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 for stationary energy purposes.

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:

Cpog is the consumption of petroleum based oils or petroleum based greases estimated in accordance with Division 2.4.6.

Waste Oilpog is the quantity of waste 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 at point of consumption — criterion AA

For paragraph 2.50 (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 at point of consumption — criterion AAA

(1) For paragraph 2.50 (c), criterion AAA is the measurement during the year of the liquid fuel combusted from the operation of the facility at the point of combustion.

(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 (d), 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 (coke ovens)

2.57 Application

This Division applies to solid fuel transformation (coke ovens).

2.58 Methods

(1) If:

(a) a facility is constituted by the manufacture of solid fuel using coke ovens; and

(b) in the manufacture, fuels are combusted for energy;

then the methods for estimating emissions during a year from that combustion are provided in Part 4.4.

(2) These emissions are taken to be emissions from fuel combustion.

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);

2.62 Method 2 — petrochemical production

(1) Method 2 is the same as method 1 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.

2.63 Method 3— petrochemical production

(1) Method 3 is the same as method 1 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.

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 D6866–08.

(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—08 or a standard that is equivalent to that standard.

Part 2.7 Estimation of energy for certain purposes

2.68 Amount of fuel 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

(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.

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 that is apportioned between electricity generation, transport (excluding international bunker fuels) and other stationary energy purposes may be determined using the corporation’s records if the records are based on the measurement equipment used by the corporation to measure consumption of the fuel types.

Chapter 3 Fugitive emissions from fuels

Part 3.1 Preliminary

3.1 Outline of Chapter

This Chapter provides for fugitive emissions from fuels 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) method 1 under section 3.14 must be used for estimating emissions of methane released;

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 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, 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

(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 paragraph 3.4 (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, as follows:

(a) for a gassy mine — 0.305;

(b) for a non‑gassy mine — 0.008.

3.6 Method 4 — extraction of coal

(1) For paragraph 3.4 (2) (b) and subsection 3.4 (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 × 21; 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 3.12.

(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 measured in accordance with section 1.34.

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 0.98/0.995, which is the correction factor for the oxidation of coal mine waste gas (i) flared.

3.15 Method 2 — coal mine waste gas flared

(1) For subparagraph 3.4 (4) (a) (ii), method 2 is the same as method 1 under section 3.14.

(2) In applying method 1 under section 3.14, the facility specific emission factor (EFij) must be determined in accordance with the procedure for determining EFi CO2ox,ec in 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 1 under section 3.14.

(2) In applying method 1 under section 3.14, the facility specific emission factor EFij must be determined in accordance with the procedure for determining EFi CO2ox,ec 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 0.014, 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 — 0.045;

(b) for a mine in Victoria — 0.0007;

(d) for a mine in Western Australia — 0.017;

(e) for a mine in South Australia — 0.0007;

(f) for a mine in Tasmania — 0.014.

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 × 21;

(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 and 3.25.

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.

β 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;

3.23 Estimate of proportion of gas content released below pit floor

For paragraph (b) of the factor β in subsection 3.22 (1):

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.

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 an appropriate standard.

Note 1 An appropriate standard for analysis of a gas includes AS 3980—1999 Guide to the determination of gas content of coal—Direct desorption method.

Note 2 An appropriate standard for analysis of a gas bearing strata includes AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits.

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 that have been closed for a continuous period of at least 1 year but less than 20 years.

3.31 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 a decommissioned underground mine that has been closed for a continuous period of at least 1 year but less than 20 years 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 for combustion 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 full year that the mine was in operation measured in CO2‑e tonnes and estimated under section 3.5 or 3.6.

EFdm is the emission factor for the mine calculated under section 3.33.

Fdm is the fraction of the mine flooded during the year, as estimated under section 3.34.

(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‑1,

where:

A is:

(a) for a gassy mine — 0.23; or

(b) for a non‑gassy mine — 0.35.

T is the number of years since the mine was decommissioned.

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 section 3.32, 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.

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 coal seam methane that is captured for combustion where the production of coal is not intended to occur.

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

3.42 Application

This Division applies to fugitive emissions from flaring from oil or gas exploration activities, including emissions from:

(a) oil well drilling; and

(b) gas well drilling; and

(d) well completions.

3.43 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 3.44;

(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 2 under section 3.45; and

Note There is no method 4 under paragraph (a), no methods 3 or 4 under paragraph (b) and no methods 2, 3 or 4 under paragraph (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	0.7	0.03
2	Crude oil	3.2	0.007	0.07

3.45 Method 2 — oil or gas exploration

(1) Method 2 is the same as method 1 but the carbon dioxide emission factor EFij must be determined in accordance with:

(a) for the combustion of gaseous fuels — method 2 specified in Division 2.3.3;

(b) for the combustion of liquid fuels — method 2 specified in Division 2.4.3.

(2) The methane emission factor must be determined with section 4.4 of the API Compendium.

3.46 Method 3 — oil or gas exploration

Method 3 is the same as method 1 but the carbon dioxide emission factor EFij must be determined in accordance with:

(a) for the combustion of gaseous fuels — method 3 specified in Division 2.3.4;

(b) for the combustion of liquid fuels — method 3 specified in Division 2.4.4.

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 emissions of methane

3.48 Available methods

(1) Subject to section 1.18, for estimating fugitive emissions of methane, other than from oil or gas flaring, 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.

(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 1.2 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	8.4 10‑7
2	Fixed roof tank	4.2 10‑6
3	Floating tank	3.2 10‑6

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 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 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 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 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 3.55;

(ii) method 2 under section 3.56; and

Note There is no method 4 under paragraph (a), no methods 3 or 4 under paragraph (b) and no methods 2, 3 or 4 under paragraph (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	0.7	0.03
2	Crude oil	3.2	0.007	0.07

3.53 Method 2 — crude oil production (flared) emissions of carbon dioxide

For subparagraph 3.51 (a) (ii), method 2 is the same as method 1 but the emission factor EFij must be determined in accordance with:

(a) for the combustion of gaseous fuels — method 2 specified in Division 2.3.3; and

(b) for the combustion of liquid fuels — method 2 specified in Division 2.4.3.

3.54 Method 3 — crude oil production (flared) emissions of carbon dioxide

For subparagraph 3.51 (a) (iii), method 3 is the same as method 1 but the emission factor EFij must be determined in accordance with:

(a) for the combustion of gaseous fuels — method 3 specified in Division 2.3.4; and

(b) for the combustion of liquid fuels — method 3 specified in Division 2.4.4.

3.55 Method 1 — crude oil production (flared) emissions of methane and nitrous oxide

For subparagraph 3.51 (b) (i) and paragraph 3.51 (c), method 1 is as provided for section 3.52.

3.56 Method 2 — crude oil production (flared) emissions of methane and nitrous oxide

For subparagraph 3.51 (b) (ii), method 2 is the same as method 1 in section 3.55, but the emission factor EFij must be determined in accordance with section 4.4 of the API Compendium.

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 7.3 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) one of the following methods must be used for estimating emissions of methane released:

(i) method 1 under section 3.67;

(ii) method 2 under section 3.68; and

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, no method 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.

(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 7.1 x 10‑4 tonnes CO2‑e per tonne of crude oil refined and 1.3 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 EFijk 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	0.1	0.03

3.68 Method 2 — gas flared from crude oil refining

(1) Method 2 is the same as method 1 under section 3.67 but the carbon dioxide emission factor EFij must be determined in accordance with method 2 for the consumption of gaseous fuels as specified in Division 2.3.3.

(2) The methane emission factor must be determined with section 4.4 of the API Compendium.

3.69 Method 3 — gas flared from crude oil refining

Method 3 is the same as method 1 under section 3.67 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 1.2 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	8.4 10‑7
2	Fixed roof tank	4.2 10‑6
3	Floating tank	3.2 10‑6

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 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 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 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 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 8.7 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.

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 subsection (2), one of the following methods must be used for estimating fugitive emissions 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 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.

3.80 Method 1 — natural gas distribution

(1) Method 1 is:

where:

Eij is the fugitive emissions of gas type (j) that result from natural gas distribution through a system of pipelines with sales of gas (Sp) during the year, measured in CO2‑e tonnes.

Sp is the total gas sales during the year from the pipeline system measured in terajoules.

%UAGp is the percentage of unaccounted for gas in the pipeline system in a State or Territory, relative to the amount of gas issued annually by gas utilities in that State or Territory.

Note The value 0.55 following the variable %UAGp in method 1 represents the proportion of gas that is unaccounted for and released as emissions.

Ci,p,j is the natural gas composition factor for gas type (j) for the natural gas supplied from the pipeline system in a State or Territory measured in CO2‑e tonnes per terajoule.

(2) For %UAGp in subsection (1), column 3 of an item in the following table specifies the percentage of unaccounted for gas in the pipeline system in a State or Territory specified in column 2 of that item.

(3) For Ci,p,j in subsection (1), columns 4 and 5 of an item in the following table specify the natural gas composition factor for carbon dioxide and methane for a pipeline system in a State or Territory specified in column 2.

Item	State	Unaccounted for gas (a)%	Natural gas composition factor (a)(tonnes CO2‑e/TJ)
	State	UAGp	CO2	CH4
1	NSW and ACT	2.40	0.8	328
2	VIC	2.75	0.9	326
3	QLD	2.63	0.8	317
4	WA	2.55	1.1	306
5	SA	4.00	0.8	328
6	TAS	0.40	0.9	326
7	NT	0.10	0.0	264

3.81 Method 2 — natural gas distribution

(1) Method 2 is:

where:

Ej is the fugitive emissions of gas type (j) that result from the natural gas distribution during the year measured in CO2‑e tonnes.

Σk is the total of emissions of gas type (j) measured in CO2‑e tonnes 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 natural gas distribution.

EFjk is the emission factor for 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, if the equipment is used in the natural gas distribution.

(2) For EFjk, the emission factors for 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; 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 using adjusted factors; or

(d) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type — those factors.

(3) In paragraph 3.81 (2) (c), a reference to factors adjusted is a reference to the factors in Table 5-3 of the publication entitled Greenhouse Gas Emission Estimation Methodologies, Procedures and Guidelines for the Natural Gas Distribution Sector, American Gas Association, April 2008, that are adjusted for variations in estimated gas composition in accordance with:

(a) section 5.2.1 of that publication; and

(b) Division 2.3.3.

Division 3.3.9 Natural gas production or processing (emissions that are vented or flared)

3.82 Application

This Division applies to fugitive emissions from venting or flaring from natural gas production or processing activities, including emissions from:

(a) the venting of natural gas; and

(b) the venting of waste gas and vapour streams at facilities that are constituted by natural gas production or processing; and

3.83 Available methods

(1) Subject to section 1.18, for estimating emissions (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 the methods as set out in this section must be used.

(2) One of the following methods must be used for estimating fugitive emissions of methane that result from deliberate releases from process vents, system upsets and accidents:

(i) method 1 under section 3.84; and

(ii) method 4 under Part 1.3.

Note There is no method 2 or 3 for subsection (2).

(3) For estimating emissions released from gas flared from natural gas production and processing:

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

(i) method 1 under section 3.85;

(ii) method 2 under section 3.86;

(iii) method 3 under section 3.87; and

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

(i) method 1 under section 3.85;

(ii) method 2 under section 3.86; and

Note The flaring of gas from natural gas production and processing releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.85 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, no method 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.

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

Subdivision 3.3.9.1 Fugitive emissions that result from deliberate releases from process vents, system upsets and accidents

3.84 Method 1 — deliberate releases from process vents, system upsets and accidents

Method 1 is as described in section 5 of the API Compendium.

Subdivision 3.3.9.2 Emissions released from gas flared from natural gas production and processing

3.85 Method 1 — gas flared from natural gas production and processing

(1) Method 1 is:

where:

Eij is the emissions of gas type (j) measured in CO2‑e tonnes that result from a fuel type (i) flared in the natural gas production and processing during the year.

Qi is the quantity measured in tonnes of gas flared during the year.

EFij is the emission factor for gas type (j) measured in CO2‑e tonnes of emissions per tonne of gas flared (i) in the natural gas production and processing during the year.

(2) For EFij mentioned in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor for 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	0.1	0.03

3.86 Method 2 — gas flared from natural gas production and processing

(1) Method 2 is the same as method 1 but the carbon dioxide emission factor (EFij) must be determined in accordance with method 2 for the consumption of gaseous fuels as specified in Division 2.3.3.

(2) The methane emission factor must be determined with section 4.4 of the API Compendium.

3.87 Method 3 — gas flared from natural gas production and processing

Method 3 is the same as method 1 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.

Chapter 4 Industrial processes emissions

Part 4.1 Preliminary

4.1 Outline of Chapter

(1) This Chapter provides for emissions from:

(a) the consumption of carbonates; or

(b) the use of fuels as:

(i) feedstock; or

(ii) carbon reductants;

from sources that are industrial processes mentioned in subsection (2).

(2) For subsection (1), the industrial processes are as follows:

(a) in Part 4.2:

(i) producing cement clinker (see Division 4.2.1);

(ii) producing lime (see Division 4.2.2);

(iii) using carbonate for the production of a product other than cement clinker, lime or soda ash (see Division 4.2.3);

(iv) using and producing soda ash (see Division 4.2.4);

(b) in Part 4.3 — the production of:

(i) ammonia (see Division 4.3.1);

(ii) nitric acid (see Division 4.3.2);

(iii) adipic acid (see Division 4.3.3);

(iv) carbide (see Division 4.3.4);

(v) a chemical or mineral product other than carbide using a carbon reductant (see Division 4.3.5);

(i) iron and steel (see Division 4.4.1);

(ii) ferroalloy metals (see Division 4.4.2);

(iii) aluminium (see Divisions 4.4.3 and 4.4.4);

(iv) other metals (see Division 4.4.5).

(3) This Chapter, in Part 4.5, also applies to emissions released from the consumption of the following synthetic gases:

(a) hydrofluorocarbons;

(b) sulphur hexafluoride.

(4) This Chapter does not apply to emissions from fuel combusted for energy production.

Part 4.2 Industrial processes — mineral products

Division 4.2.1 Cement clinker production

4.2 Application

This Division applies to cement clinker production.

4.3 Available methods

(1) Subject to section 1.18, one of the following methods must be used for estimating emissions of carbon dioxide released during a year from the operation of a facility that is constituted by the production of cement clinker:

(a) method 1 under section 4.4;

(b) method 2 under section 4.5;

(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.

4.4 Method 1 — cement clinker production

Method 1 is:

where:

Eij is the emissions of carbon dioxide (j) released from the production of cement clinker (i) during the year measured in CO2‑e tonnes.

EFij is 0.534, which is the carbon dioxide (j) emission factor for cement clinker (i), measured in tonnes of emissions of carbon dioxide per tonne of cement clinker produced.

EFtoc,j is 0.010, which is the carbon dioxide (j) emission factor for carbon‑bearing non‑fuel raw material, measured in tonnes of emissions of carbon dioxide per tonne of cement clinker produced.

Ai is the quantity of cement clinker (i) produced during the year measured in tonnes and estimated under Division 4.2.5.

Ackd is the quantity of cement kiln dust produced as a result of the production of cement clinker during the year, measured in tonnes and estimated under Division 4.2.5.

Fckd is:

(a) the degree of calcination of cement kiln dust produced as a result of the production of cement clinker during the year, expressed as a decimal fraction; or

(b) if the information mentioned in paragraph (a) is not available — the value 1.

4.5 Method 2 — cement clinker production

(1) Subject to this section, method 2 is the same as method 1 under section 4.4.

(2) In applying method 1 under section 4.4, EFij is taken to be:

where:

FCaO is the estimated fraction of cement clinker that is calcium oxide derived from carbonate sources and produced from the operation of the facility.

FMgO is the estimated fraction of cement clinker that is magnesium oxide derived from carbonate sources and produced from the operation of the facility.

Note The molecular weight ratio of carbon dioxide to calcium oxide is 0.785, and the molecular weight ratio of carbon dioxide to magnesium oxide is 1.092.

(3) Method 2 requires cement clinker to be sampled and analysed in accordance with sections 4.6 and 4.7.

4.6 General requirements for sampling cement clinker

(1) A sample of cement clinker must be derived from a composite of amounts of the cement clinker produced.

(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.

Note An appropriate standard is AS 4264.4—1996, Coal and coke – Sampling Part 4: Determination of precision and bias.

(5) The value obtained from the sample must only be used for the production period for which it was intended to be representative.

4.7 General requirements for analysing cement clinker

(1) Analysis of a sample of cement clinker, including determining the fraction of the sample that is calcium oxide or magnesium oxide, must be done in accordance with industry practice and must be consistent with the principles in section 1.13.

(2) The minimum frequency of analysis of samples of cement clinker must be in accordance with the Tier 3 method for cement clinker in section 2.2.1.1 in Part 1 of Volume 3 of the 2006 IPCC Guidelines.

4.8 Method 3 — cement clinker production

(1) Method 3 is:

Step 1	Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each pure carbonate calcined in the production of cement clinker during the year as follows:
Step 1	where: Eij is the emissions of carbon dioxide (j) released from the carbonate (i) calcined in the production of cement clinker during the year measured in CO2‑e tonnes.
	EFij is the carbon dioxide (j) emission factor for the carbonate (i) measured in tonnes of emissions of carbon dioxide per tonne of pure carbonate, as follows: (a) for calcium carbonate — 0.440; and (b) for magnesium carbonate — 0.522; and (c) for dolomite — 0.477; and (d) for any other pure carbonate — the factor for the carbonate in accordance with section 2.1 of Part 1 of Volume 3 of the 2006 IPCC Guidelines.
	Qi is the quantity of the pure carbonate (i) consumed in the calcining process for the production of cement clinker during the year measured in tonnes and estimated under Division 4.2.5.
	Fcal is: (a) the amount of the carbonate calcined in the production of cement clinker during the year, expressed as a decimal fraction; or (b) if the information mentioned in paragraph (a) is not available — the value 1.
	Ackd is the quantity of cement kiln dust lost from the kiln in the production of cement clinker during the year measured in tonnes and estimated under Division 4.2.5.
	EFckd is 0.440, which is the carbon dioxide emission factor for calcined cement kiln dust lost from the kiln.
	Fckd is: (a) the fraction of calcination achieved for cement kiln dust lost from the kiln in the production of cement clinker during the year; or (b) if the information mentioned in paragraph (a) is not available — the value 1.
	Qtoc is the quantity of total carbon‑bearing non‑fuel raw material consumed in the production of cement clinker during the year measured in tonnes and estimated under Division 4.2.5.
	EFtoc is 0.010, which is the emission factor for carbon‑bearing non‑fuel raw material, measured in tonnes of carbon dioxide produced per tonne of carbon.
Step 2	Add together the amount of emissions of carbon dioxide as measured in CO2‑e tonnes released for each pure carbonate calcined in the production of cement clinker during the year.

(2) For the factor EFckd in subsection (1), the carbon dioxide emission factor for calcined cement kiln dust is assumed to be the same as the emission factor for calcium carbonate.

(3) For the factor Qtoc in subsection (1), the quantity of carbon‑bearing non‑fuel raw material must be estimated in accordance with Division 4.2.5 as if a reference to carbonates consumed from the activity was a reference to carbon‑bearing non‑fuel raw material consumed from the activity.

(4) Method 3 requires carbonates to be sampled and analysed in accordance with sections 4.9 and 4.10.

4.9 General requirements for sampling carbonates

(1) Method 3 requires carbonates to be sampled in accordance with the procedure for sampling cement clinker specified under section 4.6 for method 2.

(2) In applying section 4.6, a reference in that section to cement clinker is taken to be a reference to a carbonate.

4.10 General requirements for analysing carbonates

(1) Analysis of samples of carbonates, including determining the quantity (in tonnes) of pure carbonate, must be done in accordance with industry practice or standards, and must be consistent with the principles in section 1.13.

