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Determinations/Other as made
This Determination provides for the Minister to determine methods, or criteria for methods, for the measurement of greenhouse gas emissions, the production of energy and the consumption of energy.
Administered by: Climate Change, Energy, the Environment and Water
Exempt from sunsetting by the Legislation (Exemptions and Other Matters) Regulation 2015 s12 item 42A
Registered 27 Jun 2008
Tabling HistoryDate
Tabled HR26-Aug-2008
Tabled Senate26-Aug-2008

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


Contents

Chapter 1            General

Part 1.1                 Preliminary

                      1.1     Name of Determination                                                                       18

                      1.2     Commencement                                                                                18

Division 1.1.1          Overview

                      1.3     Overview — general                                                                            18

                      1.4     Overview — methods for measurement                                                19

                      1.5     Overview — energy                                                                            19

                      1.6     Overview — scope 2 emissions                                                           19

                      1.7     Overview — assessment of uncertainty                                                19

Division 1.1.2          Definitions and interpretation

                      1.8     Definitions                                                                                         20

                      1.9     Interpretation                                                                                     25

                    1.10     Description of sources                                                                        25

Part 1.2                 General

                    1.11     Purpose of Part                                                                                 26

Division 1.2.1          Measurement and standards

                    1.12     Measurement of emissions                                                                 26

                    1.13     General principles for measuring emissions                                          26

                    1.14     Assessment of uncertainty                                                                 26

                    1.15     Units of measurement                                                                        27

                    1.16     Rounding of amounts                                                                         27

                    1.17     Status of standards                                                                            27

Division 1.2.2          Methods

                    1.18     Method to be used for a source                                                           27

                    1.19     Temporary unavailability of method                                                      28

Part 1.3                 Method 4 — Direct measurement of emissions

Division 1.3.1          Preliminary

                    1.20     Overview                                                                                           29

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                                         29

Subdivision 1.3.2.2     Method 4 (CEM) — use of equipment

                    1.22     Overview                                                                                           30

                    1.23     Selection of sampling positions for CEM equipment                              31

                    1.24     Measurement of flow rates by CEM                                                     31

                    1.25     Measurement of gas concentrations by CEM                                       31

                    1.26     Frequency of measurement by CEM                                                    32

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                                         32

                    1.28     Calculation of emission factors                                                            33

Subdivision 1.3.3.2     Method 4 (PEM) — use of equipment

                    1.29     Overview                                                                                           33

                    1.30     Selection of sampling positions for PEM equipment                              33

                    1.31     Measurement of flow rates by PEM equipment                                     34

                    1.32     Measurement of gas concentrations by PEM                                       34

                    1.33     Representative data for PEM                                                               34

Division 1.3.4          Performance characteristics of equipment

                    1.34     Performance characteristics of CEM or PEM equipment                        34

Chapter 2            Fuel combustion (UNFCCC Category 1.A)

Part 2.1                 Preliminary

                      2.1     Outline of Chapter                                                                              36

Part 2.2                 Emissions released from the combustion of solid fuels

Division 2.2.1          Preliminary

                      2.2     Application                                                                                        37

                      2.3     Available 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

                      2.4     Method 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

                      2.5     Method 2 — estimating carbon dioxide using oxidation factor                38

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      40

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                                       41

                      2.8     General requirements for analysis of solid fuels                                    42

                      2.9     Requirements for analysis of furnace ash and fly ash                            42

                    2.10     Requirements for sampling for carbon in furnace ash                             42

                    2.11     Sampling for carbon in fly ash                                                             43

Division 2.2.4          Method 3 — Solid fuels

                    2.12     Method 3 — solid fuels using oxidation factor or an estimated oxidation factor  43

Division 2.2.5          Measurement of consumption of solid fuels

                    2.13     Purpose of Division                                                                            45

                    2.14     Criteria for measurement                                                                    45

                    2.15     Indirect measurement at point of consumption — criterion AA                45

                    2.16     Direct measurement at point of consumption — criterion AAA               46

                    2.17     Simplified consumption measurements — criterion BBB                       46

Part 2.3                 Emissions released from the combustion of gaseous fuels

Division 2.3.1          Preliminary

                    2.18     Application                                                                                        47

                    2.19     Available methods                                                                              47

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

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

                    2.21     Method 2 — emissions of carbon dioxide from the combustion of gaseous fuels           49

                    2.22     Calculation of emission factors from combustion of gaseous fuel            50

Subdivision 2.3.3.2     Sampling and analysis

                    2.23     General requirements for sampling under method 2                               51

                    2.24     Standards for analysing samples of gaseous fuels                                52

                    2.25     Frequency of analysis                                                                        56

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

                    2.26     Method 3 — emissions of carbon dioxide from the combustion of gaseous fuels           56

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

                    2.27     Method 2 —emissions of methane from the combustion of gaseous fuels 58

Division 2.3.6          Measurement of quantity of gaseous fuels

                    2.28     Purpose of Division                                                                            58

                    2.29     Criteria for measurement                                                                    59

                    2.30     Indirect measurement at point of consumption — criterion AA                59

                    2.31     Direct measurement at point of consumption — criterion AAA               59

                    2.32     Volumetric measurement — general                                                    60

                    2.33     Volumetric measurement — super‑compressed gases                          61

                    2.34     Gas measuring equipment — requirements                                          62

                    2.35     Flow devices — requirements                                                             62

                    2.36     Flow computers — requirements                                                         63

                    2.37     Gas chromatographs                                                                          63

                    2.38     Simplified consumption measurements — criterion BBB                       63

Part 2.4                 Emissions released from the combustion of liquid fuels

Division 2.4.1          Preliminary

                    2.39     Application                                                                                        64

                    2.40     Available methods                                                                              64

Division 2.4.2          Method 1 — emissions of carbon dioxide, methane and nitrous oxide

                    2.41     Method 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

                    2.42     Method 2 — emissions of carbon dioxide from the combustion of liquid fuels    66

                    2.43     Calculation of emission factors from combustion of liquid fuel                 66

Subdivision 2.4.3.2     Sampling and analysis

                    2.44     General requirements for sampling under method 2                               67

                    2.45     Standards for analysing samples of liquid fuels                                     67

                    2.46     Frequency of analysis                                                                        70

Division 2.4.4          Method 3 — emissions of carbon dioxide released from the combustion of liquid fuels

                    2.47     Method 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

                    2.48     Method 2 — emissions of methane and nitrous oxide from the combustion of liquid fuels           72

Division 2.4.6          Measurement of quantity of liquid fuels

                    2.49     Purpose of Division                                                                            73

                    2.50     Criteria for measurement                                                                    73

                    2.51     Indirect measurement at point of consumption — criterion AA                73

                    2.52     Direct measurement at point of consumption — criterion AAA               73

                    2.53     Simplified consumption measurements — criterion BBB                       74

Part 2.5                 Emissions released from fuel use by certain industries

                    2.54     Application                                                                                        75

Division 2.5.1          Energy — petroleum refining

                    2.55     Application                                                                                        75

                    2.56     Methods                                                                                           75

Division 2.5.2          Energy — manufacture of solid fuels (coke ovens)

                    2.57     Application                                                                                        75

                    2.58     Methods                                                                                           75

Division 2.5.3          Energy — petrochemical production

                    2.59     Application                                                                                        76

                    2.60     Available methods                                                                              76

                    2.61     Method 1 — petrochemical production                                                 76

                    2.62     Method 2 — petrochemical production                                                 78

                    2.63     Method 3— petrochemical production                                                  78

Part 2.6                 Blended fuels

                    2.64     Purpose                                                                                            79

                    2.65     Application                                                                                        79

                    2.66     Blended solid fuels                                                                             79

                    2.67     Blended liquid fuels                                                                            79

Part 2.7                 Estimation of energy for certain purposes

                    2.68     Amount of fuel consumed without combustion                                      80

                    2.69     Apportionment of fuel consumed as carbon reductant or feedstock and energy 80

                    2.70     Amount of energy consumed in a cogeneration process                        81

                    2.71     Apportionment of energy consumed for electricity, transport and for stationary energy   81

Chapter 3            Fugitive emissions from fuels (UNFCCC Category 1.B)

Part 3.1                 Preliminary

                      3.1     Outline of Chapter                                                                              82

Part 3.2                 Coal mining

Division 3.2.1          Preliminary

                      3.2     Outline of Part                                                                                   83

Division 3.2.2          Underground mines

Subdivision 3.2.2.1     Preliminary

                      3.3     Application                                                                                        83

                      3.4     Available methods                                                                              83

Subdivision 3.2.2.2     Fugitive emissions from extraction of coal

                      3.5     Method 1 — extraction of coal                                                            85

                      3.6     Method 4 — extraction of coal                                                            85

                      3.7     Estimation of emissions                                                                     86

                      3.8     Overview — use of equipment                                                             86

                      3.9     Selection of sampling positions for PEM                                              87

                    3.10     Measurement of volumetric flow rates by PEM                                      87

                    3.11     Measurement of concentrations by PEM                                              87

                    3.12     Representative data for PEM                                                               87

                    3.13     Performance characteristics of equipment                                            87

Subdivision 3.2.2.3     Emissions released from coal mine waste gas flared

                    3.14     Method 1 — coal mine waste gas flared                                               88

                    3.15     Method 2 — coal mine waste gas flared                                               88

                    3.16     Method 3 — coal mine waste gas flared                                               88

Subdivision 3.2.2.4     Fugitive emissions from post‑mining activities

                    3.17     Method 1 — post‑mining activities related to gassy mines                     89

Division 3.2.3          Open cut mines

Subdivision 3.2.3.1     Preliminary

                    3.18     Application                                                                                        89

                    3.19     Available methods                                                                              89

Subdivision 3.2.3.2     Fugitive emissions from extraction of coal

                    3.20     Method 1 — extraction of coal                                                            90

                    3.21     Method 2 — extraction of coal                                                            91

                    3.22     Total gas contained by gas bearing strata                                            91

                    3.23     Estimate of proportion of gas content released below pit floor                 92

                    3.24     General requirements for sampling                                                      93

                    3.25     General requirements for analysis of gas and gas bearing strata            93

                    3.26     Method 3 — extraction of coal                                                            93

Subdivision 3.2.3.3     Emissions released from coal mine waste gas flared

                    3.27     Method 1 — coal mine waste gas flared                                               94

                    3.28     Method 2 — coal mine waste gas flared                                               94

                    3.29     Method 3 — coal mine waste gas flared                                               94

Division 3.2.4          Decommissioned underground mines

Subdivision 3.2.4.1     Preliminary

                    3.30     Application                                                                                        94

                    3.31     Available methods                                                                              94

Subdivision 3.2.4.2     Fugitive emissions from decommissioned underground mines

                    3.32     Method 1 — decommissioned underground mines                                95

                    3.33     Emission factor for decommissioned underground mines                       96

                    3.34     Measurement of proportion of mine that is flooded                                 96

                    3.35     Water flow into mine                                                                          97

                    3.36     Size of mine void volume                                                                    97

                    3.37     Method 4 — decommissioned underground mines                                97

Subdivision 3.2.4.3     Fugitive emissions from coal mine waste gas flared

                    3.38     Method 1 — coal mine waste gas flared                                               97

                    3.39     Method 2 — coal mine waste gas flared                                               98

                    3.40     Method 3 — coal mine waste gas flared                                               98

Part 3.3                 Oil and natural gas — fugitive emissions

Division 3.3.1          Preliminary

                    3.41     Outline of Part                                                                                   99

Division 3.3.2          Oil and gas exploration

                    3.42     Application                                                                                        99

                    3.43     Available methods                                                                              99

                    3.44     Method 1 — oil and gas exploration                                                   100

                    3.45     Method 2 — oil and gas exploration                                                   100

                    3.46     Method 3 — oil and gas exploration                                                   101

Division 3.3.3          Crude oil production

Subdivision 3.3.3.1     Preliminary

                    3.47     Application                                                                                      101

Subdivision 3.3.3.2     Crude oil production (non‑flared) — fugitive emissions of methane

                    3.48     Available methods                                                                            101

                    3.49     Method 1 — crude oil production (non‑flared) emissions of methane     102

                    3.50     Method 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

                    3.51     Available methods                                                                            103

                    3.52     Method 1 — crude oil production (flared) emissions                             104

                    3.53     Method 2 — crude oil production (flared) emissions of carbon dioxide   104

                    3.54     Method 3 — crude oil production (flared) emissions of carbon dioxide   105

                    3.55     Method 1 — crude oil production (flared) emissions of methane and nitrous oxide         105

                    3.56     Method 2 — crude oil production (flared) emissions of methane and nitrous oxide         105

Division 3.3.4          Crude oil transport

                    3.57     Application                                                                                      105

                    3.58     Available methods                                                                            105

                    3.59     Method 1 — crude oil transport                                                         106

                    3.60     Method 2 — fugitive emissions from crude oil transport                        106

Division 3.3.5          Crude oil refining

                    3.61     Application                                                                                      107

                    3.62     Available methods                                                                            107

Subdivision 3.3.5.1     Fugitive emissions from crude oil refining and from storage tanks for crude oil

                    3.63     Method 1 — crude oil refining and storage tanks for crude oil               108

                    3.64     Method 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

                    3.65     Method 1 — fugitive emissions from deliberate releases from process vents, system upsets and accidents                                                                                        109

                    3.66     Method 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

                    3.67     Method 1 — gas flared from crude oil refining                                      110

                    3.68     Method 2 — gas flared from crude oil refining                                      110

                    3.69     Method 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)

                    3.70     Application                                                                                      111

                    3.71     Available methods                                                                            111

                    3.72     Method 1 — natural gas production and processing (other than emissions that are vented or flared)                                                                                                      111

                    3.73     Method 2— natural gas production and processing (other than venting and flaring)        112

Division 3.3.7          Natural gas transmission

                    3.74     Application                                                                                      113

                    3.75     Available methods                                                                            113

                    3.76     Method 1 — natural gas transmission                                                113

                    3.77     Method 2 — natural gas transmission                                                113

Division 3.3.8          Natural gas distribution

                    3.78     Application                                                                                      114

                    3.79     Available methods                                                                            114

                    3.80     Method 1 — natural gas distribution                                                   115

                    3.81     Method 2 — natural gas distribution                                                   116

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

                    3.82     Application                                                                                      117

                    3.83     Available methods                                                                            117

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

                    3.84     Method 1 — deliberate releases from process vents, system upsets and accidents      118

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

                    3.85     Method 1 — gas flared from natural gas production and processing      118

                    3.86     Method 2 — gas flared from natural gas production and processing      118

                    3.87     Method 3 — gas flared from natural gas production and processing      119

Chapter 4            Industrial processes emissions (UNFCCC Category 2)

