Untitled document
National Greenhouse and Energy Reporting (Measurement) Determination 20081
National Greenhouse and Energy Reporting Act 2007
I, PENELOPE YING YEN WONG, Minister for Climate Change and Water, make this Determination under subsection 10 (3) of the National Greenhouse and Energy Reporting Act 2007.
Dated 25 June 2008
PENNY WONG
Minister for Climate Change and Water
Contents
Chapter 1General
Part 1.1Preliminary
1.1Name of Determination 18
1.2Commencement 18
Division 1.1.1 Overview
1.3Overview — general 18
1.4Overview — methods for measurement 19
1.5Overview — energy 19
1.6Overview — scope 2 emissions 19
1.7Overview — assessment of uncertainty 19
Division 1.1.2 Definitions and interpretation
1.8Definitions 20
1.9Interpretation 25
1.10Description of sources 25
Part 1.2General
1.11Purpose of Part 26
Division 1.2.1 Measurement and standards
1.12Measurement of emissions 26
1.13General principles for measuring emissions 26
1.14Assessment of uncertainty 26
1.15Units of measurement 27
1.16Rounding of amounts 27
1.17Status of standards 27
Division 1.2.2 Methods
1.18Method to be used for a source 27
1.19Temporary unavailability of method 28
Part 1.3Method 4 — Direct measurement of emissions
Division 1.3.1 Preliminary
1.20Overview 29
Division 1.3.2 Operation of method 4 (CEM)
Subdivision 1.3.2.1 Method 4 (CEM)
1.21Method 4 (CEM) — estimation of emissions 29
Subdivision 1.3.2.2 Method 4 (CEM) — use of equipment
1.22Overview 30
1.23Selection of sampling positions for CEM equipment 31
1.24Measurement of flow rates by CEM 31
1.25Measurement of gas concentrations by CEM 31
1.26Frequency of measurement by CEM 32
Division 1.3.3 Operation of method 4 (PEM)
Subdivision 1.3.3.1 Method 4 (PEM)
1.27Method 4 (PEM) — estimation of emissions 32
1.28Calculation of emission factors 33
Subdivision 1.3.3.2 Method 4 (PEM) — use of equipment
1.29Overview 33
1.30Selection of sampling positions for PEM equipment 33
1.31Measurement of flow rates by PEM equipment 34
1.32Measurement of gas concentrations by PEM 34
1.33Representative data for PEM 34
Division 1.3.4 Performance characteristics of equipment
1.34Performance characteristics of CEM or PEM equipment 34
Chapter 2Fuel combustion (UNFCCC Category 1.A)
Part 2.1Preliminary
2.1Outline of Chapter 36
Part 2.2Emissions released from the combustion of solid fuels
Division 2.2.1 Preliminary
2.2Application 37
2.3Available methods for estimating emissions of carbon dioxide, methane and nitrous oxide 37
Division 2.2.2 Method 1 — emissions of carbon dioxide, methane and nitrous oxide from solid fuels
2.4Method 1 — solid fuels 37
Division 2.2.3 Method 2 — emissions from solid fuels
Subdivision 2.2.3.1 Method 2 — estimating carbon dioxide using default oxidation factor
2.5Method 2 — estimating carbon dioxide using oxidation factor 38
Subdivision 2.2.3.2 Method 2 — estimating carbon dioxide using an estimated oxidation factor
2.6Method 2 — estimating carbon dioxide using an estimated oxidation factor 40
Subdivision 2.2.3.3 Sampling and analysis for method 2 under sections 2.5 and 2.6
2.7General requirements for sampling solid fuels 41
2.8General requirements for analysis of solid fuels 42
2.9Requirements for analysis of furnace ash and fly ash 42
2.10Requirements for sampling for carbon in furnace ash 42
2.11Sampling for carbon in fly ash 43
Division 2.2.4 Method 3 — Solid fuels
2.12Method 3 — solid fuels using oxidation factor or an estimated oxidation factor 43
Division 2.2.5 Measurement of consumption of solid fuels
2.13Purpose of Division 45
2.14Criteria for measurement 45
2.15Indirect measurement at point of consumption — criterion AA 45
2.16Direct measurement at point of consumption — criterion AAA 46
2.17Simplified consumption measurements — criterion BBB 46
Part 2.3Emissions released from the combustion of gaseous fuels
Division 2.3.1 Preliminary
2.18Application 47
2.19Available methods 47
Division 2.3.2 Method 1 — emissions of carbon dioxide, methane and nitrous oxide
2.20Method 1 — emissions of carbon dioxide, methane and nitrous oxide 48
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
2.21Method 2 — emissions of carbon dioxide from the combustion of gaseous fuels 49
2.22Calculation of emission factors from combustion of gaseous fuel 50
Subdivision 2.3.3.2 Sampling and analysis
2.23General requirements for sampling under method 2 51
2.24Standards for analysing samples of gaseous fuels 52
2.25Frequency of analysis 56
Division 2.3.4 Method 3 — emissions of carbon dioxide released from the combustion of gaseous fuels
2.26Method 3 — emissions of carbon dioxide from the combustion of gaseous fuels 56
Division 2.3.5 Method 2 — emissions of methane from the combustion of gaseous fuels
2.27Method 2 —emissions of methane from the combustion of gaseous fuels 58
Division 2.3.6 Measurement of quantity of gaseous fuels
2.28Purpose of Division 58
2.29Criteria for measurement 59
2.30Indirect measurement at point of consumption — criterion AA 59
2.31Direct measurement at point of consumption — criterion AAA 59
2.32Volumetric measurement — general 60
2.33Volumetric measurement — super‑compressed gases 61
2.34Gas measuring equipment — requirements 62
2.35Flow devices — requirements 62
2.36Flow computers — requirements 63
2.37Gas chromatographs 63