(2) The minimum frequency of analysis of samples of carbonates must be in accordance with the Tier 3 method in section 2.2.1.1 of Part 1 of Volume 3 of the 2006 IPCC Guidelines.

Division 4.2.2 Lime production

4.11 Application

This Division applies to lime production (other than the in‑house production of lime in the metals industry).

4.12 Available methods

(a) method 1 under section 4.13;

(b) method 2 under section 4.14;

(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.

4.13 Method 1 — lime production

Method 1 is:

where:

Eij is the emissions of carbon dioxide (j) released from the production of lime (i) during the year measured in CO2‑e tonnes.

Ai is the quantity of lime produced during the year measured in tonnes and estimated under Division 4.2.5.

EFij is the carbon dioxide (j) emission factor for lime measured in tonnes of emission of carbon dioxide per tonne of lime produced, as follows:

(a) for commercial lime production — 0.675;

(b) for non‑commercial lime production — 0.730.

4.14 Method 2 — lime production

(1) Subject to this section, method 2 is the same as method 1 under section 4.13.

(2) In applying method 1 under section 4.13, EFij is taken to be:

where:

Fi is the estimated fractional purity of lime.

Note 44.01 is the molecular weight of carbon dioxide, and 56.08 is the molecular weight of calcium oxide.

(3) Method 2 requires lime to be sampled and analysed in accordance with sections 4.15 and 4.16.

4.15 General requirements for sampling

(1) A sample of lime must be derived from a composite of amounts of the lime produced.

(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.

Note An appropriate standard 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 production period for which it was intended to be representative.

4.16 General requirements for analysis of lime

(1) Analysis of a sample of lime, including determining the fractional purity of the sample, must be done in accordance with industry practice and must be consistent with the principles in section 1.13.

(2) The minimum frequency of analysis of samples of lime must be in accordance with the Tier 3 method in section 2.2.1.1 of Part 1 of Volume 3 of the 2006 IPCC Guidelines.

4.17 Method 3 — lime production

(1) Method 3 is:

Step 1	Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each pure carbonate calcined in the production of lime during the year as follows: where: Eij is the emissions of carbon dioxide (j) released from a carbonate (i) calcined in the production of lime during the year measured in CO2‑e tonnes.
	EFij is the carbon dioxide (j) emission factor for the carbonate (i), measured in tonnes of emissions of carbon dioxide per tonne of pure carbonate as follows: (a) for calcium carbonate — 0.440; (b) for magnesium carbonate — 0.522; (c) for dolomite — 0.477; (d) for any other carbonate — the factor for the carbonate in accordance with Tier 3 of Part 1 of Volume 3 of the 2006 IPCC Guidelines.
	Qi is the quantity of the pure carbonate (i) entering the calcining process in the production of lime during the year measured in tonnes and estimated under Division 4.2.5. Fcal is: (a) the amount of the carbonate calcined in the production of lime during the year expressed as a decimal fraction; or (b) if the information mentioned in paragraph (a) is not available — the value 1. Alkd is the quantity of lime kiln dust lost in the production of lime during the year, measured in tonnes and estimated under Division 4.2.5.
	EFlkd is 0.440, which is the emission factor for calcined lime kiln dust lost from the kiln. Flkd is: (a) the fraction of calcination achieved for lime kiln dust in the production of lime during the year; or (b) if the data in paragraph (a) is not available — the value 1.
Step 2	Add together the amount of emissions of carbon dioxide for each pure carbonate calcined in the production of lime during the year.

(2) For the factor EFlkd in subsection (1), the emission factor for calcined lime kiln dust is assumed to be the same as the emission factor for calcium carbonate.

(3) Method 3 requires each carbonate to be sampled and analysed in accordance with sections 4.18 and 4.19.

4.18 General requirements for sampling

(1) For section 4.17, carbonates must be sampled in accordance with the procedure for sampling lime specified under section 4.15 for method 2.

(2) In applying section 4.15, a reference in that section to lime is taken to be a reference to carbonates.

4.19 General requirements for analysis of carbonates

(1) For section 4.17, samples must be analysed in accordance with the procedure for analysing lime specified under section 4.16 for method 2.

(2) In applying section 4.16, a reference in that section to lime is taken to be a reference to carbonates.

Division 4.2.3 Use of carbonates for production of a product other than cement clinker, lime or soda ash

4.20 Application

This Division applies to emissions from the use of carbonate for the production of a product other than cement clinker, lime or soda ash:

(a) involving the consumption or any other use of carbonates; and

(b) generating emissions of carbon dioxide.

Note Examples of activities involving the consumption of carbonates include the following:

 metallurgy

 glass manufacture, including fibreglass and mineral wools

 magnesia production

 agriculture

 construction

 environment pollution control

 use as a flux or slagging agent

 in-house production of lime in the metals industry.

4.21 Available methods

(1) Subject to section 1.18 one of the following methods must be used for estimating emissions of carbon dioxide released during a year from the operation of a facility constituted by the calcination or any other use of carbonates that produces carbon dioxide (the industrial process) in an industrial process (other than cement clinker production or lime production):

(a) method 1 under section 4.22;

(b) method 3 under section 4.23;

Note There is no method 2 for this Division.

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

4.22 Method 1 — product other than cement clinker, lime or soda ash [see Note 2]

Method 1 is:

Step 1	Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each raw carbonate material consumed in the industrial process during the year as follows: where:
	Eij is the emissions of carbon dioxide (j) released from raw carbonate material (i) consumed in the industrial process during the year measured in CO2‑e tonnes. Qi is the quantity of the raw carbonate material (i) consumed in the calcining process for the industrial process during the year measured in tonnes and estimated under Division 4.2.5. EFij is the carbon dioxide (j) emission factor for the raw carbonate material (i) measured in tonnes of emissions of carbon dioxide per tonne of carbonate, that is: (a) for calcium carbonate — 0.396; and (b) for magnesium carbonate — 0.522; and (c) for dolomite — 0.453; and (d) for any other raw carbonate material — the factor for the raw carbonate material in accordance with section 2.1 of Part 1 of Volume 3 of the 2006 IPCC Guidelines.
	Fcal is: (a) the fraction of the raw carbonate material consumed in the industrial process during the year; or (b) if the information in paragraph (a) is not available — the value 1.
Step 2	Add together the amount of emissions of carbon dioxide for each carbonate consumed in the industrial process during the year.

Note For the factor EFij in step 1, the emission factor value given for a raw carbonate material is based on a method of calculation that ascribed the following content to the material:

(a) for calcium carbonate — at least 90% calcium carbonate;

(b) for magnesium carbonate — 100% magnesium carbonate;

4.23 Method 3 — product other than cement clinker, lime or soda ash

(1) Method 3 is:

Step 1	Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each pure carbonate consumed in the industrial process during the year as follows: where: Eij is the emissions of carbon dioxide (j) from a pure carbonate (i) consumed in the industrial process during the year measured in CO2‑e tonnes.
	EFij is the carbon dioxide (j) emission factor for the pure carbonate (i) in tonnes of emissions of carbon dioxide per tonne of pure carbonate, that is: (a) for calcium carbonate — 0.440; (b) for magnesium carbonate — 0.522; (c) for dolomite — 0.477; (d) for any other pure carbonate — the factor for the carbonate in accordance with Part 1 of Volume 3 of the 2006 IPCC Guidelines. Qi is the quantity of the pure carbonate (i) entering the industrial process during the year measured in tonnes and estimated under Division 4.2.5.
	Fcal is: (a) the fraction of the pure carbonate consumed in the industrial process during the year; or (b) if the information in paragraph (a) is not available — the value 1.
Step 2	Add together the amount of emissions of carbon dioxide for each pure carbonate consumed in the industrial process during the year.

(2) Method 3 requires each carbonate to be sampled and analysed in accordance with sections 4.24 and 4.25.

4.24 General requirements for sampling carbonates

(1) A sample of a carbonate must be derived from a composite of amounts of the carbonate consumed.

(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.

Note An example of an appropriate standard is AS 4264.4—1996 – Coal and coke – sampling – Determination of precision and bias.

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

4.25 General requirements for analysis of carbonates

(1) Analysis of samples of carbonates must be in accordance with industry practice and must be consistent with the principles in section 1.13.

(2) The minimum frequency of analysis of samples of carbonates must be in accordance with the Tier 3 method of section 2.2.1.1 of Part 1 of Volume 3 of the 2006 IPCC Guidelines.

Division 4.2.4 Soda ash use and production

4.26 Application

This Division applies to the use and production of soda ash.

Note Examples of uses of soda ash in industrial processes include the following:

 glass production

 soap and detergent production

 flue gas desulphurisation

 pulp and paper production.

4.27 Outline of Division

Emissions released from the use and production of soda ash must be estimated in accordance with:

(a) for the use of soda ash in production processes — Subdivision 4.2.4.1; or

(b) for the production of soda ash — Subdivision 4.2.4.2.

Subdivision 4.2.4.1 Soda ash use

4.28 Available methods

(1) Subject to section 1.18, one of the following methods must be used for estimating emissions of carbon dioxide released during a year from the operation of a facility constituted by the use of soda ash in a production process:

(a) method 1 under section 4.29;

(b) method 4 under Part 1.3.

Note There is no method 2 or 3 for this Division.

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

4.29 Method 1 — use of soda ash

Method 1 is:

where:

Eij is the emissions of carbon dioxide (j) from soda ash (i) consumed in the production process during the year measured in CO2‑e tonnes.

Qi is the quantity of soda ash (i) consumed in the production process during the year measured in tonnes and estimated under Division 4.2.5.

EFij is 0.415, which is the carbon dioxide (j) emission factor for soda ash (i) measured in tonnes of carbon dioxide emissions per tonne of soda ash.

Subdivision 4.2.4.2 Soda ash production

4.30 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 constituted by the production of soda ash:

(a) method 1 under section 4.31;

(b) method 2 under section 4.32;

(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.

4.31 Method 1 — production of soda ash

(1) Method 1 is:

where:

Eij is the emissions of each gas type (j), that is carbon dioxide, methane and nitrous oxide, released from the feedstock type (i) consumed from the production of soda ash during the year measured in CO2‑e tonnes.

Qi is the quantity of the feedstock type (i) consumed from the production of soda ash during the year measured in the appropriate unit and estimated under Division 2.2.5, 2.3.6 or 2.4.6.

ECi is the energy content factor for fuel type (i) used as a feedstock or carbon reductant in the production of soda ash during the year, estimated under section 6.5.

EFij is the gas type (j) emission factor for the feedstock type (i), including the effects of oxidation, as mentioned in Schedule 1, measured in CO2‑e kilograms per gigajoule.

Note Emissions of carbon dioxide, methane and nitrous oxide are released from the production of soda ash.

4.32 Method 2 — production of soda ash

(1) Subject to this section, method 2 is the same as method 1 under section 4.31.

(2) In applying method 1 under section 4.31, the facility specific emission factor (EFij) must be determined in accordance with the following:

(a) for estimating emissions released from the production of soda ash using solid fuels — the procedure for determining EFico2oxec in method 2 under Division 2.2.3;

(b) for estimating emissions released from the production of soda ash using gaseous fuels — the procedure for determining EFico2oxec in method 2 under Division 2.3.3;

(c) for estimating emissions released from the production of soda ash using liquid fuels — the procedure for determining EFico2oxec in method 2 under Division 2.4.3.

4.33 Method 3 — production of soda ash

(1) Subject to this section, method 3 is the same as method 1 under section 4.31.

(2) In applying method 1 under section 4.31, the facility specific emission factor EFi must be determined in accordance with the following:

(a) for estimating emissions released from the production of soda ash using solid fuels — the procedure for determining EFico2oxec in method 3 under Division 2.2.4;

(b) for estimating emissions released from the production of soda ash using gaseous fuels — the procedure for determining EFico2oxec in method 3 under Division 2.3.4;

(c) for estimating emissions released from the production of soda ash using liquid fuels — the procedure for determining EFico2oxec in method 3 under Division 2.4.4.

Division 4.2.5 Measurement of quantity of carbonates consumed and products derived from carbonates

4.34 Purpose of Division

(1) This Division applies to the operation of a facility (the activity) that is constituted by:

(a) the production of cement clinker; or

(b) the production of lime; or

(d) the use and production of soda ash.

(2) This Division sets out how the quantities of carbonates consumed from the operation of the activity, and the quantities of products derived from carbonates produced from the operation of the activity, are to be estimated for the following:

(a) Ai and Ackd in section 4.4;

(b) Qi and Qtoc in section 4.8;

(d) Qi and Alkd in section 4.17;

(e) Qi in sections 4.22, 4.23, and 4.29.

4.35 Criteria for measurement

(1) Quantities of carbonates consumed from the operation of the activity, or quantities of products derived from carbonates produced from the operation of the activity, must be estimated in accordance with this section.

Acquisition involves commercial transaction

(2) If the acquisition of the carbonates, or the dispatch of the products derived from carbonates, involves a commercial transaction, the quantity of the carbonates or products must be estimated using one of the following criteria:

(a) the quantity of the carbonates acquired or products dispatched for the facility during the year as evidenced by invoices issued by the vendor of the carbonates or products (criterion A);

(b) as provided in section 4.36 (criterion AA);

(3) If, during a year, criterion AA, or criterion AAA using paragraph 4.37 (2) (a), is used to estimate the quantity of carbonates acquired or products dispatched, then, in each year following that year, only criterion AA, or criterion AAA using paragraph 4.37 (2) (a), (respectively) is to be used.

Acquisition does not involve commercial transaction

(4) If the acquisition of the carbonates or the dispatch of the products does not involve a commercial transaction, the quantity the carbonates or products must be estimated using one of the following criteria:

(a) as provided in paragraph 4.37 (2) (a) (criterion AAA);

(b) as provided in section 4.38 (criterion BBB).

4.36 Indirect measurement at point of consumption or production — criterion AA

(1) For paragraph 4.35(b), criterion AA is the amount of carbonates consumed from the operation of the activity, or the amount of products derived from carbonates produced from the operation of the activity, during the year based on amounts delivered or dispatched during the year:

(a) as evidenced by invoices; and

(b) as adjusted for the estimated change in the quantity of the stockpiles of carbonates or the quantity of the stockpiles of products derived from carbonates during the year.

(2) The volume of carbonates, or products derived from carbonates, in the stockpile for the activity must be measured in accordance with industry practice.

4.37 Direct measurement at point of consumption or production — criterion AAA

(1) For paragraph 4.35 (c), criterion AAA is the direct measurement during the year of:

(a) the quantities of carbonates consumed from the operation of the activity; or

(b) the quantities of products derived from carbonates produced from the operation of the activity.

(2) The measurement must be:

(a) carried out using measuring equipment calibrated to a measurement requirement; or

(b) for measurement of the quantities of carbonates consumed from the operation of the activity — carried out 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 carbonates for the activity during the year is less than 1% of total consumption of the carbonates from the operation of the activity on average during the year; and

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

4.38 Acquisition or use or disposal without commercial transaction — criterion BBB

For paragraph 4.35 (d), criterion BBB is the estimation of the consumption of carbonates, or the products derived from carbonates, during the year in accordance with industry practice if the equipment used to measure consumption of the carbonates, or the products derived from carbonates, is not calibrated to a measurement requirement.

4.39 Units of measurement

Measurements of carbonates and products derived from carbonates must be converted to units of tonnes.

Part 4.3 Industrial processes — chemical industry

Division 4.3.1 Ammonia production

4.40 Application

This Division applies to chemical industry ammonia production.

4.41 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 the production of ammonia:

(a) method 1 under section 4.42;

(b) method 2 under section 4.43;

(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.

4.42 Method 1 — ammonia production

(1) Method 1 is:

where:

Eij is the emissions of carbon dioxide released from the production of ammonia during the year measured in CO2‑e tonnes.

Qi is the quantity of each type of feedstock or type of fuel (i) consumed from the production of ammonia during the year, measured in the appropriate unit and estimated using a criterion in Division 2.3.6.

ECi is the energy content factor for fuel type (i) used as a feedstock in the production of ammonia during the year, estimated under section 6.5.

EFij is the carbon dioxide emission factor for each type of feedstock or type of fuel (i) used in the production of ammonia during the year, including the effects of oxidation, measured in kilograms for each gigajoule according to source as mentioned in Part 2 of Schedule 1.

R is the quantity of carbon dioxide measured in tonnes derived from the production of ammonia during the year, captured and transferred for use in the operation of another facility, estimated using an applicable criterion in Division 2.3.6 and in accordance with any other requirements of that Division.

4.43 Method 2 — ammonia production

(1) Subject to this section, method 2 is the same as method 1 under section 4.42.

(2) In applying method 1 under section 4.42, the method for estimating emissions for gaseous fuels in Division 2.3.3 applies for working out the factor EFij.

4.44 Method 3 — ammonia production

(1) Subject to this section, method 3 is the same as method 1 under section 4.42.

(2) In applying method 1 under section 4.42, the method for estimating emissions for gaseous fuels in Division 2.3.4 applies for working out the factor EFij.

Division 4.3.2 Nitric acid production

4.45 Application

This Division applies to chemical industry nitric acid production.

4.46 Available methods

(1) Subject to section 1.18 and this section, one of the following methods must be used for estimating emissions during a year from the operation of a facility that is constituted by the production of nitric acid at a plant:

(a) method 1 under section 4.47;

(b) method 2 under section 4.48;

Note There is no method 3 for this Division.

(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 if the plant has used measures to reduce nitrous oxide emissions.

4.47 Method 1 — nitric acid production

(1) Method 1 is:

where:

Eijk is the emissions of nitrous oxide released during the year from the production of nitric acid at plant type (k) measured in CO2‑e tonnes.

EFijk is the emission factor of nitrous oxide for each tonne of nitric acid produced during the year from plant type (k).

Aik is the quantity, measured in tonnes, of nitric acid produced during the year from plant type (k).

(2) For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor of nitrous oxide for each tonne of nitric acid produced from a plant type (k) specified in column 2 of that item.

Item	Plant type (k)	Emission factor of nitrous oxide (tonnes CO2‑e per tonne of nitric acid production)
1	Atmospheric pressure plants	1.55
2	Medium pressure combustion plant	2.17
3	High pressure plant	2.79

Note The emission factors specified in this table apply only to method 1 and the operation of a facility that is constituted by a plant that has not used measures to reduce nitrous oxide emissions.

4.48 Method 2 — nitric acid production

(1) Subject to this section, method 2 is the same as method 1 under section 4.47.

(2) In applying method 1 under section 4.47, to work out the factor EFijk:

(a) periodic emissions monitoring must be used and conducted in accordance with Part 1.3; and

(b) the emission factor must be measured as nitrous oxide in CO2‑e tonnes for each tonne of nitric acid produced during the year from the plant.

(3) For method 2, all data on nitrous oxide concentrations, volumetric flow rates and nitric acid production for each sampling period must be used to estimate the flow‑weighted average emission rate of nitrous oxide for each unit of nitric acid produced from the plant.

Division 4.3.3 Adipic acid production

4.49 Application

This Division applies to chemical industry adipic acid production.

4.50 Available methods

(1) Subject to section 1.18, one of the methods for measuring emissions released in the production of adipic acid set out in section 3.4 of the 2006 IPCC Guidelines must be used for estimating emissions during a year from the operation of a facility that is constituted by the production of adipic acid.

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

Division 4.3.4 Carbide production

4.51 Application

This Division applies to chemical industry carbide production.

4.52 Available methods

(1) Subject to section 1.18, one of the methods for measuring emissions from carbide production set out in section 3.6 of the 2006 IPCC Guidelines must be used for estimating emissions during a year from the operation of a facility that is constituted by carbide production.

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

Division 4.3.5 Chemical or mineral production, other than carbide production, using a carbon reductant

4.53 Application

This Division applies to emissions from activities producing a chemical or mineral product (other than carbide production) using a carbon reductant, including the following products:

(a) titanium dioxide;

(b) synthetic rutile;

4.54 Available methods

(a) method 1 under section 4.55;

(b) method 2 under section 4.56;

(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.