Part 4.1                 Preliminary

                      4.1     Outline of Chapter                                                                            120

Part 4.2                 Industrial processes — mineral products

Division 4.2.1          Cement clinker production

                      4.2     Application                                                                                      122

                      4.3     Available methods                                                                            122

                      4.4     Method 1 — cement clinker production                                              122

                      4.5     Method 2 — cement clinker production                                              123

                      4.6     General requirements for sampling cement clinker                              123

                      4.7     General requirements for analysing cement clinker                              124

                      4.8     Method 3 — cement clinker production                                              124

                      4.9     General requirements for sampling carbonates                                    125

                    4.10     General requirements for analysing carbonates                                   125

Division 4.2.2          Lime production

                    4.11     Application                                                                                      126

                    4.12     Available methods                                                                            126

                    4.13     Method 1 — lime production                                                             126

                    4.14     Method 2 — lime production                                                             126

                    4.15     General requirements for sampling                                                     127

                    4.16     General requirements for analysis of lime                                           127

                    4.17     Method 3 — lime production                                                             128

                    4.18     General requirements for sampling                                                     129

                    4.19     General requirements for analysis of carbonates                                 129

Division 4.2.3          Other uses of carbonates

                    4.20     Application                                                                                      129

                    4.21     Available methods                                                                            129

                    4.22     Method 1 — industrial processes involving calcination of carbonates     130

                    4.23     Method 3 — industrial processes involving calcination of carbonates     131

                    4.24     General requirements for sampling carbonates                                    131

                    4.25     General requirements for analysis of carbonates                                 132

Division 4.2.4          Soda ash use and production

                    4.26     Application                                                                                      132

                    4.27     Outline of Division                                                                            132

Subdivision 4.2.4.1     Soda ash use

                    4.28     Available methods                                                                            132

                    4.29     Method 1 — use of soda ash                                                            133

Subdivision 4.2.4.2     Soda ash production

                    4.30     Available methods                                                                            133

                    4.31     Method 1 — production of soda ash                                                   133

                    4.32     Method 2 — production of soda ash                                                   134

                    4.33     Method 3 — production of soda ash                                                   134

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

                    4.34     Purpose of Division                                                                           135

                    4.35     Criteria for measurement                                                                   135

                    4.36     Indirect measurement at point of consumption or production — criterion AA     135

                    4.37     Direct measurement at point of consumption or production — criterion AAA     136

                    4.38     Acquisition or use or disposal without commercial transaction — criterion BBB            136

                    4.39     Units of measurement                                                                      137

Part 4.3                 Industrial processes — chemical industry

Division 4.3.1          Ammonia production

                    4.40     Application                                                                                      138

                    4.41     Available methods                                                                            138

                    4.42     Method 1 — ammonia production                                                      138

                    4.43     Method 2 — ammonia production                                                      139

                    4.44     Method 3 — ammonia production                                                      139

Division 4.3.2          Nitric acid production

                    4.45     Application                                                                                      139

                    4.46     Available methods                                                                            139

                    4.47     Method 1 — nitric acid production                                                     140

                    4.48     Method 2 — nitric acid production                                                     140

Division 4.3.3          Adipic acid production

                    4.49     Application                                                                                      141

                    4.50     Available methods                                                                            141

Division 4.3.4          Carbide production

                    4.51     Application                                                                                      141

                    4.52     Available methods                                                                            141

Division 4.3.5          Titanium dioxide

                    4.53     Application                                                                                      141

                    4.54     Available methods                                                                            142

                    4.55     Method 1 — titanium dioxide production                                             142

                    4.56     Method 2 — titanium dioxide production                                             143

                    4.57     Method 3 — titanium dioxide production                                             143

Division 4.3.6          Synthetic rutile production

                    4.58     Application                                                                                      143

                    4.59     Available methods                                                                            143

                    4.60     Method 1 — synthetic rutile production                                              144

                    4.61     Method 2 — synthetic rutile production                                              145

                    4.62     Method 3 — synthetic rutile production                                              145

Part 4.4                 Industrial processes — metal industry

Division 4.4.1          Iron and steel production

                    4.63     Application                                                                                      146

                    4.64     Purpose of Division                                                                           146

                    4.65     Available methods for iron and steel production                                   146

                    4.66     Method 1 — iron and steel production                                                147

                    4.67     Method 2 — iron and steel production                                                148

                    4.68     Method 3 — iron and steel production                                                149

Division 4.4.2          Ferroalloy metal

                    4.69     Application                                                                                      149

                    4.70     Available methods                                                                            149

                    4.71     Method 1 — ferroalloy metal                                                             150

                    4.72     Method 2 — ferroalloy metal                                                             150

                    4.73     Method 3 — ferroalloy metals                                                            151

Division 4.4.3          Aluminium (carbon dioxide emissions)

                    4.74     Application                                                                                      151

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

                    4.75     Available methods                                                                            151

                    4.76     Method 1 — aluminium (baked carbon anode consumption)                 152

                    4.77     Method 2 — aluminium (baked carbon anode consumption)                 152

                    4.78     Method 3 — aluminium (baked carbon anode consumption)                 153

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

                    4.79     Available methods                                                                            153

                    4.80     Method 1 — aluminium (baked carbon anode production)                    153

                    4.81     Method 2 — aluminium (baked carbon anode production)                    154

                    4.82     Method 3 — aluminium (baked carbon anode production)                    154

Division 4.4.4          Aluminium (perfluoronated carbon compound emissions)

                    4.83     Application                                                                                      155

Subdivision 4.4.4.1     Aluminium — emissions of tetrafluoromethane in aluminium production

                    4.84     Available methods                                                                            155

                    4.85     Method 1 — aluminium (tetrafluoromethane)                                       155

                    4.86     Method 2 — aluminium (tetrafluoromethane)                                       155

                    4.87     Method 3 — aluminium (tetrafluoromethane)                                       156

Subdivision 4.4.4.2     Aluminium — emissions of hexafluoroethane in aluminium production

                    4.88     Available methods                                                                            156

                    4.89     Method 1 — aluminium production (hexafluoroethane)                         156

                    4.90     Method 2 — aluminium production (hexafluoroethane)                         156

                    4.91     Method 3 — aluminium production (hexafluoroethane)                         156

Division 4.4.5          Other metals

                    4.92     Application                                                                                      157

                    4.93     Available methods                                                                            157

                    4.94     Method 1 — other metals                                                                 157

                    4.95     Method 2 — other metals                                                                 158

                    4.96     Method 3 — other metals                                                                 158

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

                    4.97     Application                                                                                      159

                    4.98     Available method                                                                              159

                    4.99     Meaning of hydrofluorocarbons                                                          159

                  4.100     Meaning of synthetic gas generating activities                                    159

                  4.101     Reporting threshold                                                                          160

                  4.102     Method 1                                                                                         160

Chapter 5            Waste (UNFCCC Category 6)

Part 5.1                 Preliminary

                      5.1     Outline of Chapter                                                                            162

Part 5.2                 Emissions released from solid waste disposal on land — UNFCCC Category 6.A

Division 5.2.1          Preliminary

                      5.2     Application                                                                                      163

                      5.3     Available methods                                                                            163

Division 5.2.2          Method 1 — emissions of methane released from landfills

                      5.4     Method 1 — methane released from landfills (other than from flaring of methane)           164

                      5.5     Criteria for estimating tonnage of total solid waste                               165

                      5.6     Criterion A                                                                                       165

                      5.7     Criterion AAA                                                                                  166

                      5.8     Criterion BBB                                                                                  166

                      5.9     Composition of solid waste                                                               166

                    5.10     Waste streams                                                                                166

                    5.11     Waste mix types                                                                             167

                    5.12     Degradable organic carbon content                                                    168

                    5.13     Opening stock of degradable organic carbon                                       168

                    5.14     Methane 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

                    5.15     Method 2 — methane released from landfills (other than from flaring of methane)           170

Subdivision 5.2.3.2     Sampling and analysis

                    5.16     General requirements for sampling under method 2                             171

                    5.17     Standards for analysis                                                                      171

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

                    5.18     Method 3 — methane released from solid waste at landfills (other than from flaring of methane)  171

Division 5.2.5          Solid waste at landfills — Flaring

                    5.19     Method 1 — landfill gas flared                                                           172

                    5.20     Method 2 — landfill gas flared                                                           172

                    5.21     Method 3 — landfill gas flared                                                           172

Division 5.2.6          Biological treatment of solid waste

                    5.22     Method 1 — biological treatment of solid waste at the landfill               173

Part 5.3                 Emissions from wastewater handling (domestic and commercial) — UNFCCC Category 6.B.2

Division 5.3.1          Preliminary

                    5.23     Application                                                                                      174

                    5.24     Available methods                                                                            174

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

                    5.25     Method 1 — methane released from wastewater handling (domestic and commercial)   175

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

                    5.26     Method 2 — methane released from wastewater handling (domestic and commercial)   177

                    5.27     General requirements for sampling under method 2                             178

                    5.28     Standards for analysis                                                                      178

                    5.29     Frequency of sampling and analysis                                                  179

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

                    5.30     Method 3 — methane released from wastewater handling (domestic and commercial)   179

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

                    5.31     Method 1 — nitrous oxide released from wastewater handling (domestic and commercial)         179

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

                    5.32     Method 2 — nitrous oxide released from wastewater handling (domestic and commercial)         180

                    5.33     General requirements for sampling under method 2                             180

                    5.34     Standards for analysis                                                                      181

                    5.35     Frequency of sampling and analysis                                                  181

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

                    5.36     Method 3 — nitrous oxide released from wastewater handling (domestic and commercial)         181

Division 5.3.8          Wastewater handling (domestic and commercial) — Flaring

                    5.37     Method 1 — Flaring of methane in sludge biogas from wastewater handling (domestic and commercial)                                                                                    182

                    5.38     Method 2 — flaring of methane in sludge biogas                                 182

                    5.39     Method 3 — flaring of methane in sludge biogas                                 182

Part 5.4                 Emissions released from wastewater handling (industrial) — UNFCCC Category 6.B.1

Division 5.4.1          Preliminary

                    5.40     Application                                                                                      183

                    5.41     Available methods                                                                            183

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

                    5.42     Method 1 — methane released from wastewater handling (industrial)    184

Division 5.4.3          Method 2 — methane released from wastewater handling (industrial)

                    5.43     Method 2 — methane released from wastewater handling (industrial)    187

                    5.44     General requirements for sampling under method 2                             187

                    5.45     Standards for analysis                                                                      188

                    5.46     Frequency of sampling and analysis                                                  188

Division 5.4.4          Method 3 — methane released from wastewater handling (industrial)

                    5.47     Method 3 — methane released from wastewater handling (industrial)    188

Division 5.4.5          Wastewater handling (industrial) — Flaring of methane in sludge biogas

                    5.48     Method 1 — flaring of methane in sludge biogas                                 188

                    5.49     Method 2 — flaring of methane in sludge biogas                                 189

                    5.50     Method 3 — flaring of methane in sludge biogas                                 189

Part 5.5                 Emissions released from waste incineration — UNFCCC Category 6.C

                    5.51     Application                                                                                      190

                    5.52     Available methods — emissions of carbon dioxide from waste incineration 190

                    5.53     Method 1 — emissions of carbon dioxide released from waste incineration 190

Chapter 6            Energy

Part 6.1                 Production

                      6.1     Purpose                                                                                          191

                      6.2     Quantity of energy produced                                                             191

                      6.3     Energy content of fuel produced                                                        192

Part 6.2                 Consumption

                      6.4     Purpose                                                                                          194

                      6.5     Energy content of energy consumed                                                  194

Chapter 7            Scope 2 emissions

                      7.1     Outline of Chapter                                                                            195

                      7.2     Method 1 — purchase of electricity from network                                195

Chapter 8            Assessment of uncertainty

Part 8.1                 Preliminary

                      8.1     Outline of Chapter                                                                            196

Part 8.2                 Rules for assessment of uncertainty

                      8.2     Purpose of Part                                                                                197

                      8.3     Rules about assessment of uncertainty                                              197

                      8.4     Uncertainty to be assessed having regard to all facilities                      197

Part 8.3                 Uncertainty levels for use with method 1

                      8.5     Purpose of Part                                                                                198

                      8.6     Assessment of uncertainty using method 1 — carbon dioxide emissions from combustion of fuels                                                                                                      198

                      8.7     Assessment of uncertainty using method 1 — methane and nitrous oxide emissions from combustion of fuels                                                                          200

                      8.8     Assessment of uncertainty using method 1 — fugitive emissions         200

                      8.9     Assessment of uncertainty using method 1 — emissions from industrial processes      201

Schedule 1             Energy content factors and emission factors                                 202

Part 1                      Fuel combustion — solid fuels and certain coal‑based products           202

Part 2                      Fuel combustion — gaseous fuels                                                     203

Part 3                      Fuel combustion — liquid fuels and certain petroleum‑based products for stationary energy purposes                                                                                         204

Part 4                      Fuel 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 5                      Consumption of fuels for non‑energy product purposes                        208

Part 6                      Indirect (scope 2) emission factors from consumption of purchased electricity from grid 208

Schedule 2             Standards and frequency for analysing energy content factor etc for solid fuels 209

Schedule 3             Carbon content factors for fuels                                                     213

Part 1                      Solid fuels and certain coal‑based products                                        213

Part 2                      Gaseous fuels                                                                                 214

Part 3                      Liquid fuels and certain petroleum‑based products                              214

Part 4                      Petrochemical 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.

1.15        Units of measurement

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

                (a)    for solid fuel, to tonnes; and

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

                (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 CO2e 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.

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

2.16        Direct measurement at point of consumption — criterion AAA

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

         (2)   The measurement must be carried out either:

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

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

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

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

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

2.17        Simplified consumption measurements — criterion BBB

                For paragraph 2.14 (d), criterion BBB is the estimation of the solid fuel combusted during a year from the operation of the facility in accordance with industry practice if:

                (a)    the acquisition of the fuel does not involve a commercial transaction; and

               (b)    the equipment used to measure combustion of the fuel is not calibrated to a measurement requirement.

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

Part 2.3              Emissions released from the combustion of gaseous fuels

Division 2.3.1        Preliminary

2.18        Application

                This Part applies to UNFCCC category 1.A — gaseous fuels.

2.19        Available methods

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

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

                                   (i)    method 1 under section 2.20;

                         (ii)    method 2 under section 2.21;

                         (iii)    method 3 under section 2.26;

                        (iv)    method 4 under Part 1.3; and

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

                          (i)    method 1 under section 2.20;

                         (ii)    method 2 under section 2.27; and

                (c)    method 1 under section 2.20 must be used for estimating emissions of nitrous oxide.

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

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

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

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

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

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

where:

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

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

ECi is the energy content factor of fuel type (i) specified in Part 2 of Schedule 1 and measured in gigajoules per cubic metre.

EFijoxec is the emission factor for each gas type (j) released during the year (which includes the effect of an oxidation factor) measured in kilograms CO2‑e per gigajoule of fuel type (i) according to source as mentioned in Part 2 of Schedule 1.

         (2)   If Qi is measured in gigajoules, then ECi is 1.

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

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

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

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

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

where:

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

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

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

                (a)    estimated from analysis under Subdivision 2.3.3.2; or

               (b)    according to source as mentioned in Schedule 1.

EFiCO2ox,ec is the carbon dioxide emission factor for fuel type (i) measured in kilograms CO2‑e per gigajoule and calculated in accordance with section 2.22.

         (2)   If Qi is measured in gigajoules, then ECi is 1.

         (3)   Method 2 requires gaseous fuels to be sampled and analysed in accordance with the requirements in sections 2.23, 2.24 and 2.25.

2.22        Calculation of emission factors from combustion of gaseous fuel

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

where:

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

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

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

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

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

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

OFg is the oxidation factor 0.995 applicable to gaseous fuels.

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

where:

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

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

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

 

Item

Component gas y

Molecular Wt (kg/kmole)

Number of carbon atoms in component molecules

1

Methane

16.043

1

2

Ethane

30.070

2

3

Propane

44.097

3

4

Butane

58.123

4

5

Pentane

72.150

5

6

Carbon monoxide

28.016

1

7

Hydrogen

2.016

0

8

Hydrogen sulphide

34.082

0

9

Oxygen

31.999

0

10

Water

18.015

0

11

Nitrogen

28.013

0

12

Argon

39.948

0

13

Carbon dioxide

44.010

1

         (4)   The carbon dioxide emission factor EFi CO2,ox,ec derived from the calculation in subsection (1) must be expressed in terms of kilograms of carbon dioxide per gigajoule calculated using the following formula:

where:

ECi is the energy content factor of the fuel type (i) as obtained under section 2.21 and expressed in gigajoules per cubic metre.

Ci is the density of fuel type (i) expressed in kilograms of fuel per cubic metre.

