EXPLANATORY STATEMENT

Issued by the authority of the Minister for Climate Change and Energy

National Greenhouse and Energy Reporting Act 2007

National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment

(Default Emissions Intensities) Rules 2022

Background

The National Greenhouse and Energy Reporting Act 2007 (the Act) establishes a single national framework for reporting and disseminating company information about greenhouse gas emissions, energy production, energy consumption and other information. The Safeguard Mechanism is part of the Act. Together with the reporting obligations under the Act, the Safeguard Mechanism provides a framework for Australia’s largest emitters to measure, report and manage their emissions.

Section 22XS of the Act empowers the Minister to make rules to implement the Safeguard Mechanism by legislative instrument. The Safeguard Mechanism was established through the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 (the Principal Rule). The Principal Rule specifies the administrative detail of how Safeguard provisions are implemented and the administrative processes for demonstrating compliance with Safeguard obligations.

The Safeguard Mechanism commenced on 1 July 2016. It applies to facilities with more than 100,000 tonnes of scope 1 (direct) carbon dioxide equivalent (t CO2-e) emissions each year. These facilities must keep their emissions below a legislated baseline or purchase Australian carbon credit units to make up the difference.

The Safeguard Mechanism was amended in March 2019. Those amendments:

1. allow facilities to update baselines using more up-to-date information;
2. give businesses the option of using standardised Government-determined prescribed production variables (which define what is produced at Safeguard facilities) and associated default emissions intensity values for calculating baselines; and
3. allow baselines to adjust annually with production.

The March 2019 amendments established a transition period that allowed baselines to be updated in 2018-19 and 2019-20. Due to the impacts of the COVID-19 pandemic, the Safeguard Mechanism was amended in May 2020 to extend the transition period by one year to include the 2020-21 compliance year. All facilities could apply for a transitional calculated baseline during this period and they had the option to use either:

• default values: Government-determined prescribed production variables and default emissions intensity values (collectively referred to as ‘default values’); or
• estimated (site-specific) values: which take account of individual facility circumstances, either as a site-specific production variable or a site-specific ‘estimated’ emissions intensity value.

In March and October 2020, and October 2021, the Safeguard Rule was amended to insert the majority of Government-determined prescribed production variables and many of the corresponding default emissions intensity values into Schedules 2 and 3 to give effect to the amendments made to the Safeguard Rule in March 2019.

If facilities apply for a transitional calculated baseline from the 2021-22 year onwards, they must use Government-determined prescribed production variables and default emissions intensity values, or benchmark emissions intensity values if they are a new entrant.

Purpose and operation

The National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Default Emissions Intensities) Rules 2022 (the Amendment Rule):

• inserts additional default emissions intensity values for Government-determined prescribed production variables that were set in the Safeguard Rule previously into Schedule 2 of the Safeguard Rule;
• inserts minor technical corrections to prescribed production variables set in the Safeguard Rule in 2020 and 2021; and
• removes the default emissions intensity value for refined lead due to an error that has been identified.

The default values have been developed by the Department of Industry, Science, Energy and Resources (now the Department of Climate Change, Energy, the Environment and Water) in close consultation with industry. They have been developed in line with ‘The Framework for developing default production variables and emissions intensity values’ (the Framework), which underwent public consultation during development of the March 2019 amendments to the Safeguard Rule, and the Guidance on supplementary approaches – companion document to the Framework.

The Amendment Rule is intended to complete the process of updating the Safeguard Rule in line with the March 2019 amendments. The amendment will not impact the planned reforms to the Safeguard Mechanism as announced by the Government, including declining baselines. The announced reforms to the Safeguard Mechanism will be subject to a separate consultation process.

Authority

The Amendment Rule is made under subsection 22XS(1) of the Act.

Consultation

The default values have been developed in close consultation with industry. They have been assessed by independent technical experts, and reviewed by an external consultant to ensure the Framework principles have been applied consistently within and between sectors.

On 21 May 2022, the Government released the proposed amendments to the Principal Rule together with an accompanying explanatory document. Comments closed on 3 August 2022. Two formal submissions were received from the public consultation process.

Regulatory impact analysis

The Amendment Rule inserts additional technical detail into the Principal Rule that is required to give effect to amendments made in March 2019. The March 2019 amendments were covered by the Amendments to the Emissions Reduction Fund Safeguard Mechanism Final Assessment Regulation Impact Statement, which was assessed as compliant and consistent with best practice by the Office of Best Practice Regulation (reference number 22431).

Incorporation

The Amendment Rule refers to a document as in force at the commencement of the amendment, defined as the Safeguard Mechanism document. The full name of the document is: “Safeguard Mechanism: Prescribed production variables and default emissions intensities”. This document was published on the website of the Department of Climate Change, Energy, the Environment and Water (www.dcceew.gov.au) and is incorporated as in force from the commencement of the Amendment Rule consistent with paragraph 14(1) (b) of the Legislation Act 2003.  The document is also attached to this explanatory statement at Attachment C.

This document is incorporated to ensure the technical accuracy of the production variables and ensure the production variables are interpreted and used consistently with industry standards and applicable legislation.

Principle Rule details

The Principal Rule and the Amendment Rule are legislative instruments within the meaning of the Legislation Act 2003. The Principal Rule commenced on 1 July 2016. The whole of the Amendment Rule will commence on the day after registration. The ordinary repeal arrangements for amending instruments apply. Details of the amendments are at Attachment A. The scope of each of the production variables are also set out in further detail in the Safeguard Mechanism document at Attachment C.

Statement of Compatibility with Human Rights

A Statement of Compatibility with Human Rights, prepared in accordance with the Human Rights (Parliamentary Scrutiny) Act 2011, is at Attachment B of the Explanatory Statement.

Attachment A

Details of the sections in the Amendment Rule

Section 1 – Name of Instrument

This section specifies the name of the Amendment Rule is the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Default Emissions Intensities) Rules 2022

Section 2 – Commencement

This section provides that the whole of the Amendment Rule commences the day after it is registered.

Section 3 – Authority

The Amendment Rule is made under subsection 22XS(1) of the Act. The power to make rules under this subsection includes the power to amend or revoke rules that have already been made; subsection 33(3) of the Acts Interpretation Act 1901.

Section 4 – Schedules

This section provides that each instrument specified in a Schedule to the Amendment Rule is amended or repealed as set out in the applicable items in the Schedule concerned, and any other item in a Schedule to the Amendment Rule has effect according to its terms. The Amendment Rule contains only one Schedule.

Schedule 1 – Amendments

1. Section 4 – Definition of Safeguard Mechanism document

This item replaces the existing definition of the Safeguard Mechanism document with a new definition that refers to an updated version of the document. The updated version includes the new default values that this Amendment Rule incorporates into the Principal Rule. The Safeguard Mechanism document contains detailed definitions of the prescribed production variables, together with a list of inclusions and exclusions of emissions sources that have been included in the development of the default emissions intensity values. This detail can assist businesses to understand which emissions sources have been used in the development of the default emissions intensity values, and which emissions sources can be used in an estimated (site-specific) emissions intensity value calculation for a calculated baseline application.  The Safeguard Mechanism document is published on the website of the Department of Climate Change, Energy, the Environment and Water (www.dcceew.gov.au). The Safeguard Mechanism document is also at Attachment C of this Explanatory Statement.

2.       Note after subsection 21(3) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for the manganese ore or mining activity production variable in Schedule 2.

3.        Note after subsection 26(4) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for extracted oil and gas covered by subsections 26(1) and 26(2) of Schedule 2 products.

4.        Note after subsection 27(3) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for the crude oil or condensate stabilisation activity (stabilisation only) variable in Schedule 2.

5.        Note after subsection 29(2) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for the processed natural gas (processing only) production variable in Schedule 2.

6.        Note after subsection 30(4) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for the processed natural gas (integrated extraction and processing) production variable in Schedule 2.

7.        Note after subsection 31(3) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for the liquefied natural gas (from unprocessed natural gas) production variable in Schedule 2.

8.        Note after subsection 34(2) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for the liquefied petroleum gas production variable in Schedule 2.

9.        Note after subsection 54A(2) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for the non-bulk freight production variable in Schedule 2.

10.    Note after subsection 54B(2) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for the non-bulk (temperature controlled) freight production variable in Schedule 2.

11.    Note after subsection 54C(2) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for the specialised and heavy haulage production variable in Schedule 2.

12.    Note after subsection 54D(2) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for bulk freight production variable in Schedule 2.

13.    Note after subsection 60(4) of Schedule 2

This item repeals the note. The note being repealed states that it is intended that there will be a section 61 of Schedule 2 for a further natural gas transmission production variable. The note is no longer needed as section 61 of Schedule 2 was enacted by the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Prescribed Production Variables Update) Rule 2021 (F2021L00991).

14.    Note after subsection 66(3) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for quarried rock production variable in Schedule 2.

15.    Note after subsection 68(2) of Schedule 2

This item repeals the note and inserts the default emissions intensity value for lead bullion production variable in Schedule 2.

16.    Note after subsection 69(2) of Schedule 2

This item repeals the note and substitutes that with: Note (1) The blasting and sintering processes used in the activity may also treat either or both of concentrated mineralised zinc compounds and zinc bearing secondary materials and Note (2) The default emissions intensity for this prescribed production variable is yet to be calculated and specified in the Schedule.

17.    Subsection 69(3) of Schedule 2

This item repeals the subsection to remove the default emissions intensity for refined lead.

18.    After subsection 88(4) of Schedule 2

This item inserts the default emissions intensity value for products covered by subsections 88(1) and (2) of Schedule 2 (dried gluten).

19.    After subsection 89(4) of Schedule 2

This item inserts the default emissions intensity value for products covered by subsections 89(1) and (2) of Schedule 2 (dried wheat starch).

20.    After subsection 90(4) of Schedule 2

This item inserts the default emissions intensity value for products covered by subsections 90(1) and (2) of Schedule 2 (wheat based glucose).

21.    After subsection 91(3) of Schedule 2

This item inserts the default emissions intensity value for wheat based dried distillers grain production variable in Schedule 2.

22.    After subsection 92(4) of Schedule 2

This item inserts the default emissions intensity value for ethanol-95 covered by subsections 92(1) and (2) of Schedule 2.

23.    After subsection 93(4) of Schedule 2

This item inserts the default emissions intensity value for ethanol-absolute covered by subsections 93(1) and (2) of Schedule 2

24.    After subsection 94(4) of Schedule 2

This item inserts the default emissions intensity value for beverage grade ethanol covered by subsections 94(1) and (2) of Schedule 2.