4.55 Method 1 — chemical or mineral production, other than carbide production, using a carbon reductant

(1) Method 1 is:

where:

Eij is the emissions of carbon dioxide released from activities producing a chemical or mineral product, other than carbide production, using a carbon reductant, measured in CO2‑e tonnes.

Qi is the quantity of each fuel type (i) consumed as a carbon reductant in the production of a chemical or mineral product during the year measured in the appropriate unit and estimated in accordance with:

(a) for solid fuels — Division 2.2.5, or

(b) for gaseous fuels — Division 2.3.6; or

ECi is the energy content factor for the fuel type (i) consumed as a carbon reductant in the production of a chemical or mineral product during the year, estimated under section 6.5.

EFij is the carbon dioxide emission factor for the fuel type (i) used in the production of a chemical or mineral product during the year, including effects of oxidation, measured in kilograms for each gigajoule according to source as mentioned in:

(a) for solid fuel combustion — Part 1 of Schedule 1; and

(b) for gaseous fuel combustion — Part 2 of Schedule 1; and

4.56 Method 2 — chemical or mineral production, other than carbide production, using a carbon reductant

Method 2 is:

(a) for estimating emissions released in the consumption of a carbon reductant in the production of a chemical or mineral product using solid fuels during the year — the same as method 2 under Division 2.2.3; and

(b) for estimating emissions released in the consumption of a carbon reductant in the production of a chemical or mineral product using gaseous fuels during the year — the same as method 2 under Division 2.3.3; and

(c) for estimating emissions released in the consumption of a carbon reductant in the production of a chemical or mineral product using liquid fuels during the year — the same as method 2 under Division 2.4.3.

4.57 Method 3 — chemical or mineral production, other than carbide production, using a carbon reductant

Method 3 is:

Part 4.4 Industrial processes — metal industry

Division 4.4.1 Iron, steel or other metal production using an integrated metalworks

4.63 Application

This Division applies to emissions from integrated metalworks.

4.64 Purpose of Division

(1) This Division applies to determining emissions released during a year from the operation of a facility that is constituted by an activity that produces a metal, for example, an integrated metalworks.

(2) An integrated metalworks means a metalworks that produces coke and a metal (for example, iron or steel).

(3) The emissions from the activity are to be worked out as a total of emissions released from the production of a metal and from all other emissions released from the operation of the activity (including the production of coke if the activity is an integrated metalworks).

(4) However, the amount of emissions to be determined for this source is only the amount of emissions from the use of coke as a carbon reductant in the metal production estimated in accordance with section 2.69.

Note The amount of emissions to be determined for other activities is as provided for in other provisions of this Determination.

4.65 Available methods for production of a metal from an integrated metalworks

(1) Subject to section 1.18, one of the following methods must be used for estimating emissions released from the activity during a year:

(a) method 1 under section 4.66;

(b) method 2 under section 4.67;

(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.

4.66 Method 1 — production of a metal from an integrated metalworks

Method 1, based on a carbon mass balance approach, is:

Step 1

Calculate 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 sum 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 Division 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 measured in tonnes of carbon 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 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

Calculate 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 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 types (r).

Yr is the quantity of waste by‑product types (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 in tonnes of carbon 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 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 increase 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

Calculate 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 a year.

4.67 Method 2 — production of a metal from an integrated metalworks

(1) Subject to this section, method 2 is the same as method 1.

(2) 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.

(3) 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, liquid or gaseous fuels.

4.68 Method 3 — production of a metal from an integrated metalworks

(1) Subject to this section, method 3 is the same as method 1.

(3) 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:

Division 4.4.2 Ferroalloys production

4.69 Application

This Division applies to ferroalloy production.

4.70 Available methods

(1) Subject to section 1.18, one of the following methods must be used for estimating emissions of carbon dioxide during a year from the operation of a facility that is constituted by the production of ferroalloy metal:

(a) method 1 under section 4.71;

(b) method 2 under section 4.72;

(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.

4.71 Method 1 — ferroalloy metal

(1) Method 1 is:

where:

Eij is the emissions of carbon dioxide released from the consumption of a carbon reductant in the production of ferroalloy metal during the year, measured in CO2‑e tonnes.

Qi is the quantity of each carbon reductant (i), used in the production of ferroalloy metal during the year, measured in the appropriate unit and estimated in accordance with:

(a) for solid fuels — Division 2.2.5; or

(b) for gaseous fuels — Division 2.3.6; or

ECi is the energy content factor for the fuel type (i) consumed as a carbon reductant in the production of ferroalloy metal during the year, estimated under section 6.5.

EFij is the emission factor of carbon reductant type (i), measured in kilograms of CO2‑e per gigajoule of reductant used in the production of the ferroalloy metal during the year.

(2) In subsection (1), for the factor EFij , the emission factor of each carbon reductant means the emission factor for that reductant as mentioned in Schedule 1.

4.72 Method 2 — ferroalloy metal

Method 2 is:

(a) for estimating emissions released from carbon reductants used in the production of ferroalloy metal using solid fuels — the same as method 2 under Division 2.2.3; and

(b) for estimating emissions released from carbon reductants used in the production of ferroalloy metal using gaseous fuels — the same as method 2 under Division 2.3.3; and

(c) for estimating emissions released from carbon reductants used in the production of ferroalloy metal using liquid fuels — the same as method 2 under Division 2.4.3.

4.73 Method 3 — ferroalloy metals

Method 3 is:

(a) for estimating emissions released from carbon reductants used in the production of ferroalloy metal using solid fuels — the same as method 3 under Division 2.2.4; and

(b) for estimating emissions released from carbon reductants used in the production of ferroalloy metal using gaseous fuels — the same as method 3 under Division 2.3.4; and

(c) for estimating emissions released from carbon reductants used in the production of ferroalloy metal using liquid fuels — the same as method 3 under Division 2.4.4.

Division 4.4.3 Aluminium production (carbon dioxide emissions)

4.74 Application

This Division applies to aluminium production.

Subdivision 4.4.3.1 Aluminium — emissions from consumption of baked carbon anodes in aluminium production

4.75 Available methods

(1) Subject to section 1.18, for estimating emissions of carbon dioxide released during a year from the operation of a facility that is constituted by the production of aluminium involving the consumption of baked carbon anodes, one of the following methods must be used:

(a) method 1 under section 4.76;

(b) method 2 under section 4.77;

(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.

4.76 Method 1 — aluminium (baked carbon anode consumption)

Method 1 is:

where:

Eij is the emissions of carbon dioxide released from aluminium smelting and production involving the consumption of baked carbon anodes during the year measured in CO2‑e tonnes.

Ai is the amount of primary aluminium produced in tonnes during the year.

EFij is the carbon dioxide emission factor for baked carbon anode consumption, measured in CO2‑e tonnes for each tonne of aluminium produced during the year, estimated in accordance with the following formula:

where:

NAC is the amount of carbon consumed from a baked carbon anode consumed in the production of aluminium during the year, worked out at the rate of 0.413 tonnes of baked carbon anode consumed for each tonne of aluminium produced.

Sa is the mass of sulphur content in baked carbon anodes that is consumed in the production of aluminium during the year, expressed as a percentage of the mass of the baked carbon anodes, and is taken to be 2.

Asha is the mass of ash content in baked carbon anodes that is consumed in the production of aluminium during the year, expressed as a percentage of the mass of the baked carbon anodes, and is taken to be 0.4.

4.77 Method 2 — aluminium (baked carbon anode consumption)

(1) Subject to this section, method 2 is the same as method 1 under section 4.76.

(2) In applying method 1 under section 4.76, the method for sampling and analysing the fuel type (i) for the factors NAC, Sa and Asha must be determined by sampling and analysing the fuel type for sulphur and ash content, as the case may be, in accordance with:

(a) for solid fuels — method 2 in Division 2.2.3; and

(b) for gaseous fuels — method 2 in Division 2.3.3; and

(3) However, in applying method 1 under section 4.76, the factor Sa may be the amount for the factor as mentioned in section 4.76.

(4) If the amount for the factor Sa as mentioned in section 4.76 is not used, then Sa must be determined by sampling and analysing the fuel type (i) for sulphur content in accordance with subsection (2).

4.78 Method 3 — aluminium (baked carbon anode consumption)

(1) Subject to this section, method 3 is the same as method 1 under section 4.76.

(2) In applying method 1 under section 4.76, the method for sampling and analysing fuel type (i) for the factors NAC, Sa and Asha must be determined by sampling and analysing the fuel type for sulphur and ash content, as the case may be, in accordance with:

(a) for solid fuels — method 3 in Division 2.2.4; and

(b) for gaseous fuels — method 3 in Division 2.3.4; and

Subdivision 4.4.3.2 Aluminium — emissions from production of baked carbon anodes in aluminium production

4.79 Available methods

(1) Subject to section 1.18, for estimating emissions of carbon dioxide released during a year from the operation of a facility that is constituted by the production of aluminium involving the production of baked carbon anodes, one of the following methods must be used:

(a) method 1 under section 4.80;

(b) method 2 under section 4.81;

(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.

4.80 Method 1 — aluminium (baked carbon anode production)

Method 1 is:

where:

Eij is the emissions of carbon dioxide released from baked carbon anode production for the facility during the year.

GA is the initial weight of green anodes used in the production process of the baked carbon anode.

Hw is the weight of the hydrogen content in green anodes used in the production of the baked carbon anode during the year measured in tonnes.

BA is the amount of baked carbon anode produced during the year measured in tonnes.

WT is the amount, in tonnes, of waste tar collected in the production of baked carbon anodes during the year.

ΣQi is the quantity of fuel type (i), measured in the appropriate unit, consumed in the production of baked carbon anodes during the year and estimated in accordance with the requirements set out in the following Divisions:

(a) if fuel type (i) is a solid fuel — Division 2.2.5;

(b) if fuel type (i) is a gaseous fuel — Division 2.3.6;

Si is the mass of sulphur content in baked carbon anodes that is consumed in the production of aluminium during the year, expressed as a percentage of the mass of the baked carbon anodes, and is taken to be 2.

Ashi is the mass of ash content in baked carbon anodes that is consumed in the production of aluminium during the year, expressed as a percentage of the mass of the baked carbon anodes, and is taken to be 0.4.

Note The default value for Hw is 0.5% of GA.

4.81 Method 2 — aluminium (baked carbon anode production)

(1) Subject to this section, method 2 is the same as method 1 under section 4.80.

(2) In applying method 1 under section 4.80, the method for sampling and analysing fuel type (i) for the factors Si and Ashi must be determined by sampling and analysing the fuel type for sulphur and ash content, as the case may be, in accordance with:

(a) for solid fuels — method 2 in Division 2.2.3; and

(b) for gaseous fuels — method 2 in Division 2.3.3; and

4.82 Method 3 — aluminium (baked carbon anode production)

(1) Subject to this section, method 3 is the same as method 1 under section 4.80.

(2) In applying method 1 under section 4.80, the method for sampling and analysing the fuel type (i) for the factors Si and Ashi must be determined by sampling and analysing the fuel type for sulphur and ash content, as the case may be, in accordance with:

(a) for solid fuels — method 3 in Division 2.2.4; and

(b) for gaseous fuels — method 3 in Division 2.3.4; and

Division 4.4.4 Aluminium production (perfluoronated carbon compound emissions)

4.83 Application

This Division applies to aluminium production.

Subdivision 4.4.4.1 Aluminium — emissions of tetrafluoromethane in aluminium production

4.84 Available methods

(1) Subject to section 1.18, one of the following methods must be used for estimating emissions of tetrafluoromethane released during a year from the operation of a facility that is constituted by the production of aluminium:

(b) method 2 under section 4.86;

Note There is no method 1 or 4 for this provision.

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

4.85 Method 1 — aluminium (tetrafluoromethane)

Method 1 is:

where:

Eij is the amount of emissions of tetrafluoromethane released from primary aluminium production during the year measured in CO2‑e tonnes.

Ai is the amount of primary aluminium production during the year measured in tonnes.

EFij is 0.26, which is the emission factor for tetrafluoromethane measured in CO2‑e tonnes for each tonne of aluminium produced during the year.

4.86 Method 2 — aluminium (tetrafluoromethane)

Method 2 is the Tier 2 method for estimating perfluorocarbon emissions as set out in the Perfluorocarbon protocol.

4.87 Method 3 — aluminium (tetrafluoromethane)

Method 3 is the Tier 3 method for estimating facility‑specific perfluorocarbon emissions as set out in the Perfluorocarbon protocol.

Subdivision 4.4.4.2 Aluminium — emissions of hexafluoroethane in aluminium production

4.88 Available methods

(1) Subject to section 1.18, one of the following methods must be used for estimating emissions of hexafluoroethane released during a year from the operation of a facility that is constituted by the production of aluminium:

(b) method 2 under section 4.90;

Note There is no method 1 or 4 for this provision.

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

4.89 Method 1 — aluminium production (hexafluoroethane)

Method 1 is:

where:

Eij is the emissions of hexafluoroethane released from primary aluminium production during the year measured in CO2‑e tonnes.

Ai is the amount of primary aluminium production during the year measured in tonnes.

EFij is 0.05, which is the emission factor for hexafluoroethane measured in CO2‑e tonnes for each tonne of aluminium produced during the year.

4.90 Method 2 — aluminium production (hexafluoroethane)

Method 2 is the Tier 2 method for estimating facility‑specific perfluorocarbon emissions as set out in the Perfluorocarbon protocol.

4.91 Method 3 — aluminium production (hexafluoroethane)

Method 3 is the Tier 3 method for estimating facility‑specific perfluorocarbon emissions as set out in the Perfluorocarbon protocol.

Division 4.4.5 Other metals production

4.92 Application

This Division applies to emissions from activities producing metals other than aluminium, ferroalloys, iron, steel or any other metal produced using an integrated metalworks.

4.93 Available methods

(1) Subject to section 1.18, one of the following methods must be used for estimating emissions of carbon dioxide from the use of carbon reductants during a year from the operation of a facility that is constituted by the production of metals to which this Division applies:

(a) method 1 under section 4.94;

(b) method 2 under section 4.95;

(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.

4.94 Method 1 — other metals

(1) Method 1 is:

where:

ECi is the energy content factor for the fuel type (i) consumed as a carbon reductant in the production of the metal during the year, estimated under section 6.5.

Qi is the quantity of each carbon reductant type (i) consumed in the production of the metal during the year, measured in the appropriate unit and estimated in accordance with the requirements set out in the following Divisions:

(a) if fuel type (i) is a solid fuel — Division 2.2.5;

(b) if fuel type (i) is a gaseous fuel — Division 2.3.6;

ECi is the energy content factor of the carbon reductant type (i) measured in gigajoules per the appropriate unit for the reductant used in the production of the metal during the year.

EFi is the emission factor of each carbon reductant type (i) measured in kilograms of CO2‑e for each gigajoule of reductant consumed in the production of the metal during the year.

(2) In subsection (1), for EFi, the emission factor of each carbon reductant means the emission factor for that reductant as mentioned in Schedule 1.

4.95 Method 2 — other metals

Method 2 is:

(a) for estimating emissions released from carbon reductants consumed in the production of other metals using solid fuels — the same as method 2 under Division 2.2.3; and

(b) for estimating emissions released from carbon reductants consumed in the production of other metals using gaseous fuels — the same as method 2 under Division 2.3.3; and

(c) for estimating emissions released from carbon reductants consumed in the production of other metals using liquid fuels — the same as method 2 under Division 2.4.3.

4.96 Method 3 — other metals

Method 3 is:

(a) for estimating emissions released from carbon reductants consumed in the production of other metals using solid fuels — the same as method 3 under Division 2.2.4; and

(b) for estimating emissions released from carbon reductants consumed in the production of other metals using gaseous fuels — the same as method 3 under Division 2.3.4; and

(c) for estimating emissions released from carbon reductants consumed in the production of other metals using liquid fuels — the same as method 3 under Division 2.4.4.

Part 4.5 Industrial processes — emissions of hydrofluorocarbons and sulphur hexafluoride gases

4.97 Application

This Part applies to emissions of hydrofluorocarbons and sulphur hexafluoride gases.

4.98 Available method

(1) Subject to section 1.18, for estimating emissions of hydrofluorocarbons or sulphur hexafluoride during a year from the operation of a facility that is constituted by synthetic gas generating activities, one of the following methods must be used:

(a) method 1 under section 4.102;

(b) method 2, for both hydrofluorocarbons and sulphur hexafluoride, under section 4.103;

(i) for hydrofluorocarbons under subsection 4.104 (1); and

(ii) for sulphur hexafluoride under subsection 4.104 (2).

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

Note There is no method 4 for this Part.

4.99 Meaning of hydrofluorocarbons

Hydrofluorocarbons means any of the hydrofluorocarbons listed in the table in regulation 2.04 of the Regulations.

4.100 Meaning of synthetic gas generating activities

Hydrofluorocarbons

(1) Synthetic gas generating activities, for emissions of hydrofluorocarbons, are activities of a facility that:

(a) require the use of any thing:

(i) mentioned in paragraph 4.16 (1) (a) of the Regulations; and

(ii) containing a refrigerant charge of more than 100 kilograms of refrigerants for each unit; and

(iii) using a refrigerant that is a greenhouse gas with a Global Warming Potential of more than 1 000; and

(b) are attributable primarily to any one of the following ANZSIC industry classifications:

(i) food product manufacturing (ANZSIC classification, Subdivision 11);

(ii) beverage and tobacco product manufacturing (ANZSIC classification, Subdivision 12);

(iii) retail trade (ANZSIC classification, Division G);

(iv) warehousing and storage services (ANZSIC classification, number 530);

(v) wholesale trade (ANZSIC classification Division F);

(vi) rental, hiring and real estate services (ANZSIC classification, Division L).

Sulphur hexafluoride

(2) Synthetic gas generating activities, for emissions of sulphur hexafluoride, are any activities of a facility that emit sulphur hexafluoride.

4.101 Reporting threshold

For paragraph 4.22 (1) (b) of the Regulations, the threshold mentioned in column 3 of an item in the following table resulting from a provision of this Determination mentioned in column 2 of that item is a reporting threshold.

Item	Provision in Determination	Threshold
1	Subparagraph 4.100 (1) (a) (ii)	100 kilograms for each unit (hydrofluorocarbons)
2	Subsection 4.100 (2)	Any emission (sulphur hexafluoride)

4.102 Method 1

(1) Method 1 is:

where:

Ejk is the emissions of gas type (j), either hydrofluorocarbons or sulphur hexafluoride, summed over each equipment type (k) during a year measured in CO2‑e tonnes.

Stockjk is the stock of gas type (j), either hydrofluorocarbons or sulphur hexafluoride, contained in equipment type (k) during a year measured in CO2‑e tonnes.

Ljk is the default leakage rates for a year of gas type (j) mentioned in columns 3 or 4 of an item in the table in subsection (4) for the equipment type (k) mentioned in column 2 for that item.

(2) For the factor Stockjk, an estimation of the stock of synthetic gases contained in an equipment type must be based on one of the following sources:

(a) the stated capacity of the equipment according to the manufacturer’s nameplate;

(b) estimates based on:

(i) the opening stock of gas in the equipment; and

(ii) transfers into the facility from additions of gas from purchases of new equipment and replenishments; and

(iii) transfers out of the facility from disposal of equipment or gas.

(3) For equipment type (k), the equipment are the things mentioned in subregulation 4.16 (1) of the Regulations.

(4) For subsection (1), columns 3 and 4 of an item in the following table set out default leakage rates of gas type (j), for either hydrofluorocarbons or sulphur hexafluoride, in relation to particular equipment types (k) mentioned in column 2 of the item:

Item	Equipment type (k)	Default annual leakage rate of gas (j)
Item	Equipment type (k)	Hydrofluorocarbons	Sulphur hexafluoride
1	Commercial air conditioning	0.09
2	Commercial refrigeration	0.23
3	Industrial refrigeration	0.16
4	Gas insulated switchgear and circuit breaker applications		0.005

4.103 Method 2

For paragraph 4.98 (1) (b), method 2 for estimating emissions of hydrofluorocarbons or sulphur hexafluoride during a year uses the tables in Appendix A of the publication entitled ENA Industry Guideline for SF6 Management, Energy Networks Association, 2008.