Subdivision 2.3.3.2     Sampling and analysis

2.23        General requirements for sampling under method 2

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

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

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

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

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

2.24        Standards for analysing samples of gaseous fuels

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

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

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

 

Item

Fuel type

Energy content

Gas Composition

1

Natural gas if distributed in a pipeline

ASTM D 1826 — 94 (2003)

ASTM D 7164 — 05

ASTM 3588 — 98 (2003)

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

ISO 6976:1995

GPA 2172 — 96

ASTM D 1945 — 03

ASTM D 1946 — 90 (2006)

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

GPA 2145 – 03

GPA 2261 – 00

2

Coal seam methane that is captured for combustion

ASTM D 1826 — 94 (2003)

ASTM D 7164 — 05

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

ISO 6976:1995

GPA 2172 — 96

ASTM D 1945 — 03

ASTM D 1946 — 90 (2006)

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

GPA 2145 – 03

GPA 2261 – 00

3

Coal mine waste gas that is captured for combustion

ASTM D 1826 – 94 (2003)

ASTM D 7164 – 05

ASTM 3588 — 98 (2003)

ISO 6974

  part 1 (2000)

  part 2 (2001)

  part 3 (2000)

  part 4 (2000)

  part 5 (2000)

  part 6 (2002)

ISO 6976:1995

GPA 2172 — 96

ASTM D 1945 – 03

ASTM D 1946 – 90 (2006)

ISO 6974

  part 1 (2000)

  part 2 (2001)

  part 3 (2000)

  part 4 (2000)

  part 5 (2000)

  part 6 (2002)

GPA 2145 – 03

GPA 2261 – 00

4

Compressed natural gas

ASTM 3588 — 98 (2003)

N/A

5

Unprocessed natural gas

ASTM D 1826 — 94 (2003)

ASTM D 7164 — 05

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

ISO 6976:1995

GPA 2172 — 96

ASTM D 1945 — 03

ASTM D 1946 — 90 (2006)

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

GPA 2145 – 03

GPA 2261 – 00

6

Ethane

ASTM D 3588 – 98 (2003)

IS0 6976:1995

ASTM D 1945 – 03

ASTM D 1946 – 90 (2006)

7

Coke oven gas

ASTM D 3588 — 98 (2003)

ISO 6976:1995

ASTM D 1945 — 03

ASTM D 1946 — 90 (2006)

8

Blast furnace gas

ASTM D 3588 — 98 (2003)

ISO 6976:1995

ASTM D 1945 — 03

ASTM D 1946 — 90 (2006)

9

Town gas

ASTM D 1826 — 94 (2003)

ASTM D 7164 — 05

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

ISO 6976:1995

GPA 2172 — 96

ASTM D 1945 — 03

ASTM D 1946 — 90 (2006)

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

GPA 2145 – 03

GPA 2261 – 00

10

Liquefied natural gas

ISO 6976:1995

ASTM D 1945 – 03

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

11

Landfill biogas that is captured for combustion

ASTM D 1826 — 94 (2003)

ASTM D 7164 — 05

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

ISO 6976:1995

GPA 2172 — 96

ASTM D 1945 — 03

ASTM D 1946 — 90 (2006)

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

GPA 2145 – 03

GPA 2261 – 00

12

Sludge biogas that is captured for combustion

ASTM D 1826 – 94 (2003)

ASTM D 7164 – 05

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

ISO 6976:1995

GPA 2172 — 96

ASTM D 1945 – 03

ASTM D 1946 – 90 (2006)

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

GPA 2145 – 03

GPA 2261 – 00

13

A biogas that is captured for combustion, other than those mentioned in items 11 and 12

ASTM D 1826 — 94 (2003)

ASTM D 7164 — 05

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

ISO 6976:1995

GPA 2172 — 96

ASTM D 1945 — 03

ASTM D 1946 — 90 (2006)

ISO 6974

part 1 (2000)

part 2 (2001)

part 3 (2000)

part 4 (2000)

part 5 (2000)

part 6 (2002)

GPA 2145 – 03

GPA 2261 – 00

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

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

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

2.25        Frequency of analysis

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

 

Item

Fuel

Parameter

Frequency

1

Pipeline quality gases

Gas composition

Monthly

Energy content

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

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

2

All other gases

Gas composition

Energy content

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

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

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

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

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

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

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

 

Item

Gaseous fuel

Standard

1

Natural gas if distributed in a pipeline

ISO 10715:1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

GPA 2166–05

2

Coal seam methane that is captured for combustion

ISO 10715:1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

GPA 2166–05

3

Coal mine waste gas that is captured for combustion

ISO 10715:1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

GPA 2166–05

4

Compressed natural gas

ASTM F 307–02 (2007)

5

Unprocessed natural gas

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

GPA 2166–05

6

Ethane

ISO 10715:1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

7

Coke oven gas

ISO 10715 ‑1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

8

Blast furnace gas

ISO 10715:1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

9

Town gas

ISO 10715:1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

GPA 2166–05

10

Liquefied natural gas

ISO 8943:2007

11

Landfill biogas that is captured for combustion

ISO 10715:1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

GPA 2166–05

12

Sludge biogas that is captured for combustion

ISO 10715:1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

GPA 2166–05

13

A biogas that is captured for combustion, other than those mentioned in items 11 and 12

ISO 10715:1997

ASTM D 5287–97 (2002)

ASTM F 307–02 (2007)

ASTM D 5503–94 (2003)

GPA 2166–05

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

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

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

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

         (2)   In applying method 1 under section 2.20, the emission factor EFijoxec is to be obtained by using the equipment type emission factors set out in Volume 2, section 2.3.2.3 of the 2006 IPCC Guidelines corrected to gross calorific values.

Division 2.3.6        Measurement of quantity of gaseous fuels

2.28        Purpose of Division

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

2.29        Criteria for measurement

         (1)   For the purposes of calculating the combustion of gaseous fuel from the operation of a facility for a year and, in particular, for Qi in sections 2.20 and 2.21, the combustion must be estimated using one of the following criteria:

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

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

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

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

         (2)   For paragraph (1) (a), the amount of gaseous fuel delivered must be expressed in cubic metres or gigajoules.

2.30        Indirect measurement at point of consumption — criterion AA

                For paragraph 2.29 (1) (b), criterion AA is the amount of a gaseous fuel combusted from the operation of the facility during the year based on amounts delivered during the year (evidenced by invoices) as adjusted for the estimated change in the quantity of the stockpile of the fuel for the facility during the year.

2.31        Direct measurement at point of consumption — criterion AAA

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

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

                (a)    using volumetric measurement in accordance with:

                          (i)    for gases generally — section 2.32; and

                         (ii)    for supercompressed gases — section 2.33; and

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

         (3)   The measurement must be either:

                (a)    carried out using measuring equipment that:

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

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

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

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

 

Item

Gas measuring equipment category

Maximum daily quantity of gas combusted GJ/day

Transmitter and accuracy requirements (% of range)

1

1

0–1750

Pressure <±0.25%

Diff. pressure <±0.25%

Temperature <±0.50%

2

2

1751–3500

Pressure <±0.25%

Diff. pressure <±0.25%

Temperature <±0.50%

3

3

3501–17500

Smart transmitters:

Pressure <±0.10%

Diff. pressure <±0.10%

Temperature <±0.25%

4

4

17501 or more

Smart transmitters:

Pressure <±0.10%

Diff. pressure <±0.10%

Temperature <±0.25%

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

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

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

2.32        Volumetric measurement — general

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

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

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

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

                (a)    for orifice plate measuring systems — the publication entitled American Gas Report No. 3 published by the American Gas Association or Parts 1 to 4 of the publication entitled API 14.3 published by the American Petroleum Institute;

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

                (c)    for positive displacement measuring systems — ANSI B109.3—1986.

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

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

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

         (7)   Standard conditions means:

                (a)    air pressure of 101.323 kilopascals; and

               (b)    air temperature of 15.0 degrees celsius; and

                (c)    air density of 1.225 kilograms per cubic metre.

2.33        Volumetric measurement — super‑compressed gases

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

         (2)   If, in determining volume in relation to super‑compressed gases, it is necessary to correct for deviation from the ideal gas law, the correction must be determined using the relevant method contained in the publication entitled American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility published by the American Gas Association.

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

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

               (b)    if the measuring equipment is category 1 or 2 equipment in accordance with the table in section 2.31 — using an alternative method set out in the publication entitled American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility published by the American Gas Association.

2.34        Gas measuring equipment — requirements

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

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

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

                (c)    if the equipment uses gas chromatographs— the requirements relating to chromatographs set out in section 2.37.

2.35        Flow devices — requirements

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

Note   The publication entitled American Gas Association Report No. 3, published by the American Gas Association, sets out a manner that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%.

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

Note   The publication entitled American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility, published by the American Gas Association, sets out a manner that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%.

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

Note   ANSI B109.3—1986 sets out a manner for installation that ensures that the maximum uncertainty of flow is ±1.5%.

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

         (5)   All flow devices that are used by measuring equipment of a category specified in column 2 of the table in section 2.31 must, wherever possible, be calibrated for pressure, differential pressure and temperature in accordance with the requirements specified in column 4 for the category of equipment specified in column 2 for that item. The calibrations must take into account the effects of static pressure and ambient temperature.

2.36        Flow computers — requirements

                For paragraph 2.34 (b), the requirement is that the flow computer that is used by the equipment for measuring purposes must record the instantaneous values for all primary measurement inputs and must also record the following outputs:

                (a)    instantaneous corrected volumetric flow;

               (b)    cumulative corrected volumetric flow;

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

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

                (e)    super‑compressibility factor.

2.37        Gas chromatographs

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

                (a)    be factory tested and calibrated using a measurement standard produced by gravimetric methods and traceable to Australian units of measurement required by or under the National Measurement Act 1960; and

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

                (c)    include a mechanism for re‑calibration against a certified reference gas.

2.38        Simplified consumption measurements — criterion BBB

         (1)   For paragraph 2.29 (1) (d), criterion BBB is the estimation of gaseous fuel in accordance with industry practice if:

                (a)    the acquisition of the gaseous fuel does not involve a commercial transaction; and

               (b)    the measuring equipment used to estimate consumption of the fuel does not meet the requirements of criterion AAA.

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

                (a)    the energy content of the captured landfill gas may be estimated by assuming that measured electricity dispatched for sale (sent out generation) represents 36% of the energy content of all fuel used to produce electricity; and

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

Part 2.4              Emissions released from the combustion of liquid fuels

Division 2.4.1        Preliminary

2.39        Application

                This Part applies to UNFCCC category 1.A — liquid fuels.

2.40        Available methods

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

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

                                   (i)    method 1 under section 2.41;

                         (ii)    method 2 under section 2.42;

                         (iii)    method 3 under section 2.47;

                        (iv)    method 4 under Part 1.3; and

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

                          (i)    method 1 under section 2.41;

                         (ii)    method 2 under section 2.48.

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

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

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

Division 2.4.2        Method 1 — emissions of carbon dioxide, methane and nitrous oxide

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

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

where:

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

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

                (a)    stationary energy purposes; and

               (b)    transport energy purposes;

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

ECi is the energy content factor of fuel type (i) measured as energy content in gigajoules per kilolitre according to source as mentioned in:

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

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

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

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

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

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

Division 2.4.3        Method 2 — emissions of carbon dioxide 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

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

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

where:

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

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

ECi is the energy content of fuel type (i) measured in gigajoules per kilolitre:

                (a)    estimated from analysis under Subdivision 2.3.3.2; or

               (b)    according to source as mentioned in Schedule 1.

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

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

2.43        Calculation of emission factors from combustion of liquid fuel

         (1)   For section 2.42, the emission factor EFiCO2ox,ec from the combustion of fuel type (i) must allow for oxidation effects and must first estimate EFi,co2,ox,kg in accordance with the following formula:

where:

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

OFi is the oxidation factor 0.99 applicable to liquid fuels.

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

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

where:

ECi is the energy content factor of fuel type (i) as obtained under subsection 2.42 (1) and expressed in gigajoules per kilolitre.

Ci is the density of the fuel expressed in kilograms of fuel per thousand litres.

Subdivision 2.4.3.2     Sampling and analysis

2.44        General requirements for sampling under method 2

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

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

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

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

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

2.45        Standards for analysing samples of liquid fuels

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

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

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

                (c)    density analysis — column 5 for that item.

 

Item

Fuel

Energy Content

Carbon

Density

1

Petroleum based oils (other than petroleum based oils used as fuel)

N/A

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005)

2

Petroleum based greases

N/A

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005)

3

Crude oil including crude oil condensates

ASTM D 240‑02 (2007)

ASTM D 4809‑06

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005)

4

Other natural gas liquids

N/A

N/A

ASTM D 1298 – 99 (2005)

5

Gasoline (other than for use as fuel in an aircraft)

ASTM D 240‑02 (2007)

ASTM D 4809‑06

N/A

ASTM D 1298 – 99 (2005)

6

Gasoline for use as fuel in an aircraft

ASTM D 240‑02 (2007)

ASTM D 4809‑06

N/A

ASTM D 1298 – 99 (2005)

7

Kerosene (other than for use as fuel in an aircraft)

ASTM D 240‑02 (2007)

ASTM D 4809‑06

N/A

ASTM D 1298 – 99 (2005)

8

Kerosene for use as fuel in an aircraft

ASTM D 240‑02 (2007)

ASTM D 4809‑06

N/A

ASTM D 1298 – 99 (2005)

9

Heating oil

ASTM D 240‑02 (2007)

ASTM D 4809‑06

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005)

10

Diesel oil

ASTM D 240‑02 (2007)

ASTM D 4809‑06

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005)

11

Fuel oil

ASTM D 240‑02 (2007)

ASTM D 4809‑06

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005)

12

Liquefied aromatic hydrocarbons

N/A

N/A

ASTM D 1298 – 99 (2005)

13

Solvents if mineral turpentine or white spirits

N/A

N/A

N/A

14

Liquefied Petroleum Gas

N/A

ISO 7941:1988

ISO 6578:1991

ISO 8973:1997

15

Naphtha

N/A

N/A

N/A

16

Petroleum coke

N/A

N/A

N/A

17

Refinery gas and liquids

N/A

N/A

N/A

18

Refinery coke

N/A

N/A

N/A

19

Petroleum based products other than:

   (a)  petroleum based oils and petroleum based greases mentioned in items 1and 2

   (b)  the petroleum based products mentioned in items 3 to 18

N/A

N/A

N/A

20

Biodiesel

N/A

N/A

N/A

21

Ethanol for use as a fuel in an internal combustion engine

N/A

N/A

N/A

22

Biofuels other than those mentioned in items 20 and 21

N/A

N/A

N/A

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

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

2.46        Frequency of analysis

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

 

Item

Fuel

Parameter

Frequency

1

All types of liquid fuel

Carbon

Quarterly or by delivery of the fuel

2

All types of liquid fuel

Energy

Quarterly or by delivery of the fuel

Division 2.4.4        Method 3 — emissions of carbon dioxide released from the combustion of liquid fuels

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

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

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

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

 

item

Liquid Fuel

Standard

1

Petroleum based oils (other than petroleum based oils used as fuel)

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

2

Petroleum based greases

 

3

Crude oil including crude oil condensates

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

4

Other natural gas liquids

ASTM D1265 ‑ 05

5

Gasoline (other than for use as fuel in an aircraft)

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

6

Gasoline for use as fuel in an aircraft

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

7

Kerosene (other than for use as fuel in an aircraft)

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

8

Kerosene for use as fuel in an aircraft

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

9

Heating oil

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

10

Diesel oil

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

11

Fuel oil

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

12

Liquefied aromatic hydrocarbons

ASTM D 4057 – 06

13

Solvents if mineral turpentine or white spirits

ASTM D 4057 – 06

14

Liquefied Petroleum Gas

ASTM D1265 ‑ 05)

ISO 4257:2001

15

Naphtha

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

16

Petroleum coke

ASTM D 4057 – 06

17

Refinery gas and liquids

ASTM D 4057 – 06

18

Refinery coke

ASTM D 4057 – 06

19

Petroleum based products other than:

   (a)  petroleum based oils and petroleum based greases mentioned in items 1 and 2; and

   (b)  the petroleum based products mentioned in items 3 to 18

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

20

Biodiesel

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

21

Ethanol for use as a fuel in an internal combustion engine

ASTM D 4057 – 06

22

Biofuels other than those mentioned in items 20 and 21

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

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

Division 2.4.5        Method 2 — emissions of methane and nitrous oxide from the combustion of liquid fuels

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

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

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

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

               (b)    for combustion of fuel by trucks that meet the design standards mentioned in column 2 of the table in Division 4.3 of Part 4 of Schedule 1 — column 4 of the table in that Division.

Division 2.4.6        Measurement of quantity of liquid fuels

2.49        Purpose of Division

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

2.50        Criteria for measurement

                For the purposes of calculating the combustion of a liquid fuel from the operation of a facility for a year and, in particular, for Qi in sections 2.41 and 2.42 the combustion must be estimated using one of the following criteria:

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

               (b)    as provided in section 2.51 (criterion AA);

                (c)    as provided in section 2.52 (criterion AAA);

               (d)    as provided in section 2.53 (criterion BBB).

2.51        Indirect measurement at point of consumption — criterion AA

                For paragraph 2.50 (b), criterion AA is the amount of the liquid fuel combusted from the operation of the facility during the year based on amounts delivered during the year (evidenced by invoices) as adjusted for the estimated change in the quantity of the stockpile of the fuel for the facility during the year.

2.52        Direct measurement at point of consumption — criterion AAA

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

         (2)   The measurement must be carried out:

                (a)    at the point of combustion at ambient temperatures and converted to standard temperatures, using measuring equipment calibrated to a measurement requirement; or

               (b)    at ambient temperatures and converted to standard temperatures, at the point of sale of the liquid fuel, using measuring equipment calibrated to a measurement requirement.

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

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

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

2.53        Simplified consumption measurements — criterion BBB

                For paragraph 2.50 (d), criterion BBB is the estimation of the combustion of a liquid fuel for the year using accepted industry measuring devices or, in the absence of such measuring devices, in accordance with industry practice if:

                (a)    the acquisition of the fuel does not involve a commercial transaction; and

               (b)    the equipment used to measure consumption of the fuel is not calibrated to a measurement requirement.

Part 2.5              Emissions released from fuel use by certain industries

  

2.54        Application

                This Part applies to UNFCCC Categories 1A.1.b, 1A.1.c and 1A.2.c — petroleum refining, solid fuel transformation (coke ovens) and petrochemical production.