25.    Paragraph 4(4)(a) of Schedule 3

Paragraph 4(4)(a) of Schedule 3 refers to paragraph 4(1)(a) to (d). This cross-reference is incorrect as it should refer to paragraphs 4(3)(a) to (d). This item amends paragraph 4(4)(a) of Schedule 3 to correct this.

Table 1 at the end of Attachment A summarises Schedule 2 and 3 default emissions intensity values and indicates the additions from the Amendment Rule. The Amendment Rule does not contain any additional Schedule 3 prescribed (fixed) production variables.

Table 1: Summary of Schedule 2 and 3 of the Safeguard Mechanism Rule

The green shaded boxes indicate the new default emissions intensity values.

Attachment B

Statement of Compatibility with Human Rights

Prepared in accordance with Part 3 of the Human Rights (Parliamentary Scrutiny) Act 2011

National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Default Emissions Intensities) Rules 2022

This Rule is compatible with the human rights and freedoms recognised or declared in the international instruments listed in section 3 of the Human Rights (Parliamentary Scrutiny) Act 2011.

Overview of the legislative instrument

The National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Default Emissions Intensities) Rules 2022 (the Amendment Rule) inserts additional Government-determined default emissions intensity values into Schedule 2 of the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 (the Principal Rule). The Amendment Rule follows amendments to the Rule in March and October 2020, and October 2021, which set the majority of prescribed production variables and default emissions intensity values in Schedules 2 and 3.

It also inserts minor technical corrections to prescribed production variables set in the Safeguard Rule in 2020 and 2021 and removes the emissions intensity for refined lead due to an error that was identified.

Human rights implications

The Amendment Rule does not engage any of the applicable rights or freedoms.

The Amendment Rule inserts additional technical detail into the Principal Rule that is required to give effect to amendments to the Principal Rule made in March 2019. Whilst confidential information was collected and used during the development of the values, the legislative instrument does not involve personal information, and therefore the right to privacy is not limited by this legislative instrument. The legislative instrument does not authorise an unlawful interference with an individual’s privacy because it applies to large facilities whose responsible emitters are only likely to be large businesses, not individuals, and the legislative instrument adequately specifies the circumstances in which information may be collected.

As part of developing default emissions intensity values, confidential data on production and emissions intensity was collected from facilities operating in Australia. A guiding principle for this is protecting the confidentiality of sensitive industry data through the use of high quality and robust data. To preserve confidentiality, an average of multiple data points (over multiple facilities and multiple years) was taken rather than data from a single facility. Where a sector has one facility contributing data, these facilities were given the option to raise commercial confidentially issues with publishing the data with the Department.

Conclusion

This disallowable Legislative Instrument is compatible with human rights as it does not raise any human rights issues.

The Hon. Chris Bowen MP

Minister for Climate Change and Energy

Attachment C

Safeguard Mechanism: Prescribed production variables and default emissions intensities

PURPOSE OF THIS DOCUMENT

EMISSIONS INTENSITY VALUES

SCHEDULE 2 PRODUCTION VARIABLES

Manufacturing (other)

1. Bulk flat glass

2. Glass containers

3. Aluminium

4. Alumina

5. Ammonia

6. Ammonium nitrate

7. Carbamide (urea)

8. Ammonium phosphates

9. Sodium cyanide

10. Synthetic rutile

11. White titanium dioxide pigment

Coal mining

12. Run of mine coal

13. Coal mine waste gas

14. Fugitive emissions at a decommissioned underground coal mine

Iron ore mining

15. Iron ore

Other mining

16. Manganese ore

17. Bauxite

18. Heavy metal concentrate (mineral sands)

19. Run of mine metal ore

20. Non-metallic mineral quarrying

Oil and gas

21. Extracted oil and gas

22. Stabilised crude oil or condensate (stabilisation only)

23. Stabilised crude oil (integrated extraction and stabilisation)

24. Processed natural gas (processing only)

25. Processed natural gas (integrated extraction and processing)

26. Liquefied natural gas (from unprocessed natural gas)

27. Liquefied natural gas (from processed natural gas)

28. Ethane

29. Liquefied petroleum gas

30. Reservoir carbon dioxide

Steel manufacturing

31. Coke oven coke (integrated iron and steel manufacturing)

32. Lime (integrated iron and steel manufacturing)

33. Iron ore sinter (integrated iron and steel manufacturing)

34. Iron ore pellets (integrated iron and steel manufacturing)

35. Continuously cast carbon steel products and ingots of carbon steel (integrated iron and steel manufacturing)

36. Hot-rolled long products

37. Hot-rolled flat products

38. Continuously cast carbon steel products and ingots of carbon steel (manufacture of carbon steel products from cold ferrous feed)

39. Iron ore pellets (not from integrated iron and steel manufacturing)

40. Treated steel flat products

Rail transport

41. Net-tonne-kilometres of bulk freight on a dedicated line

42. Net-tonne-kilometres of bulk freight on a non‑dedicated line

43. Net-tonne-kilometres of non-bulk freight

44. Passenger-kilometres of rail passenger transport

Air transport

45. Revenue-tonne-kilometres of air transport

Road transport - freight

46. Non-bulk freight road transport

47. Non-bulk freight (temperature-controlled) road transport

48. Bulk freight road transport

49. Specialised and heavy haulage road transport

Road transport - passenger

50. Vehicle-kilometres of passenger road transport

Water transport

51. Bulk freight water transport

52. Deadweight-tonne-kilometres of mixed passenger and freight water transport

Wastewater

53. Wastewater handling (domestic and commercial)

Electricity

54. Electricity generation

Pipelines

55. Natural gas distribution

56. Fugitive emissions from transmission pipelines

57. Gas transmission

Clinker and cement

58. Clinker

59. Cement

60. Lime

Metal manufacturing

61. Silicon

62. Lead bullion

63. Refined lead

64. Zinc in fume

65. Caustic calcined magnesia

66. Copper anode

67. Manganese sinter

68. Ferromanganese alloy

69. Silicomanganese alloy

Nickel manufacturing

70. Primary nickel product (produced from nickel bearing inputs)

71. Primary nickel product (produced from imported intermediate nickel products)

72. Intermediate nickel product (produced from nickel bearing inputs)

Pulp and paper manufacturing

73. Tissue paper manufacturing

74. Packaging and industrial paper manufacturing

75. Printing and writing paper manufacturing

76. Newsprint manufacturing

77. Pulp manufacturing

Ethylene and polyethylene

78. Ethene (ethylene)

79. Polyethylene

Food manufacturing

80. Wheat Protein Products (Dried Gluten)

81. Dried Wheat Starch

82. Wheat Based Glucose

83. Wheat Based Dried Distillers Grain (DDG)

84. Ethanol—95

85. Ethanol—Absolute

86. Beverage Grade Ethanol

87. Raw Sugar

88. Exported steam related to the raw sugar manufacturing activity

SCHEDULE 3 PRODUCTION VARIABLES

89. Petroleum refining

Abbreviations and acronyms

PURPOSE OF THIS DOCUMENT

The purpose of this document is to define production variables for use in calculated baseline applications made under the Safeguard Mechanism.

They will be used for setting baselines using the following formula:

Each production variable definition identifies the emissions sources that can contribute to the calculation of an emissions intensity value.

There are two types of emissions intensity values:

• Default emissions intensity values: are set by the Government and published in the Safeguard Mechanism Rule. They represent the industry average emissions intensity of production over five years.
• Estimated (site-specific) emissions intensity values: are set by businesses. They represent the emissions intensity of production at an individual facility.

This document can help businesses to understand which emissions sources have been used in the development of the default emissions intensity values, and which emissions sources can be used in an estimated (site-specific) emissions intensity value calculation.

This document, known as the ‘Safeguard Mechanism document’, is referred to in section 6 of the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 (Safeguard Rule). It is available on the Department of Industry, Science, Energy and Resources website[2].

Background

Sources of emissions used in setting default emissions intensity values

Production variable definitions and default emissions intensity values are published in Schedules 2 and 3 of the Safeguard Rule.

• Schedule 2 production variables result in baselines that can be updated each year for actual production.
• Schedule 3 production variables result in baselines that are fixed.

Almost all production variables are in Schedule 2. Schedule 3 is intended to allow for circumstances where an appropriate output-based production variable could not be found, so a proxy has been used that is not appropriate for annual adjustment.

All facilities can access a transitional calculated baseline in 2018-19, 2019-20 or 2020-21. During this transitional phase, the use of default emissions intensity values is optional.

A facility with multiple outputs could use a combination of default and estimated (site‑specific) emissions intensity values. In these cases, it is important that emissions are not counted twice. That is, emissions should only be assigned to one production variable. In some cases, emissions from a particular process will need to be apportioned among two or more production variables.

The Safeguard Mechanism: Prescribed production variables and default emissions intensities document defines the production variables and specifies the sources of emissions used by the Department to calculate default emissions intensity values. It provides guidance for businesses and auditors on the emissions sources facilities can use in site-specific emissions intensity calculations and how apportioning should be done.

Sources of emissions that can be used by Responsible Emitters when setting an estimated (site-specific) emissions intensity for a prescribed production variable

Subsection 6(8B) of the Safeguard Rule establishes that where a facility uses an estimated (site-specific) emissions intensity value, the facility can only include emissions relevant to the calculation of the default emissions intensity value (or emissions relevant in defining the prescribed production variable wherever a prescribed production variable has no associated default emissions intensity). The inclusion lists will help businesses calculate estimated (site-specific) emissions intensity values.      

Defining prescribed production variables and default emissions intensities

The process of defining the production variables and default emissions intensity values has involved extensive stakeholder consultation and independent technical expert review. It was undertaken in accordance with the Framework for developing default production variables and emissions-intensity values (the Framework document). The Framework document was consulted on publicly as part of the consultation for the March 2019 amendments.    

Production variables and default emissions intensity values have been reviewed by an independent expert for adherence to the Framework document, including to check that the principles in the Framework document have been applied consistently across sectors.   

Production variable definitions and emissions source boundaries

The following sections set out the emissions sources that were either included in or excluded from default emissions intensity calculations, and specify which emissions sources can be included in the calculation of an estimated (site-specific) emissions intensity value for a prescribed production variable. Additional information is provided for most production variables in the mining, oil and gas sectors, as there are a wide variety of facility structures, with many facilities producing multiple products.

Emissions-intensity values

Table 1 (below) sets out the emissions-intensity values for each production variable. AR5 values apply to baselines that relate to 2020‑21 and later years.  

Note: Throughout this document, the terms ‘on-site’ and ‘off-site’ refer to the site of a facility.