2.38Simplified consumption measurements — criterion BBB 63
Part 2.4Emissions released from the combustion of liquid fuels
Division 2.4.1 Preliminary
2.39Application 64
2.40Available methods 64
Division 2.4.2 Method 1 — emissions of carbon dioxide, methane and nitrous oxide
2.41Method 1 — emissions of carbon dioxide, methane and nitrous oxide 65
Division 2.4.3 Method 2 — emissions of carbon dioxide released from the combustion of liquid fuels
Subdivision 2.4.3.1 Method 2 — emissions of carbon dioxide released from the combustion of liquid fuels
2.42Method 2 — emissions of carbon dioxide from the combustion of liquid fuels 66
2.43Calculation of emission factors from combustion of liquid fuel 66
Subdivision 2.4.3.2 Sampling and analysis
2.44General requirements for sampling under method 2 67
2.45Standards for analysing samples of liquid fuels 67
2.46Frequency of analysis 70
Division 2.4.4 Method 3 — emissions of carbon dioxide released from the combustion of liquid fuels
2.47Method 3 — emissions of carbon dioxide from the combustion of liquid fuels 70
Division 2.4.5 Method 2 — emissions of methane and nitrous oxide from the combustion of liquid fuels
2.48Method 2 — emissions of methane and nitrous oxide from the combustion of liquid fuels 72
Division 2.4.6 Measurement of quantity of liquid fuels
2.49Purpose of Division 73
2.50Criteria for measurement 73
2.51Indirect measurement at point of consumption — criterion AA 73
2.52Direct measurement at point of consumption — criterion AAA 73
2.53Simplified consumption measurements — criterion BBB 74
Part 2.5Emissions released from fuel use by certain industries
2.54Application 75
Division 2.5.1 Energy — petroleum refining
2.55Application 75
2.56Methods 75
Division 2.5.2 Energy — manufacture of solid fuels (coke ovens)
2.57Application 75
2.58Methods 75
Division 2.5.3 Energy — petrochemical production
2.59Application 76
2.60Available methods 76
2.61Method 1 — petrochemical production 76
2.62Method 2 — petrochemical production 78
2.63Method 3— petrochemical production 78
Part 2.6Blended fuels
2.64Purpose 79
2.65Application 79
2.66Blended solid fuels 79
2.67Blended liquid fuels 79
Part 2.7Estimation of energy for certain purposes
2.68Amount of fuel consumed without combustion 80
2.69Apportionment of fuel consumed as carbon reductant or feedstock and energy 80
2.70Amount of energy consumed in a cogeneration process 81
2.71Apportionment of energy consumed for electricity, transport and for stationary energy 81
Chapter 3Fugitive emissions from fuels (UNFCCC Category 1.B)
Part 3.1Preliminary
3.1Outline of Chapter 82
Part 3.2Coal mining
Division 3.2.1 Preliminary
3.2Outline of Part 83
Division 3.2.2 Underground mines
Subdivision 3.2.2.1 Preliminary
3.3Application 83
3.4Available methods 83
Subdivision 3.2.2.2 Fugitive emissions from extraction of coal
3.5Method 1 — extraction of coal 85
3.6Method 4 — extraction of coal 85
3.7Estimation of emissions 86
3.8Overview — use of equipment 86
3.9Selection of sampling positions for PEM 87
3.10Measurement of volumetric flow rates by PEM 87
3.11Measurement of concentrations by PEM 87
3.12Representative data for PEM 87
3.13Performance characteristics of equipment 87
Subdivision 3.2.2.3 Emissions released from coal mine waste gas flared
3.14Method 1 — coal mine waste gas flared 88
3.15Method 2 — coal mine waste gas flared 88
3.16Method 3 — coal mine waste gas flared 88
Subdivision 3.2.2.4 Fugitive emissions from post‑mining activities
3.17Method 1 — post‑mining activities related to gassy mines 89
Division 3.2.3 Open cut mines
Subdivision 3.2.3.1 Preliminary
3.18Application 89
3.19Available methods 89
Subdivision 3.2.3.2 Fugitive emissions from extraction of coal
3.20Method 1 — extraction of coal 90
3.21Method 2 — extraction of coal 91
3.22Total gas contained by gas bearing strata 91
3.23Estimate of proportion of gas content released below pit floor 92
3.24General requirements for sampling 93
3.25General requirements for analysis of gas and gas bearing strata 93
3.26Method 3 — extraction of coal 93
Subdivision 3.2.3.3 Emissions released from coal mine waste gas flared
3.27Method 1 — coal mine waste gas flared 94
3.28Method 2 — coal mine waste gas flared 94
3.29Method 3 — coal mine waste gas flared 94
Division 3.2.4 Decommissioned underground mines
Subdivision 3.2.4.1 Preliminary
3.30Application 94
3.31Available methods 94
Subdivision 3.2.4.2 Fugitive emissions from decommissioned underground mines
3.32Method 1 — decommissioned underground mines 95
3.33Emission factor for decommissioned underground mines 96
3.34Measurement of proportion of mine that is flooded 96
3.35Water flow into mine 97
3.36Size of mine void volume 97
3.37Method 4 — decommissioned underground mines 97
Subdivision 3.2.4.3 Fugitive emissions from coal mine waste gas flared
3.38Method 1 — coal mine waste gas flared 97
3.39Method 2 — coal mine waste gas flared 98
3.40Method 3 — coal mine waste gas flared 98
Part 3.3Oil and natural gas — fugitive emissions
Division 3.3.1 Preliminary
3.41Outline of Part 99
Division 3.3.2 Oil and gas exploration
3.42Application 99
3.43Available methods 99
3.44Method 1 — oil and gas exploration 100
3.45Method 2 — oil and gas exploration 100
3.46Method 3 — oil and gas exploration 101