Division 2.5.1        Energy — petroleum refining

2.55        Application

                This Division applies to UNFCCC Category 1A.1.b — petroleum refining.

2.56        Methods

         (1)   If:

                (a)    the operation of a facility is constituted by petroleum refining; and

               (b)    the refinery combusts fuels for energy;

then the methods for estimating emissions during a year from that combustion are as provided in Parts 2.2, 2.3 and 2.4.

         (2)   The method for estimating emissions from the production of hydrogen by the petroleum refinery must be in accordance with the method set out in section 5 of the API Compendium.

         (3)   Fugitive emissions released from the petroleum refinery must be estimated using methods provided for in Chapter 3.

Division 2.5.2        Energy — manufacture of solid fuels (coke ovens)

2.57        Application

                This Division applies to UNFCCC Category 1A.1.c — solid fuel transformation (coke ovens).

2.58        Methods

         (1)   If:

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

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

then the methods for estimating emissions during a year from that combustion are provided in Part 4.3.

         (2)   These emissions are to be reported under this UNFCCC Category.

Division 2.5.3        Energy — petrochemical production

2.59        Application

                This Division applies to Source UNFCCC Category 1A.2.c — petrochemical production (where fuel is consumed as a feedstock).

2.60        Available methods

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

                (a)    method 1 under section 2.61;

               (b)    method 2 under section 2.62;

                (c)    method 3 under section 2.63;

               (d)    method 4 under Part 1.3.

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

2.61        Method 1 — petrochemical production

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

 

Step 1

Calculate the carbon content in all fuel types (i) delivered for the activity during the year as follows:

where:

Si means sum the carbon content values obtained for all fuel types (i).

CCFi is the carbon content factor measured in tonnes of carbon for each tonne of fuel type (i) as mentioned in Schedule 3 consumed in the operation of the activity.

Qi is the quantity of fuel type (i) delivered for the activity during the year measured in tonnes and estimated in accordance with criterion A in Divisions 2.2.5, 2.3.6 and 2.4.6.

Step 2

Calculate the carbon content in products (p) leaving the activity during the year as follows:

where:

Sp means sum the carbon content values obtained for all product types (p).

CCFp is the carbon content factor measured in tonnes of carbon for each tonne of product (p).

Ap is the quantity of products produced (p) leaving the activity during the year measured in tonnes.

Step3

Calculate the carbon content in waste by‑products (r) leaving the activity, other than as an emission of greenhouse gas, during the year as follows:

where:

Sr means sum the carbon content values obtained for all waste by‑product types (r).

CCFr is the carbon content factor measured in tonnes of carbon for each tonne of waste by‑product (r).

Yr is the quantity of waste by‑product (r) leaving the activity during the year measured in tonnes.

Step 4

Calculate the carbon content in the amount of the increase in stocks of inputs, products and waste by‑products held within the boundary of the activity during the year as follows:

where:

Si has the same meaning as in step 1.

CCFi has the same meaning as in step 1.

ΔSqi is the increase in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year measured in tonnes.

Sp has the same meaning as in step 2.

CCFp has the same meaning as in step 2.

ΔSap is the increase in stocks of products produced (p) by the activity and held within the boundary of the activity during the year measured in tonnes.

 

Sr has the same meaning as in step 3.

CCFr has the same meaning as in step 3.

ΔSyr is the increase in stocks of waste by‑products (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes.

Step 5

Calculate the emissions of carbon dioxide released from the activity during the year measured in CO2‑e tonnes as follows:

   (a)  add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A)

   (b)  subtract amount A from the amount worked out under step 1 to work out a new amount (amount B);

   (c)  multiply amount B by 3.664 to work out the amount of emissions released from the activity during a year.

2.62        Method 2 — petrochemical production

         (1)   Method 2 is the same as method 1 but sampling and analysis of fuel types (i) is used to determine carbon content of the fuel.

         (2)   The sampling and analysis is to be carried out using the methods set out in Divisions 2.2.3, 2.3.3 and 2.4.3 that apply to the combustion of solid, liquid or gaseous fuels.

2.63        Method 3— petrochemical production

         (1)   Method 3 is the same as method 1 but the sampling and analysis of fuel types (i) is used to determine carbon content of the fuel.

         (2)   The sampling and analysis is to be carried out using the methods set out in Divisions 2.2.4, 2.3.4 and 2.4.4 that apply to the combustion of solid, liquid or gaseous fuels.

Part 2.6              Blended fuels

  

2.64        Purpose

                This Part sets out how to determine the amounts of each kind of fuel that is in a blended fuel.

2.65        Application

                This Part sets out how to determine the amount of each fuel type (i) that is in a blended fuel if that blended fuel is a solid fuel or a liquid fuel.

2.66        Blended solid fuels

         (1)   In determining the amounts of each kind of fuel that is in a blended solid fuel, a person may adopt the outcome of the sampling and analysis done by the manufacturer of the fuel if:

                (a)    the sampling has been done in accordance with subsections 2.12 (3) and (4); and

               (b)    the analysis has been done in accordance with one of the following standards or a standard that is equivalent to one of those standards:

                          (i)    CEN/TS15440:2006;

                         (ii)    ASTM D 6866‑06a.

         (2)   The person may use his or her own sampling and analysis of the fuel if the sampling and analysis complies with the requirements of paragraphs (1) (a) and (b).

2.67        Blended liquid fuels

                The person may adopt the manufacturer’s determination of each kind of fuel that is in a blended liquid fuel or adopt the analysis arrived at after doing both of the following:

                (a)    sampling the fuel in accordance with a standard mentioned in subsections 2.47 (3) and (4);

               (b)    analysing the fuel in accordance with ASTM: D6866‑06a or a standard that is equivalent to that standard.

Part 2.7              Estimation of energy for certain purposes

  

2.68        Amount of fuel consumed without combustion

                For paragraph 4.22 (1) (b) of the Regulations:

                (a)    the energy is to be measured :

                          (i)    for solid fuel — in tonnes estimated under Division 2.2.5; or

                         (ii)    for gaseous fuel — in cubic metres estimated under Division 2.3.6; or

                         (iii)    for liquid fuel — in kilolitres estimated under Division 2.4.6; and

               (b)    the reporting threshold is:

                          (i)    for solid fuel —20 tonnes; or

                         (ii)    for gaseous fuel —13 000 cubic metres; or

                         (iii)    for liquid fuel —15 kilolitres.

Example

A fuel is consumed without combustion when it is used as a solvent or a flocculent, or as an ingredient in the manufacture of products such as paints, solvents or explosives.

2.69        Apportionment of fuel consumed as carbon reductant or feedstock and energy

         (1)   This section applies, other than for Division 2.5.3, if:

                (a)    a fuel type as provided for in a method is consumed from the operation of a facility as either a reductant or a feedstock; and

               (b)    the fuel is combusted for energy; and

                (c)    the equipment used to measure the amount of the fuel for the relevant purpose was not calibrated to a measurement requirement.

Note   Division 2.5.3 deals with petrochemicals. For petrochemicals, all fuels, whether used as a feedstock, a reductant or combusted as energy are reported as energy.

         (2)   The amount of the fuel type consumed as a reductant or a feedstock may be estimated:

                (a)    in accordance with industry measuring devices or industry practice; or

               (b)    if it is not practicable to estimate as provided for in paragraph (a) — to be the whole of the amount of the consumption of that fuel type from the operation of the facility.

         (3)   The amount of the fuel type combusted for energy may be estimated as the difference between the total amount of the fuel type consumed from the operation of the facility and the estimated amount worked out under subsection (2).

2.70        Amount of energy consumed in a cogeneration process

         (1)   For subregulation 4.23 (3) of the Regulations and subject to subsection (3), the method is the efficiency method.

         (2)   The efficiency method is as described in the publication entitled Allocation of Emissions from a Combined Heat and Power (CHP) Plant Guide to calculation worksheets (September 2006) v1.0 issued by the World Resource Institute and World Business Council for Sustainable Development.

         (3)   Where heat is to be used mainly for producing mechanical work, the work potential method may be used.

         (4)   The work potential method is as described in the publication entitled Allocation of Emissions from a Combined Heat and Power (CHP) Plant Guide to calculation worksheets (September 2006) v1.0 issued by the World Resource Institute and World Business Council for Sustainable Development.

2.71        Apportionment of energy consumed for electricity, transport and for stationary energy

                Subject to section 2.70, the amount of fuel type (i) consumed by a reporting corporation that is apportioned between electricity generation, transport (excluding international bunker fuels) and other stationary energy purposes may be determined using the corporation’s records if the records are based on the measurement equipment used by the corporation to measure consumption of the fuel types.

Chapter 3    Fugitive emissions from fuels (UNFCCC Category 1.B)

Part 3.1              Preliminary

  

3.1           Outline of Chapter

                This Chapter provides for UNFCCC Category 1.B — fugitive emissions from fuels, as follows:

                (a)    Part 3.2 provides for fugitive emissions from coal mining — UNFCCC Category 1.B.1;

               (b)    Part 3.3 provides for fugitive emissions from oil and natural gas activities — UNFCCC Category 1.B.2.

Note   The above UNFCCC categories include emissions from flaring and other combustion of fuels for a purpose other than producing energy.

Part 3.2              Coal mining

Division 3.2.1        Preliminary

3.2           Outline of Part

                This Part provides for UNFCCC Category 1.B.1 — fugitive emissions from coal mining, as follows:

                (a)    UNFCCC Category 1.B.1.a.i — underground mining activities (see Division 3.2.2);

               (b)    UNFCCC Category 1.B.1.a.ii — open cut mining activities (see Division 3.2.3);

                (c)    UNFCCC Category 1.B.1.c — decommissioned underground mines (see Division 3.2.4).

Division 3.2.2        Underground mines

Subdivision 3.2.2.1     Preliminary

3.3           Application

                This Division applies to UNFCCC Category 1.B.1.a.i — fugitive emissions from underground mining activities (other than decommissioned underground mines).

3.4           Available methods

         (1)   Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by underground mining activities (other than decommissioned underground mines) the methods as set out in this section must be used.

Methane from extraction of coal

         (2)   One of the following methods must be used for estimating fugitive emissions of methane that result from the extraction of coal from the underground mine:

                (a)    subject to subsection (8), method 1 under section 3.5;

               (b)    method 4 under section 3.6.

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

Carbon dioxide from extraction of coal

         (3)   If method 4 under section 3.6 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the underground mine.

Note   There is no method 1, 2 or 3 for subsection (3).

Flaring

         (4)   For estimating emissions released from coal mine waste gas flared from the underground mine:

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

                          (i)    method 1 under section 3.14;

                         (ii)    method 2 under section 3.15;

                         (iii)    method 3 under section 3.16; and

               (b)    method 1 under section 3.14 must be used for estimating emissions of methane released;

                (c)    method 1 under section 3.14 must be used for estimating emissions of nitrous oxide released.

Note   The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 under section 3.14 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 2, 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.

Venting or other fugitive release before extraction of coal

         (5)   Method 4 under Part 1.3 must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, that result from venting or other fugitive release of gas from the underground mine before coal is extracted from the mine.

Note   There is no method 1, 2 or 3 for subsection (5).

Post‑mining activities

         (6)   Method 1 under section 3.17 must be used for estimating fugitive emissions of methane that result from post‑mining activities related to a gassy mine.

Note   There is no method 2, 3 or 4 for subsection (6).

         (7)   However, for incidental emission source streams, another method may be used that is consistent with the principles in section 1.13.

         (8)   If coal mine waste gas from the mine is captured for combustion during the year, method 1 in subsection (2) must not be used.

Subdivision 3.2.2.2     Fugitive emissions from extraction of coal

3.5           Method 1 — extraction of coal

                For paragraph 3.4 (2) (a), method 1 is:

where:

Ej is the fugitive emissions of methane (j) that result from the extraction of coal from the mine during the year measured in CO2‑e tonnes.

Q is the quantity of run‑of‑mine coal extracted from the mine during the year measured in tonnes.

EFj is the emission factor for methane (j), measured in CO2‑e tonnes per tonne of run‑of‑mine coal extracted from the mine, as follows:

                (a)    for a gassy mine — 0.305;

               (b)    for a non‑gassy mine — 0.008.

3.6           Method 4 — extraction of coal

         (1)   For paragraph 3.4 (2) (b) and subsection 3.4 (3), method 4 is:

where:

Ej is the fugitive emissions of gas type (j) that result from the extraction of coal from the mine during the year, measured in CO2‑e tonnes.

CO2‑e j gen, total is the total mass of gas type (j) generated from the mine during the year before capture and flaring is undertaken at the mine, measured in CO2‑e tonnes and estimated using the direct measurement of emissions in accordance with subsection (2).

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes, being:

                (a)    for methane — 6.784 × 10‑4 × 21; and

               (b)    for carbon dioxide — 1.861 × 10‑3.

Qij,cap is the quantity of gas type (j) in coal mine waste gas type (i) captured for combustion from the mine and used during the year, measured in cubic metres and estimated in accordance with Division 2.3.6.

Qij,flared is the quantity of gas type (j) in coal mine waste gas type (i) flared from the mine during the year, measured in cubic metres and estimated in accordance with Division 2.3.6.

Qijtr is the quantity of gas type (j) in coal mine waste gas type (i) transferred out of the mining activities during the year measured in cubic metres.

         (2)   The direct measurement of emissions released from the extraction of coal from an underground mine during a year by monitoring the gas stream at the underground mine may be undertaken by one of the following:

                (a)    continuous emissions monitoring (CEM) in accordance with Part 1.3;

               (b)    periodic emissions monitoring (PEM) in accordance with sections 3.7 to 3.12.

         (3)   For Qijtr in subsection (1), the quantity of gas type (j) must be estimated in accordance with Division 2.3.6 as if a reference in that Division to quantities of gaseous fuels combusted from the operation of a facility was a reference to quantities of gaseous fuels transferred out of the operation of a facility.

3.7           Estimation of emissions

         (1)   To obtain an estimate of the mass emissions rate of gas (j), being methane and carbon dioxide, at the time of measurement at the underground mine, the formula in subsection 1.21 (1) must be applied.

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

         (3)   The average mass emission rate for gas type (j) measured in CO2–e tonnes per hour for a year must be calculated from the estimates obtained under subsections (1) and (2).

         (4)   The total mass of emissions of gas type (j) from the underground mine for the year is calculated by multiplying the average emissions rate obtained under subsection (3) by the number of hours during the year.

3.8           Overview — use of equipment

                The following requirements apply to the use of PEM equipment:

                (a)    the requirements in section 3.9 about location of the sampling positions for the PEM equipment;

               (b)    the requirements in section 3.10 about measurement of volumetric flow rates in a gas stream;

                (c)    the requirements in section 3.11 about measurement of the concentrations of gas type (j) in the gas stream;

               (d)    the requirements in section 3.12 about representative data.

                (e)    the requirements in section 3.13 about performance characteristics of equipment.

3.9           Selection of sampling positions for PEM

                For paragraph 3.8 (a), an appropriate standard or applicable State or Territory legislation must be complied with for the location of sampling positions for PEM equipment.

Note   Appropriate standards include:

·      AS 4323.1—1995/Amdt 1‑1995, Stationary source emissions — Selection of sampling positions

·      USEPA Method 1 — Sample and velocity traverses for stationary sources (2000)

3.10        Measurement of volumetric flow rates by PEM

                For paragraph 3.8 (b), the measurement of the volumetric flow rates by PEM of the gas stream must be undertaken in accordance with an appropriate standard or applicable State or Territory legislation.

Note   Appropriate standards include:

·      ISO 14164:1999 Stationary source emissions. Determination of the volume flowrate of gas streams in ducts ‑ automated method

·      ISO 10780:1994 Stationary source emissions. Measurement of velocity and volume flowrate of gas streams in ducts

·      USEPA Method 2 — Determination of stack gas velocity and volumetric flow rate (Type S Pitot tube) (2000)

·      USEPA Method 2A — Direct measurement of gas volume through pipes and small ducts (2000).

3.11        Measurement of concentrations by PEM

                For paragraph 3.8 (c), the measurement of the concentrations of gas type (j) in the gas stream by PEM must be undertaken in accordance with an appropriate standard or applicable State or Territory legislation.

Note   Appropriate standards include USEPA — Method 3C — Determination of carbon dioxide, methane, nitrogen and oxygen from stationary sources (1996).

3.12        Representative data for PEM

         (1)   For paragraph 3.8 (d), sampling by PEM must be undertaken during the year for a sufficient duration to produce representative data that may be reliably extrapolated to provide estimates of emissions across the full range of operating conditions for that year.