4.104 Method 3

(1) For paragraph 4.98 (1) (c), method 3 for estimating emissions of hydrofluorocarbons uses the tables in Appendix B of the publication entitled ENA Industry Guideline for SF6 Management, Energy Networks Association, 2008.

(2) For paragraph 4.98 (1) (c), method 3 for estimating emissions of sulphur hexafluoride during a year uses the Tier 3 method set out in section 6.3 of the publication mentioned in subsection (1).

Chapter 5 Waste

Part 5.1 Preliminary

5.1 Outline of Chapter

This Chapter provides for emissions from the following sources:

(a) solid waste disposal on land (see Part 5.2);

(b) wastewater handling (domestic and commercial) (see Part 5.3);

(d) waste incineration (see Part 5.5).

Part 5.2 Solid waste disposal on land

Division 5.2.1 Preliminary

5.2 Application

(1) This Part applies to emissions released from:

(a) the decomposition of organic material from solid waste disposal in a landfill; and

(b) flaring of landfill gas.

(2) This Part does not apply to a landfill unless:

(a) the landfill was open for the acceptance of waste on and after 1 July 2008; and

(b) during a year the landfill emits more than 10 000 tonnes of CO2‑e from solid waste disposal at the landfill.

5.3 Available methods

(1) Subject to section 1.18 for estimating emissions released from the operation of a facility that is constituted by a landfill during a year:

(a) subject to paragraph (c), one of the following methods must be used for emissions of methane from the landfill (other than from flaring of methane):

(i) method 1 under section 5.4;

(ii) method 2 under section 5.15;

(iii) method 3 under section 5.18; and

(b) one of the following methods must be used for emissions for each gas type released as a result of methane flared from the operation of the landfill:

(i) method 1 under section 5.19;

(ii) method 2 under section 5.20;

(iii) method 3 under section 5.21; and

(2) Under paragraph (1) (b), the same method must be used for estimating emissions of each gas type.

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

Note There is no method 4 for paragraphs (a) and (b) and no methods 2, 3 or 4 for paragraph (1) (c). It is proposed that a method 4 will be developed in the future.

Division 5.2.2 Method 1 — emissions of methane released from landfills

5.4 Method 1 — methane released from landfills (other than from flaring of methane)

(1) For subparagraph 5.3 (1) (a) (i), method 1 is:

where:

Ej is the emissions of methane released by the landfill during the year measured in CO2‑e tonnes.

CH4* is the estimated quantity of methane in landfill gas generated by the landfill during the year as determined under subsection (2) and measured in CO2‑e tonnes.

γ is the factor 6.784 × 10‑4 × 21 converting cubic metres of methane at standard conditions to CO2‑e tonnes.

Qcap is the quantity of methane in landfill gas captured for combustion from the landfill during the year and measured in cubic metres in accordance with Division 2.3.6.

Qflared is the quantity of methane in landfill gas flared from the landfill during the year and measured in cubic metres in accordance with Division 2.3.6.

Qtr is the quantity of methane in landfill gas transferred out of the landfill during the year and measured in cubic metres in accordance with Division 2.3.6.

OF is the oxidation factor (0.1) for near surface methane in the landfill.

(2) For subsection (1), if:

is less than or equal to 0.75, then:

where:

CH4gen is the quantity of methane in landfill gas generation released from the landfill during the year estimated in accordance with subsection (5) and measured in CO2‑e tonnes.

(3) For subsection (1), if:

is greater than 0.75, then:

where:

γ is the factor 6.784 x 10‑4 x 21 converting cubic metres of methane at standard conditions to CO2‑e tonnes.

Qcap is the quantity of methane in landfill gas captured for combustion from the landfill during the year and measured in cubic metres.

(4) For subsections (1) and (3), Qcap is to be calculated in accordance with Division 2.3.6.

(5) For subsection (2), CH4gen must be calculated using:

(a) the Tier 2 first order decay model (the Tier 2 FOD model) in Volume 5, Chapter 3 of the 2006 IPCC Guidelines; and

(b) estimates, in accordance with sections 5.5 to 5.14, of the following:

(i) the tonnage of total solid waste disposed of in the landfill during the year (see section 5.5);

(ii) the composition of the solid waste disposed of in the landfill during the year (see section 5.9);

(iii) the degradable organic carbon content of the solid waste disposed of in the landfill by waste type (see section 5.12);

(iv) the opening stock of degradable organic carbon in the solid waste at the landfill at the start of the first reporting period for the landfill (see section 5.13);

(v) methane generation constants (k values) for the solid waste at the landfill (see section 5.14).

5.5 Criteria for estimating tonnage of total solid waste

For the purpose of estimating the tonnage of waste disposed of in a landfill, the tonnage of total solid waste received at the landfill during the year is to be estimated using one of the following criteria:

(a) as provided in section 5.6 (criterion A);

(b) as provided in section 5.7 (criterion AAA);

5.6 Criterion A

For paragraph 5.5 (a), criterion A is:

(a) the amount of solid waste received at the landfill during the year as evidenced by invoices; or

(b) if the amount of solid waste received at the landfill during the year is measured in accordance with State or Territory legislation applying to the landfill — that measurement.

5.7 Criterion AAA

For paragraph 5.5 (b), criterion AAA is the direct measurement of quantities of solid waste received at the landfill during the year using measuring equipment calibrated to a measurement requirement.

5.8 Criterion BBB

For paragraph 5.5 (c), criterion BBB is the estimation of solid waste received at the landfill during the year in accordance with industry estimation practices (including the use of accepted industry weighbridges) that meet the general criteria in section 1.13.

5.9 Composition of solid waste

(1) For subparagraph 5.4 (5) (b) (ii), the composition of solid waste received at the landfill during the year must be classified by waste stream in accordance with subsection 5.10 (1) and an estimate of tonnage for each waste stream must be provided in accordance with subsection 5.10 (2) or (3).

(2) For each waste stream classification there must be a further classification in accordance with section 5.11 showing the waste mix types in each waste stream, expressed as a percentage of the total tonnage of solid waste in the waste stream.

5.10 Waste streams

(1) For subsection 5.9 (1), the waste streams are as follows:

(a) municipal solid waste;

(b) commercial and industrial waste;

(2) For subsection 5.9 (1), the tonnage of each waste stream must be estimated:

(a) if the operator of the landfill is required, under a law of the State or Territory in which the landfill is located, to collect data on tonnage of waste received at the landfill according to the waste streams set out in column 2 of the following table — by using that data; or

(b) if paragraph (a) does not apply and there is no restriction on the waste streams that can be received at the landfill — by using the percentage values in columns 3 to 10 of an item in the following table for each waste stream in column 2 for the item for the State or Territory in which the landfill is located.

Item	Waste stream	NSW %	VIC %	QLD %	WA %	SA %	TAS %	ACT %	NT %
1	Municipal solid waste	31	36	43	26	36	57	43	43
2	Commercial and industrial	42	24	14	17	19	33	42	14
3	Construction and demolition	27	40	43	57	45	10	15	43

(3) For subsection 5.9 (1), if the landfill is permitted to receive only:

(a) non-putrescible waste; or

(b) commercial and industrial waste and construction and demolition waste;

the waste may be assumed to consist of only commercial and industrial waste and construction and demolition waste.

(4) If subsection (3) applies, the tonnage of each waste stream must be estimated by using the percentage values in columns 3 to 10 of an item in the following table for each waste stream in column 2 for the item for the State or Territory in which the landfill is located.

Item	Waste stream	NSW (%)	VIC (%)	QLD (%)	WA (%)	SA (%)	TAS (%)	ACT (%)	NT (%)
1	Commercial and industrial waste	61	38	25	23	30	77	74	25
2	Construction and demolition waste	39	62	75	77	70	23	26	75

5.11 Waste mix types

(1) For subsection 5.9 (2), the waste mix types are as follows:

(a) food;

(b) paper and paper board;

(d) garden and park;

(e) wood and wood waste;

(f) sludge;

(g) nappies;

(h) rubber and leather;

(i) inert waste (including concrete, metal, plastic and glass).

(2) The percentage of the total waste tonnage for each waste mix type mentioned in column 2 of an item in the following table must be estimated by using:

(a) sampling techniques specified in:

(i) waste audit guidelines issued by the State or Territory in which the landfill is located; or

(ii) if no guidelines have been issued by the State or Territory in which the landfill is located — ASTM D 5231–92 (Reapproved 2008) or an equivalent Australian or international standard; or

(b) the tonnage of each waste mix type received at the landfill estimated in accordance with the criteria set out in section 5.5; or

(c) subject to subsection 5.11 (3), the default waste stream percentages in columns 3, 4 and 5 for the item for each waste mix type.

Item	Waste mix type	Municipal solid waste default (%)	Commercial and industrial waste default (%)	Construction and demolition waste default (%)
1	Food	35	21.5	0
2	Paper and paper board	13	15.5	3
3	Garden and park	16.5	4	2
4	Wood and wood waste	1	12.5	6
5	Textiles	1.5	4	0
6	Sludge	0	1.5	0
7	Nappies	4	0	0
8	Rubber and Leather	1	3.5	0
9	Inert waste (including concrete, metal, plastic and glass)	28	37.5	89

(3) If the licence or other authorisation authorising the operation of the landfill restricts the waste mix types (restricted waste mix type) that may be received at the landfill, the percentage of the total waste volume for each waste mix type mentioned in column 2 of an item of the following table (appearing immediately before the example) must be estimated:

(a) for a restricted waste mix type — by using the maximum permitted tonnage of the restricted waste mix type received at the landfill, as a percentage of the total waste received at the landfill; and

(b) for each waste mix type that is not a restricted waste mix type (unrestricted waste mix type) — by adjusting the default percentages in columns 3, 4 and 5 of the following table for the item for each unrestricted waste mix type, in accordance with the following formula:

where:

Wmtuadj is the adjusted percentage for each unrestricted waste mix type.

Wmtu is the default percentage for each unrestricted waste mix type in columns 3, 4 and 5 of the table appearing immediately before the example.

Wmtr is the default percentage for each restricted waste mix type in columns 3, 4 and 5 of the table appearing immediately before the example.

Wmtrmax is the maximum percentage for each restricted waste mix type.

∑ means sum the results for each unrestricted waste mix type.

Item	Waste mix type	Municipal solid waste default (%)	Commercial and industrial waste default (%)	Construction and demolition waste default (%)
1	Food	35	21.5	0
2	Paper and paper board	13	15.5	3
3	Garden and park	16.5	4	2
4	Wood and wood waste	1	12.5	6
5	Textiles	1.5	4	0
6	Sludge	0	1.5	0
7	Nappies	4	0	0
8	Rubber and leather	1	3.5	0
9	Inert waste (including concrete, metal, plastic and glass)	28	37.5	89

Example

A landfill in a State is licensed only to receive commercial and industrial waste. A condition of the licence is that the landfill is restricted to receiving no more than 5% (Wmtrmax = 5%) food waste in its deliveries. The landfill operator accounts for this restriction by using the formula for each unrestricted waste type (Wmtu) in the table above. So, for paper and paper board waste, the calculation is:

The operator would continue to use the formula for each unrestricted waste mix type. For the restricted waste mix type the percentage used is Wmtrmax.

The following table sets out all the relevant variables and results for this example.

Item	Waste mix type	Wmtu (%)	Wmtr (%)	Wmtrmax (%)	Wmtadj (%)
1	Food		21.5	5.0
2	Paper and paper board	15.5			18.8
3	Garden and park	4.0			4.8
4	Wood and wood waste	12.5			15.1
5	Textiles	4.0			4.8
6	Sludge	1.5			1.8
7	Nappies	0.0			0.0
8	Rubber and leather	3.5			4.2
9	Inert waste (including concrete, metal, plastic and glass)	37.5			45.4

5.11A Certain waste to be deducted from waste received at landfill when estimating waste disposed in landfill

When estimating the tonnage of waste by waste mix type disposed of in a landfill, the tonnage of the following waste is to be deducted from the estimates of waste received at the landfill:

(a) waste that is taken from the landfill for recycling or biological treatment;

(b) waste that is received at the landfill for recycling or biological treatment at the landfill site;

(c) inert waste that is used at the landfill for construction purposes, daily cover purposes, intermediate cover purposes or final capping and cover purposes.

5.12 Degradable organic carbon content

For subparagraph 5.4 (5) (b) (iii), the amount of the degradable organic carbon content of the solid waste at the landfill must be estimated by using the degradable organic carbon values in column 3 of an item in the following table for each waste mix type in column 2 for that item.

Item	Waste mix type	Degradable organic carbon value
1	Food	0.15
2	Paper and cardboard	0.40
3	Garden and green	0.20
4	Wood	0.43
5	Textiles	0.24
6	Sludge	0.05
7	Nappies	0.24
8	Rubber and Leather	0.39
9	Concrete, metal, plastic and glass	0.00

5.13 Opening stock of degradable organic carbon

(1) For subparagraph 5.4 (5) (b) (iv), the amount of opening stock of degradable organic carbon at the landfill at the start of the first reporting period for the landfill must be estimated in accordance with the Tier 2 FOD model mentioned in subsection 5.4 (5):

(a) by using the details of the total tonnage of solid waste (broken down into waste stream and waste mix type and estimated in accordance with section 5.5) disposed of in the landfill each year over the lifetime of the landfill until the start of the first reporting period for the landfill; or

(b) if the operator of a landfill is unable to comply with paragraph (a) — by using the following information in relation to the landfill:

(i) the number of years that the landfill has been in operation;

(ii) the estimated annual tonnage of solid waste disposed of in the landfill over the lifetime of the landfill until the start of the first reporting period for the landfill, worked out in accordance with subsection (2);

(iii) the State or Territory in which the landfill is located.

(2) For subparagraph (1) (b) (ii), the estimated annual tonnage of waste is to be worked out:

(a) by using the average annual tonnage of solid waste disposed of in the landfill for the years for which data is available; or

(b) by conducting a volumetric survey of the landfill in accordance with subsections (3) and (4).

(3) For paragraph (2) (b), the survey:

(a) must be a ground-based survey or an aerial survey; and

(b) must be conducted by a qualified surveyor.

(4) For the volumetric survey, the volume of waste is to be converted to mass by using one of the following volume-to-mass conversion factors:

(a) the landfill volume-to-mass conversion factors that were used during the most recent reporting year in order to comply with a landfill reporting requirement of the State or Territory in which the landfill is located;

(b) if the factors mentioned in paragraph (a) were not used during the most recent reporting year in order to comply with a landfill reporting requirement of the State or Territory in which the landfill is located — the volume-to-mass conversion factors specified in column 3 of an item in the following table for a waste stream specified in column 2 of the item.

Item	Waste stream	Volume-to-mass conversion factor
1	Municipal solid waste	1.1 tonnes per cubic metre
2	Commercial and industrial waste	1.1 tonnes per cubic metre
3	Construction and demolition waste	1.1 tonnes per cubic metre

5.14 Methane generation constants — (k values)

For subparagraph 5.4 (5) (b) (v), the methane generation constants (k values) for solid waste at a landfill in a State or Territory mentioned in column 2 of an item in the following table are the constants set out in column 4 for a waste mix type mentioned in column 3 for the item.

Item	State/Territory	Waste mix type	k values
1	NSW	Food	0.185
		Paper and cardboard	0.06
		Garden and Green	0.10
		Wood	0.03
		Textiles	0.06
		Sludge	0.185
		Nappies	0.06
		Rubber and Leather	0.06
2	VIC, WA, SA, TAS, ACT	Food	0.06
		Paper and cardboard	0.04
		Garden and Green	0.05
		Wood	0.02
		Textiles	0.04
		Sludge	0.06
		Nappies	0.06
		Rubber and Leather	0.04
3	QLD, NT	Food	0.4
		Paper and cardboard	0.07
		Garden and Green	0.17
		Wood	0.035
		Textiles	0.07
		Sludge	0.4
		Nappies	0.07
		Rubber and Leather	0.07

Division 5.2.3 Method 2 — emissions of methane released from landfills

Subdivision 5.2.3.1 methane released from landfills

5.15 Method 2 — methane released from landfills (other than from flaring of methane)

(1) For subparagraph 5.3 (1) (a) (ii), method 2 is:

where:

Ej is the emissions of methane released by the landfill during the year measured in CO2‑e tonnes.

CH4gen is the estimated quantity of methane in landfill gas generated by the landfill during the year as calculated under subsection (2) and measured in CO2‑e tonnes.

γ is the factor 6.784 x 10‑4 x 21 converting cubic metres of methane at standard conditions measured to CO2‑e tonnes.

Qcap is the quantity of methane in landfill gas captured for combustion from the landfill during the year measured in cubic metres in accordance with Division 2.3.6.

Qflared is the quantity of methane in landfill gas flared from the landfill during the year measured in cubic metres in accordance with Division 2.3.6.

Qtr is the quantity of methane in landfill gas transferred out of the landfill during the year measured in cubic metres in accordance with Division 2.3.6.

OF is the oxidation factor (0.1) for near surface methane in the landfill.

(2) For subsection (1), CH4gen must be calculated using the Tier 2 first order decay model (the Tier 2 FOD model) in Volume 5, Chapter 3, of the 2006 IPCC Guidelines.

(3) In calculating CH4gen for the purposes of subsection (2), the methane generation constant (k) must be estimated by:

(a) selecting a representative zone at the landfill, in accordance with sections 5.16 to 5.17B, from which estimates of methane generation are to be obtained; and

(b) using the formula in section 5.17L.

(5) This method may only be used if specific information is available on the waste mix types at the landfill.

Subdivision 5.2.3.2 Requirements for calculating the methane generation constant (k)

5.16 Procedures for selecting representative zone

For paragraph 5.13 (3) (a), the operator of the landfill must select a representative zone in accordance with sections 5.17 to 5.17B for the purpose of estimating the methane generated from the landfill.

5.17 Preparation of site plan

(1) Before selecting a representative zone, the operator must prepare a site plan of the landfill.

(2) The site plan must be consistent with the provisions of the technical guidelines relating to landfill site plans.

5.17A Representative zone

(1) After preparing a site plan, the operator of the landfill must select a representative zone at the landfill.

(2) The representative zone must be a single, contiguous area within the landfill and the methane generated from the representative zone must be representative of the methane that is generated at the landfill.

(3) The representative zone must cover an area of at least 1 hectare and must contain a sufficient number of operating gas collection wells to enable accurate and representative estimates to be obtained of the methane being generated from the zone.

(4) The representative zone must contain only waste that has been undisturbed:

(a) for at least 12 months before any methane generation is measured under section 5.17H; or

(b) in the case of a representative zone that is on landfill that recirculates leachate or adds moisture through the waste to promote methane generation — for the period determined by an independent expert.

(5) The following characteristics of the representative zone must be representative of the landfill:

(a) the depth of waste in the zone;

(b) moisture levels in the zone;

5.17B Independent verification

(1) After selecting a representative zone, the operator must arrange for an independent expert to certify, in writing, that:

(a) the representative zone is representative of the landfill; and

(b) the boundaries of the zone are appropriate for the purpose of obtaining accurate and representative estimates of the methane being generated from the zone.

(2) The independent expert must also prepare a written report for the zone.

(3) The report must include the details specified in the technical guidelines in relation to expert reports.

5.17C Estimation of waste and degradable organic content in representative zone

The amount of waste, and the amount of degradable organic content in the waste, disposed of in the representative zone must be estimated in accordance with sections 5.5 to 5.12 for each reporting year that waste is disposed of in the representative zone.