EMISSIONS INTENSITY VALUES

Table 1: Emissions-intensity values

Schedule 2

SCHEDULE 3

SCHEDULE 2 PRODUCTION VARIABLES

Manufacturing (other)

1.                            Bulk flat glass

1.1.             Production variable definition

1. Tonnes of bulk flat glass that:

(a)            is produced as part of carrying on the bulk flat glass activity at the facility; and

(b)            is of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of producing bulk flat glass through the physical and chemical transformation of silica (silicon dioxide (SiO2)) and other raw and recycled materials (such as cullet) to produce bulk flat glass products, including wired glass and patterned glass, by controlled melting and forming in a contiguous process (the bulk flat glass activity).

1.2.             Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• melting, refining and conditioning;
• primary colouring, coating and trimming/cutting;
• secondary finishing of bulk flat glass such as secondary coating, laminating, toughening, mirroring, printing, cutting, edgeworking, insulating, glazing, encapsulating, extrusion assembling and moulding;
• complementary processes, such as packaging, head office, administrative and marketing operations where they are undertaken at the facility;
• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the facility or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity;
• furnaces, including to melt raw materials;

• cleaning of flat glass for reuse in its same physical form; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

Bulk flat glass production includes the float glass and rolled glass methods of production, as well as the sheet and plate glass methods of production.

The default emissions intensity value for the bulk flat glass activity includes all scope 1 NGER-reported emissions from the facilities relevant for setting the default intensity value, except scope 1 emissions from on-site electricity generation.

1.3.             Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• processes that do not occur within the facility:

• off-site cutting, polishing, and washing of glass;
• off-site processes such as: the extraction of silica; collection, sorting and transport of cullet; and secondary processing of flat glass products (such as secondary coating, laminating, toughening, mirroring, printing, cutting, polishing, washing, edge working, insulating, glazing, encapsulating, extrusion assembling and moulding); and

• on-site electricity generation.

2.                            Glass containers

2.1.             Production variable definition

1. Tonnes of blown and pressed glass containers that:

(a)            are produced as part of carrying on the glass containers activity at the facility; and

(b)            are of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of producing glass containers through the physical and chemical transformation of silica (silicon dioxide (SiO2)) and other raw and recycled materials (such as cullet) to produce blown or pressed glass containers, by controlled melting and forming in a contiguous process (the glass containers activity).

2.2.             Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• secondary finishing of glass containers such as printing / labelling, treatment for chemical resistance and coating;
• complementary processes, such as packaging, head office, administrative and marketing operations;
• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the facility or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity;
• furnaces;

• the washing and cleaning of a glass container for reuse in its same physical form; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

The production of glass containers includes the alternative processes of the production of borosilicate glass to produce borosilicate glass containers (such as pyrex) and the production of glass containers entirely from cullet.

To produce glass containers, the controlled melting and forming may use both the ‘blow and blow’ method and/or the ‘press and blow’ method.

The default emissions intensity value for the glass containers activity includes all scope 1 NGER-reported emissions from the facilities relevant for setting the default intensity value, except scope 1 emissions from on-site electricity generation.

2.3.             Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• the quarrying of silica;
• processes that do not occur within the facility:

• the off-site sorting and processing of cullet,
• the off-site processing of glass containers (such as labelling, treatment for chemical resistance and coating); and

• on-site electricity generation.

3.                            Aluminium

3.1.             Production variable definition

3.       Tonnes of primary aluminium (Al) that:

(a)            has a concentration of aluminium equal to or greater than 98%; and

(b)             is produced as part of carrying on the aluminium smelting activity at the facility; and

(c)             is weighed after electrolysis but before casting.

4.       The metric in subsection (1) is applicable to a facility that conducts the activity of aluminium smelting through the physical and chemical transformation of alumina (aluminium oxide (Al2O3)) into saleable aluminium metal (Al) (the aluminium smelting activity).

3.2.             Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity;

• electrolysis, including using a process commonly referred to as the Hall-Héroult Process;
• alloying and casting of primary aluminium into saleable aluminium metal;
• the production of anodes;
• waste heat recovery within the facility; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

The default emissions intensity value for the aluminium smelting activity includes all scope 1 NGER-reported emissions from the facilities relevant for setting the default intensity value, except scope 1 emissions from on-site electricity generation.

3.3.             Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• the production of alumina (aluminium oxide, Al203);
• the production of cathodes;
• the production of alloying materials;
• the smelting and associated casting of secondary aluminium metal (Al); 
• processes that do not occur within the facility, such as downstream processing of aluminium metal (Al) beyond the facility; and
• on-site electricity generation.

4.                            Alumina

4.1.             Production variable definition

1. Combined:

(a)             tonnes of alumina (aluminium oxide (Al2O3)) that:

 (i) has a concentration of aluminium oxide equal to or greater than 95%; and

 (ii) is produced as part of carrying on the alumina refining activity at the facility; and

 (iii) is of saleable quality; and

(b)             alumina equivalent tonnes of alumina trihydrate (Al(OH)3) that:

 (i) is produced as part of carrying on the alumina refining activity at the facility; and

 (ii) is of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of alumina refining through the physical and chemical transformation of bauxite (which is an ore containing mineralised aluminium compounds) into either or both of alumina (aluminium oxide (Al2O3)) with a concentration of aluminium oxide equal to or greater than 95% and alumina trihydrate (Al(OH)3) (the alumina refining activity).

4.2.             Inclusions

Note that this production variable includes production of specialty aluminas and hydrate (alumina trihydrate, Al(OH)3).

When converting alumina trihydrate (on a dry tonnes basis) to alumina equivalent tonnes, the following industry standard conversion formula should be used:

1 t Al(OH)3 = 0.6538 t Al2O3 (102/(2 x 78))

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, for example:

• machinery used to move materials within and as part of the activity;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where it involves the recovery of materials for re-use within the activity or is necessary for the activity to proceed as described;
• processing of waste materials from the activity;

• wet grinding, digestion, clarification, precipitation and calcination, including using a process commonly referred to as the ‘Bayer Process’;
• any bauxite residue processing which involves caustic liquor recovery for reuse in the activity;
• waste heat recovery within the facility;
• production of lime (calcium oxide compounds);
• production of feedstock caustic soda (sodium hydroxide, NaOH) besides that which is generated or recovered in the activity;
• the production of steam; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

The default emissions intensity value for the alumina refining activity includes all scope 1 NGER-reported emissions from the facilities relevant for setting the default intensity value, except scope 1 emissions from on-site electricity generation.

4.3.             Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• extraction (e.g. mining) and pre-processing (e.g. crushing) of bauxite prior to wet grinding, including washing and crushing at the bauxite mine;
• processes that do not occur within the facility; and
• on-site electricity generation.

5.                            Ammonia

5.1.             Production variable definition

5.       Tonnes of 100% equivalent anhydrous ammonia (NH3) contained within anhydrous ammonia that:

• has a concentration of ammonia equal to or greater than 98%; and
• is produced as part of carrying on the ammonia production activity at the facility; and
• is of saleable quality.

6.       The metric in subsection (1) is applicable to a facility that conducts the activity of producing ammonia through the chemical transformation of hydrocarbons (or other hydrogen feedstock) to hydrogen (H2) that is subsequently reacted with nitrogen (N2) to produce anhydrous ammonia (NH3) that has a concentration of ammonia (NH3) equal to or greater than 98% (the ammonia production activity).

5.2.             Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• chemical transformation of a hydrocarbon feedstock (or other hydrogen feedstock) to hydrogen;
• extraction of nitrogen from air, where the nitrogen is used for the ammonia production process;
• removal of carbon dioxide gas prior to the synthesis of ammonia;
• liquefaction of ammonia product;
• transfer and refrigeration of ammonia to/from storage within the facility;
• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity; and

• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all Scope 1 NGER-reported emissions from a facility can be assigned to a production variable, but where a facility produces multiple products, emissions cannot be counted more than once.

When calculating an estimated (site‑specific) emissions intensity values, a facility can assign emissions which do not relate to a specific output either to one production variable only, or apportion those emissions among production variables on a justifiable basis.

5.3.             Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• upstream production of the hydrogen feedstock (such as natural gas extraction and distribution or synthesis gas production);
• downstream processing of the ammonia into ammonium nitrate, urea or any other product;
• processes which do not occur within the facility; and
• on-site electricity generation.

6.                            Ammonium nitrate

6.1.             Production variable definition

7.       Tonnes of 100% equivalent ammonium nitrate (NH4NO3) contained within ammonium nitrate solution (NH4NO3(aq)) that:

(d)            has a concentration of ammonium nitrate (NH4NO3) equal to or greater than 60%; and

(e)            is produced as part of carrying on the ammonium nitrate production activity at the facility; and

(f)            is of saleable quality.

8.       The metric in subsection (1) is applicable to a facility that conducts the activity of producing ammonium nitrate through the chemical transformation of anhydrous ammonia (NH3) to ammonium nitrate solution (NH4NO3(aq)) that has a concentration of ammonium nitrate (NH4NO3) equal to or greater than 60% (the ammonium nitrate production activity).

6.2.             Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• catalytic oxidisation of ammonia to create nitric acid;
• reaction of nitric acid and ammonia to create ammonium nitrate;
• product prilling (drying and coating or conditioning), storage and despatch;
• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity; and

• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all Scope 1 NGER-reported emissions from a facility can be assigned to a production variable, but where a facility produces multiple products, emissions cannot be counted more than once.

When calculating estimated (site‑specific) emissions intensity values, a facility can assign emissions which do not relate to a specific output either to one production variable only, or apportion those emissions among production variables on a justifiable basis.

6.3.             Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• upstream production of the anhydrous ammonia feedstock;
• production of ammonium nitrate using nitric acid imported from a source off-site;
• processes that do not occur within the facility; and
• on-site electricity generation.

7.                            Carbamide (urea)

7.1.             Production variable definition

1. Tonnes of 100% equivalent carbamide (urea (CO(NH2)2)) on a dry weight basis that is:

(a)            contained within either of the following products:

(i)      carbamide solutions (urea (CO(NH2)2(aq)));

(ii)    saleable, granulated, prilled or other solid forms of carbamide (urea (CO(NH2)2(s))); and

(b)            produced as part of carrying on the urea production activity at the facility; and

(c)            contained within products of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of producing carbamide (urea (CO(NH2)2)) through the chemical transformation of carbon dioxide (CO2) and anhydrous ammonia (NH3) to produce carbamide solution (urea (CO(NH2)2(aq))) that:

(a)            has a concentration of carbamide (urea (CO(NH2)2)) equal to or greater than 80%; and

(b)            is subsequently used to produce either or both of:

(i)      carbamide solutions (urea (CO(NH2) 2(aq))); and

(ii)    saleable granulated, prilled or other solid forms of carbamide (urea (CO(NH2)2(s))).

3.       The activity in subsection (2) is the urea production activity.

7.2.             Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• reaction of carbon dioxide with anhydrous ammonia to create a carbamide solution;
• production of finished products through prilling, granulation etc.;
• product drying / conditioning, storage and despatch;
• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity; and

• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable, but where a facility produces multiple products, emissions cannot be counted more than once.