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

3.13        Performance characteristics of equipment

                For paragraph 3.8 (e), the performance characteristics of PEM equipment must be measured in accordance with section 1.34.

Subdivision 3.2.2.3     Emissions released from coal mine waste gas flared

3.14        Method 1 — coal mine waste gas flared

                For subparagraph 3.4 (4) (a) (i) and paragraphs 3.4 (4) (b) and (c), method 1 is:

where:

E(fl)ij is the emissions of gas type (j) released from coal mine waste gas (i) flared from the mine during the year, measured in CO2‑e tonnes.

Qi,flared is the quantity of coal mine waste gas (i) flared from the mine during the year, measured in cubic metres and estimated under Division 2.3.6.

ECi is the energy content factor of coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in gigajoules per cubic metre.

EFij is the emission factor for gas type (j) and coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in CO2‑e tonnes per gigajoule.

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

3.15        Method 2 — coal mine waste gas flared

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

         (2)   In applying method 1 under section 3.14, the facility specific emission factor (EFij) must be determined in accordance with the procedure for determining EFi CO2ox,ec in Division 2.3.3.

3.16        Method 3 — coal mine waste gas flared

         (1)   For subparagraph 3.4 (4) (a) (iii), method 3 is the same as method 1 under section 3.14.

         (2)   In applying method 1 under section 3.14, the facility specific emission factor EFij must be determined in accordance with the procedure for determining EFi CO2ox,ec in Division 2.3.4.

Subdivision 3.2.2.4     Fugitive emissions from post‑mining activities

3.17        Method 1 — post‑mining activities related to gassy mines

         (1)   For subsection 3.4 (6), method 1 is the same as method 1 under section 3.5.

         (2)   In applying method 1 under section 3.5, EFj is taken to be 0.014, which is the emission factor for methane (j), measured in CO2‑e tonnes per tonne of run‑of‑mine coal extracted from the mine.

Division 3.2.3        Open cut mines

Subdivision 3.2.3.1     Preliminary

3.18        Application

                This Division applies to UNFCCC Category 1.B.1.a.ii — fugitive emissions from open cut mining activities.

3.19        Available methods

         (1)   Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by an open cut mine the methods as set out in this section must be used.

Methane from extraction of coal

         (2)   Subject to subsection (7), one of the following methods must be used for estimating fugitive emissions of methane that result from the extraction of coal from the mine:

                (a)    method 1 under section 3.20;

               (b)    method 2 under section 3.21;

                (c)    method 3 under section 3.26.

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

Carbon dioxide from extraction of coal

         (3)   If method 2 under section 3.21 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the open cut mine.

         (4)   If method 3 under section 3.26 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the open cut mine.

Note   There is no method 1 or 4 for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from an open cut mine.

Flaring

         (5)   For estimating emissions released from coal mine waste gas flared from the open cut mine:

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

                          (i)    method 1 under section 3.27;

                         (ii)    method 2 under section 3.28;

                         (iii)    method 3 under section 3.29; and

               (b)    method 1 under section 3.27 must be used for estimating emissions of methane released; and

                (c)    method 1 under section 3.27 must be used for estimating emissions of nitrous oxide released.

Note   The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 2, 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.

Venting or other fugitive release before extraction of coal

         (6)   Method 4 under Part 1.3 must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, that result from venting or other fugitive release of gas from the mine before coal is extracted from the mine.

Note   There is no method 1, 2 or 3 for subsection (6).

         (7)   However, for incidental emission source streams another method may be used that is consistent with the principles in section 1.13.

Subdivision 3.2.3.2     Fugitive emissions from extraction of coal

3.20        Method 1 — extraction of coal

                For paragraph 3.19 (2) (a), method 1 is:

where:

Ej is the fugitive emissions of methane (j) that result from the extraction of coal from the mine during the year measured in CO2‑e tonnes.

Q is the quantity of run‑of‑mine coal extracted from the mine during the year measured in tonnes.

EFj is the emission factor for methane (j), measured in CO2‑e tonnes per tonne of run‑of‑mine coal extracted from the mine, taken to be the following:

                (a)    for a mine in New South Wales — 0.045;

               (b)    for a mine in Victoria — 0.0007;

                (c)    for a mine in Queensland — 0.017;

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

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

                (f)    for a mine in Tasmania — 0.014.

3.21        Method 2 — extraction of coal

         (1)   For paragraph 3.19 (2) (b) and subsection 3.19 (3), method 2 is:

where:

Ej is the fugitive emissions of gas type (j) that result from the extraction of coal from the mine during the year, measured in CO2‑e tonnes.

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes, as follows:

                (a)    for methane — 6.784 × 10‑4 × 21;

               (b)    for carbon dioxide — 1.861 × 10‑3.

z (Sj,z) is the total of gas type (j) in all gas bearing strata (z) under the extraction area of the mine during the year, measured in cubic metres, where the gas in each strata is estimated under section 3.22.

         (2)   Method 2 requires each gas in a gas bearing strata to be sampled and analysed in accordance with the requirements in sections 3.24 and 3.25.

3.22        Total gas contained by gas bearing strata

         (1)   For method 2 under subsection 3.21 (1), Sj,z for gas type (j) contained in a gas bearing strata (z) under the extraction area of the mine during the year, measured in cubic metres, is:

where:

Mz is the mass of the gas bearing strata (z) under the extraction area of the mine during the year, measured in tonnes.

β is the proportion of the gas content of the gas bearing strata (z) that is released by extracting coal from the extraction area of the mine during the year, as follows:

(a)    if the gas bearing strata is at or above the pit floor — 1;

(b)    in any other case — as estimated under section 3.23.

GCjz is the content of gas type (j) contained by the gas bearing strata (z) before gas capture, flaring or venting is undertaken at the extraction area of the mine during the year, measured in cubic metres per tonne of gas bearing strata at standard conditions.

Qij,cap,z is the total quantity of gas type (j) in coal mine waste gas (i) captured for combustion from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres.

∑Qij,flared,z is the total quantity of gas type (j) in coal mine waste gas (i) flared from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres.

∑Qijtr is the total quantity of gas type (j) in coal mine waste gas (i) transferred out of the mining activities at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres.

∑Ej,vented,z is the total emissions of gas type (j) vented from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres and estimated under subsection 3.19 (6).

         (2)   For ∑Qij,cap,z, ∑Qij,flared,z and ∑Qijtr in subsection (1), the quantity of gas type (j) must be estimated in accordance with Division 2.3.6 as if a reference in that Division to quantities of gaseous fuels combusted from the operation of a facility was a reference to the following:

                (a)    for ∑Qij,cap,z — quantities of gaseous fuels captured from the operation of a facility;

               (b)    for tQij,flared,z — quantities of gaseous fuels flared from the operation of a facility;

                (c)    for ∑Qijtr — quantities of gaseous fuels transferred out of the operation of a facility.

3.23        Estimate of proportion of gas content released below pit floor

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

where:

x is the depth in metres of the floor of the gas bearing strata (z) measured from ground level.

h is the depth in metres of the pit floor of the mine measured from ground level.

dh is 20, being representative of the depth in metres of the gas bearing strata below the pit floor that releases gas.

3.24        General requirements for sampling

         (1)   Core samples of a gas bearing strata must be collected to produce estimates of gas content that are representative of the gas bearing strata in the extraction area of the mine during the year.

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

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

         (4)   The value obtained from the samples must only be used for the open cut mine from which it was intended to be representative.

3.25        General requirements for analysis of gas and gas bearing strata

                Analysis of a gas and a gas bearing strata, including the mass and gas content of the strata, must be done in accordance with an appropriate standard.

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

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

3.26        Method 3 — extraction of coal

         (1)   For paragraph 3.19 (2) (c) and subsection 3.19 (4), method 3 is the same as method 2 under section 3.21

         (2)   In applying method 2 under section 3.21 a sample of gas bearing strata must be collected in accordance with an appropriate standard, including:

                (a)    AS 2617—1996 Sampling from coal seams or an equivalent standard; and

               (b)    AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits or an equivalent standard.

Subdivision 3.2.3.3     Emissions released from coal mine waste gas flared

3.27        Method 1 — coal mine waste gas flared

         (1)   For subparagraph 3.19 (5) (a) (i) and paragraph 3.19 (5) (b) and paragraph (5) (c), method 1 is the same as method 1 under section 3.14.

         (2)   In applying method 1 under section 3.14, a reference to an underground mine is taken to be a reference to an open cut mine.

3.28        Method 2 — coal mine waste gas flared

                For subparagraph 3.19 (5) (a) (ii), method 2 is the same as method 2 under section 3.15.

3.29        Method 3 — coal mine waste gas flared

                For subparagraph 3.19 (5) (a) (iii), method 3 is the same as method 3 under section 3.16.

Division 3.2.4        Decommissioned underground mines

Subdivision 3.2.4.1     Preliminary

3.30        Application

                This Division applies to UNFCCC Category 1.B.1.c — fugitive emissions from decommissioned underground mines that have been closed for a continuous period of at least 1 year but less than 20 years.

3.31        Available methods

         (1)   Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by a decommissioned underground mine that has been closed for a continuous period of at least 1 year but less than 20 years the methods as set out in this section must be used.

Methane from decommissioned mines

         (2)   One of the following methods must be used for estimating fugitive emissions of methane that result from the mine:

                (a)    subject to subsection (6), method 1 under section 3.32;

               (b)    method 4 under section 3.37.

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

Carbon dioxide from decommissioned mines

         (3)   If method 4 under section 3.37 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the mine.

Note   There is no method 1, 2 or 3 for subsection (3).

Flaring

         (4)   For estimating emissions released from coal mine waste gas flared from the mine:

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

                          (i)    method 1 under section 3.38;

                         (ii)    method 2 under section 3.39;

                         (iii)    method 3 under section 3.40; and

               (b)    method 1 under section 3.38 must be used for estimating emissions of methane released.

                (c)    method 1 under section 3.38 must be used for estimating emissions of nitrous oxide released.

Note   The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 2, 3 or 4 for emissions of methane and no method 2, 3 or 4 for nitrous oxide.

         (5)   However, for incidental emission source streams another method may be used that is consistent with the principles in section 1.13.

         (6)   If coal mine waste gas from the decommissioned underground mine is captured for combustion during the year, method 1 in subsection (2) must not be used.

Subdivision 3.2.4.2     Fugitive emissions from decommissioned underground mines

3.32        Method 1 — decommissioned underground mines

         (1)   For paragraph 3.31 (2) (a), method 1 is:

where:

Edm is the fugitive emissions of methane from the mine during the year measured in CO2‑e tonnes.

Etdm is the emissions from the mine for the last full year that the mine was in operation measured in CO2‑e tonnes and estimated under section 3.5 or 3.6.

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

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

         (2)   However, if, under subsection (1), the estimated emissions in CO2‑e tonnes for the mine during the year is less than 0.02 ´ Etdm, the estimated emissions for the mine during the year is taken to be 0.02 ´ Etdm.

3.33        Emission factor for decommissioned underground mines

                For section 3.32, EFdm is the integral under the curve of:

for the period between T and T‑1,

where:

A is:

                (a)    for a gassy mine — 0.23; or

               (b)    for a non‑gassy mine — 0.35.

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

b is:

                (a)    for a gassy mine — ‑1.45; or

               (b)    for a non‑gassy mine — ‑1.01.

C is:

                (a)    for a gassy mine — 0.024; or

               (b)    for a non‑gassy mine — 0.088.

3.34        Measurement of proportion of mine that is flooded

                For section 3.32, Fdm is:

where:

MWI is the rate of water flow into the mine in cubic metres per year as measured under section 3.35.

MVV is the mine void volume in cubic metres as measured under section 3.36.

3.35        Water flow into mine

                For MWI in section 3.34, the rate of water flow into the mine must be measured by:

                (a)    using water flow rates for the mine estimated in accordance with an appropriate standard; or

               (b)    using the following average water flow rates:

                          (i)    for a mine in the southern coalfield of New South Wales — 913 000 cubic metres per year; or

                         (ii)    for a mine in the Newcastle, Hunter, Western or Gunnedah coalfields in New South Wales — 450 000 cubic metres per year; or

                         (iii)    for a mine in Queensland — 74 000 cubic metres per year.

Note   An appropriate standard includes AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits.

3.36        Size of mine void volume

                For MVV in section 3.34, the size of the mine void volume must be measured by:

                (a)    using mine void volumes for the mine estimated in accordance with industry practice; or

               (b)    dividing the total amount of run‑of‑mine coal extracted from the mine before the mine was decommissioned by 1.425.

3.37        Method 4 — decommissioned underground mines

         (1)   For paragraph 3.31 (2) (b) and subsection 3.31 (3), method 4 is the same as method 4 in section 3.6.

         (2)   In applying method 4 under section 3.6, a reference to an underground mine is taken to be a reference to a decommissioned underground mine.

Subdivision 3.2.4.3     Fugitive emissions from coal mine waste gas flared

3.38        Method 1 — coal mine waste gas flared

         (1)   For subparagraph 3.31 (4) (a) (i) and paragraphs 3.31 (4) (b) and (4) (c), method 1 is the same as method 1 under section 3.14.

         (2)   In applying method 1 under section 3.14, a reference to an underground mine is taken to be a reference to a decommissioned underground mine.

3.39        Method 2 — coal mine waste gas flared

                For subparagraph 3.31 (4) (a) (ii), method 2 is the same as method 2 under section 3.15.

3.40        Method 3 — coal mine waste gas flared

                For subparagraph 3.31 (4) (a) (iii), method 3 is the same as method 3 under section 3.16.

Part 3.3              Oil and natural gas — fugitive emissions

Division 3.3.1        Preliminary

3.41        Outline of Part

                This Part provides for UNFCCC Category 1.B.2 — fugitive emissions as follows:

                (a)    UNFCCC Category 1.B.2.a.i — oil exploration (see Division 3.3.2);

               (b)    UNFCCC Category 1.B.2.b.i — gas exploration (see Division 3.3.2);

                (c)    UNFCCC Category 1.B.2.a.ii — crude oil production (see Division 3.3.3);

               (d)    UNFCCC Category 1.B.2.a.iii — crude oil transport (see Division 3.3.4);

                (e)    UNFCCC Category 1.B.2.a.iv — crude oil refining (see Division 3.3.5);

                (f)    UNFCCC Category 1.B.2.b.ii — natural gas production and processing other than emissions that are vented or flared (see Division 3.3.6);

                (g)    UNFCCC Category 1.B.2.b.iii — natural gas transmission (see Division 3.3.7);

                (h)    UNFCCC Category 1.B.2.b.iv — natural gas distribution (see Division 3.3.8);

                 (i)    UNFCCC Category 1.B.2.c. — natural gas production and processing (emissions that are vented or flared) (see Division 3.3.9).

Division 3.3.2        Oil and gas exploration

3.42        Application

                This Division applies to fugitive emissions from oil and gas exploration, UNFCCC Category 1.B.2a.i (oil) and UNFCCC Category 1.B.2.b.i (gas).

3.43        Available methods

         (1)   Subject to section 1.18, for estimating emissions released by oil or gas flaring during a year from the operation of a facility that is constituted by crude oil production:

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

                          (i)    method 1 under section 3.44;

                         (ii)    method 2 under section 3.45;

                         (iii)    method 3 under section 3.46; and

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

                          (i)    method 1 under section 3.44;

                         (ii)    method 2 under section 3.45; and

                (c)    if estimating emissions of nitrous oxide released — method 1 under section 3.44 must be used.

Note   There is no method 4 under paragraph (a), no methods 3 or 4 under paragraph (b) and no methods 2, 3 or 4 under paragraph (c).

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

3.44        Method 1 — oil and gas exploration

         (1)   Method 1 is:

where:

Eij is the fugitive emissions of gas type (j) from a fuel type (i) flared in the oil and gas exploration during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) flared in the oil and gas exploration during the year measured in tonnes.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of the fuel type (i) flared.

         (2)   For EFij in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor, for gas type (j), for each fuel type (i) specified in column 2 of that item.

 

Item

Fuel type (i)

Emission factor for gas type (j) (tonnes CO2‑e/tonnes of fuel flared)

 

CO2

CH4

N2O

1

Unprocessed gas flared

2.8

0.7

0.03

2

Crude oil

3.2

0.007

0.07

3.45        Method 2 — oil and gas exploration

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

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

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

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

3.46        Method 3 — oil and gas exploration

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

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

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

Division 3.3.3        Crude oil production

Subdivision 3.3.3.1     Preliminary

3.47        Application

                This Division applies to UNFCCC Category 1.B.2.a.ii — fugitive emissions from crude oil production.