Division 3.3.3 Crude oil production
Subdivision 3.3.3.1 Preliminary
3.47Application 101
Subdivision 3.3.3.2 Crude oil production (non‑flared) — fugitive emissions of methane
3.48Available methods 101
3.49Method 1 — crude oil production (non‑flared) emissions of methane 102
3.50Method 2 — crude oil production (non‑flared) emissions of methane 103
Subdivision 3.3.3.3 Crude oil production (flared) — fugitive emissions of carbon dioxide, methane and nitrous oxide
3.51Available methods 103
3.52Method 1 — crude oil production (flared) emissions 104
3.53Method 2 — crude oil production (flared) emissions of carbon dioxide 104
3.54Method 3 — crude oil production (flared) emissions of carbon dioxide 105
3.55Method 1 — crude oil production (flared) emissions of methane and nitrous oxide 105
3.56Method 2 — crude oil production (flared) emissions of methane and nitrous oxide 105
Division 3.3.4 Crude oil transport
3.57Application 105
3.58Available methods 105
3.59Method 1 — crude oil transport 106
3.60Method 2 — fugitive emissions from crude oil transport 106
Division 3.3.5 Crude oil refining
3.61Application 107
3.62Available methods 107
Subdivision 3.3.5.1 Fugitive emissions from crude oil refining and from storage tanks for crude oil
3.63Method 1 — crude oil refining and storage tanks for crude oil 108
3.64Method 2 — crude oil refining and storage tanks for crude oil 108
Subdivision 3.3.5.2 Fugitive emissions from deliberate releases from process vents, system upsets and accidents
3.65Method 1 — fugitive emissions from deliberate releases from process vents, system upsets and accidents 109
3.66Method 4 — deliberate releases from process vents, system upsets and accidents 109
Subdivision 3.3.5.3 Fugitive emissions released from gas flared from the oil refinery
3.67Method 1 — gas flared from crude oil refining 110
3.68Method 2 — gas flared from crude oil refining 110
3.69Method 3 — gas flared from crude oil refining 110
Division 3.3.6 Natural gas production and processing (other than emissions that are vented or flared)
3.70Application 111
3.71Available methods 111
3.72Method 1 — natural gas production and processing (other than emissions that are vented or flared) 111
3.73Method 2— natural gas production and processing (other than venting and flaring) 112
Division 3.3.7 Natural gas transmission
3.74Application 113
3.75Available methods 113
3.76Method 1 — natural gas transmission 113
3.77Method 2 — natural gas transmission 113
Division 3.3.8 Natural gas distribution
3.78Application 114
3.79Available methods 114
3.80Method 1 — natural gas distribution 115
3.81Method 2 — natural gas distribution 116
Division 3.3.9 Natural gas production and processing (emissions that are vented or flared)
3.82Application 117
3.83Available methods 117
Subdivision 3.3.9.1 Fugitive emissions that result from deliberate releases from process vents, system upsets and accidents
3.84Method 1 — deliberate releases from process vents, system upsets and accidents 118
Subdivision 3.3.9.2 Emissions released from gas flared from natural gas production and processing
3.85Method 1 — gas flared from natural gas production and processing 118
3.86Method 2 — gas flared from natural gas production and processing 118
3.87Method 3 — gas flared from natural gas production and processing 119
Chapter 4Industrial processes emissions (UNFCCC Category 2)
Part 4.1Preliminary
4.1Outline of Chapter 120
Part 4.2Industrial processes — mineral products
Division 4.2.1 Cement clinker production
4.2Application 122
4.3Available methods 122
4.4Method 1 — cement clinker production 122
4.5Method 2 — cement clinker production 123
4.6General requirements for sampling cement clinker 123
4.7General requirements for analysing cement clinker 124
4.8Method 3 — cement clinker production 124
4.9General requirements for sampling carbonates 125
4.10General requirements for analysing carbonates 125
Division 4.2.2 Lime production
4.11Application 126
4.12Available methods 126
4.13Method 1 — lime production 126
4.14Method 2 — lime production 126
4.15General requirements for sampling 127
4.16General requirements for analysis of lime 127
4.17Method 3 — lime production 128
4.18General requirements for sampling 129
4.19General requirements for analysis of carbonates 129
Division 4.2.3 Other uses of carbonates
4.20Application 129
4.21Available methods 129
4.22Method 1 — industrial processes involving calcination of carbonates 130
4.23Method 3 — industrial processes involving calcination of carbonates 131
4.24General requirements for sampling carbonates 131
4.25General requirements for analysis of carbonates 132
Division 4.2.4 Soda ash use and production
4.26Application 132
4.27Outline of Division 132
Subdivision 4.2.4.1 Soda ash use
4.28Available methods 132
4.29Method 1 — use of soda ash 133
Subdivision 4.2.4.2 Soda ash production
4.30Available methods 133
4.31Method 1 — production of soda ash 133
4.32Method 2 — production of soda ash 134
4.33Method 3 — production of soda ash 134
Division 4.2.5 Measurement of quantity of carbonates consumed and products derived from carbonates
4.34Purpose of Division 135
4.35Criteria for measurement 135
4.36Indirect measurement at point of consumption or production — criterion AA 135