When calculating estimated (site‑specific) emissions intensity values, a facility can assign emissions which do not relate to a specific output either to one production variable only, or apportion those emissions among production variables on a justifiable basis.

7.3.             Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• upstream production of the anhydrous ammonia feedstock;
• production of carbon dioxide;
• processes that do not occur within the facility;
• on-site electricity generation.

8.                            Ammonium phosphates

8.1.             Production variable definition

9.       Tonnes of diammonium phosphate ((NH4)2HPO4) products and monoammonium phosphate ((NH4)H2PO4) products that:

(a)            have a concentration of diammonium phosphate or monoammonium phosphate equal to or greater than 70%; and

(b)            are produced as part of carrying on the ammonium phosphate production activity at the facility; and

(c)            have a free moisture content less than 2.5%; and

(d)            are of saleable quality.

10.   The metric in subsection (1) is applicable to a facility that conducts the activity of producing either or both of diammonium phosphate and monoammonium phosphate through:

(a)            the chemical transformation of phosphate rock to phosphoric acid (H3PO4); and

(b)            the chemical transformation of that phosphoric acid and anhydrous ammonia (NH3) to produce either or both of diammonium phosphate ((NH4)2H2PO4) and monoammonium phosphate ((NH4)H2PO4).

11.   The activity in subsection (2) is the ammonium phosphate production activity.

8.2.             Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the mining and beneficiation of phosphate rock;
• the reaction of phosphate rock with sulphuric acid to create phosphoric acid;
• reaction of phosphoric acid and ammonia to produce ammonium phosphates;
• product drying / conditioning, storage and despatch; 
• by-product (gypsum) handling and storage;
• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity; and

• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable, but where a facility produces multiple products, emissions cannot be counted more than once.

When calculating estimated (site‑specific) emissions intensity values, a facility can assign emissions which do not relate to a specific output either to one production variable only, or apportion those emissions among production variables on a justifiable basis.

8.3.             Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• upstream production of the anhydrous ammonia feedstock;
• production of sulphuric acid used as in an input into the conversion of phosphate rock to phosphoric acid;
• production of ammonium phosphates using phosphoric acid imported from a source off‑site;
• processes that do not occur within the facility; and
• on-site electricity generation.

9.                            Sodium cyanide

9.1.             Production variable definition

12.   Tonnes of 100% equivalent sodium cyanide (NaCN) on a dry weight basis that is contained within sodium cyanide products:

(g)            produced as part of carrying on the sodium cyanide production activity at the facility; and

(h)            of saleable quality.

13.   The metric in subsection (1) is applicable to a facility that conducts the activity of producing sodium cyanide through all of the following processes:

(i)            the chemical transformation of methane, anhydrous ammonia (NH3) and air to produce hydrogen isocyanine (HCN);

(j)            electrolysis of sodium chloride (NaCl) solution to produce caustic soda (NaOH);

(k)            the chemical transformation of hydrogen isocyanine (HCN) and caustic soda produce sodium cyanide (NaCN).

14.   The activity in subsection (2) is the sodium cyanide production activity.

9.2.             Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• production of hydrogen isocyanine;
• production of caustic soda;  
• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity; and

• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all Scope 1 NGER-reported emissions from a facility can be assigned to a production variable, but where a facility produces multiple products, emissions cannot be counted more than once.

When calculating estimated (site‑specific) emissions intensity values, a facility can assign emissions which do not relate to a specific output either to one production variable only, or apportion those emissions among production variables on a justifiable basis.

9.3.             Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• upstream production of the anhydrous ammonia feedstock;
• upstream production of the hydrogen feedstock (such as natural gas extraction and distribution or synthesis gas production);
• processes that do not occur within the facility; and
• on-site electricity generation.

10.                     Synthetic rutile

10.1.        Production variable definition

15.   Tonnes of synthetic rutile that:

(l)            has a titanium dioxide (TiO2) concentration equal to or greater than 88% and less than 95.5%; and

(m)            has an iron (Fe) concentration greater than 0.5%; and

(n)            are produced as part of carrying on the synthetic rutile production activity at the facility; and

(o)            are of saleable quality.

16.   The metric in subsection (1) is applicable to a facility that conducts the activity of producing synthetic rutile through the chemical transformation of ilmenite ore (ore containing FeTiO3) through the reduction of iron oxides in order to increase the titanium dioxide (TiO2) concentration to produce synthetic rutile that:

(p)            has a titanium dioxide (TiO2) concentration equal to or greater than 88% and less than 95.5%; and

(q)            has an iron (Fe) concentration greater than 0.5%.

Note: The transformation described in subsection (2) is known as the Becher process.

17.   The activity in subsection (2) is the synthetic rutile production activity.

10.2.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• oxidation process that involves heating the ilmenite in a rotary kiln with air to convert the iron in the ilmenite grains to iron(III) oxide;
• reduction process that involves further heating the oxidated ilmenite, with coal being used as reductant, in a rotary kiln to reduce the iron oxide in the mineral grains to metallic iron;
• aeration process that involves the removal of the metallic iron by rusting it out, commonly achieved in a continuously agitated tank that contain mile ammonium chloride solution with air being pumped through the tank;
• acid leaching process that involves removal of the remainder of iron oxide using mild sulfuric acid;
• mechanical handling and processing materials for the purpose undertaking the above processes;
• mineral separation process;
• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the facility or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity;
• furnaces;
• flaring; and

• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

The default emissions intensity value for the synthetic rutile production activity includes all scope 1 NGER-reported emissions from the facilities relevant for setting the default intensity value, except scope 1 emissions from on-site electricity generation.

10.3.        Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• upstream production of the ilmenite feedstock, such as mining;
• upstream production materials that are used in the oxidation, reduction, aeration and acid leaching processes, such as mining of coal, production of ammonium chloride or sulfuric acid;
• downstream processing of the synthetic rutile into products, such as titanium dioxide pigment, with a purity of titanium dioxide that is higher than 99.5%;
• processes that do not occur within the facility; and
• on-site electricity generation.

11.                     White titanium dioxide pigment

11.1.        Production variable definition

18.   Tonnes of white titanium dioxide (TiO2) pigment that:

(a)            conform with ASTM classification D476‑00 (2011); and

(b)            have an iron (Fe) concentration less than or equal to 0.5%; and

(c)            are produced as part of carrying on the white titanium dioxide pigment production activity at the facility; and

(d)            are of saleable quality.

Note:  In 2020, the standard could be accessed from http://www.astm.org.

19.   The metric in subsection (1) is applicable to a facility that conducts the activity of producing white titanium dioxide (TiO2) pigment through the chemical transformation of 1 or more of the following:

(a)            rutile (TiO2);

(b)            synthetic rutile (TiO2);

(c)            ilmenite (FeTiO3);

(d)            leucoxene;

(e)            titanium slag that has an iron (Fe) concentration of greater than or equal to 7%;

to produce white titanium dioxide (TiO2) pigment.

20.   The white titanium dioxide (TiO2) pigment produced under subsection (2) must:

(a)             conform with ASTM classification D476‑00 (2011); and

(b)             have an iron (Fe) concentration of less than or equal to 0.5%.

Note:          In 2020, the standard could be accessed from http://www.astm.org.

21.   The activity in subsection (2) is the white titanium dioxide pigment production activity.

11.2.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the reduction of inputs with carbon and oxidisation with chlorine to produce titanium tetrachloride;
• the distillation of titanium tetrachloride and re-oxidisation to produce white titanium dioxide pigment while re-generating chlorine for re-use;
• the use of machinery, equipment and processes for the chemical transformation described in the activity, including for example:

• machinery used to move materials within and as part of the activity;
• control rooms, laboratories maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• on-site processing of by-products and waste materials required to comply with Commonwealth, State or Territory obligations.

• waste heat recovery;
• production of nitrogen and oxygen consumed within the activity; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

The default emissions intensity value for the white titanium dioxide pigment activity includes all scope 1 NGER-reported emissions from the facilities relevant for setting the default intensity value, except scope 1 emissions from on-site electricity generation.

11.3.        Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• upstream production of rutile, synthetic rutile, ilmenite, titanium slag or leucoxene;
• production of hydrated titanium dioxide pigment (raw pigment) that is not further processed into saleable white titanium dioxide pigment;
• production of white titanium dioxide pigment that is produced from hydrated titanium dioxide pigment (raw pigment) that is not produced on site;
• processes that do not occur within the facility; and
• on-site electricity generation.

Coal mining

12.                     Run of mine coal

12.1.        Production variable definition

1. Tonnes of run-of-mine coal that is produced as part of carrying on the coal mining activity at the facility.

Note:          The coal may be sold with or without beneficiation.

2.       The metric in subsection (1) is applicable to a facility that:

(a)            conducts the coal mining activity; and

(b)            if it includes an underground coal mine—uses the coal mine waste gas production variable.

3.       The default emissions intensity is:

                      (a)  for a tonne of run-of-mine coal from an underground coal mine—the sum of:

                              (i)  the default run-of-mine coal emissions intensity value; and

                             (ii)  if section 3.4(6) of the NGER Measurement Determination applies to the coal mine—the factor EFj given by subsection 3.17(2) of the NGER Measurement Determination for the coal mine;

                        per tonne of run-of-mine coal.

                     (b)  for a tonne of run-of-mine coal from an open cut coal mine—the sum of:

                              (i)  the default run-of-mine coal emissions intensity value; and

                             (ii)  the emissions, in t CO2-e, calculated under section 3.20, 3.21 or 3.26 of the NGER Measurement Determination for the coal mine in the relevant report under the Act for the financial year divided by the tonnes of run-of-mine coal for the same year;

                        per tonne of run-of-mine coal.

Definition of coal mining activity

Where the activity of coal mining is the physical extraction of coal in an open-cut or underground coal mine and includes activities to enable the extraction of coal and post-mining activities.

12.2.        Scope of the activity

Saleable coal is the primary output from a coal mine. In some cases, the run-of-mine (ROM) coal is the saleable product, while in other circumstances the ROM coal requires beneficiation. Therefore, ROM coal can be an output or intermediate product depending on the facility circumstances. 

The production variable is for the production of coal from underground and open-cut mining processes. The scope of the production variable includes the processes required to extract the coal and to prepare for and undertake beneficiation.

Beneficiation can include:

• crushing so that the product coal is of relatively uniform size;
• washing and flotation to remove partings and lower ash content; and
• disposal of waste.

The production variable includes all development processes required to allow extraction of the coal, including development of new mining areas through the life of the facility. This includes land clearing, removal and storage of topsoil for later use, and rehabilitation of mined areas that occurs during the continued operation of the mine.