Subdivision 3.3.3.2     Crude oil production (non‑flared) — fugitive emissions of methane

3.48        Available methods

         (1)   Subject to section 1.18, for estimating fugitive emissions of methane, other than from oil or gas flaring, during a year from the operation of a facility that is constituted by crude oil production, one of the following methods must be used:

                (a)    method 1 under section 3.49;

               (b)    method 2 under section 3.50;

Note   There is no method 3 or 4 for this Division.

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

3.49        Method 1 — crude oil production (non‑flared) emissions of methane

         (1)   Method 1 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from all of the equipment of type (k) specified in column 2 of the table in subsection (2), if the equipment is used in the crude oil production.

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the crude oil production.

EFijk is the emission factor for methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the crude oil production.

Qi is the total quantity of crude oil (i) measured in tonnes that passes through the crude oil production.

EF(l) ij is 1.2 x 10‑3, which is the emission factor for methane (j) from general leaks in the crude oil production, measured in CO2‑e tonnes per tonne of crude oil that passes through the crude oil production.

         (2)   For EFijk mentioned in subsection (1), column 3 of an item in the following table specifies the emission factor for an equipment of type (k) specified in column 2 of that item:

 

Item

Equipment type (k)

Emission factor for gas type (j) (tonnes CO2‑e/tonnes fuel throughput)

 

CH4

1

Internal floating tank

8.4 10‑7

2

Fixed roof tank

4.2  10‑6

3

Floating tank

3.2  10‑6

3.50        Method 2 — crude oil production (non‑flared) emissions of methane

         (1)   Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment type is used in the crude oil production.

Qik is the total of the quantities of crude oil that pass through each equipment type (k), or the number of equipment units of type (k), listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production, measured in tonnes.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production.

         (2)   For EFijk, the emission factors for methane (j), as crude oil passes through an equipment type (k), are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

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

Subdivision 3.3.3.3     Crude oil production (flared) — fugitive emissions of carbon dioxide, methane and nitrous oxide

3.51        Available methods

         (1)   Subject to section 1.18, for estimating emissions released by oil or gas flaring during a year from the operation of a facility that is constituted by crude oil production:

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

                          (i)    method 1 under section 3.52;

                         (ii)    method 2 under section 3.53;

                         (iii)    method 3 under section 3.54; and

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

                          (i)    method 1 under section 3.55;

                         (ii)    method 2 under section 3.56; and

                (c)    if estimating emissions of nitrous oxide released — method 1 under section 3.55 must be used.

Note   There is no method 4 under paragraph (a), no methods 3 or 4 under paragraph (b) and no methods 2, 3 or 4 under paragraph (c).

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

3.52        Method 1 — crude oil production (flared) emissions

         (1)   For subparagraph 3.51 (a) (i), method 1 is:

where:

Eij is the emissions of gas type (j) measured in CO2‑e tonnes from a fuel type (i) flared in crude oil production during the year.

Qi is the quantity of fuel type (i) measured in tonnes flared in crude oil production during the year.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of the fuel type (i) flared.

         (2)   For EFij mentioned in subsection (1), columns 3, 4 and 5 of an item in following table specify the emission factor for each fuel type (i) specified in column 2 of that item.

 

Item

Fuel type (i)

Emission factor for gas type (j) (tonnes CO2‑e/tonnes of fuel flared)

 

CO2

CH4

N2O

1

Unprocessed gas flared

2.8

0.7

0.03

2

Crude oil

3.2

0.007

0.07

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

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

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

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

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

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

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

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

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

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

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

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

Division 3.3.4        Crude oil transport

3.57        Application

                This Division applies to UNFCCC category 1.B.2.a.iii. — fugitive emissions from crude oil transport.

3.58        Available methods

         (1)   Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane released during a year from the operation of a facility that is constituted by crude oil transport:

                (a)    method 1 under section 3.59;

               (b)    method 2 under section 3.60.

Note   There is no method 3 or 4 for this Division.

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

3.59        Method 1 — crude oil transport

                Method 1 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil transport during the year measured in CO2‑e tonnes.

Qi is the quantity of crude oil (i) measured in tonnes and transported during the year.

EFij is the emission factor for methane (j), which is 7.3 x 10‑4 tonnes CO2‑e per tonnes of crude oil transported during the year.

3.60        Method 2 — fugitive emissions from crude oil transport

         (1)   Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil transport during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport .

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes though each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport.

         (2)   For EFijk, the emission factors for methane (j), as crude oil passes through equipment type (k), are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

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

Division 3.3.5        Crude oil refining

3.61        Application

                This Division applies to UNFCCC Category 1.B.2.a.iv — fugitive emissions from crude oil refining.

3.62        Available methods

         (1)   Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by crude oil refining the methods as set out in this section must be used.

Crude oil refining and storage tanks

         (2)   One of the following methods must be used for estimating fugitive emissions of methane that result from crude oil refining and from storage tanks for crude oil:

                (a)    method 1 under section 3.63;

               (b)    method 2 under section 3.64.

Note   There is no method 3 or 4 for subsection (2).

Process vents, system upsets and accidents

         (3)   One of the following methods must be used for estimating fugitive emissions of each type of gas, being carbon dioxide, methane and nitrous oxide, that result from deliberate releases from process vents, system upsets and accidents:

                (a)    method 1 under section 3.65;

               (b)    method 4 under section 3.66.

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

Flaring

         (4)   For estimating emissions released from gas flared from crude oil refining:

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

                          (i)    method 1 under section 3.67;

                         (ii)    method 2 under section 3.68;

                         (iii)    method 3 under section 3.69; and

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

                          (i)    method 1 under section 3.67;

                         (ii)    method 2 under section 3.68; and

                (c)    method 1 under section 3.67 must be used for estimating emissions of nitrous oxide released.

Note   The flaring of gas from crude oil refining releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 under section 3.67 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.

         (5)   However, for incidental emission source streams another method may be used that is consistent with the principles in section 1.13.

Subdivision 3.3.5.1     Fugitive emissions from crude oil refining and from storage tanks for crude oil

3.63        Method 1 — crude oil refining and storage tanks for crude oil

                Method 1 is:

where:

Eij is the fugitive emissions of methane (j) from fuel type (i) being crude oil refined or stored in tanks during the year measured in CO2‑e tonnes.

I is the sum of emissions of methane (j) released during refining and from storage tanks during the year.

Qi is the quantity of crude oil (i) refined or stored in tanks during the year measured in tonnes.

EFij is the emission factor for methane (j) being 7.1 x 10‑4 tonnes CO2‑e per tonne of crude oil refined and 1.3 x 10‑4 tonnes CO2‑e per tonne of crude oil stored in tanks.

3.64        Method 2 — crude oil refining and storage tanks for crude oil

         (1)   Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil refining and from storage tanks during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) measured in tonnes of CO2‑e estimated by summing up the emissions released from each equipment types (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.

EFijk is the emission factor for methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes though each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.

         (2)   For EFijk, the emission factors for methane (j) as the crude oil passes through an equipment type (k) are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

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

Subdivision 3.3.5.2     Fugitive emissions from deliberate releases from process vents, system upsets and accidents

3.65        Method 1 — fugitive emissions from deliberate releases from process vents, system upsets and accidents

                Method 1 is:

where:

Ei is the fugitive emissions during the year from deliberate releases from process vents, system upsets and accidents in the crude oil refining measured in CO2‑e tonnes.

Qi is the quantity of refinery coke (i) burnt to restore the activity of the catalyst of the crude oil refinery (and not used for energy) during the year measured in tonnes.

CCFi is the carbon content factor for refinery coke (i) as mentioned in Schedule 3.

3.664 is the conversion factor to convert an amount of carbon in tonnes to an amount of carbon dioxide in tonnes.

3.66        Method 4 — deliberate releases from process vents, system upsets and accidents

         (1)   Method 4 is:

                (a)    is as set out in Part 1.3; or

               (b)    uses the process calculation approach in section 5.2 of the API Compendium.

         (2)   For paragraph (1) (b), all carbon monoxide is taken to fully oxidise to carbon dioxide and must be included in the calculation.

Subdivision 3.3.5.3     Fugitive emissions released from gas flared from the oil refinery

3.67        Method 1 — gas flared from crude oil refining

         (1)   Method 1 is:

where:

Eij is the emissions of gas type (j) released from the gas flared in the crude oil refining during the year measured in CO2‑e tonnes.

Qi is the quantity of gas type (i) flared during the year measured in tonnes.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of gas type (i) flared in the crude oil refining during the year.

         (2)   For EFijk in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor for gas type (j) for the fuel type (i) specified in column 2 of that item:

 

Item

fuel type (i)

Emission factor of gas type (j) (tonnes CO2‑e/tonnes fuel flared)

 

CO2

CH4

N2O

1

gas

2.7

0.1

0.03

3.68        Method 2 — gas flared from crude oil refining

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

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

3.69        Method 3 — gas flared from crude oil refining

                Method 3 is the same as method 1 under section 3.67 but the emission factor EFij must be determined in accordance with method 3 for the consumption of gaseous fuels as specified in Division 2.3.4.

Division 3.3.6        Natural gas production and processing (other than emissions that are vented or flared)

3.70        Application

                This Division applies to UNFCCC category 1.B.2.b.ii — natural gas production and processing (other than emissions that are vented or flared).

3.71        Available methods

         (1)   Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane (other than emissions that are vented or flared) released during a year from the operation of a facility that is constituted by natural gas production and processing:

                (a)    method 1 under section 3.72;

               (b)    method 2 under section 3.73.

Note   There is no method 3 or 4 for this Division.

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

3.72        Method 1 — natural gas production and processing (other than emissions that are vented or flared)

         (1)   Method 1 is:

where:

Eij is the fugitive emissions of methane (j) (other than emissions that are vented or flared) from the natural gas production and processing during the year measured in CO2‑e tonnes.

Σk is the total emissions of methane (j), measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) specified in column 2 of an item in the table in subsection (2), if the equipment is used in the natural gas production and processing.

Qik is the total of the quantities of natural gas that pass through each equipment type (k), or the number of equipment units of type (k) specified in column 2 of the table in subsection (2), measured in tonnes.

EFijk is the emission factor for methane (j) measured in CO2‑e tonnes per tonne of natural gas that passes through each equipment type (k) during the year if the equipment is used in the natural gas production and processing.

Qi is the total quantity of natural gas (i) that passes through the natural gas production and processing measured in tonnes.

EF(l) ij is 1.2 x 10‑3, which is the emission factor for methane (j) from general leaks in the natural gas production and processing, measured in CO2‑e tonnes per tonne of natural gas that passes through the natural gas production and processing.

         (2)   For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item:

 

Item

Equipment type (k)

Emission factor for methane (j)
(tonnes CO2‑e/tonnes fuel throughput)

1

Internal floating tank

8.4 10‑7

2

Fixed roof tank

4.2  10‑6

3

Floating tank

3.2  10‑6

3.73        Method 2— natural gas production and processing (other than venting and flaring)

         (1)   Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the natural gas production and processing during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

Qik is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of natural gas that passes through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

         (2)   For EFijk, the emission factors for methane (j) as the natural gas passes through the equipment types (k) are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

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

Division 3.3.7        Natural gas transmission

3.74        Application

                This Division applies to UNFCCC category 1.B.2.b.iii — natural gas transmission.

3.75        Available methods

         (1)   Subject to section 1.18 and subsection (2), one of the following methods must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, released from the operation of a facility that is constituted by natural gas transmission through a system of pipelines during a year:

                (a)    method 1 under section 3.76;

               (b)    method 2 under section 3.77.

Note   There is no method 3 or 4 for this Division.

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

3.76        Method 1 — natural gas transmission

                Method 1 is:

where:

Eij is the fugitive emissions of gas type (j) from natural gas transmission through a system of pipelines of length (i) during the year measured in CO2‑e tonnes.

Qi is the length of the system of pipelines (i) measured in kilometres.

EFij is the emission factor for gas type (j), which is 0.02 for carbon dioxide and 8.7 for methane, measured in tonnes of CO2‑e emissions per kilometre of pipeline (i).

3.77        Method 2 — natural gas transmission

         (1)   Method 2 is:

where:

Ej is the fugitive emissions of gas type (j) measured in CO2‑e tonnes from the natural gas transmission through the system of pipelines during the year.

Σk is the total of emissions of gas type (j) measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas transmission.

Qk is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) or the number of equipment units of type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas transmission.

EFjk is the emission factor of gas type (j) measured in CO2‑e tonnes for each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, where the equipment is used in the natural gas transmission.

         (2)   For EFjk, the emission factors for a gas type (j) as the natural gas passes through the equipment type (k) are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

               (b)    as listed in that Compendium for the equipment type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s sections 5 and 6.1.2, and the requirements of Division 2.3.3; or

                (c)    as listed in that Compendium for the equipment type with emission factors adjusted for variations in the type of equipment material estimated in accordance with the results of published research for the crude oil industry and the principles of section 1.13; or

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

Division 3.3.8        Natural gas distribution

3.78        Application

                This Division applies to UNFCCC Category 1.B.2.b.iv — natural gas distribution.

3.79        Available methods

         (1)   Subject to section 1.18 and subsection (2), one of the following methods must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, released during a year from the operation of a facility that is constituted by natural gas distribution through a system of pipelines:

                (a)    method 1 under section 3.80;

               (b)    method 2 under section 3.81.

Note   There is no method 3 or 4 for this Division.

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

3.80        Method 1 — natural gas distribution

         (1)   Method 1 is:

where:

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

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

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

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

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

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

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

 

Item

State

Unaccounted for gas (a)%

Natural gas composition factor (a)(tonnes CO2‑e/TJ)

 

UAGp

CO2

CH4

1

NSW and ACT

2.40

0.8

328

2

VIC

2.75

0.9

326

3

QLD

2.63

0.8

317

4

WA

2.55

1.1

306

5

SA

4.00

0.8

328

6

TAS

0.40

0.9

326

7

NT

0.10

0.0

264

3.81        Method 2 — natural gas distribution

         (1)   Method 2 is:

where:

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

Σk is the total of emissions of gas type (j) measured in CO2‑e tonnes and estimated by summing up the emissions from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution.

Qk is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) or the number of equipment units of type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution.

EFjk is the emission factor for gas type (j) measured in CO2‑e tonnes for each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution.

         (2)   For EFjk, the emission factors for gas type (j) as the natural gas passes through the equipment type (k) are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium; or

               (b)    as listed in that Compendium for the equipment type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s Sections 5 and 6.1.2, and the requirements of Division 2.3.3; or

                (c)    as listed in that Compendium for the equipment type with emission factors adjusted for variations in the type of equipment material estimated in accordance with the results of published research for the crude oil industry and the principles of section 1.13; or

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

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

3.82        Application

                This Division applies to UNFCCC Category 1.B.2.c — natural gas production and processing (emissions that are vented or flared).

3.83        Available methods

         (1)   Subject to section 1.18, for estimating emissions (emissions that are vented or flared) released during a year from the operation of a facility that is constituted by natural gas production and processing the methods as set out in this section must be used.

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

                          (i)    method 1 under section 3.84; and

                         (ii)    method 4 under Part 1.3.

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

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

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

                          (i)    method 1 under section 3.85;

                         (ii)    method 2 under section 3.86;

                         (iii)    method 3 under section 3.87; and

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

                          (i)    method 1 under section 3.85;

                         (ii)    method 2 under section 3.86; and

                (c)    method 1 under section 3.85 must be used for estimating emissions of nitrous oxide released.

Note   The flaring of gas from natural gas production and processing releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.85 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.

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

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

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

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

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

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

         (1)   Method 1 is:

where:

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

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

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

         (2)   For EFij mentioned in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor for fuel type (i) specified in column 2 of that item.

 

Item

fuel type (i)

Emission factor of gas type (j) (tonnes CO2‑e/tonnes fuel flared)

 

CO2

CH4

N2O

1

gas

2.7

0.1

0.03

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

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

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

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

                Method 3 is the same as method 1 but the emission factor (EFij) must be determined in accordance with method 3 for the consumption of gaseous fuels as specified in Division 2.3.4.

Chapter 4    Industrial processes emissions (UNFCCC Category 2)

Part 4.1              Preliminary

  

4.1           Outline of Chapter

         (1)   This Chapter provides for UNFCCC Category 2 — industrial processes emissions that are released by industries mentioned in subsection (2) that need for their operation:

                (a)    the calcination of carbonates; or

               (b)    the use of fuels as:

                          (i)    feedstock; or

                         (ii)    carbon reductants.