4.37Direct measurement at point of consumption or production — criterion AAA 136
4.38Acquisition or use or disposal without commercial transaction — criterion BBB 136
4.39Units of measurement 137
Part 4.3Industrial processes — chemical industry
Division 4.3.1 Ammonia production
4.40Application 138
4.41Available methods 138
4.42Method 1 — ammonia production 138
4.43Method 2 — ammonia production 139
4.44Method 3 — ammonia production 139
Division 4.3.2 Nitric acid production
4.45Application 139
4.46Available methods 139
4.47Method 1 — nitric acid production 140
4.48Method 2 — nitric acid production 140
Division 4.3.3 Adipic acid production
4.49Application 141
4.50Available methods 141
Division 4.3.4 Carbide production
4.51Application 141
4.52Available methods 141
Division 4.3.5 Titanium dioxide
4.53Application 141
4.54Available methods 142
4.55Method 1 — titanium dioxide production 142
4.56Method 2 — titanium dioxide production 143
4.57Method 3 — titanium dioxide production 143
Division 4.3.6 Synthetic rutile production
4.58Application 143
4.59Available methods 143
4.60Method 1 — synthetic rutile production 144
4.61Method 2 — synthetic rutile production 145
4.62Method 3 — synthetic rutile production 145
Part 4.4Industrial processes — metal industry
Division 4.4.1 Iron and steel production
4.63Application 146
4.64Purpose of Division 146
4.65Available methods for iron and steel production 146
4.66Method 1 — iron and steel production 147
4.67Method 2 — iron and steel production 148
4.68Method 3 — iron and steel production 149
Division 4.4.2 Ferroalloy metal
4.69Application 149
4.70Available methods 149
4.71Method 1 — ferroalloy metal 150
4.72Method 2 — ferroalloy metal 150
4.73Method 3 — ferroalloy metals 151
Division 4.4.3 Aluminium (carbon dioxide emissions)
4.74Application 151
Subdivision 4.4.3.1 Aluminium — emissions from consumption of baked carbon anodes in aluminium production
4.75Available methods 151
4.76Method 1 — aluminium (baked carbon anode consumption) 152
4.77Method 2 — aluminium (baked carbon anode consumption) 152
4.78Method 3 — aluminium (baked carbon anode consumption) 153
Subdivision 4.4.3.2 Aluminium — emissions from production of baked carbon anodes in aluminium production
4.79Available methods 153
4.80Method 1 — aluminium (baked carbon anode production) 153
4.81Method 2 — aluminium (baked carbon anode production) 154
4.82Method 3 — aluminium (baked carbon anode production) 154
Division 4.4.4 Aluminium (perfluoronated carbon compound emissions)
4.83Application 155
Subdivision 4.4.4.1 Aluminium — emissions of tetrafluoromethane in aluminium production
4.84Available methods 155
4.85Method 1 — aluminium (tetrafluoromethane) 155
4.86Method 2 — aluminium (tetrafluoromethane) 155
4.87Method 3 — aluminium (tetrafluoromethane) 156
Subdivision 4.4.4.2 Aluminium — emissions of hexafluoroethane in aluminium production
4.88Available methods 156
4.89Method 1 — aluminium production (hexafluoroethane) 156
4.90Method 2 — aluminium production (hexafluoroethane) 156
4.91Method 3 — aluminium production (hexafluoroethane) 156
Division 4.4.5 Other metals
4.92Application 157
4.93Available methods 157
4.94Method 1 — other metals 157
4.95Method 2 — other metals 158
4.96Method 3 — other metals 158
Part 4.5Industrial processes — emissions of hydrofluorocarbons and sulphur hexafluoride gases
4.97Application 159
4.98Available method 159
4.99Meaning of hydrofluorocarbons 159
4.100Meaning of synthetic gas generating activities 159
4.101Reporting threshold 160
4.102Method 1 160
Chapter 5Waste (UNFCCC Category 6)
Part 5.1Preliminary
5.1Outline of Chapter 162
Part 5.2Emissions released from solid waste disposal on land — UNFCCC Category 6.A
Division 5.2.1 Preliminary
5.2Application 163
5.3Available methods 163
Division 5.2.2 Method 1 — emissions of methane released from landfills
5.4Method 1 — methane released from landfills (other than from flaring of methane) 164
5.5Criteria for estimating tonnage of total solid waste 165
5.6Criterion A 165
5.7Criterion AAA 166
5.8Criterion BBB 166
5.9Composition of solid waste 166
5.10Waste streams 166
5.11Waste mix types 167
5.12Degradable organic carbon content 168
5.13Opening stock of degradable organic carbon 168
5.14Methane generation constants — (k values) 168
Division 5.2.3 Method 2 — emissions of methane released from landfills
Subdivision 5.2.3.1 methane released from landfills
5.15Method 2 — methane released from landfills (other than from flaring of methane) 170
Subdivision 5.2.3.2 Sampling and analysis
5.16General requirements for sampling under method 2 171
5.17Standards for analysis 171
Division 5.2.4 Method 3 — emissions of methane released from solid waste at landfills
5.18Method 3 — methane released from solid waste at landfills (other than from flaring of methane) 171
Division 5.2.5 Solid waste at landfills — Flaring
5.19Method 1 — landfill gas flared 172
5.20Method 2 — landfill gas flared 172
5.21Method 3 — landfill gas flared 172
Division 5.2.6 Biological treatment of solid waste
5.22Method 1 — biological treatment of solid waste at the landfill 173
Part 5.3Emissions from wastewater handling (domestic and commercial) — UNFCCC Category 6.B.2
Division 5.3.1 Preliminary
5.23Application 174
5.24Available methods 174