Coal is mined from both open-cut and underground mines, based on the physical characteristics of the mine geology and the most economically efficient mining method. Both open-cut and underground mining may be used for any particular coal seam, and separate seams mined at a single facility. Both mining methods are covered by this production variable.

Fugitive coal mine waste gas

Emissions from coal mine waste gas at an underground mine are excluded from the production variable. A coal mine waste gas production variable is available to provide a baseline component for fugitive emissions at underground coal mines.

Fugitive emissions at open-cut coal mines are included in this production variable using the factor EFj given by section 3.20 of the NGER Measurement Determination for the coal mine; per tonne of run-of-mine coal.

Fugitive emissions at an underground coal mine for post-mining fugitive emissions are allocated using the factor EFj given by subsection 3.17(2) of the NGER Measurement Determination where this applies to the coal mine; per tonne of

run-of-mine coal.

Open-cut mining of coal

Open-cut mining includes all forms of extraction that are not conducted underground. Open-cut mining involves the removal and storage of overburden and interburden material to allow access to the production coal seams. The overburden, interburden and coal are mined using drill and blasting techniques to break up the materials to allow extraction. Mining equipment includes draglines, hydraulic shovels, excavators, haul trucks, earth moving equipment and conveyor systems.

The primary source of scope 1 emissions is the combustion of liquid fuel – usually diesel – used in hydraulic shovels, excavators, bulldozers, haul trucks, drilling rigs and stationary diesel engines used for water management, electricity generation, and sometimes in-pit or primary ROM crushing. Major equipment items such as draglines commonly use electric power.

Emissions from blasting include the oxidation of hydrocarbons (diesel) mixed with other materials, usually ammonium nitrate, to generate the explosive reaction.

During the life of the mine, waste material will require multiple movements as the mine plan evolves. All movement of waste material within the facility is covered by the production variable.

The movement of coal within the mine may involve temporary storage intended to provide buffering for the crushing and beneficiation process and short-term storage of saleable coal (either ROM or washed coal) prior to shipment. Washery tailings are usually stored in a tailings pond.

As mining is completed in different parts of the facility the mined area is rehabilitated by profiling the surface to a finished level, replacing topsoil, and revegetation. The emissions from rehabilitation are included in the production variable.

Underground mining of coal

Underground mining, like open-cut mining, requires significant activity to prepare for the extraction of coal. Shallow underground mines may include the development of an access ramp allowing vehicles to access the underground mining areas for haulage of coal and waste material (during development) to the surface. Deeper mines would generally be developed with one or more vertical shafts to lift coal and possibly waste material (during development) to the surface. Underground mines also include vertical shafts for ventilation including powerful ventilation fans, and sometimes cooling water supply and other services such as electricity and communications.

Different mining techniques can be employed underground depending on the characteristics of the mine geology. The most common techniques are long-wall mining and continuous mining. In each case the primary mining equipment is electrically operated. There is minimal waste material during normal mining operations. Waste material is, when possible, left underground as backfill of previous voids. Coal, and waste when required, is brought to the surface for treatment (coal) or storage (coal and waste).

The primary source of scope 1 emissions from underground mining is from the combustion of liquid fuel – usually diesel – used in underground vehicles, haul trucks, and drilling rigs when access ramps are available, stationary engines used for water management, electricity generation and sometimes underground primary ROM crushing. Emissions from blasting will occur.

Beneficiation of ROM coal

A coal preparation plant (CPP; also known as a coal handling and preparation plant (CHPP), coal handling plant, prep plant, tipple or wash plant) is a facility that washes coal of soil and rock, crushes it into graded sized chunks (sorting), stockpiles grades preparing it for sale.

Measurement of ROM coal

The output of the activity is defined as tonnes of ROM coal, that is coal that is produced in the mining operations before screening, crushing or preparation of the coal has occurred. The measurement of this output is expected to be based on company records of the quantity of ROM coal mined and received for beneficiation or sale. The measurement of the output for the issue of a baseline is by tonne of ROM coal that is suitable to be: further processed on-site (or transferred to another facility) to produce a saleable product; or sold directly from the facility, where the coal was mined.

Mine rehabilitation

Rehabilitation for an individual mine or part of a mine may occur at a facility while other parts of the mine continue in operation, or at the end of life of the facility. The rehabilitation that occurs during the continued operation of the mine are included in the production variable. End of mine life rehabilitation is not included in the production variable.

12.3.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of on-site machinery, equipment and processes for the extraction and treatment of the ore described in the activity definition, including, for example:

• machinery used to:

­        prepare and remove topsoil and overburden to allow mining of ore;

­        develop underground access roadways;

­        install equipment required to move materials;

­        allow drainage of coal mine waste gas;

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• on-site processing of waste materials from the activity;

• beneficiation of coal including:

• crushing to size the coal;
• washing to remove waste material;
• sorting by coal quality;

• the supply of utilities such as, but not limited to, compressed air, cooling and water where these are used in support of the activity and within the facility;
• the regeneration of any solvents used within the activity;
• fugitive emissions from post-mining storage of coal from an underground mine where the average annual percentage of methane in VAM exceeds 0.1%;
• the storage and loading of the saleable coal into a medium of transportation such as trucks or rail trains;
• transportation of inputs used in the activity to storage at the facility, where the transport activity wholly occurs within the facility;
• transportation of the output of the activity from storage at the facility, where the transport activity wholly occurs within the facility;
• complementary processes, such as packaging, head office, administrative and marketing operations, which occur within the boundary of the facility that is undertaking the activity;
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value; and
• where the facility is (or includes) an open-cut coal mine, the fugitives emissions associated with the open-cut coal mine are included.

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

12.4.        Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• on-site electricity generation;
• processes that are included in the definition of another production variable, such as fugitive emissions from coal mine waste gas (CMWG) at an underground coal mine; and
• processes that do not occur within the facility.

13.                     Coal mine waste gas

13.1.        Production variable definition

1. Tonnes of CO2-e of unmitigated coal mine waste gas:

(a)             generated at the facility as part of carrying on the coal mining activity at the facility; and

(b)            not from a decommissioned underground mine.

Note:  This includes pre-mine drainage, mining phase activities and post mining activities creating coal mine waste gas in the relevant reporting period.

2.       The metric in subsection (1) is applicable to a facility that:

(a)            conducts the coal mining activity at an underground coal mine; and

(b)            uses the run-of-mine coal production variable.

3.       The t of CO2-e of unmitigated coal mine waste gas generated must be measured consistently with the NGER (Measurement) Determination.

Definition of coal mine waste gas

Where coal mine waste gas means a substance that:

• consists of:

• naturally occurring hydrocarbons; or
• a naturally occurring mixture of hydrocarbons and non‑hydrocarbons; and

• is:

• drained from:

­        an underground coal mine that is covered by a lease (however described) that authorises coal mining; or

­        a closed underground coal mine that is, or was, covered by a lease (however described) that authorises, or authorised, coal mining; or

• conveyed in a ventilation air shaft or duct to the surface of a mine mentioned in subparagraph (i).

Emissions-intensity calculation method

The method to allocate a baseline for fugitive emissions from an operating underground mine is to multiply the amount of fugitive emissions generated by a factor that represents a proportion to be captured and destroyed. Under this approach, fugitive emissions can be considered the ‘production variable’ and the factor representing the amount to capture and destroy the ‘emissions intensity’. This is an alternate approach to an output-based production variable because fugitive emissions are a waste stream (although some fugitive emissions captured can be sold as natural gas of saleable quality), not a final output or intermediate product, so the conventional meaning of emissions intensity cannot apply.

This alternative approach achieves a similar outcome to the standard method of allocating baselines: [amount of coal mine waste gas generated: “production”] x [factor representing amount to capture and destroy: “emissions intensity”]

The default emissions intensity is worked out as 1 – default capture rate, where this rate is calculated as the ratio of the amount of methane in CMWG destroyed to the amount generated. 

13.2.        Scope of the activity

The variable that is equivalent to the production variable is coal mine waste gas generated in the relevant reporting period as part of the extraction of coal from underground mining processes. The scope of the variable includes all sources of fugitive emissions:

• surface in-seam pre-mining drainage;
• underground in-seam pre-mining drainage;
• drainage of waste coal mine gas from the goaf (the mined area of an underground mine);
• waste coal mine gas entrained in ventilation air (VAM), excluding naturally occurring CO2 and emissions from fuels combusted underground;

The default CMWG capture rate takes into account all methods used for the destruction (beneficial or otherwise) of waste coal mine gas including but not limited to:

• combustion in a flare;
• combustion in a generator to produce electricity;
• combustion in a boiler;
• catalytic combustion (or similar) of VAM; and
• sale of waste coal mine gas that is of saleable quality.

CMWG generated and CMWG captured are measured in accordance with the methods described in the NGER (Measurement) Determination authorised for use in each reporting period.

Measurement of CMWG

The output metric of the activity is defined as tonnes of coal mine waste gas generated from mining processes at the facility during the reporting period expressed in t CO2-e before any emission abatement or transfer processes. The amount of CMWG is estimated in accordance with the methods described in the NGER (Measurement) Determination authorised for use in each reporting period. Measurement and records of CMWG generated is as required by the methods described in the NGER (Measurement) Determination authorised for use in the reporting period.

13.3.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• Emissions which result from CMWG sources at an underground mine.

13.4.        Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• processes that are included in the definition of another production variable, including the ROM coal production variable;
• processes that do not occur within the facility;
• on-site electricity generation;
• fugitive emissions from an open-cut mine;
• Post-mining fugitives from the storage of coal from an underground mine where the average annual percentage of methane in VAM exceeds 0.1%; and
• CMWG from a decommissioned underground mine.

14.                     Fugitive emissions at a decommissioned underground coal mine

14.1.        Production variable definition

1. Tonnes of CO2-e emissions reported under Division 3.2.4 of the NGER (Measurement) Determination for the facility.
2. The metric in subsection (1) is applicable to a facility that is a decommissioned underground mine.
3. The default emissions intensity is 1 t CO2-e per t CO2-e of reported emissions.
4. The t of CO2-e of emissions must be measured consistently with the NGER (Measurement) Determination.

Definition of decommissioned underground mine

Where decommissioned underground mine means an underground coal mine where the following activities have ceased to occur and are not expected to occur in the future:

• coal production;
• active mine ventilation, including the operation of ventilation fans at the mine.