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

                (a)    in Part 4.2 — mineral industries:

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

                         (ii)    producing lime (Division 4.2.2); or

                         (iii)    other than an industry mentioned in subparagraph (i) or (ii) which involve the calcination of carbonates (Division 4.2.3); or

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

               (b)    in Part 4.3 — chemical industries producing:

                          (i)    ammonia (Division 4.3.1); or

                         (ii)    nitric acid (Division 4.3.2); or

                         (iii)    adipic acid (Division 4.3.3); or

                        (iv)    carbide (Division 4.3.4); or

                         (v)    titanium dioxide (Division 4.3.5); or

                        (vi)    synthetic rutile (Division 4.3.6);

                (c)    in Part 4.4 — metal industries producing:

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

                         (ii)    ferroalloy metal (Division 4.4.2); or

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

                        (iv)    other metals (Division 4.4.5);

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

                (a)    hydrofluorocarbons;

               (b)    sulphur hexafluoride.

Part 4.2              Industrial processes — mineral products

Division 4.2.1        Cement clinker production

4.2           Application

                This Division applies to UNFCCC Category 2.A.1 — cement clinker production.

4.3           Available methods

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

                (a)    method 1 under section 4.4;

               (b)    method 2 under section 4.5;

                (c)    method 3 under section 4.8;

               (d)    method 4 under Part 1.3.

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

4.4           Method 1 — cement clinker production

                Method 1 is:

where:

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

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

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

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

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

Fckd is:

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

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

4.5           Method 2 — cement clinker production

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

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

where:

FCaO is the estimated fraction of cement clinker that is calcium oxide.

FMgO is the estimated fraction of cement clinker that is magnesium oxide.

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

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

4.6           General requirements for sampling cement clinker

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

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

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

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

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

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

4.7           General requirements for analysing cement clinker

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

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

4.8           Method 3 — cement clinker production

         (1)   Method 3 is:

Step 1

Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each pure carbonate calcined in the production of cement clinker during the year as follows:

where:

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

 

EFij is the carbon dioxide (j) emission factor for the carbonate (i) measured in tonnes of emissions of carbon dioxide per tonne of pure carbonate, as follows:

   (a)  for calcium carbonate — 0.440; and

   (b)  for magnesium carbonate — 0.522; and

   (c)  for dolomite — 0.477; and

   (d)  for any other pure carbonate — the factor for the carbonate in accordance with section 2.1 of Part 1 of Volume 3 of the 2006 IPCC Guidelines.

Qi is the quantity of the pure carbonate (i) consumed in the calcining process for the production of cement clinker during the year measured in tonnes and estimated under Division 4.2.5.

Fcal is:

(a)    the amount of the carbonate calcined in the production of cement clinker during the year, expressed as a decimal fraction; or

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

Ackd is the quantity of cement kiln dust lost from the kiln in the production of cement clinker during the year measured in tonnes and estimated under Division 4.2.5.

EFckd is 0.440, which is the carbon dioxide emission factor for calcined cement kiln dust lost from the kiln.

Fckd is:

   (a)  the fraction of calcination achieved for cement kiln dust lost from the kiln in the production of cement clinker during the year; or

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

Qtoc is the quantity of total carbon‑bearing non‑fuel raw material consumed in the production of cement clinker during the year measured in tonnes and estimated under Division 4.2.5.

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

Step 2

Add together the amount of emissions of carbon dioxide as measured in CO2‑e tonnes released for each pure carbonate calcined in the production of cement clinker during the year.

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

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

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

4.9           General requirements for sampling carbonates

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

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

4.10        General requirements for analysing carbonates

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

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

Division 4.2.2        Lime production

4.11        Application

                This Division applies to UNFCCC Category 2.A.2 — lime production (other than the in‑house production of lime in the ferrous metals industry).

4.12        Available methods

         (1)   Subject to section 1.18, one of the following methods must be used for estimating emissions of carbon dioxide released during a year from the operation of a facility that is constituted by the production of lime (other than the in‑house production of lime in the ferrous metals industry):

                (a)    method 1 under section 4.13;

               (b)    method 2 under section 4.14;

                (c)    method 3 under section 4.17;

               (d)    method 4 under Part 1.3.

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

4.13        Method 1 — lime production

                Method 1 is:

where:

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

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

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

                (a)    for commercial lime production — 0.675;

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

4.14        Method 2 — lime production

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

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

where:

Fi is the estimated fractional purity of lime.

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

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

4.15        General requirements for sampling

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

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

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

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

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

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

4.16        General requirements for analysis of lime

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

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

4.17        Method 3 — lime production

         (1)   Method 3 is:

Step 1

Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each pure carbonate calcined in the production of lime during the year as follows:

where:

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

EFij is the carbon dioxide (j) emission factor for the carbonate (i), measured in tonnes of emissions of carbon dioxide per tonne of pure carbonate as follows:

   (a)  for calcium carbonate — 0.440;

   (b)  for magnesium carbonate — 0.522;

   (c)  for dolomite — 0.477;

   (d)  for any other carbonate — the factor for the carbonate in accordance with Tier 3 of Part 1 of Volume 3 of the 2006 IPCC Guidelines.

 

Qi is the quantity of the pure carbonate (i) entering the calcining process in the production of lime during the year measured in tonnes and estimated under Division 4.2.5.

Fcal is:

(a)    the amount of the carbonate calcined in the production of lime during the year expressed as a decimal fraction; or

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

Alkd is the quantity of lime kiln dust lost in the production of lime during the year, measured in tonnes and estimated under Division 4.2.5.

 

EFlkd is 0.440, which is the emission factor for calcined lime kiln dust lost from the kiln.

Flkd is:

   (a)  the fraction of calcination achieved for lime kiln dust in the production of lime during the year; or

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

Step 2

Add together the amount of emissions of carbon dioxide for each pure carbonate calcined in the production of lime during the year.

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

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

4.18        General requirements for sampling

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

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

4.19        General requirements for analysis of carbonates

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

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

Division 4.2.3        Other uses of carbonates

4.20        Application

                This Division applies to UNFCCC Category 2.A.3 — industrial processes (other than cement clinker production or lime production) involving the calcination of carbonates, including the in‑house production of lime in the ferrous metals industry.

Note   Examples of industrial processes involving the calcination of carbonates include the following:

·      metallurgy

·      glass manufacture, including fibreglass and mineral wools

·      magnesia production

·      agriculture

·      construction

·      environment pollution control.

4.21        Available methods

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

                (a)    method 1 under section 4.22;

               (b)    method 3 under section 4.23;

                (c)    method 4 under Part 1.3.

Note   There is no method 2 for this Division.

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

4.22        Method 1 — industrial processes involving calcination of carbonates

                Method 1 is:

Step 1

Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each raw carbonate material calcined in the industrial process during the year as follows:

where:

 

Eij is the emissions of carbon dioxide (j) released from raw carbonate material (i) calcined in the industrial process during the year measured in CO2‑e tonnes.

Qi is the quantity of the raw carbonate material (i) consumed in the calcining process for the industrial process during the year measured in tonnes and estimated under Division 4.2.5.

EFij is the carbon dioxide (j) emission factor for the raw carbonate material (i) measured in tonnes of emissions of carbon dioxide per tonne of carbonate, that is:

   (a)  for calcium carbonate — 0.396; and

   (b)  for magnesium carbonate — 0.522; and

   (c)  for dolomite — 0.453; and

   (d)  for any other raw carbonate material — the factor for the raw carbonate material in accordance with section 2.1 of Part 1 of Volume 3 of the 2006 IPCC Guidelines.

 

Fcal is:

   (a)  the fraction of the raw carbonate material calcined in the industrial process during the year; or

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

Step 2

Add together the amount of emissions of carbon dioxide for each carbonate calcined in the industrial process during the year.

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

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

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

(c)   for dolomite — at least 95% dolomite.

4.23        Method 3 — industrial processes involving calcination of carbonates

         (1)   Method 3 is:

Step 1

Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each pure carbonate calcined in the industrial process during the year as follows:

where:

Eij is the emissions of carbon dioxide (j) from a pure carbonate (i) calcined in the industrial process during the year measured in CO2‑e tonnes.

 

EFij is the carbon dioxide (j) emission factor for the pure carbonate (i) in tonnes of emissions of carbon dioxide per tonne of pure carbonate, that is:

   (a)  for calcium carbonate — 0.440;

   (b)  for magnesium carbonate — 0.522;

   (c)  for dolomite — 0.477;

   (d)  for any other pure carbonate — the factor for the carbonate in accordance with Part 1 of Volume 3 of the 2006 IPCC Guidelines.

Qi is the quantity of the pure carbonate (i) entering the calcination process for the industrial process during the year measured in tonnes and estimated under Division 4.2.5.

 

Fcal is:

   (a)  the fraction of the pure carbonate calcined in the industrial process during the year; or

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

Step 2

Add together the amount of emissions of carbon dioxide for each pure carbonate calcined in the industrial process during the year.

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

4.24        General requirements for sampling carbonates

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

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

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

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

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

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

4.25        General requirements for analysis of carbonates

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

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

Division 4.2.4        Soda ash use and production

4.26        Application

                This Division applies to UNFCCC Category 2.A.4 — the use and production of soda ash.

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

·      glass production

·      soap and detergent production

·      flue gas desulphurisation

·      pulp and paper production.

4.27        Outline of Division

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

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

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

Subdivision 4.2.4.1     Soda ash use

4.28        Available methods

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

                (a)    method 1 under section 4.29;

               (b)    method 4 under Part 1.3.

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

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

4.29        Method 1 — use of soda ash

                Method 1 is:

where:

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

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

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

Subdivision 4.2.4.2     Soda ash production

4.30        Available methods

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

                (a)    method 1 under section 4.31;

               (b)    method 2 under section 4.32;

                (c)    method 3 under section 4.33;

               (d)    method 4 under Part 1.3.

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

4.31        Method 1 — production of soda ash

         (1)   Method 1 is:

where:

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

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

ECi is the energy content factor for the feedstock type (i), as mentioned in Schedule 1 measured in gigajoules per the appropriate unit.

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

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

         (2)   If Qi is measured in gigajoules, then ECi is 1.

4.32        Method 2 — production of soda ash

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

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

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

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

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

4.33        Method 3 — production of soda ash

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

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

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

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

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

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

4.34        Purpose of Division

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

                (a)    the production of cement clinker; or

               (b)    the production of lime; or

                (c)    the calcination of carbonates in an industrial process; or

               (d)    the use and production of soda ash.

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

(a)    Ai and Ackd in section 4.4;

(b)    Qi and Qtoc in section 4.8;

(c)    Ai in section 4.13;

(d)    Qi and Alkd in section 4.17;

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

4.35        Criteria for measurement

                Quantities of carbonates consumed from the operation of the activity, or quantities of products derived from carbonates produced from the operation of the activity, must be estimated using one of the following criteria:

                (a)    the amount of carbonates delivered for the activity, or the amount of products derived from carbonates dispatched from the activity, during the year as evidenced by invoices issued by the vendor of the carbonates or the products derived from carbonates (criterion A);

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

                (c)    as provided in section 4.37 (criterion AAA);

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

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

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

                (a)    as evidenced by invoices; and

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

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

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

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

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

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

         (2)   The measurement must be:

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

               (b)    for measurement of the quantities of carbonates consumed from the operation of the activity — carried out at the point of sale using measuring equipment calibrated to a measurement requirement.

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

                (a)    the change in the stockpile of the carbonates for the activity during the year is less than 1% of total consumption of the carbonates from the operation of the activity on average during the year; and

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

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

                For paragraph 4.35 (d), criterion BBB is the estimation of the consumption of carbonates, or the products derived from carbonates, during the year in accordance with industry practice if:

                (a)    the delivery of the carbonates, or the dispatch of the products derived from carbonates, does not involve a commercial transaction; and

               (b)    the equipment used to measure consumption of the carbonates, or the products derived from carbonates, is not calibrated to a measurement requirement.

4.39        Units of measurement

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

Part 4.3              Industrial processes — chemical industry

Division 4.3.1        Ammonia production

4.40        Application

                This Division applies to UNFCCC Category 2.B.1 — chemical industry ammonia production.

4.41        Available methods

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

                (a)    method 1 under section 4.42;

               (b)    method 2 under section 4.43;

                (c)    method 3 under section 4.44;

               (d)    method 4 under Part 1.3.

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

4.42        Method 1 — ammonia production

         (1)   Method 1 is:

where:

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

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

ECi is the energy content factor of the type of feedstock or type of fuel (i) used in the production of ammonia during the year, measured in gigajoules per cubic metre according to the source mentioned in Part 2 of Schedule 1.

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

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

         (2)   If Qi is measured in gigajoules, then ECi is 1.

4.43        Method 2 — ammonia production

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

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

4.44        Method 3 — ammonia production

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

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

Division 4.3.2        Nitric acid production

4.45        Application

                This Division applies to UNFCCC Category 2.B.2 — chemical industry nitric acid production.

4.46        Available methods

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

                (a)    method 1 under section 4.47;

               (b)    method 2 under section 4.48;

                (c)    method 4 under Part 1.3.

Note   There is no method 3 for this Division.

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

         (3)   Method 1 must not be used if the plant has used measures to reduce nitrous oxide emissions.

4.47        Method 1 — nitric acid production

         (1)   Method 1 is:

where:

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

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

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

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

 

Item

Plant type (k)

Emission factor of nitrous oxide
(tonnes CO2‑e per tonne of nitric acid production)

1

Atmospheric pressure plants

1.55

2

Medium pressure combustion plant

2.17

3

High pressure plant

2.79

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

4.48        Method 2 — nitric acid production

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

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

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

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

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

Division 4.3.3        Adipic acid production

4.49        Application

                This Division applies to UNFCCC Category 2.B.3 — chemical industry adipic acid production.

4.50        Available methods

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

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

Division 4.3.4        Carbide production

4.51        Application

                This Division applies to UNFCCC Category 2.B.4 — chemical industry carbide production.

4.52        Available methods

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

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

Division 4.3.5        Titanium dioxide

4.53        Application

                This Division applies to UNFCCC Category 2.B.5 — chemical industry titanium dioxide production.

4.54        Available methods

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

                (a)    method 1 under section 4.55;

               (b)    method 2 under section 4.56;

                (c)    method 3 under section 4.57;

               (d)    method 4 under Part 1.3.

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

4.55        Method 1 — titanium dioxide production

         (1)   Method 1 is:

where:

Eij is the emissions of carbon dioxide released from the fuel type (i) used in the production of titanium dioxide during the year and measured in CO2‑e tonnes.

Qi is the quantity of each fuel type (i) consumed in the production of titanium dioxide from the production of titanium dioxide during the year measured in the appropriate unit and estimated in accordance with:

(a)    for solid fuels — Division 2.2.5, or

(b)    for gaseous fuels — Division 2.3.6; or

(c)    for liquid fuels — Division 2.4.6.

ECi is the energy content factor of the fuel type (i) used in the production of titanium dioxide during the year, measured in gigajoules per the unit of measurement mentioned in column 3 of a table in Schedule 1 for the fuel type according to source as mentioned in:

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

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

                (c)    for liquid fuel combustion for stationery energy purposes — Part 3 of Schedule 1.

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

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

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

                (c)    for liquid fuel combustion for stationery energy purposes — Part 3 of Schedule 1.

         (2)   If Qi is measured in gigajoules, then ECi is 1.

4.56        Method 2 — titanium dioxide production

                Method 2 is:

                (a)    for estimating emissions released in the production of titanium dioxide using solid fuels during the year — the same as method 2 under Division 2.2.3; and

               (b)    for estimating emissions released in the production of titanium dioxide using gaseous fuels during the year — the same as method 2 under Division 2.3.3; and

                (c)    for estimating emissions released in the production of titanium dioxide using liquid fuels during the year — the same as method 2 under Division 2.4.3.

4.57        Method 3 — titanium dioxide production

                Method 3 is:

                (a)    for estimating emissions released in the production of titanium dioxide using solid fuels during the year — the same as method 3 under Division 2.2.4; and

               (b)    for estimating emissions released in the production of titanium dioxide using gaseous fuels during the year — the same as method 3 under Division 2.3.4; and

                (c)    for estimating emissions released in the production of titanium dioxide using liquid fuels during the year — the same as method 3 under Division 2.4.4.

Division 4.3.6        Synthetic rutile production

4.58        Application

                This Division applies to UNFCCC Category 2.B.5 — chemical industry synthetic rutile production.

4.59        Available methods

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

                (a)    method 1 under section 4.60;

               (b)    method 2 under section 4.61;

                (c)    method 3 under section 4.62;

               (d)    method 4 under Part 1.3.

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

4.60        Method 1 — synthetic rutile production

         (1)   Method 1 is:

where:

Eij is the emissions of carbon dioxide released as a result of the consumption of a carbon reductant in the production of synthetic rutile during the year measured in CO2‑e tonnes.