Division 5.3.2 Method 1 — methane released from wastewater handling (domestic and commercial)
5.25Method 1 — methane released from wastewater handling (domestic and commercial) 175
Division 5.3.3 Method 2 — methane released from wastewater handling (domestic and commercial)
5.26Method 2 — methane released from wastewater handling (domestic and commercial) 177
5.27General requirements for sampling under method 2 178
5.28Standards for analysis 178
5.29Frequency of sampling and analysis 179
Division 5.3.4 Method 3 — methane released from wastewater handling (domestic and commercial)
5.30Method 3 — methane released from wastewater handling (domestic and commercial) 179
Division 5.3.5 Method 1 — emissions of nitrous oxide released from wastewater handling (domestic and commercial)
5.31Method 1 — nitrous oxide released from wastewater handling (domestic and commercial) 179
Division 5.3.6 Method 2 — emissions of nitrous oxide released from wastewater handling (domestic and commercial)
5.32Method 2 — nitrous oxide released from wastewater handling (domestic and commercial) 180
5.33General requirements for sampling under method 2 180
5.34Standards for analysis 181
5.35Frequency of sampling and analysis 181
Division 5.3.7 Method 3 — emissions of nitrous oxide released from wastewater handling (domestic and commercial)
5.36Method 3 — nitrous oxide released from wastewater handling (domestic and commercial) 181
Division 5.3.8 Wastewater handling (domestic and commercial) — Flaring
5.37Method 1 — Flaring of methane in sludge biogas from wastewater handling (domestic and commercial) 182
5.38Method 2 — flaring of methane in sludge biogas 182
5.39Method 3 — flaring of methane in sludge biogas 182
Part 5.4Emissions released from wastewater handling (industrial) — UNFCCC Category 6.B.1
Division 5.4.1 Preliminary
5.40Application 183
5.41Available methods 183
Division 5.4.2 Method 1 — methane released from wastewater handling (industrial)
5.42Method 1 — methane released from wastewater handling (industrial) 184
Division 5.4.3 Method 2 — methane released from wastewater handling (industrial)
5.43Method 2 — methane released from wastewater handling (industrial) 187
5.44General requirements for sampling under method 2 187
5.45Standards for analysis 188
5.46Frequency of sampling and analysis 188
Division 5.4.4 Method 3 — methane released from wastewater handling (industrial)
5.47Method 3 — methane released from wastewater handling (industrial) 188
Division 5.4.5 Wastewater handling (industrial) — Flaring of methane in sludge biogas
5.48Method 1 — flaring of methane in sludge biogas 188
5.49Method 2 — flaring of methane in sludge biogas 189
5.50Method 3 — flaring of methane in sludge biogas 189
Part 5.5Emissions released from waste incineration — UNFCCC Category 6.C
5.51Application 190
5.52Available methods — emissions of carbon dioxide from waste incineration 190
5.53Method 1 — emissions of carbon dioxide released from waste incineration 190
Chapter 6Energy
Part 6.1Production
6.1Purpose 191
6.2Quantity of energy produced 191
6.3Energy content of fuel produced 192
Part 6.2Consumption
6.4Purpose 194
6.5Energy content of energy consumed 194
Chapter 7Scope 2 emissions
7.1Outline of Chapter 195
7.2Method 1 — purchase of electricity from network 195
Chapter 8Assessment of uncertainty
Part 8.1Preliminary
8.1Outline of Chapter 196
Part 8.2Rules for assessment of uncertainty
8.2Purpose of Part 197
8.3Rules about assessment of uncertainty 197
8.4Uncertainty to be assessed having regard to all facilities 197
Part 8.3Uncertainty levels for use with method 1
8.5Purpose of Part 198
8.6Assessment of uncertainty using method 1 — carbon dioxide emissions from combustion of fuels 198
8.7Assessment of uncertainty using method 1 — methane and nitrous oxide emissions from combustion of fuels 200
8.8Assessment of uncertainty using method 1 — fugitive emissions 200
8.9Assessment of uncertainty using method 1 — emissions from industrial processes 201
Schedule 1Energy content factors and emission factors 202
Part 1Fuel combustion — solid fuels and certain coal‑based products 202
Part 2Fuel combustion — gaseous fuels 203
Part 3Fuel combustion — liquid fuels and certain petroleum‑based products for stationary energy purposes 204
Part 4Fuel combustion — fuels for transport energy purposes 206
Division 4.1 Fuel combustion — fuels for transport energy purposes
Division 4.2 Fuel combustion — liquid fuels for transport energy purposes for post‑2004 vehicles
Division 4.3 Fuel combustion — liquid fuels for transport energy purposes for certain trucks
Part 5Consumption of fuels for non‑energy product purposes 208
Part 6Indirect (scope 2) emission factors from consumption of purchased electricity from grid 208
Schedule 2Standards and frequency for analysing energy content factor etc for solid fuels 209
Schedule 3Carbon content factors for fuels 213
Part 1Solid fuels and certain coal‑based products 213
Part 2Gaseous fuels 214
Part 3Liquid fuels and certain petroleum‑based products 214
Part 4Petrochemical feedstocks and products 215
Chapter 1 General
Part 1.1 Preliminary
1.1 Name of Determination
This Determination is the National Greenhouse and Energy Reporting (Measurement) Determination 2008.
1.2 Commencement
This Determination commences on 1 July 2008.