Emissions-intensity calculation method

The method to allocate a baseline for fugitive emissions at a decommissioned coal mine is for the baseline to equal the amount of fugitive emissions reported by the facility. This is achieved by multiplying the amount of fugitive emissions generated at the decommissioned mine by 1. Under this approach, fugitive emissions can be considered the ‘production variable’ and the factor of 1 the ‘emissions intensity’. This is an alternative approach to using an output-based production variable because fugitive emissions are a waste stream, not a final output or intermediate product, so the correct interpretation of emissions intensity does not apply. This approach also recognises that the fugitive emissions at a decommissioned coal mine cannot be mitigated by a facility in a reporting sense, as they are reported on the basis of a decay curve based on the emissions in the final year of operation.

This alternative approach achieves a similar outcome to the standard method of allocating baselines: [amount of CMWG generated at the decommissioned mine: “production”] x [1: “emissions intensity”].

The metric for fugitive emissions at a decommissioned coal mine is applicable to a facility that is (or includes) a decommissioned underground coal mine on-site. The default ‘emissions intensity’ is 1.0 t CO2-e per tonne of fugitive emissions for the decommissioned underground coal mine.

14.2.        Scope of the activity

This production variable is intended to provide a baseline equal to the reported fugitive emissions from a decommissioned coal mine.

The NGER (Measurement) Determination provides methods to report coal mine waste gas (CMWG) emissions for decommissioned underground coal mines that are dependent on the level of fugitive emissions prior to decommissioning, and decrease over time. The appropriate method should be used.

Measurement of fugitive emissions from decommissioned mines

The output of the activity is defined as tonnes of fugitive coal mine waste gas estimated in accordance with the methods described in the NGER (Measurement) Determination authorised for use in each reporting period.

14.3.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the fugitive emissions as estimated by the applicable NGER method for decommissioned underground coal mines.

14.4.        Exclusions

Scope 1 emissions excluded from the prescribed production variable for fugitive emissions from decommissioned mines are those not reported as fugitive emissions from a decommissioned underground coal mine.

Iron ore mining

15.                     Iron ore

15.1.         Production variable definition

22.   Tonnes of iron ore, on a wet basis, that:

(a)            is produced as part of carrying on the iron ore mining activity at the facility; and

(b)            is of saleable quality.

23.   The metric in subsection (1) is applicable to a facility that conducts the activity of mining iron ore through:

(a)            the physical extraction of mineral ores that contain iron ore metal; and

(b)            the processing of the extracted ores to produce an iron ore product of saleable quality.

Note:  The processes may include crushing, screening, grinding, separation, concentrating, filtration and waste to tailings.

24.   The activity in subsection (2) is the iron ore mining activity.

15.2.        Scope of the activity

Hematite ore is the most common oxide mineral form requiring limited processing including crushing and screening. Magnetite ore requires additional processing to remove impurities. Magnetite ore processing leads to a concentrate.

The production variable includes all development processes required to allow extraction of the iron ore, including development of new mining areas through the life of the facility. This includes land clearing and removal and storage of topsoil for later use.

Iron ores are presently mined from open-cut mines in Australia. This production variable would apply to underground mines should they be developed.

Open-cut mining of iron ore

Open-cut mining involves the removal and storage of overburden material that allows access to the iron ore. The overburden and ore are mined using drill and blasting techniques to break up the materials to allow extraction, usually via excavator loading into trucks.

Dewatering is a significant activity at mines that are below the natural water table.

The primary source of scope 1 emissions is the combustion of liquid fuel – usually diesel – used in excavators, bulldozers, haul trucks, drilling rigs and stationary diesel engines used for water management, electricity generation, and sometimes in-pit or primary ROM crushing.

Emissions from blasting include the oxidation of hydrocarbons mixed with other materials, usually ammonium nitrate, to generate the explosive reaction.

During the life of the mine, material may require multiple movements as the mine plan evolves. All movement of waste material within the facility is covered by the production variable.

The hauling of ore for treatment may involve temporary storage intended to provide buffering for the milling process, or for longer-term storage of lower grade ores for later blending or treatment, often at the end of the mine life.

Underground mining of iron ore

Underground mining, like open-cut mining, requires significant activity to prepare for the extraction of ore for treatment. Shallow underground mines may include the development of an access ramp allowing vehicles to access the underground mining areas for haulage of ore and possibly waste to the surface. Deeper mines would generally be developed with one or more vertical shafts to lift ore and possibly waste material to the surface. Underground mines would also include vertical shafts for ventilation, and sometimes cooling water supply and other services such as electricity and communications.

Different mining techniques can be employed underground depending on the characteristics of the ore body. All involve drilling, blasting and movement of any waste required to access the ore. Waste material is, when possible, left underground as backfill of previous voids. Ore, and waste when required, is brought to the surface for treatment (ore) or storage (ore and waste).

The primary source of scope 1 emissions from underground mining is from the combustion of liquid fuel – usually diesel – used in underground vehicles, haul trucks, and drilling rigs when access ramps are available, stationary engines used for water management, electricity generation and sometimes underground primary ROM crushing. Emissions from blasting will occur.

Processing of iron ore

Some iron ore mines require limited or no additional processing. Crushing, screening to separate waste material and ore into fines and lumps for sale and washing. Large material may undergo further crushing and return to the separation process.

Other iron ore mines may require more significant processing which could include crushing, grinding, separation and filtration to produce a concentrate for sale with waste going to a tailings facility.

The processing of iron ore is primarily electrically driven machinery. Scope 1 emissions are primarily related to ore and material handling processes.

Measurement of saleable iron ore

The output of the activity is defined as tonnes of saleable iron ore. The measurement of this output is expected to be based on records of the quantity of saleable iron ore produced, measured on a wet basis (for magnetite concentrate measurement would occur after dewatering) using calibrated instruments or other industry standards as applicable. Evidence of the measurement may include third party transport bill of lading records or internal company production records. The measurement of the production variable is by tonne of saleable iron ore that is produced at the facility where the iron ore was mined.

Mine rehabilitation

Rehabilitation for individual mines may occur at a facility while other mines are operated, or at the end of life of the facility. The rehabilitation which occurs during the continued operation of the mine are included in the production variable. End of mine life rehabilitation is not included in the production variable.

15.3.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of on-site machinery, equipment and processes for the extraction and treatment of the ore to produce the iron ore product at the facility described in the activity definition, including, for example:

• machinery used to:

­        prepare and remove topsoil and overburden to allow mining of ore;

­        develop underground access pathways;

­        dewater mine areas;

­        install equipment required to move materials;

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• on-site processing of waste materials;

• the treatment of mined iron ore to size and separate iron ore from waste materials, including:

• crushing, grinding, screening and filtration to separate waste material and appropriately size material for sale or further processing;
• washing of ore;
• mineral recovery processes intended to return iron ore to the crushing and screening process;

• the supply of utilities such as, but not limited to, compressed air, cooling and water where these are used in support of the activity and within the facility;
• drilling and blasting using explosives and other equipment;
• the storage and loading of the iron ore product into a medium of transportation such as trucks or rail trains;
• transportation of inputs used in the activity to storage at the facility, where the transport activity wholly occurs within the facility;
• transportation of the output of the activity from storage at the facility, where the transport activity wholly occurs within the facility;
• complementary processes, such as packaging, head office, administrative and marketing operations, which occur within the boundary of the facility which is undertaking the activity; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

15.4.        Exclusions

Scope 1 emissions from the following processes were not included in the calculation of the default emissions intensity for the iron ore prescribed production variable:

• on-site electricity generation; and
• processes that do not occur within the facility.

Other mining

16.                     Manganese ore

16.1.         Production variable definition

1. Tonnes of manganese ore product, on a wet basis, that:

(a)            is produced as part of carrying on the manganese ore mining activity at the facility; and

(b)            is of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of mining manganese ore through:

(a)            the physical extraction of mineral ores that contain manganese metal; and

(b)            the processing of the extracted ores by crushing and separation into a manganese ore product.

3.       The activity in subsection (2) is the manganese ore mining activity.

16.2.        Scope of the activity

Manganese ore is mined in open-cut mines and undergoes crushing, screening and washing.

The production variable includes all development processes required to allow extraction of the manganese ore, including development of new mining areas through the life of the facility. This includes land clearing and removal and storage of topsoil for later use.

Open-cut mining of manganese ore

Open-cut mining involves the removal and storage of overburden material that allows access to the iron ore. The overburden and ore are mined using drill and blasting techniques to break up the materials to allow extraction, usually via excavator loading into trucks.

The primary source of scope 1 emissions is liquid fuel – usually diesel – used in excavators, bulldozers, haul trucks and stationary engines used for drilling, water management, and sometimes in-pit crushing.

Emissions from blasting include the oxidation of hydrocarbons mixed with other materials, usually ammonium nitrate, to generate the explosive reaction.

During the life of the mine, movement of waste material may require multiple movements as the mine plan evolves. All movement of waste material within the facility is covered by the production variable.

The hauling of ore for treatment may involve temporary storage intended to provide buffering for the milling process, or longer-term storage of lower grade ores for later blending or treatment, often at the end of the mine life.

Processing of manganese ore

Manganese ore mines require limited processing with some ore exported directly without processing. Crushing and the separation via screening of ore by fines and lump ore and removal of waste clay material by washing and gravity and cyclonic separation techniques.

The processing of manganese ore is primarily electrically driven machinery. Scope 1 emissions are limited to ore handling processes.

Measurement of saleable manganese

The output of the activity is defined as tonnes of saleable manganese. The measurement of this output is expected to be based on records of the quantity of saleable manganese measured on a wet basis using calibrated instruments or other industry standards as applicable. Evidence of the measurement may include third party transport bill of lading records or internal company production records. The measurement of the output for the issue of a baseline is by tonne of saleable manganese that is produced: at the facility; or transported away from the facility, where the manganese ore was mined.

Mine rehabilitation

Rehabilitation for individual mines may occur at a facility while other mines are operated, or at the end of life of the facility. The rehabilitation which occurs during the continued operation of the mine are included in the production variable. End of mine life rehabilitation is not included in the production variable.

16.3.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

•  the use of on-site machinery, equipment and processes for the extraction and treatment of the ore described in the activity definition, including, for example:

• machinery used to:

­        prepare and remove topsoil and overburden to allow mining of ore;

­        dewatering of mine areas;

­        install equipment required to move materials;

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• on-site processing of waste materials from the activity;

• the treatment of mined manganese ore to size and separate manganese ore from waste materials, including:

• crushing to produced fines and lumps of required size;
• washing process and separation processes for removal of waste material.

• the supply of utilities such as, but not limited to, compressed air, cooling and water where these are used in support of the activity and within the facility;
• drilling and blasting using explosives and other equipment;
• the storage and loading of the manganese ore product into a medium of transportation such as trucks or rail trains;
• transportation of inputs used in the activity to storage at the facility, where the transport activity wholly occurs within the facility;
• transportation of the output of the activity from storage at the facility, where the transport activity wholly occurs within the facility;
• complementary processes, such as packaging, head office, administrative and marketing operations, which occur within the boundary of the facility that is undertaking the activity; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

16.4.        Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• on-site electricity generation; and
• processes that do not occur within the facility.