5.17D Estimation of gas collected at the representative zone

(1) The operator of the landfill must estimate the total amount, and concentration, of landfill gas (measured in tonnes of methane per year) collected by all of the landfill gas collection wells located within the representative zone.

(2) Measurement of the landfill gas flow rate for each well must be undertaken in accordance Division 2.3.6.

(3) The methane concentration of the landfill gas from the representative zone:

(a) may be estimated from measurements of landfill gas obtained at each gas collection well located within the representative zone using industry standard landfill gas analysers that are calibrated to the manufacturer’s specifications; or

(b) may be assumed to be the methane concentration for the landfill as analysed under Subdivision 2.3.3.2.

(4) Data about the methane gas flow rates at each well in the representative zone must be:

(a) the data used for operational purposes; and

(b) recorded at least once a week for a period of at least 12 months.

(5) Fuel flow meter equipment and gas composition monitoring equipment used to measure and analyse the landfill gas must be calibrated in accordance with:

(a) a standard specified in section 2.24 or an equivalent standard; or

(b) the calibration procedures specified, and at the frequencies recommended, by the manufacturer of the equipment.

(6) Fuel flow meter equipment and gas composition monitoring equipment must be recalibrated:

(a) at the frequency specified by the manufacturer of the equipment; or

(b) if the manufacturer does not specify a recalibration period for the equipment — annually.

(7) Estimates of gas flow must be converted from cubic metres to mass by using the formula in subsection 1.21 (1).

5.17E Estimating methane generated but not collected in the representative zone

(1) The operator must estimate the amount of emissions of methane in the representative zone that is not collected by the collection wells in the zone.

(2) Estimates must be obtained by using the procedures in sections 5.17F to 5.17H.

5.17F Walkover survey

(1) The operator of the landfill must arrange for an independent expert to conduct a walkover survey of the representative zone using a portable gas measurement device in order to:

(a) determine the near surface gas concentrations in the representative zone and in the immediately surrounding area; and

(b) identify locations within the representative zone:

(i) that have high methane emissions; and

(ii) where flux boxes need to be installed in accordance with section 5.17G in order to obtain the most accurate and representative measurements of methane emissions.

(2) The portable gas measurement device must be capable of detecting hydrocarbons at 10 parts per million.

Note The publication entitled Guidance on monitoring landfill gas surface emissions published by the Environment Agency of the United Kingdom in September 2004 contains guidance on how to conduct a walkover survey.

5.17G Installation of flux boxes in representative zone

(1) After the walkover survey has been completed, the operator of the landfill must arrange for the installation of flux boxes in the representative zone.

(2) The number of flux boxes must be at least the minimum number identified during the walkover survey.

(3) The flux boxes must be installed at the locations identified in the walkover survey.

(4) If the operator installs the flux boxes, the operator must ensure that an independent expert certifies, in writing, that the boxes have been correctly installed and located.

(5) If the operator arranges for some other person to install the flux boxes, the other person must be an independent expert.

(6) The minimum number of flux boxes is to be determined by using the following formula:

where:

Z is the size of the representative zone in square metres.

Note AS/NZS 4323.4—2009 and the publication entitled Guidance on monitoring landfill gas surface emissions published by the Environment Agency of the United Kingdom in September 2004 contain guidance on how to design and install flux boxes.

5.17H Flux box measurements

(1) After the flux boxes have been installed in the representative zone, the operator must:

(a) measure the flow of methane in each flux box and arrange for an independent expert to certify, in writing, that the measurements are accurate and were correctly measured; or

(b) arrange for an independent expert to take the measurements.

(2) The flow of methane from each flux box must be calculated in accordance with the following formula:

where:

Q is the flow density of the gas in the flux box, measured in milligrams of methane per square metre per second.

V is the volume of the flux box, measured in cubic metres.

is the rate of change of gas concentration in the flux boxes over time, measured in milligrams per cubic metre per second.

A is the area covered by the flux box, measured in square metres.

(3) The total gas flow rate for the representative zone is to be obtained by using geospatial interpolation techniques.

(4) The amount of methane generated, but not collected, in the representative zone must be estimated by dividing the total gas flow rate obtained in accordance with subsection (3) by:

where:

OF is the oxidation factor mentioned in subsection 5.15 (1).

(5) The measurement of methane obtained under the formula in subsection (2) must be converted from milligrams of methane per square metre per second to tonnes of methane for the surface area of the representative zone for the reporting year.

(6) Estimates of gas flow must be converted from cubic metres to mass by using the formula in subsection 1.21 (1).

5.17I When flux box measurements must be taken

(1) Flux box measurements must be taken during the normal operating times of the gas collection wells in the representative zone.

(2) The measurements must be completed within 3 days.

5.17J Restrictions on taking flux box measurements

(1) Flux box measurements must not be taken:

(a) within 2 days of heavy rainfall over the representative area; or

(b) if barometric pressure at the landfill site is rising or falling sharply; or

(d) in any other meteorological conditions that may significantly affect the accuracy of the measurements; or

(e) in areas where there is standing water.

(2) For subsection (1), there is heavy rainfall over a representative area on any day of a month if the amount of rain that is recorded:

(a) at the landfill on that day; or

(b) if rainfall is not recorded at the landfill — at the nearest Bureau of Meteorology weather station to the landfill on that day;

exceeds the heavy rainfall benchmark, as calculated in accordance with the following formula:

where:

HRF is the heavy rainfall benchmark.

RF is the mean monthly rainfall for the month at the landfill or nearest Bureau of Meteorology weather station.

MRD is the mean rainfall days for the month at the nearest Bureau of Meteorology weather station as recorded in the publication published by the Bureau of Meteorology and known as Climate statistics for Australian locations.

5.17K Frequency of measurement

The measurement of emissions by flux boxes must be undertaken on a quarterly basis for a period of at least 12 months.

5.17L Calculating the methane generation constant (k)

(1) For paragraph 5.15 (3) (b), the formula for calculating the methane generation constant (k) is as follows:

where:

Qz is the gas flow rate for the representative zone, measured in tonnes per year, and is the sum of:

(a) the total amount of methane estimated under section 5.17D and collected at the collection wells in the representative zone; and

(b) the total amount of methane generated from the representative zone as obtained under subsection 5.17H (5).

k is the methane generation constant.

Qwaste is the total waste disposed of in the representative zone, measured in tonnes and estimated in accordance with section 5.17C.

Lo is the methane generation potential of the waste in the representative zone worked out under subsection (2) and measured in tonnes of methane per tonne of waste disposed.

e is the base number for natural logarithms (2.718).

Aavg is the average age of the waste in the representative zone, measured in years.

(2) For subsection (1), the methane generation potential (Lo) for waste disposed of in a representative zone of a landfill during a year is to be worked out using the following formula:

where:

Ca is the is the quantity of degradable organic carbon in waste disposed of in the representative zone, measured in tonnes and estimated in accordance with section 5.17C.

Qwaste is the total waste disposed in the representative zone, measured in tonnes and estimated under section 5.17C.

DOCF is the fraction of degradable organic carbon dissimilated and is equal to 0.5.

MCF is the methane correction factor for aerobic decomposition and is equal to 1.

F is the fraction by volume of methane in landfill gas as estimated in accordance with section 5.17D and collected from the representative zone.

1.336 is the factor to convert carbon to methane.

(3) For the formula in subsection (1), it is sufficient if the left-hand side of the formula is within ±0.001 of zero.

Division 5.2.4 Method 3 — emissions of methane released from solid waste at landfills

5.18 Method 3 — methane released from solid waste at landfills (other than from flaring of methane)

(1) For subparagraph 5.3 (1) (a) (iii) and subject to subsection (2), method 3 is the same as method 2 under section 5.15.

(2) In applying method 2 under section 5.15:

(a) paragraph 5.15 (3) (a) does not apply; and

(b) the gas flow rate must be estimated from sampling undertaken during the year in accordance with USEPA Method 2E—Determination of landfill gas production flow rate, as set out in Appendix A–1 of Title 40, Part 60 of the Code of Federal Regulations, Unites States of America, or an equivalent Australian or international standard.

Division 5.2.5 Solid waste at landfills — Flaring

5.19 Method 1 — landfill gas flared

(1) For subparagraph 5.3 (b) (i), method 1 is:

where:

Ej flared is the emissions of gas type (j), being methane and nitrous oxide, released from the landfill from flaring of the methane in landfill gas during the year measured in CO2‑e tonnes.

Qflared is the quantity of methane in landfill gas flared during the year measured in cubic metres in accordance with Division 2.3.6.

ECi is the energy content of methane in landfill gas in gigajoules per cubic metre (see Schedule 1).

EFij is the relevant emission factor for gas type (j), being methane and nitrous oxide, from the combustion of landfill gas in kilograms of CO2‑e per gigajoule (see Schedule 1).

(2) For Qflared in subsection (1), the methane in landfill gas is taken to constitute 50% of the landfill gas.

5.20 Method 2 — landfill gas flared

(1) For subparagraph 5.3 (1) (b) (ii) and subject to this section, method 2 is the same as method 1 under section 5.19.

(2) In applying method 1 under section 5.19, Qflared must be determined in accordance with the sampling and analysis requirements in Subdivision 2.3.3.2 and the measurement requirements in Division 2.3.6.

5.21 Method 3 — landfill gas flared

(1) For subparagraph 5.3 (1) (b) (iii) and subject to this section, method 3 is the same as method 1 under section 5.19.

(2) In applying method 1 under section 5.19, Qflared must be determined in accordance with the sampling and analysis requirements in Division 2.3.4 and the measurement requirements in Division 2.3.6.

Division 5.2.6 Biological treatment of solid waste

5.22 Method 1 — biological treatment of solid waste at the landfill

For paragraph 5.3 (1) (c), method 1 is the Tier 1 method for measuring emissions from biological treatment of solid waste set out in Volume 5, Chapter 4, of the 2006 IPCC Guidelines.

Part 5.3 Wastewater handling (domestic and commercial)

Division 5.3.1 Preliminary

5.23 Application

(1) This Part applies to emissions released from the decomposition of organic material, nitrification and denitrification processes, and flaring of sludge biogas, resulting from the handling of domestic or commercial wastewater through:

(a) treatment in wastewater collection and treatment systems; or

(b) discharge into surface waters.

(2) In this section, domestic or commercial wastewater means liquid wastes and sludge (including human waste) from housing or commercial premises.

5.24 Available methods

(1) Subject to section 1.18, for estimating emissions released from the operation of a facility that is constituted by wastewater handling (domestic and commercial) (the plant) during a year:

(a) one of the following methods must be used for emissions of methane from the plant (other than from flaring of methane):

(i) method 1 under section 5.25;

(ii) method 2 under section 5.26;

(iii) method 3 under section 5.30; and

(b) one of the following methods must be used for emissions of nitrous oxide from the plant (other than from flaring of methane):

(i) method 1 under section 5.31;

(ii) method 2 under section 5.32;

(iii) method 3 under section 5.36; and

(c) one of the following methods must be used for emissions for each gas type as a result of methane flared from the plant:

(i) method 1 under section 5.37;

(ii) method 2 under section 5.38;

(iii) method 3 under section 5.39.

(2) Under paragraph (1) (c), the same method must be used for estimating emissions of each gas type.

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

Note There is no method 4 for paragraphs (1) (a), (b) and (c).

Division 5.3.2 Method 1 — methane released from wastewater handling (domestic and commercial)

5.25 Method 1 — methane released from wastewater handling (domestic and commercial)

(1) For subparagraph 5.24 (1) (a) (i), method 1 is:

where:

Ej is the emissions of methane released by the plant during the year measured in CO2‑e tonnes.

CH4* is the estimated quantity of methane in sludge biogas released by the plant during the year measured in CO2‑e tonnes as determined under subsections (2) and (3).

γ is the factor 6.784 x 10‑4 x 21 converting cubic metres of methane at standard conditions to CO2‑e tonnes.

Qcap is the quantity of methane in sludge biogas captured for combustion for use by the plant during the year measured in cubic metres in accordance with Division 2.3.6.

Qflared is the quantity of methane in sludge biogas flared during the year by the plant measured in cubic metres in accordance with Division 2.3.6.

Qtr is the quantity of methane in sludge biogas transferred out of the plant during the year measured in cubic metres in accordance with Division 2.3.6.

(2) For subsection (1), if:

is less than or equal to 0.75, then:

where:

CH4gen is the quantity of methane in sludge biogas produced by the plant during the year, estimated in accordance with subsection (5) and measured in CO2‑e tonnes.

(3) For subsection (1), if:

is greater than 0.75, then:

where:

γ is the factor 6.784 x 10‑4 x 21 converting cubic metres of methane at standard conditions to CO2‑e tonnes.

Qcap is the quantity of methane in sludge biogas captured for combustion by the plant, measured in cubic metres in accordance with Division 2.3.6.

(4) For subsections (1) and (3), Qcap is to be calculated in accordance with Division 2.3.6.

(5) For subsection (2):

where:

CODW is the factor worked out as follows:

where:

P is the population served by the operation of the plant during the year and measured in numbers of persons.

DCw is the quantity in tonnes of COD per capita of wastewater for a year using a default of 0.0585 tonnes per person.

CH4gen is the methane generated from commercial wastewater and sludge treatment by the plant during the year measured in CO2‑e tonnes.

CODw is the chemical oxygen demand (COD) in wastewater entering the plant during the year measured in tonnes.

CODsl is the quantity of COD removed as sludge from wastewater and treated in the plant measured in tonnes of COD.

CODeff is the quantity of COD in effluent leaving the plant during the year measured in tonnes.

Fwan is the fraction of COD anaerobically treated by the plant during the year.

Note IPCC default fractions for various types of treatment are:

 managed aerobic treatment: 0

 unmanaged aerobic treatment: 0.3

 anaerobic digester/reactor: 0.8

 shallow anaerobic lagoon (<2 metres): 0.2

 deep anaerobic lagoon (>2 metres): 0.8

EFwij is the default methane emission factor for wastewater with a value of 5.3 CO2‑e tonnes per tonne COD.

CODtrl is the quantity of COD in sludge transferred out of the plant and removed to landfill measured in tonnes of COD.

CODtro is the quantity of COD in sludge transferred out of the plant and removed to a site other than landfill measured in tonnes of COD.

Fslan is the fraction of COD in sludge anaerobically treated by the plant during the year.

Note IPCC default fractions for various types of treatment are:

 managed aerobic treatment: 0

 unmanaged aerobic treatment: 0.3

 anaerobic digester/reactor: 0.8

 shallow anaerobic lagoon (<2 metres): 0.2

 deep anaerobic lagoon (>2 metres): 0.8

EFslij is the default methane emission factor for sludge with a value of 5.3 CO2‑e tonnes per tonne COD (sludge).

(6) For subsection (5), an operator of the plant must choose a treatment for Fwan and estimate the quantity of COD removed from the wastewater as sludge (CODsl).

(7) For subsection (6), the quantity of COD removed as sludge may be estimated using the following equation:

where:

VSsl is the estimated volatile solids in the sludge.

Division 5.3.3 Method 2 — methane released from wastewater handling (domestic and commercial)

5.26 Method 2 — methane released from wastewater handling (domestic and commercial)

(1) For subparagraph 5.24 (1) (a) (ii) and subject to this section, method 2 is the same as method 1 under section 5.25.

(2) In applying method 1 under section 5.25, the COD mentioned in subsection 5.25 (5) must be estimated from wastewater entering the plant and must be calculated by using:

(a) facility operating data that measures the volumetric influent and effluent rates and the influent and effluent rates of COD concentrations; or

(b) if data is available on the biochemical oxygen demand (BOD) in the wastewater — that data converted to COD in accordance with the following formula:

(2A) In applying method 1 under section 5.25, the reference to 0.75 in subsections 5.25 (2) and (3) is to read as a reference to 1.00.

(3) Wastewater used for the purposes of subsection (2), must be sampled and analysed for COD in accordance with the requirements in sections 5.27, 5.28 and 5.29.

5.27 General requirements for sampling under method 2

(1) A sample must be representative of the wastewater and the COD concentrations at the plant.

(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 may be tested in accordance with an appropriate standard (if any).

(5) The value obtained from the sample must only be used for the plant for which it was intended to be representative.

5.28 Standards for analysis

(1) Samples of wastewater must be analysed for COD in accordance with:

(a) ISO 6060:1989; or

(b) sections 5220B, 5220C or 5220D of APHA (1995); or

(2) Samples of wastewater must be analysed for BOD in accordance with:

(a) AS 4351.5—1996; or

(b) section 5210B of APHA (1995); or

5.29 Frequency of sampling and analysis

Wastewater must be sampled and analysed on at least a monthly basis.

Division 5.3.4 Method 3 — methane released from wastewater handling (domestic and commercial)

5.30 Method 3 — methane released from wastewater handling (domestic and commercial)

(1) For subparagraph 5.24 (a) (iii) and subject to subsection (2), method 3 is the same as method 2 under section 5.26.

(2) In applying method 2 under section 5.26, the wastewater must be sampled in accordance with AS/NZS 5667.10:1998 or an equivalent Australian or international standard.

Division 5.3.5 Method 1 — emissions of nitrous oxide released from wastewater handling (domestic and commercial)

5.31 Method 1 — nitrous oxide released from wastewater handling (domestic and commercial)

(1) For paragraph 5.24 (1) (b), method 1 is:

where:

Ej is the emissions of nitrous oxide released from human sewage treated by the plant during the year measured in tonnes of nitrous oxide and expressed in CO2‑e tonnes.

Nin is the quantity of nitrogen entering the plant during the year measured in tonnes of nitrogen, worked out as follows:

where:

Protein is the annual per capita protein intake in tonnes per person during the year of the population served by the plant.

FracPr is the fraction of nitrogen in protein.

P is the population serviced by the plant during the year.

Ntrl is the quantity of nitrogen in sludge transferred out of the plant and removed to landfill during the year measured in tonnes of nitrogen.

Ntro is the quantity of nitrogen in sludge transferred out of the plant and removed to a site other than landfill during the year measured in tonnes of nitrogen.

Nout is the quantity of nitrogen leaving the plant in effluent during the year measured in tonnes of nitrogen.

EFsecij is the emission factor for wastewater treatment.

EFdisij is the emission factor for nitrogen discharge differentiated by the discharge environment.

(2) For EFdisij in subsection (1), an emission factor of 4.9 tonnes of nitrous oxide measured in CO2‑e per tonne of nitrogen produced may be used.

(3) For EFsecij in subsection (1), an emission factor of 4.9 tonnes of nitrous oxide measured CO2‑e per tonne of nitrogen produced may be used.

(4) For FracPr in subsection (1), a factor of 0.16 tonnes of nitrogen per tonne of protein may be used.

(5) For Protein in subsection (1), an annual per capita protein intake of 0.036 tonnes per year may be used.

Division 5.3.6 Method 2 — emissions of nitrous oxide released from wastewater handling (domestic and commercial)

5.32 Method 2 — nitrous oxide released from wastewater handling (domestic and commercial)

(1) For subparagraph 5.24 (1) (b) (ii) and subject to this section, method 2 is the same as method 1 under section 5.31.

(2) In applying method 1 under section 5.31, nitrogen must be calculated by using facility operating data that measures the volumetric influent and effluent rates and the influent and effluent rates of nitrogen concentrations.

(3) Wastewater used for the purposes of subsection (2), must be sampled and analysed for nitrogen in accordance with the requirements in sections 5.33, 5.34 and 5.35.

5.33 General requirements for sampling under method 2

(1) A sample must be representative of the wastewater and the nitrogen concentrations at the plant.

(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 sample must only be used for the plant for which it was intended to be representative.

5.34 Standards for analysis

(1) Samples of wastewater must be analysed for nitrogen in accordance with:

(a) ISO 11905-1:1997; or

(b) sections 4500‑Norg B, 4500‑Norg C or 4500‑Norg D of APHA (1995); or

(2) Samples of sludge must be analysed for nitrogen in accordance with:

(a) EN 13342:2000; or

(b) section 4500‑Norg B of APHA (1995); or

5.35 Frequency of sampling and analysis

Wastewater must be sampled and analysed on at least a monthly basis.