Division 1.1.1 Overview
1.3 Overview — general
(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;
(c) the consumption 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 4 categories of scope 1 emissions are:
(a) UNFCCC Category 1.A — Fuel combustion activities, which deals with emissions released from fuel combustion (Chapter 2); and
(b) UNFCCC Category 1.B — Fugitive emissions from fuels, which deals with emissions released from the extraction, production, flaring of fuels, processing and distribution of fossil fuels (Chapter 3); and
(c) UNFCCC Category 2 — Industrial processes emissions, which deals with emissions released from the calcining of carbonates and the use of fuels as feedstocks or as carbon reductants, and the emission of synthetic gases in particular cases (Chapter 4); and
(d) UNFCCC Category 6 — Waste emissions, which deals with emissions which are mainly released from the decomposition of organic material in landfill or wastewater handling facilities (Chapter 5).
Note The sources are categorised according to the classification system of the IPCC (see section 1.10).
(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
(c) for liquid fuels other than those mentioned in paragraph (d) — 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.
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.
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.
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.
integrated steelworks has the meaning given in 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.
lower method has the meaning given by subsection 1.18 (6).
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 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.
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.
source means a source of emissions.
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).
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.
UNFCCC or United Nations Framework Convention on Climate Change means the convention of that name done at New York on 9 May 1992.
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 2008.
1.10 Description of sources
In this Determination, a description of a source by number followed by a letter, number or a combination of letters and numbers (for example, Source 1.A) is a reference to the source of a category of emissions corresponding to that description in the revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories as adopted by the UNFCCC.
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.
1.15Units 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
(c) for gaseous fuels, to cubic metres, corrected to standard conditions, unless otherwise specified.
(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
(c) for nitrous oxide is 44.0110‑3.
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;
(c) the requirements in section 1.25 about measurement of the concentrations of greenhouse gas 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) gas concentrations; or
(b) volumetric flow rates; or
(c) consumption of fuel; or
(d) material produced.
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;
(c) the requirements in section 1.32 about measurement of the concentrations of greenhouse gas in the 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
(c) undertaken in accordance with applicable State or Territory legislation.
(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 (UNFCCC Category 1.A)
Part 2.1 Preliminary
2.1 Outline of Chapter
This Chapter provides for UNFCCC Category 1.A (fuel combustion) and related matters as follows:
(a) Part 2.2 provides for emissions released from the combustion of solid fuels — UNFCCC Category 1.A (solid fuels);
(b) Part 2.3 provides for emissions released from the combustion of gaseous fuels — UNFCCC Category 1.A (gaseous fuels);
(c) Part 2.4 provides for emissions released from the combustion of liquid fuels — UNFCCC Category 1.A (liquid fuels);
(d) Part 2.5 provides for emissions released from fuel use by certain industries — UNFCCC categories 1.A.1.b, 1.A.1.c and 1.A.2.c;
(e) Part 2.6 provides for measurement of fuels in blended fuels;
(f) Part 2.7 provides for the estimation of energy for certain purposes.
Part 2.2 Emissions released from the combustion of solid fuels
Division 2.2.1 Preliminary
2.2 Application
This Part applies to UNFCCC Category 1.A — 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 emission source streams 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.
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 the type of fuel measured in gigajoules per tonne according to source as mentioned in Schedule 1.
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) measured in gigajoules per tonnes:
(a) estimated by analysis of the fuel in accordance with the standard indicated for that parameter in Schedule 2 or an equivalent standard; or
(b) according to source as mentioned in Schedule 1.
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 fired 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 fired 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 fired 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) measured in gigajoules per tonnes:
(a) estimated by analysis of the fuel in accordance with the standard indicated for that parameter in the table in Schedule 2 or an equivalent standard; or
(b) according to source as mentioned in Schedule 1.
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 fired 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 fired 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 fired 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 fired 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.
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 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 or by a laboratory that meets requirements equivalent to those in AS ISO/IEC 17025:2005.
(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.
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 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
For the purposes 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 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);
(c) as provided in section 2.16 (criterion AAA);
(d) 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.
Note The uncertainty estimates are from the 2006 IPCC Guidelines, volume 2.
8.7 Assessment of uncertainty using method 1 — methane and nitrous oxide emissions from combustion of fuels
In assessing uncertainty of the estimates of methane and nitrous oxide emissions released from fuel combustion using method 1, the uncertainty level is 50%.
8.8 Assessment of uncertainty using method 1 — fugitive emissions
In assessing uncertainty of the estimates of fugitive emissions estimated using method 1 for activities mentioned in column 2 of an item of the following table, column 3 for that item sets out the uncertainty levels for the emission factor mentioned in the method.
| Item | Activities | Uncertainty level (%) |
| 1 | Gas flared from natural gas production and processing1 | 25 |
| 2 | Open cut coal mines2 | 50 |
| 3 | Underground coal mines3 | 50 |
| 4 | Decommissioned mines4 | 50 |
| 5 | Oil and gas exploration, production, processing, transmission5 | 50 |
Note The uncertainty estimates are from the 2006 IPCC Guidelines, volume 2.
1 IPCC (2006, page 4.49).
2 IPCC (2006, page 4.20).
3 IPCC (2006, page 4.15).
4 IPCC (2006, page 4.29).
5 IPCC (2006, page 4.49).
8.9 Assessment of uncertainty using method 1 — emissions from industrial processes
In assessing uncertainty of the estimates of emissions estimated using method 1 for industrial process activities mentioned in column 2 of an item of the following table, column 3 for that item sets out the uncertainty levels for the emission factor mentioned in the method.
| Item | Activities | Uncertainty level (%) |
| 1 | Soda ash use and other uses of carbonates1 | 5 |
| 2 | Production of cement clinker2 | 6 |
| 3 | Production of lime3 | 6 |
| 4 | Consumption of hydrofluorocarbons and sulphur hexafluoride gases4 | 30 |
| 5 | Nitric acid production5 | 40 |
| 6 | Perfluorocarbons from aluminium production6 | –99/+380 |
Note The uncertainty estimates are from the 2006 IPCC Guidelines, volume 3.