17.                     Bauxite

17.1.         Production variable definition

1. Tonnes of bauxite product that:

(r)            is produced as part of carrying on the bauxite mining activity at the facility; and

(s)            is of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of mining bauxite through:

(a)            the physical extraction of aluminium ores such as gibbsite (Al(OH)3), boehmite (γ‑Aloo(OH)) and diaspore (α-AlO(OH)); and

(b)            the processing of the extracted ores into a bauxite product.

3.       The activity in subsection (2) is the bauxite mining activity.

17.2.        Scope of the activity

The production variable includes all development processes required to allow extraction of the bauxite, including development of new mining areas through the life of the facility. This includes land clearing and removal and storage of topsoil for later use.

Bauxites are presently mined by open-cut strip mining of shallow deposits.

Open-cut mining of bauxite

Open-cut mining involves the removal and storage of overburden material that allows access to the bauxite. The overburden is removed using truck and shovel techniques, with drill and blast only required when a substantial caprock layer is present. The bauxite is then extracted via excavator loading into trucks.

The primary source of scope 1 emissions is the combustion of liquid fuel – usually diesel – used in excavators, bulldozers, haul trucks, drilling rigs and stationary diesel engines used for water management, electricity generation, and sometimes in-pit or primary ROM crushing.

Emissions from blasting include the oxidation of hydrocarbons mixed with other materials, usually ammonium nitrate, to generate the explosive reaction.

During the life of the mine, material may require multiple movements as the mine plan evolves. All movement of waste material within the facility is covered by the production variable.

The hauling of ore for treatment may involve temporary storage intended to provide buffering for the separation process, or for longer-term storage of lower grade ores for later blending or treatment.

Processing of bauxite

Some bauxite mines require limited or no additional processing. Crushing, washing and screening to separate waste material and bauxite for sale

The processing of bauxite is primarily electrically driven machinery. Scope 1 emissions are limited to ore handling processes.

Measurement of saleable bauxite

The output of the activity is defined as tonnes of saleable bauxite suitable as a feedstock for processing into alumina. The measurement of this output is expected to be based on records of the quantity of saleable bauxite produced, measured using calibrated instruments or other industry standards as applicable. Evidence of the measurement may include third party transport bill of lading records or internal company production records. The measurement of the output for the issue of a baseline is by tonne of saleable bauxite suitable as a feedstock for processing into alumina: at the facility; or transported away from the facility, where the bauxite was mined.

Mine rehabilitation

Rehabilitation for individual mines may occur at a facility while other mines are operated, or at the end of life of the facility. The rehabilitation that occurs during the continued operation of the mine are included in the production variable. End of mine life rehabilitation is not included in the production variable.

17.3.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of on-site machinery, equipment and processes for the extraction and treatment of the ore described in the activity definition, including, for example:

• machinery used to:

­        prepare and remove topsoil and overburden to allow mining of ore;

­        install equipment required to move materials;

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• on-site processing of waste materials from the activity;

• the treatment of mined bauxite to size and separate bauxite from waste materials, including:

• crushing;
• washing and screening to separate waste material;
• mineral recovery processes intended to return bauxite to the crushing and screening process;

• the supply of utilities such as, but not limited to, compressed air, cooling and water where these are used in support of the activity and within the facility;
• the storage and loading of the bauxite product into a medium of transportation such as trucks or rail trains;
• transportation of inputs used in the activity to storage at the facility, where the transport activity wholly occurs within the facility;
• transportation of the output of the activity from storage at the facility, where the transport activity wholly occurs within the facility;
• complementary processes, such as packaging, head office, administrative and marketing operations, which occur within the boundary of the facility that is undertaking the activity; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

17.4.        Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• on-site electricity generation; and
• processes that do not occur within the facility.

18.                     Heavy metal concentrate (mineral sands)

18.1.         Production variable definition

25.   Tonnes of heavy metal concentrate, on a wet basis, that:

(a)            is suitable as a feedstock for a mineral separation process; and

(b)            is produced as part of carrying on the mineral sands mining activity at the facility; and

(c)            is of saleable quality.

26.   The metric in subsection (1) is applicable to a facility that conducts the activity of mining mineral sands through:

(a)            the physical extraction of mineral sands such as ilmenite, zircon, rutile, leucoxene and monazite; and

(b)            the processing of the extracted mineral sands by crushing and separation into a heavy metal concentrate.

27.   The activity in subsection (2) is the mineral sands mining activity.

18.2.        Scope of the activity

The term ‘mineral sands’ refers to ores containing heavy minerals including ilmenite, rutile, leucoxene, and zircon. Ilmenite, leucoxene, and rutile are titanium bearing minerals used mainly as feedstock for the production of titanium dioxide pigments. Zircon is a zirconium bearing mineral used for the manufacture of ceramics and refractories and in a range of industrial and chemical applications. Monazite is a rare earth bearing mineral found within heavy mineral sand deposits in Australia. Monazite is rich in thorium and is not widely exploited in Australia due mainly to the very limited market for monazite.

Mining of mineral sands ores is carried out either by dry mining methods or wet dredging techniques. Dry mining methods utilise heavy machinery such as scrapers to collect and transport ore located above the water table into a hopper for subsequent processing. Dry mining methods generate significant scope 1 emissions from fuel use.

Dredge mining, or wet mining, is best suited to ore reserves below the water table. Dredging involves cutting the ore under the surface of a pond and using a bucket well and suction to pump the ore in slurry form to a concentrator for separation and processing. Wet mining is primarily electricity based.

The ore is then transported (in slurry form) to a concentrator plant for separation and processing.

The production variable includes all development processes required to allow extraction of the mineral sands, including development of new mining areas through the life of the facility. This includes land clearing and removal and storage of topsoil for later use.

Mining of mineral sands

The primary source of scope 1 emissions is the combustion of liquid fuel – usually diesel – used in excavators, bulldozers, haul trucks, drilling rigs and stationary diesel engines used for dredging and water management, electricity generation, and sometimes in-pit or primary ROM crushing.

During the life of the mine, material may require multiple movements as the mine plan evolves. All movement of waste material within the facility is covered by the production variable.

The hauling of mineral sands for treatment may involve temporary storage intended to provide buffering for the concentrating process.

Processing of mineral sands

Water is added to the mineral sands to wash the slurry through a series of spiral separators that use gravity to separate the heavy mineral sands from lighter quartz sand, rock and clay. The slurry is primary separation process step is the production of a heavy mineral concentrate (HMC) using a wet gravity separation technique. The ore is washed through a series of spiral separators that utilise sizing and gravity differentiation to separate the heavy minerals from the accompanying clay, quartz sand and rock. The concentrate obtained from this process contains a mix of valuable heavy minerals as well as other non-valuable heavy mineral components and waste. The separation process produces mineral concentrate.

The heavy metal concentrate undergoes secondary processing to separate the individual minerals. Secondary processing to separate minerals is primarily an electrically driven process. This secondary processing is not included within this production variable.

Measurement of saleable heavy metal concentrate

The output of the activity is defined as tonnes of saleable heavy metal concentrate product suitable as a feedstock for mineral separation processes measured on a wet basis. The measurement of this output is expected to be based on records of the quantity of saleable heavy metal concentrate measured on a wet basis using calibrated instruments or other industry standards as applicable. Evidence of the measurement may include third party transport bill of lading records or internal company production records. The measurement of the production variable is by tonne of saleable heavy metal concentrate suitable as a feedstock for mineral separation processes: at the facility; or transported away from the facility.

Mine rehabilitation

Rehabilitation for individual mines may occur at a facility while other mines are operated, or at the end of life of the facility. The rehabilitation that occurs during the continued operation of the mine are included in the production variable. End of mine life rehabilitation is not included in the production variable.

18.3.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of on-site machinery, equipment and processes for the extraction by dry mining methods and treatment of the mineral sands described in the activity definition, including, for example:

• machinery used to:

­        prepare and remove topsoil and overburden to allow mining of mineral sands;

­        install equipment required to move materials;

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• on-site processing of waste materials from the activity;

• the treatment of mined mineral sands to separate mineral sands from waste materials to form a heavy metal concentrate, including:

• washing and screening to separate waste material;
• mineral recovery processes intended to return mineral sands to the separation process;

• the supply of utilities such as, but not limited to, compressed air, cooling and water where these are used in support of the activity and within the facility;
• the storage and loading of the heavy metal concentrate product into a medium of transportation such as trucks or rail trains;
• transportation of inputs used in the activity to storage at the facility, where the transport activity wholly occurs within the facility;
• transportation of the output of the activity from storage at the facility, where the transport activity wholly occurs within the facility;
• complementary processes, such as packaging, head office, administrative and marketing operations, which occur within the boundary of the facility that is undertaking the activity; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

18.4.        Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• on-site electricity generation;
• secondary processing of heavy metal concentrate to separate the individual minerals; and
• processes that do not occur within the facility.

19.                     Run of mine metal ore

19.1.         Production variable definition

28.   Tonnes of run-of-mine metal ore that:

(a)            contains 1 or more metals; and

(b)            is produced as part of carrying on the metal ore mining and processing activity at the facility; and

(c)            is of saleable quality; and

(d)            has not been counted, in whole or part, for another production variable at the facility; and

(e)            is not eligible to be the bauxite, manganese ore or iron ore prescribed production variable.

29.   The metric in subsection (1) is applicable to a facility that conducts the activity of mining and processing metal ore through:

(a)            the physical extraction of mineral ores containing metals; and

(b)            the processing of the extracted ores to produce a metal product or feedstock material.

30.   The activity in subsection (2) is the metal ore mining and processing activity.

19.2.        Scope of the activity

The production variable is run-of-mine metal ore, however the activity includes not just the processes required to extract the ore, but also those for on-site processing of the ore, such as into metal concentrates and bars. Processing can include:

• metal ores produced via a pyrometallurgical process from sulphate ores. Metal concentrate is produced at most metal sulphate mines and subsequently used as a feedstock for smelters to produce metals (smelting is excluded from the activity);
• alternative processing techniques, such as heap leaching and solvent extraction or electrowinning can be used for low grade metal ores, resulting in direct metal production.

If the processed outputs meet the definitions of other production variables, then the ROM metal ore production variable is not applicable, such as iron ore or bauxite.

The production variable includes all development processes required to allow extraction of the metal bearing ore, including development of new mining areas through the life of the facility. This includes land clearing and removal and storage of topsoil for later use.

Metal ores are mined from both open-cut and underground mines, based on the physical characteristics of the mine and the most economically efficient mining method. Both open-cut and underground mining may be used for any particular ore body, and separate ore bodies mined at a single facility. Both mining methods are covered by this production variable.