Division 5.3.7 Method 3 — emissions of nitrous oxide released from wastewater handling (domestic and commercial)

5.36 Method 3 — nitrous oxide released from wastewater handling (domestic and commercial)

(1) For subparagraph 5.24 (1) (b) (iii) and subject to subsection (2), method 3 is the same as method 2 under section 5.32.

(2) In applying method 2 under section 5.32, the wastewater must be sampled in accordance with AS/NZS 5667.10:1998 or an equivalent Australian or international standard.

(3) In applying method 2 under section 5.32, the sludge must be sampled in accordance with ISO 5667-13:1997 or an equivalent Australian or international standard.

Division 5.3.8 Wastewater handling (domestic and commercial) — Flaring

5.37 Method 1 — Flaring of methane in sludge biogas from wastewater handling (domestic and commercial)

(1) For subparagraph 5.24 (1) (c) (i), method 1 is:

where

Ej flared is the emissions of gas type (j) released from the plant from flaring of the methane in sludge biogas from the plant during the year measured in CO2‑e tonnes.

Qflared is the quantity of methane in sludge biogas flared from the plant during the year measured in cubic metres in accordance with Division 2.3.6.

ECi is the energy content of methane in sludge biogas in gigajoules per cubic metre (see Schedule 1).

EFij is the relevant emission factor for gas type (j) for methane in sludge biogas measured in CO2‑e per gigajoule (see Schedule 1).

(2) For Qflared in subsection (1), the methane in sludge biogas is taken to constitute 70% of the sludge biogas.

5.38 Method 2 — flaring of methane in sludge biogas

(1) For subparagraph 5.24 (1) (c) (ii) and subject to this section, method 2 is the same as method 1 under section 5.37.

(2) In applying method 1 under section 5.37, Qflared must be determined in accordance with the sampling and analysis requirements in Subdivision 2.3.3.2 and the measuring requirements in Division 2.3.6.

5.39 Method 3 — flaring of methane in sludge biogas

(1) For subparagraph 5.24 (1) (c) (iii) and subject to this section, method 3 is the same as method 1 under section 5.37.

(2) In applying method 1 under section 5.37, Qflared must be determined in accordance with the sampling and analysis requirements in Division 2.3.4 and the measuring requirements in Division 2.3.6.

Part 5.4 Wastewater handling (industrial)

Division 5.4.1 Preliminary

5.40 Application

(a) treatment in wastewater systems; or

(b) discharge into surface waters.

(2) In this section, industrial wastewater means liquid wastes and sludge resulting from the production of a commodity, by an industry, mentioned in column 2 of an item of the table in subsection 5.42 (8).

5.41 Available methods

(1) Subject to section 1.18 one of the following methods must be used for estimating emissions of methane released from the operation of a facility (other than by flaring of landfill gas containing methane) that is constituted by wastewater handling generated by the relevant industries (the plant) during a year:

(a) method 1 under section 5.42;

(b) method 2 under section 5.43;

(2) Subject to section 1.18, one of the following methods must also be used for estimating emissions of each gas type released as a result of methane in sludge biogas flared from the operation of the plant during a year:

(a) method 1 under section 5.48;

(b) method 2 under section 5.49;

(3) Under subsection (2), the same method must be used for estimating emissions of each gas type.

(4) For incidental emissions another method may be used that is consistent with the principles in section 1.13.

Note There is no method 4 for subsection (1) or (2).

Division 5.4.2 Method 1 — methane released from wastewater handling (industrial)

5.42 Method 1 — methane released from wastewater handling (industrial)

(1) For paragraph 5.41 (1) (a), method 1 is:

where:

Ej is the emissions of methane released from the plant during the year measured in CO2‑e tonnes.

CH4* is the estimated quantity of methane in sludge biogas generated by the plant during the year measured in CO2‑e tonnes as determined under subsections (2) and (3).

γ is the factor 6.784 × 10‑4.× 21 converting cubic metres of methane at standard conditions to CO2‑e tonnes.

Qcap is the quantity of methane in sludge biogas captured for combustion for the plant during the year measured in cubic metres in accordance with Division 2.3.6.

Qflared is the quantity of methane in sludge biogas flared by the plant during the year measured in cubic metres in accordance with Division 2.3.6.

Qtr is the quantity of methane in sludge biogas transferred out of the plant during the year measured in cubic metres in accordance with Division 2.3.6.

(2) For subsection (1), if:

is less than or equal to 0.75, then:

where:

CH4gen is the quantity of methane in sludge biogas produced by the plant during the year, estimated in accordance with subsection (5) and measured in CO2‑e tonnes.

(3) For subsection (1), if:

is greater than 0.75, then:

where:

γ is the factor 6.784 x 10‑4 x 21 converting cubic metres of methane at standard conditions to CO2‑e tonnes.

Qcap is the quantity of methane in sludge biogas captured for combustion for the operation of the plant measured in cubic metres.

(4) For subsections (1) and (3), Qcap is to be calculated in accordance with Division 2.3.6.

(5) For subsection (2) the factor CH4gen is estimated as follows:

where:

Σw,i is the total CODw,i of wastewater entering the plant.

CODw,i is the COD in wastewater entering the plant related to the production by the plant of any commodity mentioned in column 2 of the table in subsection (8) during the year measured in tonnes of COD, worked out as follows:

where:

Prodi has the meaning given by the table in subsection 5.42 (9).

Wgen,i is the wastewater generation rate from the production of any commodity mentioned in column 2 of the table in subsection (8) produced during the year and measured in cubic metres or kilolitres per tonne of commodity.

CODcon,i is the COD concentration in kilograms of COD per cubic metre of wastewater entering the plant during the year from the production of any commodity mentioned in column 2 of the table in subsection (8).

CODsl is the quantity of COD removed as sludge from wastewater during the year measured in tonnes of COD, worked out as follows:

where:

CODw,i is the COD in wastewater entering the plant used in the production of any commodity mentioned in column 2 of the table in subsection (8) during the year measured in tonnes of COD.

Fsl is the fraction of COD removed from wastewater as sludge by the plant during the year.

Fwan is the fraction of COD in wastewater anaerobically treated by the plant during the year.

Note IPCC default fractions for various types of treatment are:

 managed aerobic treatment: 0

 unmanaged aerobic treatment: 0.3

 anaerobic digester/reactor: 0.8

 shallow anaerobic lagoon (<2 metres): 0.2

 deep anaerobic lagoon (>2 metres): 0.8.

EFw ij is the methane emission factor for industrial wastewater.

CODtrl is the quantity of COD in sludge transferred out of the plant and removed to landfill during the year measured in tonnes of COD.

CODtro is the quantity of COD in sludge transferred out of the plant and removed to a site other than landfill during the year measured in tonnes of COD.

Fslan is the fraction of COD in sludge anaerobically treated by the plant during the year.

Note IPCC default fractions for various types of treatment are:

 managed aerobic treatment: 0

 unmanaged aerobic treatment: 0.3

 anaerobic digester/reactor: 0.8

 shallow anaerobic lagoon (<2 metres): 0.2

 deep anaerobic lagoon (>2 metres): 0.8.

EFsl ij is the methane emission factor for the treatment of sludge by the plant.

(6) For EFwij in subsection (5), an emission factor of 5.3 CO2‑e tonnes per tonne of COD may be used.

(7) For EFslij in subsection (5), a methane emission factor of 5.3 CO2‑e tonnes per tonne of COD may be used.

(8) For subsection (5), COD must be estimated for a commodity set out in column 2 of an item in the following table that is produced by the industry referred to by the ANZSIC code set out in column 2 for that item:

(a) by using the default values for Wgen,i, CODcon,i and Fwan set out in columns 3, 4 and 5 for that item; or

(b) in accordance with industry practice relevant to the measurement of the quantity of wastewater.

Item	Commodity and industry	Wgen,i default value	CODcon,i default value	Fwan default value
1	Dairy product (ANZSIC code 113)	5.7	0.9	0.4
2	Pulp, paper and paperboard (ANZSIC code 1510)	26.7	0.4	0.0
3	Meat and poultry (ANZSIC codes 1111 and 1112)	13.7	6.1	0.4
4	Organic chemicals (ANZSIC codes 18 and 19)	67.0	3.0	0.1
5	Raw sugar (ANZSIC code 1181)	0.4	3.8	0.3
6	Beer (ANZSIC code 1212)	5.3	6.0	0.5
7	Wine and other alcoholic beverage (ANZSIC code 1214)	23.0	1.5	0.0
8	Fruit and vegetable (ANZSIC code 1140)	20.0	0.2	1.0

(9) For subsection (5), Prodi is the amount of any commodity set out in column 2 of an item in the following table, produced by the industry set out in column 2 for that item, and measured in accordance with the corresponding units of measurement set out in column 3 for that item.

Item	Commodity and industry	Units of measurement
1	Dairy product (ANZSIC code 113)	tonne of product
2	Pulp, paper and paperboard (ANZSIC code 1510)	tonne of paper produced
3	Meat and poultry (ANZSIC codes 1111 and 1112)	tonne of product (hot standard carcass weight or live weight basis)
4	Organic chemicals (ANZSIC codes 18 and 19)	tonne of product
5	Raw sugar (ANZSIC code 1181)	tonne of raw sugar produced (raw sugar equivalent)
6	Beer (ANZSIC code 1212)	tonne of product
7	Wine and other alcoholic beverage (ANZSIC code 1214)	tonne of product
8	Fruit and vegetable (ANZSIC code 1140)	tonne of product

Division 5.4.3 Method 2 — methane released from wastewater handling (industrial)

5.43 Method 2 — methane released from wastewater handling (industrial)

(1) For paragraph 5.41 (1) (b) and subject to this section, method 2 for wastewater handling (industrial) is the same as method 1 under section 5.42.

(2) In applying method 1 under section 5.42, the COD mentioned in subsection 5.42 (5) must be estimated from wastewater entering the plant and must be calculated by using:

(a) facility operating data that measures the volumetric influent rate and the influent rate of COD concentrations; or

(b) if data is available on the biochemical oxygen demand (BOD) in the wastewater — that data converted to COD in accordance with the following formula:

(2A) In applying method 1 under section 5.42, the reference to 0.75 in subsections 5.42 (2) and (3) is to read as a reference to 1.00.

(3) Wastewater used for the purposes of subsection (2), must be sampled and analysed for COD in accordance with the requirements is sections 5.44, 5.45 and 5.46.

5.44 General requirements for sampling under method 2

(1) A sample must be representative of the wastewater and the COD concentrations at the plant.

(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 sample must only be used for the plant for which it was intended to be representative.

5.45 Standards for analysis

(1) Samples of wastewater must be analysed for COD in accordance with:

(a) ISO 6060:1989; or

(b) sections 5220B, 5220C or 5220D of APHA (1995); or

(2) Samples of wastewater must be analysed for BOD in accordance with:

(a) AS 4351.5—1996; or

(b) section 5210B of APHA (1995); or

5.46 Frequency of sampling and analysis

Wastewater must be sampled and analysed on at least a monthly basis.

Division 5.4.4 Method 3 — methane released from wastewater handling (industrial)

5.47 Method 3 — methane released from wastewater handling (industrial)

(1) For paragraph 5.41 (1) (c) and subject to subsection (2), method 3 is the same as method 2 under section 5.43.

(2) In applying method 2 under section 5.43, the wastewater must be sampled in accordance with AS/NZS 5667.10:1998 or an equivalent Australian or international standard.

Division 5.4.5 Wastewater handling (industrial) — Flaring of methane in sludge biogas

5.48 Method 1 — flaring of methane in sludge biogas

(1) For paragraph 5.41 (2) (a), method 1 is:

where:

Ej flared is the emissions of gas type (j) released from flaring of the methane in sludge biogas by the plant during the year measured in CO2‑e tonnes.

Qflared is the quantity of methane in sludge biogas flared by the plant during the year measured in cubic metres in accordance with Division 2.3.6.

ECi is the energy content of methane in sludge biogas measured in gigajoules per cubic metre (see Schedule 1).

EFij is the relevant emission factor for gas type (j) for methane in sludge biogas in CO2‑e tonnes per gigajoule (see Schedule 1).

(2) For Qflared in subsection (1), the methane in sludge biogas is taken to constitute 70% of the sludge biogas.

5.49 Method 2 — flaring of methane in sludge biogas

(1) For paragraph 5.41 (2) (b) and subject to this section, method 2 is the same as method 1 under section 5.48.

(2) In applying method 1 under section 5.48, Qflared must be determined in accordance with the sampling and analysis requirements in Subdivision 2.3.3.2 and the measuring requirements in Division 2.3.6.

5.50 Method 3 — flaring of methane in sludge biogas

(1) For paragraph 5.41 (2) (c) and subject to this section, method 3 is the same as method 1 under section 5.48.

(2) In applying method 1 under section 5.48, Qflared must be determined in accordance with the sampling and analysis requirements in Division 2.3.4 and the measuring requirements in Division 2.3.6.

Part 5.5 Waste incineration

5.51 Application

This Part applies to emissions released from waste incineration.

5.52 Available methods — emissions of carbon dioxide from waste incineration

Subject to section 1.18 method 1 under section 5.53 must be used for estimating emissions of carbon dioxide released from the operation of a facility that is constituted by waste incineration (the plant).

Note There is no method 2, 3 or 4 for this section.

5.53 Method 1 — emissions of carbon dioxide released from waste incineration

(1) Method 1 is:

where:

Ei is the emissions of carbon dioxide released from the incineration of waste type (i) by the plant during the year measured in CO2‑e tonnes.

Qi is the quantity of waste type (i) incinerated by the plant during the year measured in tonnes of wet weight value in accordance with:

(a) Division 2.2.5 for solid fuels; and

(b) Division 2.3.6 for gaseous fuels; and

CCi is the carbon content of waste type (i).

FCCi is the proportion of carbon in waste type (i) that is of fossil origin.

OFi is the oxidation factor for waste type (i).

(2) If waste materials other than clinical wastes have been incinerated by the plant, appropriate values for the carbon content of the waste material incinerated must be derived from Schedule 3.

(3) For CCi in subsection (1), the IPCC default of 0.60 for clinical waste must be used.

(4) For FCCi in subsection (1), the IPCC default of 0.40 for clinical waste must be used.

(5) For OFi in subsection (1), the IPCC default of 1.00 for clinical waste must be used.

Chapter 6 Energy

Part 6.1 Production

6.1 Purpose

The purpose of this Part is to provide for the estimation of the energy content of energy produced from the operation of a facility during a year.

Note 1 Energy produced from the operation of a facility is dealt with in regulation 2.23 of the Regulations.

Note 2 Energy includes the fuels and energy commodities listed in Schedule 1 to the Regulations. See the definition of energy in section 7 of the Act and in regulation 2.03 of the Regulations.

6.2 Quantity of energy produced

(1) The quantity of an energy produced from the operation of the facility during the year must be estimated:

(a) if the energy is a solid or gaseous fuel — in accordance with industry practice; or

(b) if the energy is a liquid fuel — by either of the following:

(i) using bulk filling meters corrected to 15° celsius;

(ii) by the physical measurement of the fuel corrected to its notional volumetric equivalent at a temperature of 15° Celsius; or

(i) the amount of electricity produced by the electricity generating unit for the facility as measured at the unit’s terminals; and

(ii) the sum of the amounts of electricity supplied to an electricity transmission or distribution network measured at the connection point for the network in accordance with either of the measurement requirements specified in subsection (3) and the amount of electricity supplied for use outside the operation of the facility that is not supplied to the network; or

(d) if the energy is electricity produced for use outside the operation of the facility other than for supply to an electricity transmission network or distribution network — as the sum of the following:

(i) the amount of electricity supplied to an electricity transmission or distribution network measured at the connection point to the network in accordance with either of the measurement requirements specified in subsection (3);

(ii) the amount of electricity supplied for use outside an electricity transmission or distribution network that is not supplied to the network; or

(e) if the energy is electricity supplied to an electricity transmission or distribution network — as the amount of electricity for use outside the operation of the facility for supply to the network measured at the connection point for the network in accordance with either of the measurement requirements specified in subsection (3).

Note Energy includes the fuels and energy commodities listed in Schedule 1 to the Regulations. See the definition of energy in section 7 of the Act and regulation 2.03 of the Regulations.

(2) For subsection (1), if the fuel is coal, its quantity must be estimated in the form of saleable coal on a washed basis.

(3) For paragraphs (1) (c), (d) and (e), the measurement requirements are as follows:

(a) Chapter 7 of the National Electricity Rules made under the National Electricity Law set out in the National Electricity (South Australia) Act 1996;

(b) metering requirements applicable to the region in which the facility is located.

6.3 Energy content of fuel produced

(1) The energy content of a kind of energy (fuel) produced from the operation of the facility during the year is to be worked out as follows:

where:

Zi is the energy content of fuel type (i) produced during the year and measured in gigajoules.

Qi is the quantity of fuel type (i) produced during the year.

ECi is the energy content factor of fuel type (i), measured as energy content according to the fuel type measured in gigajoules:

(a) as mentioned in Schedule 1; or

(b) in accordance with Divisions 2.2.3 and 2.2.4 (solid fuels), Divisions 2.3.3 and 2.3.4 (gaseous fuels) or Divisions 2.4.3 and 2.4.4 (liquid fuels); or

(d) for fuels measured in gigajoules, ECi is equal to 1.

Note Energy includes the fuels and energy commodities listed in Schedule 1 to the Regulations. See the definition of energy in section 7 of the Act and regulation 2.03 of the Regulations.

(2) The amount of electricity produced from the operation of the facility during the year must be evidenced by invoices, contractual arrangements or industry metering records.

Part 6.2 Consumption

6.4 Purpose

The purpose of this Part is to provide for the estimation of the energy content of energy consumed from the operation of a facility during a year.

Note 1 Energy includes the fuels and energy commodities listed in Schedule 1 to the Regulations. See the definition of energy in section 7 of the Act and regulations 2.03 of the Regulations.

Note 2 Energy consumed from the operation of a facility is dealt with in regulation 2.23 of the Regulations.

6.5 Energy content of energy consumed

(1) The energy content of a kind of energy (fuel) consumed from the operation of the facility during the year is to be worked out as follows:

where:

Zi is the energy content of fuel type (i) consumed during the year and measured in gigajoules.

Qi is the quantity of fuel type (i) consumed during the year estimated in accordance with:

(a) Divisions 2.2.5 (solid fuels), 2.3.6 (gaseous fuels) and 2.4.6 (liquid fuels); or

(b) subsection (2) for electricity.

ECi, is the energy content factor of fuel type (i) and is:

(a) for solid fuels, measured in gigajoules per tonne:

(i) as mentioned in Part 1 or Part 7 of Schedule 1; or

(ii) estimated by analysis of the fuel in accordance with the standard indicated for that energy content factor in Schedule 2 or an equivalent standard; or

(b) for gaseous fuels, measured in gigajoules per cubic metre:

(i) as mentioned in Part 2 or Part 7 of Schedule 1; or

(ii) estimated by analysis under Subdivision 2.3.3.2; or

(d) for liquid fuels, measured in gigajoules per kilolitre:

(i) as mentioned in Part 3 or Part 7 of Schedule 1 for stationary energy purposes; or

(ii) as mentioned in Division 4.1 or Part 7 of Schedule 1 for transport energy purposes; or

(iii) estimated by analysis under Subdivision 2.4.3.2; or

(e) for electricity measured in kilowatt hours — equal to 0.0036.

Note Energy includes the fuels and energy commodities listed in Schedule 1 to the Regulations. See the definition of energy in section 7 of the Act and regulation 2.03 of the Regulations.

(1A) Despite subsection (1), if:

(a) the kind of energy is one of the following:

(i) solar energy for electricity generation;

(ii) wind energy for electricity generation;

(iii) water energy for electricity generation;

(iv) geothermal energy for electricity generation; and

(b) the energy is consumed from the operation of the facility during the year; and

then the energy content of the consumed energy is taken to be equal to the energy content of the electricity produced as estimated under Part 6.1.