1 IPCC (2006, page 2.39).
2 IPCC (2006, page 2.17).
3 IPCC (2006, page 2.25).
4 IPCC (2006, page 8.21).
5 IPCC (2006, page 3.23).
6 IPCC (2006, page 4.54).
Schedule 1 Energy content factors and emission factors
(section 2.4, subsections 2.5 (1), 2.6 (1), 2.20 (1) and 2.21 (1), paragraph 2.38 (2) (b), section 2.41, subsections 2.42 (1) and 2.48 (2), section 3.14, subsections 4.31 (1), 4.42 (1) and 4.55 (1), section 4.60 and subsections 4.71 (2), 4.94 (2), 5.19 (1), 5.37 (1), 5.48 (1), 5.53 (2), 6.3 (1), 6.5 (1) and 7.2 (1))
Note Under the 2006 IPCC Guidelines, the emission factor for CO2 released from combustion of biogenic carbon fuels is zero.
Part 1 Fuel combustion — solid fuels and certain coal‑based products
| Item | Fuel combusted | Energy content factor GJ/t | Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated) | ||
| 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 and industrial 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 |
Note Energy content and emission factors for coal products are measured on an as fired basis. Black coal represents coal for uses other than electricity and coking. The energy content for black coal and coking coal (metallurgical coal) is on a washed basis.
Part 2 Fuel combustion — gaseous fuels
| Item | Fuel combusted | Energy content factor (GJ/m3 unless otherwise indicated) | Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated) | ||
| 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 | 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 | 57.5 × 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 |
Part 3 Fuel combustion — liquid fuels and certain petroleum‑based products for stationary energy purposes
| Item | Fuel combusted | Energy content factor (GJ/kL unless otherwise indicated) | Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated) | ||
| 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 |
Part 4 Fuel combustion — fuels for transport energy purposes
Division 4.1 Fuel combustion — fuels for transport energy purposes
| Item | Fuel combusted | Energy content factor (GJ/kL unless otherwise indicated) | Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated) | ||
| CO2 | CH4 | N2O | |||
| 53 | Gasoline (other than for use as fuel in an aircraft) | 34.2 | 66.7 | 0.6 | 2.3 |
| 54 | Diesel oil | 38.6 | 69.2 | 0.2 | 0.5 |
| 55 | Gasoline for use as fuel in an aircraft | 33.1 | 66.3 | 0.04 | 0.7 |
| 56 | Kerosene for use as fuel in an aircraft | 36.8 | 68.9 | 0.01 | 0.7 |
| 57 | Fuel oil | 39.7 | 72.9 | 0.06 | 0.6 |
| 58 | Liquefied petroleum gas | 26.2 | 59.6 | 0.6 | 0.6 |
| 59 | Biodiesel | 34.6 | 0.0 | 1.2 | 2.2 |
| 60 | Ethanol for use as fuel in an internal combustion engine | 23.4 | 0.0 | 1.2 | 2.2 |
| 61 | Biofuels other than those mentioned in items 59 and 60 | 23.4 | 0.0 | 1.2 | 2.2 |
| 62 | Natural gas (light duty vehicles) | 39.3 × 10‑3 GJ/m3 | 51.2 | 5.5 | 0.3 |
| 63 | Natural gas (heavy duty vehicles) | 39.3 × 10‑3 GJ/m3 | 51.2 | 2.1 | 0.3 |
Division 4.2 Fuel combustion — liquid fuels for transport energy purposes for post‑2004 vehicles
| Item | Fuel combusted | Energy content factor GJ/kL | Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated) | ||
| 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 |
Division 4.3 Fuel combustion — liquid fuels for transport energy purposes for certain trucks
| Item | Fuel type | Heavy vehicles design standard | Energy content factor GJ/kL | Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated) | ||
| 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 |
Part 5 Consumption of fuels for non‑energy product purposes
| Item | Fuel consumed | Energy content factor (GJ/t unless otherwise indicated) | Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated) | ||
| 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 | |||
Part 6 Indirect (scope 2) emission factors from consumption of purchased electricity from grid
| 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 | 0.91 |
| 80 | South Australia | 0.84 |
| 81 | South West Interconnected System in Western Australia | 0.87 |
| 82 | Tasmania | 0.12 |
| 83 | Northern Territory | 0.69 |
Schedule 2 Standards and frequency for analysing energy content factor etc for solid fuels
(subsections 2.5 (1), 2.6 (1) and 2.8 (1) and (2))
| Item | Fuel combusted | Parameter | Standard | Frequency |
| 1 | Black coal (other than that used to produce coke) | Energy content factor | AS 1038.5—1998 | Monthly sample composite |
| Carbon | AS 1038.6.1—1997 AS 1038.6.4—2005 | Monthly sample composite | ||
| Moisture | AS 1038.1—2001 AS 1038.3—2000 | Each delivery | ||
| Ash | AS 1038.3—2000 | Each delivery | ||
| 2 | Brown coal | Energy content factor | AS 1038.5—1998 | Monthly sample composite |
| Carbon | AS 2434.6—2002 | Monthly sample composite | ||
| Moisture | AS 2434.1—1999 | Each delivery | ||