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

(a)    for solid fuels — Division 2.2.5; or

(b)    for gaseous fuels — Division 2.3.6; or

(c)    for liquid fuels — Division 2.4.6.

ECi is the energy content factor of the fuel type (i), used in the production of synthetic rutile during the year, measured in gigajoules per the appropriate unit for the fuel type according to source as mentioned in:

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

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

                (c)    for liquid fuel for stationery energy purposes — Part 3 of Schedule 1.

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

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

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

                (c)    for liquid fuel combustion for stationery energy purposes — Part 3 of Schedule 1.

         (2)   If Qi is measured in gigajoules, then ECi is 1.

4.61        Method 2 — synthetic rutile production

                Method 2 is:

                (a)    for estimating emissions released in the consumption of a carbon reductant in the production of synthetic rutile using solid fuels — the same as method 2 under Division 2.2.3; and

               (b)    for estimating emissions released in the consumption of a carbon reductant in the production of synthetic rutile using gaseous fuels — the same as method 2 under Division 2.3.3; and

                (c)    for estimating emissions released in the consumption of a carbon reductant in the production of synthetic rutile using liquid fuels — the same as method 2 under Division 2.4.3.

4.62        Method 3 — synthetic rutile production

                Method 3 is:

                (a)    for estimating emissions released in the consumption of a carbon reductant in the production of synthetic rutile using solid fuels — the same as method 3 under Division 2.2.4; and

               (b)    for estimating emissions released in the consumption of a carbon reductant in the production of synthetic rutile using gaseous fuels — the same as method 3 under Division 2.3.4; and

                (c)    for estimating emissions released in the consumption of a carbon reductant in the production of synthetic rutile using liquid fuels — the same as method 3 under Division 2.4.4.

Part 4.4              Industrial processes — metal industry

Division 4.4.1        Iron and steel production

4.63        Application

                This Division applies to UNFCCC Category 2.C.1 — iron and steel production.

Note   Iron and steel production has 2 primary sources of emissions. The emissions are from the combustion of fuels for making coke and from the use of fuel as a carbon reductant in iron and steel production. Other sources include emissions from use of carbonates.

4.64        Purpose of Division

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

         (2)   An integrated steelworks means a steelworks that produces coke, iron and steel.

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

         (4)   However, the amount of emissions to be applied to UNFCCC Category 2.C.1 is only the amount of emissions from the use of coke as a carbon reductant in the iron and steel production estimated in accordance with section 2.69.

Note   The amount of emissions to be applied to other UNFCCC Categories is as provided for in other provisions of this Determination.

4.65        Available methods for iron and steel production

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

                (a)    method 1 under section 4.66;

               (b)    method 2 under section 4.67;

                (c)    method 3 under section 4.68;

               (d)    method 4 under Part 1.3.

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

4.66        Method 1 — iron and steel production

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

 

Step 1

Calculate the carbon content in fuel types (i) or carbonaceous input material delivered for the activity during the year measured in tonnes of carbon as follows:

where:

Si means sum the carbon content values obtained for all fuel types (i) or carbonaceous input material.

CCFi is the carbon content factor mentioned in Schedule 3 measured in tonnes of carbon for each appropriate unit of fuel type (i) or carbonaceous input material consumed during the year from the operation of the activity.

Qi is the quantity of fuel type (i) or carbonaceous input material delivered for the activity during the year measured in an appropriate unit and estimated in accordance with criterion A in Division 2.2.5, 2.3.6 and 2.4.6.

Step 2

Calculate the carbon content in products (p) leaving the activity during the year measured in tonnes of carbon as follows:

where:

Sp means sum the carbon content values obtained for all product types (p).

CCFp is the carbon content factor measured in tonnes of carbon for each tonne of product type (p) produced during the year.

Ap is the quantity of product types (p) produced leaving the activity during the year measured in tonnes.

Step 3

Calculate the carbon content in waste by‑product types (r) leaving the activity, other than as an emission of greenhouse gas, during the year, measured in tonnes of carbon, as follows:

where:

Sr means sum the carbon content values obtained for all waste by‑product types (r).

CCFr is the carbon content factor measured in tonnes of carbon for each tonne of waste by‑product types (r).

Yr is the quantity of waste by‑product types (r) leaving the activity during the year measured in tonnes.

Step 4

Calculate the carbon content in the amount of the increase in stocks of inputs, products and waste by‑products held within the boundary of the activity during the year in tonnes of carbon as follows:

where:

Si has the same meaning as in step 1.

CCFi has the same meaning as in step 1.

ΔSqi is the increase in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year measured in tonnes.

Sp has the same meaning as in step 2.

CCFp has the same meaning as in step 2.

ΔSap is the increase in stocks of product types (p) produced by the activity and held within the boundary of the activity during the year measured in tonnes.

 

Sr has the same meaning as in step 3.

CCFr has the same meaning as in step 3.

ΔSyr is the increase in stocks of waste by‑product types (r) produced from the operation of the activity and held within the boundary of the activity during the year measured in tonnes.

Step 5

Calculate the emissions of carbon dioxide released from the operation of the activity during the year measured in CO2‑e tonnes as follows:

   (a)  add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A);

   (b)  subtract amount A from the amount worked out under step 1 to work out a new amount (amount B);

   (c)  multiply amount B by 3.664 to work out the amount of emissions released from the operation of the activity during a year.

4.67        Method 2 — iron and steel production

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

         (2)   If a fuel type (i) or carbonaceous input material delivered for the activity during the year accounts for more than 5% of total carbon input for the activity based on a calculation using the factors specified in Schedule 3, sampling and analysis of fuel type (i) or carbonaceous input material must be carried out to determine its carbon content.

         (3)   The sampling and analysis is to be carried out using the sampling and analysis provided for in Divisions 2.2.3, 2.3.3 and 2.4.3 that apply to the combustion of solid, liquid or gaseous fuels.

4.68        Method 3 — iron and steel production

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

         (2)   If a fuel type (i) or carbonaceous input material delivered for the activity during the year accounts for more than 5% of total carbon input for the activity based on a calculation using the factors specified in Schedule 3, sampling and analysis of fuel type (i) or carbonaceous input material must be carried out to determine its carbon content.

         (3)   The sampling and analysis is to be carried out using the methods set out in Divisions 2.2.4, 2.3.4 and 2.4.4 that apply to the combustion of solid, liquid or gaseous fuels:

Division 4.4.2        Ferroalloy metal

4.69        Application

                This Division applies to UNFCCC Category 2.C.2 — ferroalloy production.

4.70        Available methods

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

                (a)    method 1 under section 4.71;

               (b)    method 2 under section 4.72;

                (c)    method 3 under section 4.73;

               (d)    method 4 under Part 1.3.

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

4.71        Method 1 — ferroalloy metal

         (1)   Method 1 is:

where:

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

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

(a)    for solid fuels — Division 2.2.5; or

(b)    for gaseous fuels — Division 2.3.6; or

(c)    for liquid fuels — Division 2.4.6.

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

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

         (2)   In subsection (1):

                (a)    subject to subsection (3), for the factor ECi — the energy content factor of a carbon reductant means the energy content factor for that reductant as mentioned in Schedule 1; and

               (b)    for the factor EFij — the emission factor of each carbon reductant means the emission factor for that reductant as mentioned in Schedule 1.

         (3)   If Qi is measured in gigajoules, then ECi is 1.

4.72        Method 2 — ferroalloy metal

                Method 2 is:

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

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

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

4.73        Method 3 — ferroalloy metals

                Method 3 is:

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

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

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

Division 4.4.3        Aluminium (carbon dioxide emissions)

4.74        Application

                This Division applies to UNFCCC Category 2.C.3 — aluminium production.

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

4.75        Available methods

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

                (a)    method 1 under section 4.76;

               (b)    method 2 under section 4.77;

                (c)    method 3 under section 4.78;

               (d)    method 4 under Part 1.3.

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

4.76        Method 1 — aluminium (baked carbon anode consumption)

                Method 1 is:

where:

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

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

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

where:

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

Sa is the sulphur content in baked carbon anodes consumed in the production of aluminium during the year, and taken to be an amount equal to 2% of the weight of the baked carbon anodes consumed.

Asha is the ash content in baked carbon anodes consumed in the production of aluminium during the year, and taken to be an amount equal to 0.4 % of the weight of the baked carbon anodes consumed.

4.77        Method 2 — aluminium (baked carbon anode consumption)

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

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

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

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

                (c)    for liquid fuels — method 2 in Division 2.4.3.

4.78        Method 3 — aluminium (baked carbon anode consumption)

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

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

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

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

                (c)    for liquid fuels — method 3 in Division 2.4.4.

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

4.79        Available methods

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

                (a)    method 1 under section 4.80;

               (b)    method 2 under section 4.81;

                (c)    method 3 under section 4.82;

               (d)    method 4 under Part 1.3.

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

4.80        Method 1 — aluminium (baked carbon anode production)

                Method 1 is:

 

where:

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

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

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

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

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

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

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

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

(c)    if fuel type (i) is a liquid fuel — Division 2.4.6.

Si is the weight of sulphur in fuel type (i) consumed in the production of baked carbon anodes during the year, worked out as equal to 2% of the weight of the fuel.

Ashi is the ash content in reductant fuel type (i) consumed in the production of baked carbon anodes during the year, worked out as equal to 0.4% of the weight of the fuel.

4.81        Method 2 — aluminium (baked carbon anode production)

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

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

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

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

                (c)    for liquid fuels — method 2 in Division 2.4.3.

4.82        Method 3 — aluminium (baked carbon anode production)

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

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

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

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

                (c)    for liquid fuels — method 3 in Division 2.4.4.

Division 4.4.4        Aluminium (perfluoronated carbon compound emissions)

4.83        Application

                This Division applies to UNFCCC Category 2.C.3 — aluminium production.

Subdivision 4.4.4.1     Aluminium — emissions of tetrafluoromethane in aluminium production

4.84        Available methods

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

                (a)    method 1 under section 4.85;

               (b)    method 2 under section 4.86;

                (c)    method 3 under section 4.87.

Note   There is no method 4 for this provision.

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

4.85        Method 1 — aluminium (tetrafluoromethane)

                Method 1 is:

where:

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

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

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

4.86        Method 2 — aluminium (tetrafluoromethane)

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

4.87        Method 3 — aluminium (tetrafluoromethane)

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

Subdivision 4.4.4.2     Aluminium — emissions of hexafluoroethane in aluminium production

4.88        Available methods

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

                (a)    method 1 under section 4.89;

               (b)    method 2 under section 4.90;

                (c)    method 3 under section 4.91.

Note   There is no method 4 for this provision.

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

4.89        Method 1 — aluminium production (hexafluoroethane)

                Method 1 is:

where:

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

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

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

4.90        Method 2 — aluminium production (hexafluoroethane)

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

4.91        Method 3 — aluminium production (hexafluoroethane)

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

Division 4.4.5        Other metals

4.92        Application

                This Division applies to Source 2 (UNFCCC Category 2.C.4) — other metals.

4.93        Available methods

         (1)   Subject to section 1.18, one of the following methods must be used for estimating emissions of carbon dioxide from the use of carbon reductants during a year from the operation of a facility that is constituted by the production of metals other than aluminium, ferroalloys and iron and steel:

                (a)    method 1 under section 4.94;

               (b)    method 2 under section 4.95;

                (c)    method 3 under section 4.96;

               (d)    method 4 under Part 1.3.

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

4.94        Method 1 — other metals

         (1)   Method 1 is:

where:

Eij is the emissions of carbon dioxide released from the consumption of a carbon reductant in the production of a metal other than aluminium, ferroalloys and iron and steel during the year measured in the appropriate unit.

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

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

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

                (c)    if fuel type (i) is a liquid fuel — Division 2.4.6.

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

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

         (2)   In subsection (1):

                (a)    subject to subsection (3), for ECi — the energy content factor of a carbon reductant means the energy content factor for that reductant as mentioned in Schedule 1; and

               (b)    for EFi — the emission factor of each carbon reductant means the emission factor for that reductant as mentioned in Schedule 1.

         (3)   If Qi is measured in gigajoules, then ECi is 1.

4.95        Method 2 — other metals

                Method 2 is:

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

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

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

4.96        Method 3 — other metals

                Method 3 is:

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

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

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

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

  

4.97        Application

                This Part applies to UNFCCC Category 2.F — emissions of hydrofluorocarbons and sulphur hexafluoride gases.

4.98        Available method

         (1)   Subject to section 1.18, method 1 under section 4.102 must be used for estimating emissions of hydrofluorocarbons or sulphur hexafluoride during a year from the operation of a facility that is constituted by synthetic gas generating activities.

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

Note   There is no method 2, 3 or 4 for this Part.

4.99        Meaning of hydrofluorocarbons

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

4.100      Meaning of synthetic gas generating activities

Hydrofluorocarbons

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

                (a)    require the use of any thing:

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

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

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

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

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

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

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

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

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

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

Sulphur hexafluoride

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

4.101      Reporting threshold

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

 

Item

Provision in Determination

Threshold

1

Subparagraph 4.100 (1) (a) (ii)

100 kilograms for each unit (hydrofluorocarbons)

2

Subsection 4.100 (2)

Any emission (sulphur hexafluoride)

4.102      Method 1

         (1)   Method 1 is:

where:

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

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

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

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

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

               (b)    estimates based on:

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

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

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

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

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

 

Item

Equipment type (k)

Default annual leakage rate of gas (j)

Hydrofluorocarbons

Sulphur hexafluoride

1

Commercial air conditioning

0.09

 

2

Commercial refrigeration

0.23

 

3

Industrial refrigeration

0.16

 

4

Gas insulated switchgear and circuit breaker applications

 

0.005

Chapter 5    Waste (UNFCCC Category 6)

Part 5.1              Preliminary

  

5.1           Outline of Chapter

                This Chapter provides for UNFCCC Category 6 (waste) as follows:

                (a)    Part 5.2 provides for emissions released from solid waste disposal on land — UNFCCC Category 6.A;

               (b)    Part 5.3 provides for emissions released from wastewater handling (domestic and commercial) — UNFCCC Category 6.B.2;

                (c)    Part 5.4 provides for emissions released from wastewater handling (industrial) — UNFCCC Category 6.B.1;

               (d)    Part 5.5 provides for emissions released from waste incineration — UNFCCC Category 6.C.

Part 5.2              Emissions released from solid waste disposal on land — UNFCCC Category 6.A

Division 5.2.1        Preliminary

5.2           Application

                This Part applies to UNFCCC Category 6.A — emissions released from solid waste disposal on land.

5.3           Available methods

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

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

                          (i)    method 1 under section 5.4;

                         (ii)    method 2 under section 5.15;

                         (iii)    method 3 under section 5.18; and

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

                          (i)    method 1 under section 5.19;

                         (ii)    method 2 under section 5.20;

                         (iii)    method 3 under section 5.21; and

                (c)    method 1 under section 5.22 must be used for emissions from the biological treatment of solid waste at the landfill.

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

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

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

Division 5.2.2        Method 1 — emissions of methane released from landfills

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

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

where:

Ej is emissions of methane released by the landfill during the year .

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

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

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

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

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

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

         (2)   For subsection (1), if  is less than or equal to 0.75, then:

where:

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

         (3)   For subsection (1), if  is greater than 0.75 then:

where:

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

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

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

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

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

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

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

                         (ii)    the composition of the solid waste received at the landfill during the year (see section 5.9);

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

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

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

5.5           Criteria for estimating tonnage of total solid waste

                For subparagraph 5.4 (5) (b) (i), the tonnage of total solid waste received at the landfill during the year is to be estimated using one of the following criteria:

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

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

                (c)    as provided in section 5.8 (criterion BBB).

5.6           Criterion A

                For paragraph 5.5 (a), criterion A is:

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

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

5.7           Criterion AAA

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

5.8           Criterion BBB

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

5.9           Composition of solid waste

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

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

5.10        Waste streams

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

                (a)    municipal solid waste stream; or

               (b)    commercial and industrial waste stream; or

                (c)    construction and demolition waste stream.

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

                (a)    by using criterion A in section 5.6, criterion AAA in section 5.7 or criterion BBB in section 5.8 to calculate the percentage of each waste stream in relation to the total tonnage of solid waste at the landfill; or

               (b)    by using the percentage values in columns 3 to 10 of an item in the following table for each waste stream in column 2 for the item for the State or Territory in which the landfill is located.

 

Item

Waste stream

NSW %

VIC %

QLD %

WA %

SA %

TAS %

ACT %

NT
%

1

Municipal solid waste

31

36

43

26

36

57

43

43

2

Commercial and industrial

42

24