(2) The amount of electricity consumed from the operation of the facility during the year must be:

(a) evidenced by invoices, contractual arrangements or industry metering records; or

(b) estimated in accordance with industry practice, if the evidence under paragraph (a) is unavailable.

(3) If, in relation to a year:

(a) a method used by a person requires the ECi factor to be estimated under this section in relation to a particular fuel type (i); and

(b) a way of estimating is chosen for the fuel type as required by this section; and

(c) other methods used by the person for the same fuel type also require the ECi factor to be estimated under this section;

then the chosen way of estimating, and the amount estimated, must also be applied in using the other methods for the fuel type in relation to that year.

Chapter 7 Scope 2 emissions

7.1 Outline of Chapter

This Chapter specifies a method of determining scope 2 emissions from the consumption of purchased electricity.

Note Scope 2 emissions result from activities that generate electricity, heating, cooling or steam that is consumed by a facility but that do not form part of the facility (see paragraph 2.23 (2) (b) of the Regulations).

7.2 Method 1 — purchase of electricity from main electricity grid in a State or Territory

(1) The following method must be used for estimating scope 2 emissions released from electricity purchased from the main electricity grid in a State or Territory and consumed from the operation of a facility during a year:

where:

Y is the scope 2 emissions measured in CO2‑e tonnes.

Q, subject to subsection (2), is the quantity of electricity purchased from the electricity grid during the year and consumed from the operation of the facility measured in kilowatt hours.

EF is the scope 2 emission factor, in kilograms of CO2‑e emissions per kilowatt hour, for the State or Territory in which the consumption occurs as mentioned in Part 6 of Schedule 1.

Note There is no other method for this section.

(2) For a facility the operation of which is constituted by an electricity transmission network or distribution network, Q is the quantity of electricity losses for that transmission network or distribution network during the year.

(3) For Q, if the electricity purchased is measured in gigajoules, the quantity of kilowatt hours must be calculated by dividing the amount of gigajoules by 0.0036.

(4) The main electricity grid, for a State or Territory, means:

(a) for Western Australia — the Southwest Interconnected System; and

(b) for each other State or Territory — the electricity grid that provides electricity to the largest percentage of the State’s or Territory’s population.

7.3 Method 1 — purchase of electricity from other sources

(1) The following formula must be used for estimating scope 2 emissions released from electricity:

(a) purchased from a grid other than the main electricity grid in a State or Territory; and

(b) consumed from the operation of a facility during a year:

where:

Y is the scope 2 emissions measured in CO2‑e tonnes during the year.

Q, subject to subsection (2), is the quantity of electricity purchased during the year and consumed from the operation of the facility, measured in kilowatt hours.

EF is the scope 2 emission factor, in kilograms of CO2‑e emissions per kilowatt hour, either:

(a) provided by the supplier of the electricity; or

(b) if that factor is not available, the emission factor for the Northern Territory as mentioned in Part 6 of Schedule 1.

Note There is no other method for this section.

(3) For Q, if the electricity purchased is measured in gigajoules, the quantity of kilowatt hours must be calculated by dividing the amount of gigajoules by 0.0036.

Chapter 8 Assessment of uncertainty

Part 8.1 Preliminary

8.1 Outline of Chapter

(1) This Chapter sets out rules about how uncertainty is to be assessed in working out estimates of scope 1 emissions for a source, a facility and a registered corporation.

(2) Part 8.2 sets out general rules for assessing uncertainty of scope 1 emissions estimates.

(3) Part 8.3 sets out how to assess the uncertainty of estimates of scope 1 emissions that have been estimated using method 1.

(4) Part 8.4 sets out how to assess the uncertainty of estimates of scope 1 emissions that have been estimated using method 2, 3 or 4.

(5) Emissions estimates for a source that are calculated using method 1, 2 or 3 are a function of a number of parameters. The uncertainty of the emissions estimates consists of the uncertainty associated with each of these parameters, which may include one or more of the following parameters:

(a) energy content factor;

(b) emissions factor;

Note In the case of fuel combustion, activity data refers to the quantity of fuel combusted. In the case of industrial processes, activity data refers to the quantity of product consumed or produced, as appropriate.

(6) Estimates of emissions need only provide for statistical uncertainty.

Note The uncertainty protocol provides information about the assessment of uncertainty.

Part 8.2 General rules for assessing uncertainty

8.2 Range for emission estimates

Uncertainty must be assessed so that the range for an emissions estimate encompasses the actual amount of the emissions with 95% confidence.

8.3 Uncertainty to be assessed having regard to all facilities

(1) Uncertainty of estimates of scope 1 emissions for a registered corporation must be assessed in accordance with Part 8.3 or with the uncertainty protocol, as appropriate, having regard to all of the facilities under the operational control of the corporation.

(2) For corporations that have multiple sources of scope 1 emissions that are estimated using a variety of method 1, 2, 3 or 4, the uncertainty associated with the emissions must be aggregated in accordance with section 8 of the uncertainty protocol.

Part 8.3 How to assess uncertainty when using method 1

8.4 Purpose of Part

This Part sets out how to assess uncertainty of scope 1 emissions if method 1 is used to estimate:

(a) scope 1 emissions for a source; and

(b) scope 1 emissions for a facility; and

8.5 General rules about uncertainty estimates for emissions estimates using method 1

(1) The total uncertainty of scope 1 emissions estimates for a source in relation to a registered corporation is to be worked out by aggregating, as applicable, the uncertainty of the emissions factor, the energy content factor and the activity data for the source in accordance with the formula in section 8.11.

Note This is generally referred to as the aggregated uncertainty for the source.

(2) The total uncertainty of scope 1 emissions estimates for a facility is to be worked out by aggregating the total uncertainty for each source associated with the facility in accordance with the formula in section 8.12.

Note This is generally referred to as the subtotal uncertainty for the facility.

(3) The total uncertainty of scope 1 emissions estimates for a registered corporation is to be worked out by aggregating the total uncertainty for each facility under the operational control of the corporation in accordance with the formula in section 8.13.

Note This is generally referred to as the total uncertainty for the corporation.

8.6 Assessment of uncertainty for estimates of carbon dioxide emissions from combustion of fuels

(1) In assessing uncertainty of the estimates of carbon dioxide emissions estimated using method 1 for a source that involves the combustion of a fuel, the assessment must include the statistical uncertainty associated with the following parameters:

(a) the energy content factor of the fuel (as specified in column 3 of the following table or as worked out in accordance with item 1, 2 or 3 of section 7 of the uncertainty protocol);

(b) the carbon dioxide emission factor of the fuel (as specified in column 4 of the following table or as worked out in accordance with item 1, 2 or 3 of section 7 of the uncertainty protocol);

(c) the quantity of fuel combusted (as worked out in accordance with subsection (2) or as worked out in accordance with item 1, 2 or 3 of section 7 of the uncertainty protocol).

Item	Fuel Combusted	Energy content uncertainty level (%)	Carbon dioxide emission factor uncertainty level (%)
1	Black coal (other than used to produce coke)	28		5
2	Brown coal	50		12
3	Coking coal	12		7
4	Brown coal briquettes	40		11
5	Coke oven coke	9		11
6	Coal tar	50		17
7	Solid fossil fuels other than those mentioned in items 1 to 5	50		15
8	Industrial materials and tyres that are derived from fossil fuels, if recycled and combusted to produce heat or electricity	50		26
9	Non‑biomass municipal materials, if recycled and combusted to produce heat or electricity	50		26
10	Dry wood	50		NA
11	Green and air-dried wood	50		NA
12	Sulphite lyes	50		NA
13	Bagasse	50		NA
14	Biomass municipal and industrial materials, if recycled and combusted to produce heat or energy	50		NA
15	Charcoal	50		NA
16	Primary solid biomass fuels other than those mentioned in items 10 to 15	50		NA
17	Natural gas if distributed in a pipeline	4		4
18	Coal seam methane that is captured for combustion	4		4
19	Coal mine waste gas that is captured for combustion	4		4
20	Compressed natural gas that has reverted to standard conditions	4		4
21	Unprocessed natural gas	4		4
22	Ethane	4		10
23	Coke oven gas	50		19
24	Blast furnace gas	50		17
25	Town gas	4		4
26	Liquefied natural gas	7		4
27	Gaseous fossil fuels other than those mentioned in items 17 to 26	50		10
28	Landfill biogas that is captured for combustion (methane only)	50		NA
29	Sludge biogas that is captured for combustion (methane only)	50		NA
30	A biogas that is captured for combustion, other than those mentioned in items 28 and 29 (methane only)	50		NA
31	Petroleum based oils (other than petroleum based oils used as fuel)	11		2
32	Petroleum based greases	11		2
33	Crude oil including crude oil condensates	6		3
34	Other natural gas liquids	7		9
35	Gasoline (other than for use as fuel in an aircraft)	3		4
36	Gasoline for use as fuel in an aircraft	3		4
37	Kerosene (other than for use as fuel in an aircraft)	3		2
38	Kerosene for use as fuel in an aircraft	3		3
39	Heating oil	5		2
40	Diesel oil	2		2
41	Fuel oil	2		2
42	Liquefied aromatic hydrocarbons	5		2
43	Solvents if mineral turpentine or white spirits	18		2
44	Liquid petroleum gas	8		3
45	Naphtha	5		5
46	Petroleum coke	19		17
47	Refinery gas and liquids	19		18
48	Refinery coke	19		17
49	Petroleum based products other than: (a) petroleum based oils and petroleum based greases mentioned in items 31 and 32; and (b) the petroleum based products mentioned in items 33 to 48	18		2
50	Biodiesel	50		NA
51	Ethanol for use as a fuel in an internal combustion engine	50		NA
52	Biofuels other than those mentioned in items 50 and 51	50		NA

(2) In the table in subsection (1), NA means not applicable.

(3) For a fuel type specified in column 2 of an item of the following table:

(a) column 3 for the item sets out the uncertainty level for the estimated quantities of fuel combusted using criterion A in Chapter 2; and

(b) column 4 for the item sets out the uncertainty level for the estimated quantities of fuel combusted using criterion AA in Chapter 2; and

(c) column 5 for the item sets out the uncertainty level for the estimated quantities of fuel combusted using criterion AAA in Chapter 2; and

(d) column 6 for the item sets out the uncertainty level for the estimated quantities of fuel combusted using criterion BBB in Chapter 2.

Note Division 2.2.5 sets out the relevant criteria for solid fuels; Division 2.3.6 sets out the relevant criteria for gaseous fuels; and Division 2.4.6 sets out the relevant criteria for liquid fuels.

Item	Fuel type	Uncertainty levels for quantities of fuel combusted (%)
		Criterion used for estimation of quantity of fuel combusted
		A	AA	AAA	BBB
1	Solid fuel	2.5	2.5	1.5	7.5
2	Liquid fuel	1.5	1.5	1.5	7.5
3	Gaseous fuel	1.5	1.5	1.5	7.5

8.7 Assessment of uncertainty for estimates of methane and nitrous oxide emissions from combustion of fuels

(1) In assessing uncertainty of the estimates of methane and nitrous oxide emissions estimated using method 1 for a source that involves the combustion of a fuel specified in column 2 of an item in the table in subsection 8.6 (1):

(a) the uncertainty level of the energy content factor is as specified in column 3 for the item; and

(b) the uncertainty level of the emissions factor is:

(i) 50%; or

(ii) as worked out in accordance with section 7 of the uncertainty protocol.

(2) In assessing uncertainty of the estimates of methane and nitrous oxide emissions estimated using method 1 for a source that involves the combustion of a fuel type specified in column 2 of an item in the table in subsection 8.6 (2):

(a) column 3 for the item sets out the uncertainty level for the estimated quantities of fuel combusted using criterion A in Chapter 2; and

(b) column 4 for the item sets out the uncertainty level for the estimated quantities of fuel combusted using criterion AA in Chapter 2; and

(c) column 5 for the item sets out the uncertainty level for the estimated quantities of fuel combusted using criterion AAA in Chapter 2; and

(d) column 6 for the item sets out the uncertainty level for the estimated quantities of fuel combusted using criterion BBB in Chapter 2.

8.8 Assessment of uncertainty for estimates of fugitive emissions

The aggregated uncertainty of the estimates of fugitive emissions estimated using method 1 for a source mentioned in column 2 of an item of the following table is:

(a) as specified in column 3 for the item; or

(b) as worked out in accordance with the uncertainty protocol.

Item	Sources	Aggregated uncertainty level (%)
1	Underground mines	50
2	Open cut mines	50
3	Decommissioned underground mines	50
4	Oil or gas exploration	50
5	Crude oil production	50
6	Crude oil transport	50
7	Crude oil refining	50
8	Natural gas production or processing (other than emissions that are vented or flared)	50
9	Natural gas transmission	50
10	Natural gas distribution	50
11	Natural gas production or processing — flaring	25

8.9 Assessment of uncertainty for estimates of emissions from industrial process sources

(1) In assessing uncertainty of the estimates of emissions estimated using method 1 for the industrial process sources mentioned in column 2 of an item of the following table, the assessment must include the uncertainty level for the emission factor and activity data associated with the source:

(a) as specified:

(i) for the emission factor — in column 3 for the item; and

(ii) for the activity data — in column 4 for the item; or

(b) as worked out in accordance with the uncertainty protocol.

Item	Industrial process sources	Emission factor uncertainty level (%)	Activity data uncertainty (%)
1	Cement clinker production	6	1.5
2	Lime production	6	1.5
3	Soda ash use	5	1.5
4	Use of carbonates for the production of a product other than cement clinker, lime or soda ash	5	1.5
5	Nitric acid production	40	1.5
6	Adipic acid production	10	1.5

(2) In assessing uncertainty of the estimates of emissions estimated using method 1 for industrial process sources mentioned in column 2 of an item of the following table, column 3 for the item sets out the aggregated uncertainty level associated with the source.

Item	Industrial process sources	Aggregated uncertainty level (%)
1	Emissions of hydrofluorocarbons and sulphur hexafluoride gas	30

(3) The uncertainty of estimates of emissions for industrial process sources that are not mentioned in subsections (1) or (2) must be assessed:

(a) if the industrial process source involves the combustion of fuel — in accordance with:

(i) for carbon dioxide emissions — section 8.6; and

(ii) for methane and nitrous oxide emissions — section 8.7; and

(b) if the industrial process source does not involve the combustion of fuel — in accordance with the uncertainty protocol.

8.10 Assessment of uncertainty for estimates of emissions from waste

In assessing uncertainty of the estimates of emissions from waste estimated using method 1 for the activities mentioned in column 2 of an item of the following table, the assessment must include the aggregated uncertainty level:

(a) as specified in column 3 for the item; or

(b) as worked out in accordance with the uncertainty protocol.

Item	Activities	Aggregated uncertainty level (%)
1	Solid waste disposal on land	35
2	Wastewater handling (industrial)	65
3	Wastewater handling (domestic or commercial)	40
4	Waste incineration	40

8.11 Assessing uncertainty of emissions estimates for a source by aggregating parameter uncertainties

(1) For subsection 8.5 (1) and subject to subsections (2) and (3), in assessing uncertainty of the estimates of scope 1 emissions that are estimated using method 1 for a source, the aggregated uncertainty for emissions from the source is to be worked out in accordance with the following formula:

where:

D is the aggregated percentage uncertainty for the emission source.

A is the uncertainty associated with the emission factor for the source, expressed as a percentage.

B is the uncertainty associated with the energy content factor for the source, expressed as a percentage.

C is the uncertainty associated with the activity data for the source, expressed as a percentage.

(2) If an assessment of uncertainty of emissions for the source does not require the use of emissions factor uncertainty, energy content factor uncertainty or activity data uncertainty, then A, B or C, as appropriate, in the formula in subsection (1) is taken to be zero.

Example

If energy content factor uncertainty is not required for an industrial process source, then B would be taken to be zero in the formula in subsection (1) when assessing the aggregated uncertainty for the source.

(3) Subsection (1) does not apply to:

(a) estimates of fugitive emissions that are assessed by using the aggregated uncertainty level in column 3 of the table in section 8.8; or

(b) estimates of emissions from industrial processes that are assessed by using the aggregated uncertainty level in column 3 of the table in subsection 8.9 (2); or

(c) estimates of emissions from waste activities that are assessed by using the aggregated uncertainty level in column 3 of the table in section 8.10.

8.12 Assessing uncertainty of emissions estimates for a facility

For subsection 8.5 (2), in assessing uncertainty of estimates of scope 1 emissions for a facility that are estimated using method 1, the following formula must be used to aggregate the uncertainty of emissions estimates for all the sources associated with the facility:

where:

Usubtotal is the percentage uncertainty for the subtotal of emissions for the facility.

D1 → Dn are the percentage uncertainties associated with each emission estimate (E1 → En) for the facility.

E1 → En are the estimated emissions from each facility under the operational control of the corporation measured in CO2-e tonnes.

8.13 Assessing uncertainty of emissions estimates for a registered corporation

For subsection 8.5 (3), in assessing uncertainty of estimates of scope 1 emissions for a registered corporation that are estimated using method 1, the following formula must be used to aggregate the uncertainty of emissions estimates for all the facilities under the operational control of the corporation:

where:

Utotal is the percentage uncertainty for the total emissions for the registered corporation.

D1 → Dn are the percentage uncertainties associated with each emission estimate (E1 → En) for the facility.

E1 → En are the estimated emissions from each facility under the operational control of the corporation measured in CO2-e tonnes.

Part 8.4 How to assess uncertainty levels when using method 2, 3 or 4

8.14 Purpose of Part

This Part sets out rules that apply in the assessment of uncertainty of scope 1 emissions from the operation of a facility that are estimated using method 2, 3 or 4.

8.15 Rules for assessment of uncertainty using method 2, 3 or 4

(1) Subject to this section, the uncertainty of scope 1 emissions estimates that are estimated using method 2, 3 or 4 must be assessed in accordance with the uncertainty protocol.

(2) Item 4 of Part 7 of the uncertainty protocol must not be used when emissions are estimated using method 2, 3 or 4.

(3) Estimates need only provide for statistical uncertainties in accordance with the uncertainty protocol.