| Ash | AS 2434.8—2002 | Each delivery | ||
| 3 | Coking coal | Energy content factor | AS 1038.5—1998 | Monthly sample composite |
| Carbon | AS 1038.6.1—1997 AS 1038.6.4—2005 | Monthly sample composite | ||
| Moisture | AS 1038.1—2001 AS 1038.3—2000 | Each delivery | ||
| Ash | AS 1038.3—2000 | Each delivery | ||
| 4 | Brown coal briquettes | Energy content factor | AS 1038.5—1998 | Monthly sample composite |
| Carbon | AS 2434.6—2002 | Monthly sample composite | ||
| Moisture | AS 2434.1—1999 | Each delivery | ||
| Ash | AS 2434.8—2002 | Each delivery | ||
| 5 | Coke oven coke | Energy content factor | AS 1038.5—1998 | Monthly sample composite |
| Carbon | AS 1038.6.1—1997 AS 1038.6.4—2005 | Monthly sample composite | ||
| Moisture | AS 1038.2—2006 | Each delivery | ||
| Ash | AS 1038.3—2000 | Each delivery | ||
| 6 | Coal tar | Energy content factor | N/A | Monthly sample composite |
| Carbon | N/A | Monthly sample composite | ||
| Moisture | N/A | Each delivery | ||
| Ash | N/A | Each delivery | ||
| 7 | Solid fuels other than those mentioned in items 1 to 5 | N/A | N/A | N/A |
| 8 | Industrial materials and tyres that are derived from fossil fuels, if recycled and combusted to produce heat or electricity | Energy content factor | CEN/TS 15400:2006 | Monthly sample composite |
| Carbon | CEN/TS 15407:2006 | Monthly sample composite | ||
| Moisture | CEN/TS 15414‑3:2006 | Each delivery | ||
| Ash | CEN/TS 15403:2006 | Each delivery | ||
| 9 | Non‑biomass municipal materials, if recycled and combusted to produce heat or electricity | Energy content factor | CEN/TS 15400:2006 | Monthly sample composite |
| Carbon | CEN/TS 15407:2006 | Monthly sample composite | ||
| Moisture | CEN/TS 15414‑3:2006 | Each delivery | ||
| Ash | CEN/TS 15403:2006 | Each delivery | ||
| 10 | Dry wood | Energy content factor | CEN/TS 15400:2006 | Monthly sample composite |
| Carbon | CEN/TS 15407:2006 | Monthly sample composite | ||
| Moisture | CEN/TS 15414‑3:2006 CEN/TS 14774‑3:2004 | Each delivery | ||
| Ash | CEN/TS 15403:2006 | Each delivery | ||
| 11 | Green and air dried wood | Energy content factor | CEN/TS 15400:2006 | Monthly sample composite |
| Carbon | CEN/TS 15407:2006 | Monthly sample composite | ||
| Moisture | CEN/TS 15414‑3:2006 CEN/TS 14774‑3:2004 | Each delivery | ||
| Ash | CEN/TS 15403:2006 | Each delivery | ||
| 12 | Sulphite lyes | Energy content factor | CEN/TS 15400:2006 | Monthly sample composite |
| Carbon | CEN/TS 15407:2006 | Monthly sample composite | ||
| Moisture | CEN/TS 15414‑3:2006 CEN/TS 14774‑3:2004 | Each delivery | ||
| Ash | CEN/TS 15403:2006 | Each delivery | ||
| 13 | Bagasse | Energy content factor | CEN/TS 15400:2006 | Monthly sample composite |
| Carbon | CEN/TS 15407:2006 | Monthly sample composite | ||
| Moisture | CEN/TS 15414‑3:2006 CEN/TS 14774‑3:2004 | Each delivery | ||
| Ash | CEN/TS 15403:2006 | Each delivery | ||
| 14 | Biomass municipal and industrial materials, if recycled and combusted to produce heat or electricity | Energy content factor | CEN/TS 15400:2006 | Monthly sample composite |
| Carbon | CEN/TS 15407:2006 | Monthly sample composite | ||
| Moisture | CEN/TS 15414‑3:2006 | Each delivery | ||
| Ash | CEN/TS 15403:2006 | Each delivery | ||
| 15 | Charcoal | Energy content factor | CEN/TS 15400:2006 | Monthly sample composite |
| Carbon | CEN/TS 15407:2006 | Monthly sample composite | ||
| Moisture | CEN/TS 15414‑3:2006 | Each delivery | ||
| Ash | CEN/TS 15403:2006 | Each delivery | ||
| 16 | Primary solid biomass fuels other than those items mentioned in items 10 to 15 | Energy content factor | CEN/TS 15400:2006 | Monthly sample composite |
| Carbon | CEN/TS 15407:2006 | Monthly sample composite | ||
| Moisture | CEN/TS 15414‑3:2006 CEN/TS 14774‑3:2004 | Each delivery | ||
| Ash | CEN/TS 15403:2006 | Each delivery |
Schedule 3 Carbon content factors for fuels
(subsection 2.61 (1), sections 3.65, 4.66 and subsections 4.67 (2) and 4.68 (2))
Note 1 Under the 2006 IPCC Guidelines, the emission factor for CO2 released from combustion of biogenic carbon fuels is zero.
Note 2 The carbon content factors in this Schedule do not include relevant oxidation factors.
Part 1 Solid fuels and certain coal‑based products
| 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 |
Part 2 Gaseous fuels
| 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 |
Part 3 Liquid fuels and certain petroleum‑based products
| 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 |
Part 4 Petrochemical feedstocks and products
| 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 | Stryrene | 0.923 |
Note
1. All legislative instruments and compilations are registered on the Federal Register of Legislative Instruments kept under the Legislative Instruments Act 2003. See
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