Item	Fuel consumed	Energy content factor (GJ/t unless otherwise indicated)	Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
Item	Fuel consumed	Energy content factor (GJ/t unless otherwise indicated)	CO2	CH4	N2O
71	Solvents if mineral turpentine or white spirits	34.4 GJ/kL	Not applicable
72	Bitumen	43.2	Not applicable
73	Waxes	45.8	Not applicable
74	Carbon black if used as a petrochemical feedstock	37.1	Not applicable
75	Ethylene if used as a petrochemical feedstock	50.3	Not applicable
76	Petrochemical feedstock other than those mentioned in items 74 and 75		Not applicable

Item	Fuel combusted	Energy content factor GJ/t	Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
Item	Fuel combusted	Energy content factor GJ/t	CO2	CH4	N2O
1	Black coal (other than that used to produce coke)	27.0	88.2	0.03	0.2
2	Brown coal	10.2	92.7	0.01	0.4
3	Coking coal	30.0	90.0	0.02	0.2
4	Brown coal briquettes	22.1	93.3	0.06	0.3
5	Coke oven coke	27.0	104.9	0.03	0.2
6	Coal tar	37.5	81.0	0.02	0.2
7	Solid fossil fuels other than those mentioned in items 1 to 5	22.1	93.3	0.06	0.3
8	Industrial materials and tyres that are derived from fossil fuels, if recycled and combusted to produce heat or electricity	26.3	79.9	0.02	0.2
9	Non‑biomass municipal materials, if recycled and combusted to produce heat or electricity	10.5	85.4	0.6	1.2
10	Dry wood	16.2	0.0	0.08	1.2
11	Green and air dried wood	10.4	0.0	0.08	1.2
12	Sulphite lyes	12.4	0.0	0.06	0.6
13	Bagasse	9.6	0.0	0.2	1.3
14	Biomass municipal and industrial materials, if recycled and combusted to produce heat or electricity	12.2	0.0	0.6	1.2
15	Charcoal	31.1	0.0	4.0	1.2
16	Primary solid biomass fuels other than those mentioned in items 10 to 15	12.2	0.0	0.6	1.2

Item	Fuel combusted	Energy content factor (GJ/m3 unless otherwise indicated)	Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
Item	Fuel combusted	Energy content factor (GJ/m3 unless otherwise indicated)	CO2	CH4	N2O
17	Natural gas distributed in a pipeline	39.3 × 10‑3	51.2	0.1	0.03
18	Coal seam methane that is captured for combustion	37.7 × 10‑3	51.1	0.2	0.03
19	Coal mine waste gas that is captured for combustion	37.7 × 10‑3	51.6	5.0	0.03
20	Compressed natural gas that has reverted to standard conditions	39.3 × 10‑3	51.2	0.1	0.03
21	Unprocessed natural gas	39.3 × 10‑3	51.2	0.1	0.03
22	Ethane	62.9 × 10-3	56.2	0.02	0.03
23	Coke oven gas	18.1 × 10‑3	36.8	0.03	0.06
24	Blast furnace gas	4.0 × 10‑3	232.8	0.02	0.03
25	Town gas	39.0 × 10‑3	59.9	0.03	0.03
26	Liquefied natural gas	25.3 GJ/kL	51.2	0.1	0.03
27	Gaseous fossil fuels other than those mentioned in items 17 to 26	39.3 × 10‑3	51.2	0.1	0.03
28	Landfill biogas that is captured for combustion (methane only)	37.7 × 10‑3	0.0	4.8	0.03
29	Sludge biogas that is captured for combustion (methane only)	37.7 × 10‑3	0.0	4.8	0.03
30	A biogas that is captured for combustion, other than those mentioned in items 28 and 29 (methane only)	37.7 × 10‑3	0.0	4.8	0.03

Item	Fuel combusted	Energy content factor (GJ/kL unless otherwise indicated)	Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
Item	Fuel combusted	Energy content factor (GJ/kL unless otherwise indicated)	CO2	CH4	N2O
31	Petroleum based oils (other than petroleum based oil used as fuel)	38.8	27.9	0.0	0.0
32	Petroleum based greases	38.8	27.9	0.0	0.0
33	Crude oil including crude oil condensates	45.3 GJ/t	68.9	0.06	0.2
34	Other natural gas liquids	46.5 GJ/t	60.4	0.06	0.2
35	Gasoline (other than for use as fuel in an aircraft)	34.2	66.7	0.2	0.2
36	Gasoline for use as fuel in an aircraft	33.1	66.3	0.2	0.2
37	Kerosene (other than for use as fuel in an aircraft)	37.5	68.2	0.01	0.2
38	Kerosene for use as fuel in an aircraft	36.8	68.9	0.01	0.2
39	Heating oil	37.3	68.8	0.02	0.2
40	Diesel oil	38.6	69.2	0.1	0.2
41	Fuel oil	39.7	72.9	0.03	0.2
42	Liquefied aromatic hydrocarbons	34.4	69.0	0.02	0.2
43	Solvents if mineral turpentine or white spirits	34.4	69.0	0.02	0.2
44	Liquefied petroleum gas	25.7	59.6	0.1	0.2
45	Naphtha	31.4	69.0	0.00	0.02
46	Petroleum coke	34.2 GJ/t	90.8	0.06	0.2
47	Refinery gas and liquids	42.9 GJ/t	54.2	0.02	0.03
48	Refinery coke	34.2 GJ/t	90.8	0.06	0.2
49	Petroleum based products other than: (a) petroleum based oils and petroleum based greases mentioned in items 31 and 32; and (b) the petroleum based products mentioned in items 33 to 48.	34.4	69.0	0.02	0.2
50	Biodiesel	34.6	0.0	0.06	0.2
51	Ethanol for use as a fuel in an internal combustion engine	23.4	0.0	0.06	0.2
52	Biofuels other than those mentioned in items 50 and 51	23.4	0.0	0.06	0.2

Item	Fuel combusted	Energy content factor GJ/kL	Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
Item	Fuel combusted	Energy content factor GJ/kL	CO2	CH4	N2O
64	Gasoline (other than for use as fuel in an aircraft)	34.2	66.7	0.02	0.2
65	Diesel oil	38.6	69.2	0.01	0.6
66	Liquefied petroleum gas	26.2	59.6	0.3	0.3
67	Ethanol for use as fuel in an internal combustion engine	23.4	0.0	0.2	0.2

Item	Fuel type	Heavy vehicles design standard	Energy content factor GJ/kL	Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
Item	Fuel type	Heavy vehicles design standard	Energy content factor GJ/kL	CO2	CH4	N2O
68	Diesel oil	Euro iv	38.6	69.2	0.05	0.5
69	Diesel oil	Euro iii	38.6	69.2	0.1	0.5
70	Diesel oil	Euro i	38.6	69.2	0.2	0.5

Item	State, Territory or grid description	Emission factor kg CO2‑e/kWh
77	New South Wales and Australian Capital Territory	0.89
78	Victoria	1.22
79	Queensland	0.89
80	South Australia	0.77
81	South West Interconnected System in Western Australia	0.84
82	Tasmania	0.23
83	Northern Territory	0.68

Item	Fuel	Energy content factor (GJ/t unless otherwise indicated)
84	Uranium (U3O8)	470 000
85	Sulphur	4.9
86	Hydrogen	143

Item	Fuel type	Carbon content factor tC/t fuel
Solid fossil fuels
1	Black coal (other than that used to produce coke)	0.663
2	Brown coal	0.260
3	Coking coal	0.752
4	Brown coal briquettes	0.574
5	Coke oven coke	0.789
6	Coal tar	0.837
7	Solid fossil fuels other than those mentioned in items 1 to 5	0.574
Fuels derived from recycled materials
8	Industrial materials and tyres that are derived from fossil fuels, if recycled and combusted to produce heat or electricity	0.585
9	Non‑biomass municipal materials, if recycled and combusted to produce heat or electricity	0.250
Primary solid biomass fuels
10	Dry wood	0
11	Green and air dried wood	0
12	Sulphite lyes	0
13	Bagasse	0
14	Biomass municipal and industrial materials, if recycled and combusted to produce heat or electricity	0
15	Charcoal	0
16	Primary solid biomass fuels other than those mentioned in items 10 to 15	0

Item	Fuel type	Carbon content factor (tC/m3 of fuel unless otherwise specified)
Gaseous fossil fuels
17	Natural gas if distributed in a pipeline	5.52 × 10‑4
18	Coal seam methane that is captured for combustion	5.29 × 10‑4
19	Coal mine waste gas that is captured for combustion	5.34 × 10‑4
20	Compressed natural gas	5.52 × 10‑4
21	Unprocessed natural gas	5.52 × 10‑4
22	Ethane	8.87 × 10‑4
23	Coke oven gas	1.83 × 10‑4
24	Blast furnace gas	2.55 × 10‑4
25	Town gas	6.41 × 10‑4
26	Liquefied natural gas	0.355 tC/kL of fuel
27	Gaseous fossil fuels other than those mentioned in items 17 to 26	5.52 × 10‑4
Biogas captured for combustion
28	Landfill biogas (methane) that is captured for combustion	0
29	Sludge biogas (methane) that is captured for combustion	0
30	A biogas (methane) that is captured for combustion, other than those mentioned in items 28 and 29	0

Item	Fuel type	Carbon content factor (tC/kL of fuel unless otherwise specified)
Petroleum based oils and petroleum based greases
31	Petroleum based oils (other than petroleum based oils used as fuel)	0.737
32	Petroleum based greases	0.737
Petroleum based products other than petroleum based oils and petroleum based greases
33	Crude oil including crude oil condensates	0.861 tC/t fuel
34	Other natural gas liquids	0.774 tC/t fuel
35	Gasoline (other than for use as fuel in an aircraft)	0.629
36	Gasoline for use as fuel in an aircraft	0.605
37	Kerosene (other than for use as fuel in an aircraft)	0.705
38	Kerosene for use as fuel in an aircraft	0.699
39	Heating oil	0.708
40	Diesel oil	0.736
41	Fuel oil	0.797
42	Liquefied aromatic hydrocarbons	0.654
43	Solvents if mineral turpentine or white spirits	0.654
44	Liquefied petroleum gas	0.422
45	Naphtha	0.597
46	Petroleum coke	0.856 tC/t fuel
47	Refinery gas and liquids	0.641 tC/t fuel
48	Refinery coke	0.856 tC/t fuel
49	Bitumen	0.951 tC/t fuel
50	Waxes	0.871 tC/t fuel
51	Petroleum based products other than: (a) petroleum based oils and petroleum based greases mentioned in items 31 and 32; and (b) the petroleum based products mentioned in items 33 to 50	0.654
Biofuels
52	Biodiesel	0
53	Ethanol for use as a fuel in an internal combustion engine	0
54	Biofuels other than those mentioned in items 52 and 53	0

Item	Fuel type	Carbon content factor (tC/t fuel unless otherwise specified)
Petrochemical feedstocks
55	Carbon black if used as a petrochemical feedstock	1
56	Ethylene if used as a petrochemical feedstock	0.856
57	Petrochemical feedstock other than those mentioned in items 55 and 56	0.856
Petrochemical products
58	Propylene	0.856
59	Polyethylene	0.856
60	Polypropylene	0.856
61	Butadiene	0.888
62	Styrene	0.923

Title	Date of FRLI registration	Date of commencement	Application, saving or transitional provisions
National Greenhouse and Energy Reporting (Measurement) Determination 2008	27 June 2008 (see F2008L02309)	1 July 2008
National Greenhouse and Energy Reporting (Measurement) Amendment Determination 2009 (No. 1)	26 June 2009 (see F2009L02571)	27 June 2009	S. 4

ad. = added or inserted am. = amended rep. = repealed rs. = repealed and substituted
Provision affected	How affected
Chapter 1
Part 1.1
Division 1.1.1
S. 1.3.................	am. 2009 No. 1
Division 1.1.2
S. 1.8.................	am. 2009 No. 1
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Part 1.3
Division 1.3.3
Subdivision 1.3.3.1
S. 1.28................	am. 2009 No. 1
Chapter 2
Heading to Chapt. 2.......	rs. 2009 No. 1
Part 2.1
S. 2.1.................	rs. 2009 No. 1
Part 2.2
Division 2.2.1
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Division 2.2.2
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Division 2.2.3
Subdivision 2.2.3.1
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Subdivision 2.2.3.2
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Subdivision 2.2.3.3
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Note to s. 2.7 (4).........	rs. 2009 No. 1
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Division 2.2.5
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Part 2.3
Division 2.3.1
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Division 2.3.2
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Division 2.3.3
Subdivision 2.3.3.1
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Division 2.3.6
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Part 2.4
Division 2.4.1
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Subdivision 2.4.1.1
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Subdivision 2.4.1.2
Subdiv. 2.4.1.2 of Div. 2.4.1.	ad. 2009 No. 1
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Division 2.4.2
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Division 2.4.3
Heading to Div. 2.4.3 of Part 2.4	rs. 2009 No. 1
Subdivision 2.4.3.1
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S. 2.42................	am. 2009 No. 1
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Division 2.4.4
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Division 2.4.5
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Division 2.4.5A
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S. 2.48A...............	ad. 2009 No. 1
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Division 2.4.6
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Part 2.5
S. 2.54................	rs. 2009 No. 1
Division 2.5.1
S. 2.55................	am. 2009 No. 1
Division 2.5.2
S. 2.57................	am. 2009 No. 1
S. 2.58................	am. 2009 No. 1
Division 2.5.3
S. 2.59................	am. 2009 No. 1
S. 2.60................	am. 2009 No. 1
Part 2.6
S. 2.66................	am. 2009 No. 1
S. 2.67................	am. 2009 No. 1
Chapter 3
Heading to Chapt. 3.......	rs. 2009 No. 1
Part 3.1
S. 3.1.................	rs. 2009 No. 1
Part 3.2
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Division 3.2.1
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Division 3.2.2
Subdivision 3.2.2.1
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Subdivision 3.2.2.3
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Division 3.2.3
Subdivision 3.2.3.1
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S. 3.19................	am. 2009 No. 1
Division 3.2.4
Subdivision 3.2.4.1
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Part 3.3
Division 3.3.1
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Division 3.3.2
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Division 3.3.3
Subdivision 3.3.3.1
S. 3.47................	rs. 2009 No. 1
Subdivision 3.3.3.2
S. 3.48................	am. 2009 No. 1
Subdivision 3.3.3.3
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Division 3.3.4
S. 3.57................	rs. 2009 No. 1
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Division 3.3.5
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Subdivision 3.3.5.2
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Division 3.3.6
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Division 3.3.7
S. 3.74................	rs. 2009 No. 1
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Division 3.3.8
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Division 3.3.9
Heading to Div. 3.3.9 of Part 3.3	rs. 2009 No. 1
S. 3.82................	rs. 2009 No. 1
S. 3.83................	am. 2009 No. 1
Chapter 4
Heading to Chapt. 4.......	rs. 2009 No. 1
Part 4.1
S. 4.1.................	am. 2009 No. 1
Part 4.2
Division 4.2.1
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Division 4.2.2
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Division 4.2.3
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S. 4.23................	am. 2009 No. 1
Division 4.2.4
S. 4.26................	am. 2009 No. 1
Subdivision 4.2.4.1
S. 4.28................	am. 2009 No. 1
Subdivision 4.2.4.2
S. 4.30................	am. 2009 No. 1
S. 4.31................	am. 2009 No. 1
Division 4.2.5
S. 4.35................	am. 2009 No. 1
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Part 4.3
Division 4.3.1
S. 4.40................	am. 2009 No. 1
S. 4.41................	am. 2009 No. 1
S. 4.42................	am. 2009 No. 1
Division 4.3.2
S. 4.45................	am. 2009 No. 1
S. 4.46................	am. 2009 No. 1
Division 4.3.3
S. 4.49................	am. 2009 No. 1
S. 4.50................	am. 2009 No. 1
Division 4.3.4
S. 4.51................	am. 2009 No. 1
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Division 4.3.5
Heading to Div. 4.3.5 of Part 4.3	rs. 2009 No. 1
S. 4.53................	rs. 2009 No. 1
S. 4.54................	am. 2009 No. 1
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S. 4.55................	am. 2009 No. 1
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S. 4.57................	am. 2009 No. 1
Div. 4.3.6 of Part 4,3......	rep. 2009 No. 1
S. 4.58................	rep. 2009 No. 1
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S. 4.60................	rep. 2009 No. 1
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S. 4.62................	rep. 2009 No. 1
Part 4.4
Division 4.4.1
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Division 4.4.2
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S. 4.69................	am. 2009 No. 1
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Division 4.4.3
Heading to Div. 4.4.3 or Part 4.4	rs. 2009 No. 1
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Subdivision 4.4.3.1
S. 4.75................	am. 2009 No. 1
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S. 4.77................	am. 2009 No. 1
Subdivision 4.4.3.2
S. 4.79................	am. 2009 No. 1
S. 4.80................	am. 2009 No. 1
Division 4.4.4
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Subdivision 4.4.4.1
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Note to s. 4.84 (1)........	rs. 2009 No. 1
Subdivision 4.4.4.2
S. 4.88................	am. 2009 No. 1
Note to s. 4.88 (1)........	rs. 2009 No. 1
Division 4.4.5
Heading to Div. 4.4.5 of Part 4.4	rs. 2009 No. 1
S. 4.92................	rs. 2009 No. 1
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S. 4.94................	am. 2009 No. 1
Part 4.5
S. 4.97................	am. 2009 No. 1
S. 4.98................	am. 2009 No. 1
Note to s. 4.98 (2)........	rs. 2009 No. 1
S. 4.102...............	am. 2009 No. 1
S. 4.103...............	ad. 2009 No. 1
S. 4.104...............	ad. 2009 No. 1
Chapter 5
Heading to Chapt. 5.......	rs. 2009 No. 1
Part 5.1
S. 5.1.................	rs. 2009 No. 1
Part 5.2
Division 5.2
Heading to s. 5.2.........	rs. 2009 No. 1
S. 5.2.................	rs. 2009 No. 1
S. 5.3.................	am. 2009 No. 1
Division 5.2.2
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S. 5.11A...............	ad. 2009 No. 1
S. 5.13................	am. 2009 No. 1
Division 5.2.3
Subdivision 5.2.3.1
S. 5.15................	am. 2009 No. 1
Subdivision 5.2.3.2
Subdiv. 5.2.3.2 of Div. 5.2.3.	rs. 2009 No. 1
S. 5.16................	rs. 2009 No. 1
S. 5.17................	rs. 2009 No. 1
S. 5.17A...............	ad. 2009 No. 1
S. 5.17B...............	ad. 2009 No. 1
S. 5.17C...............	ad. 2009 No. 1
S. 5.17D...............	ad. 2009 No. 1
S. 5.17E...............	ad. 2009 No. 1
S. 5.17F...............	ad. 2009 No. 1
S. 5.17G...............	ad. 2009 No. 1
S. 5.17H...............	ad. 2009 No. 1
S. 5.17I................	ad. 2009 No. 1
S. 5.17J...............	ad. 2009 No. 1
S. 5.17K...............	ad. 2009 No. 1
S. 5.17L...............	ad. 2009 No. 1
Division 5.2.4
S. 5.18................	am. 2009 No. 1
Part 5.3
Heading to Part 5.3 of Chapt. 5	rs. 2009 No. 1
Division 5.3.1
S. 5.23................	rs. 2009 No. 1
S. 5.24................	am. 2009 No. 1
Division 5.3.2
S. 5.25................	am. 2009 No. 1
Division 5.3.3
S. 5.26................	am. 2009 No. 1
Part 5.4
Heading to Part 5.4 of Chapt. 5	rs. 2009 No. 1
Division 5.4.1
S. 5.40................	rs. 2009 No. 1
S. 5.41................	am. 2009 No. 1
Division 5.4.2
S. 5.42................	am. 2009 No. 1
Notes to s. 5.42 (5).......	ad. 2009 No. 1
Division 5.4.3
S. 5.43................	am. 2009 No. 1
Part 5.5
Heading to Part 5.5 of Chapt. 5	rs. 2009 No. 1
S. 5.51................	am. 2009 No. 1
S. 5.53................	am. 2009 No. 1
Chapter 6
Part 6.1
S. 6.2.................	am. 2009 No. 1
S. 6.5.................	am. 2009 No. 1
Chapter 7
S. 7.1.................	am. 2009 No. 1
Heading to s. 7.2.........	rs. 2009 No. 1
S. 7.2.................	am. 2009 No. 1
S. 7.3.................	ad. 2009 No. 1
Chapter 8
Chapter 8..............	rs. 2009 No. 1
Part 8.1
S. 8.1.................	rs. 2009 No. 1
Part 8.2
S. 8.2.................	rs. 2009 No. 1
S. 8.3.................	rs. 2009 No. 1
Part 8.3
S. 8.4.................	rs. 2009 No. 1
S. 8.5.................	rs. 2009 No. 1
S. 8.6.................	rs. 2009 No. 1
S. 8.7.................	rs. 2009 No. 1
S. 8.8.................	rs. 2009 No. 1
S. 8.9.................	rs. 2009 No. 1
S. 8.10................	ad. 2009 No. 1
S. 8.11................	ad. 2009 No. 1
S. 8.12................	ad. 2009 No. 1
S. 8.13................	ad. 2009 No. 1
Part 8.4
S. 8.14................	ad. 2009 No. 1
S. 8.15................	ad. 2009 No. 1
Schedule 1
Schedule 1.............	am. 2009 No. 1
Schedule 3
Schedule 3.............	am. 2009 No. 1