Open-cut mining of metal ore

Open-cut mining involves the removal and storage of overburden material to allow access to the metal bearing ore. The overburden and ore are mined using drill and blasting techniques to break up the materials to allow extraction, usually via excavator loading into trucks.

The primary source of scope 1 emissions is the combustion of liquid fuel – usually diesel – used in excavators, bulldozers, haul trucks, drilling rigs and stationary diesel engines used for water management, electricity generation, and sometimes in-pit or primary ROM crushing.

Emissions from blasting include the oxidation of hydrocarbons mixed with other materials, usually ammonium nitrate, to generate the explosive reaction.

During the life of the mine, waste material may require multiple movements as the mine plan evolves. All movement of waste material within the facility is covered by the production variable.

The hauling of ore for treatment may involve temporary storage intended to provide buffering for the milling process, or for longer-term storage of lower grade ores for later blending or treatment, often at the end of the mine life.

Underground mining of metal ore

Underground mining, like open-cut mining, requires significant activity to prepare for the extraction of ore for treatment. Shallow underground mines may include the development of an access ramp allowing vehicles to access the underground mining areas for haulage of ore and possibly waste to the surface. Deeper mines would generally be developed with one or more vertical shafts to lift ore and possibly waste material to the surface. Underground mines would also include vertical shafts for ventilation, and sometimes cooling water supply and other services such as electricity and communications.

Different mining techniques can be employed underground depending on the characteristics of the ore body. All involve drilling, blasting and movement of any waste required to access the ore. Waste material is, when possible, left underground as backfill of previous voids. Ore, and waste when required, is brought to the surface for treatment (ore) or storage (ore and waste).

The primary source of scope 1 emissions from underground mining is from the combustion of liquid fuel – usually diesel – used in underground vehicles, haul trucks, and drilling rigs when access ramps are available, stationary engines used for water management, electricity generation and sometimes underground primary ROM crushing. Emissions from blasting will occur.

Processing of metal ore via grinding, separation and flotation

Grinding of hard rock ore may require multiple stages to reduce the particle size of mineral ore to a required size to allow formation of metal grains in a slurry prior to beneficiation by flotation. Grinding is generally electrically driven.

The flotation process involves the addition of chemical flocculant such as xanthates to increase the hydrophobic properties of the metallic mineral grains to separate the metal from the water slurry. Compressed air injection or other mixing processes are used to form air bubbles that capture the hydrophobic mineral grains and rise to the surface, forming a froth. The froth is mechanically removed, producing a concentrate of the metal mineral. The waste materials are sent to a tailings dam for storage. The flotation and separation process are generally electrically driven.

The collected metal mineral slurry from the flotation process are sent to a hydrocyclone to thicken the slurry by reducing the water content. Hydraulic presses may then be used to further dry the metal concentrate.

Processing of metal ore via leaching

Various leaching options are available for metal extraction including chemical and biological leaching. The majority of emissions expected to be covered by this production variable will result from the mining rather than processing processes.

Measurement of ROM metal ore

The output of the activity is defined as tonnes of ROM metal ore, that is, ROM metal ore produced by mining operations that is suitable for (or has been through) primary crushing. The measurement of this output is expected to be based on company records of the quantity of ROM ore mined or other industry measurement standards as applicable. The measurement of the output for the issue of a baseline is by tonne of ROM that is produced, which is suitable for: processing into concentrate, metal bar or other feedstock at the facility; or transportation away from the facility.

Mine rehabilitation

Rehabilitation for an individual mine or part of a mine may occur at a facility while other parts of the mine continue in operation, or at the end of life of the facility. The rehabilitation that occurs during the continued operation of the mine are included in the production variable. End of mine life rehabilitation is not included in the production variable.

19.3.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of on-site machinery, equipment and processes for the extraction and treatment of the ore described in the activity definition, including, for example:

• machinery used to:

­        prepare and remove topsoil and overburden to allow mining of ore;

­        develop underground access roadways;

­        dewatering mine areas;

­        install equipment required to move materials.

• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• machinery used to generate electricity that is not reported as electricity production in an NGER report;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• on-site processing of waste materials from the activity;

• the treatment of mined ore to separate metal bearing ore from waste materials and concentrating one or more metals that are subsequently contained in a solution form predominantly containing metal, including:

• crushing and grinding to produce a fine mineral slurry;
• flotation, leaching and adsorption process that separates the metal bearing ore from the waste material;
• thickening of metal containing slurry to reduce water content;
• electrochemical processes to separate metal species from a flocculant used in an adsorption process;
• drying and preparation for transport of metal concentrate;
• drying of pregnant eluate and preparation for a furnace;
• smelting the metals and setting in metal bars;
• mineral recovery processes intended to return metal ore to the flotation circuit.

• Alternative treatment processes that produce metal in a solution including:

• heap leaching & insitu leaching involving chemical or acid reagents;
• pressurised vessel leaching involving chemical or acid reagents;
• bio-leaching using microbes to extract the metal from the ore;

• waste heat recovery within the activity;
• drilling and blasting using explosives and other equipment;
• the supply of utilities such as, but not limited to, compressed air, cooling and water where these are used in support of the activity and within the facility;
• the regeneration of any solvents used within the activity;
• the storage and loading of the metal concentrate into a medium of transportation such as trucks or rail trains;
• transportation of inputs used in the activity to storage at the facility, where the transport activity wholly occurs within the facility;
• transportation of the output of the activity from storage at the facility, where the transport activity wholly occurs within the facility;
• complementary processes, such as packaging, head office, administrative and marketing operations, which occur within the boundary of the facility that is undertaking the activity; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

19.4.        Exclusions

Scope 1 emissions from the following processes were not included in the default emissions intensity calculation for this production variable, and must be excluded from the calculation of an estimated (site‑specific) emissions intensity value for the production variable:

• on-site electricity generation; and
• processes that do not occur within the facility.

20.                     Non-metallic mineral quarrying

20.1.         Production variable definition

1. Tonnes of quarried rock that:

(a)            contains 1 or more minerals that are not metals; and

(b)            is produced as part of carrying on the non-metallic mineral quarrying activity at the facility; and

(c)            is either:

1.  of saleable quality at the mine; or
2. suitable as a feed source of 1 or more non-metallic minerals for production of other processed products; and

(d)            has not been counted for another production variable at the facility; and

(e)            is not eligible to be a prescribed production variable for the metal ore or coal mining sectors.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of quarrying non-metallic minerals through:

(a)            the physical extraction of rock containing 1 or more minerals that are not metals; and

(b)            the processing of the extracted rock to produce a non-metallic mineral product or feedstock material, such as aggregates for the construction industry.

3.       The activity in subsection (2) is the non-metallic mineral quarrying activity.

20.2.        Scope of the activity

The activity includes the processes required to extract the non-metallic rock, as well as basic on-site processing of the extracted material to make it suitable as a feedstock or final product. Typical quarried products are aggregates for the construction industry as well as stones such as limestone, sandstone, marble and granite.

Quarrying involves the removal and storage of overburden material to allow access to the minerals. The overburden and rock are quarried using drill and blasting techniques to break up the materials to allow extraction, usually via excavator loading into trucks.

The primary source of scope 1 emissions is the combustion of liquid fuel – usually diesel – used in excavators, bulldozers, haul trucks and stationary diesel engines for electricity generation.

Emissions from blasting include the oxidation of hydrocarbons mixed with other materials, usually ammonium nitrate, to generate the explosive reaction.

Movement of waste material associated with the quarry is covered by the production variable, as is the development processes required to allow extraction of the quarried material, including land clearing and removal and storage of topsoil for later use.

Crushing and screening of the rock to remove waste material may be needed to ensure the product is suitable as a feedstock at the same facility or for off-site transport. These processes are generally electrically driven.

20.3.        Inclusions

For the purposes of the development of the default emissions intensity value and the preparation of an estimated (site‑specific) emissions intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of on-site machinery, equipment and processes for the extraction and treatment of the rock described in the activity definition, including, for example:

• machinery used to prepare and remove topsoil and overburden to allow quarrying;
• machinery used to move materials within the facility, including mobile equipment;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• processing of by-products and waste materials from the activity;

• waste heat recovery within the activity;
• the supply of utilities such as, but not limited to, natural gas used in heating baths, compressed air, nitrogen, steam and water where these are used in support of the activity and within the activity boundary
• drilling and blasting using explosives and other equipment;
• transportation of inputs used in the activity to storage at the facility, where the transport activity wholly occurs within the facility;
• transportation of the output of the activity from storage at the facility, where the transport activity wholly occurs within the facility;
• complementary processes, such as packaging, head office, administrative and marketing operations, which occur within the boundary of the facility that is undertaking the activity; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

Oil and gas

21.                     Extracted oil and gas

21.1.        Production variable definition

1. Total gigajoules of the following products that meet the requirements of subsection (2):

(a)            unprocessed natural gas;

(b)            unstabilised crude oil and condensate.

2.       The requirements for products to be included in subsection (1) are that the products:

(a)            consist of

(i)      naturally occurring hydrocarbons; or

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

(b)            are extracted from a naturally occurring petroleum reservoir as part of carrying on the oil and gas extraction activity at the facility; and

(c)            at the time of measurement for the production variable, have undergone minimal or partial processing that is either:

(i)      sufficient only to allow efficient transportation of the product to processing facilities; or

(ii)    less than required to be considered processed natural gas or saleable crude oil or condensate; and

(d)            are not consumed in carrying on the oil and gas extraction activity.

3.       The metric in subsection (1) is applicable to a facility that conducts the activity of oil and gas extraction through the production of a hydrocarbon stream from a naturally occurring petroleum reservoir and either:

(a)            transports the produced stream of products covered by subsection (1) to the upstream boundary of a separate facility that conducts one or more of the following activities:

(i)      natural gas processing;

(ii)    processed or unprocessed natural gas liquefaction;

(iii)   crude oil or condensate stabilisation; or

(b)            transfers the products covered by subsection (1) to downstream processes within the same facility to produce multiple products.

4.       The activity in subsection (3) is the oil and gas extraction activity.

21.2.        Scope of the activity

The extraction of unprocessed natural gas and unstabilised crude oil and/or condensate is the production of a fluid stream from a naturally occurring petroleum reservoir (which could include an unconventional source, such as coal seam gas or shale oil), that may contain gas, crude oil, condensate, natural gas liquids and non-hydrocarbon components, in a gaseous, liquid and/or mixed liquid and gaseous state, and may include transportation of the fluid stream to a facility or facilities for processing.

The produced stream may undergo a treatment stage where crude oil, condensate, natural gas liquids and/or water are separated from the gas stream and the gas stream may be compressed to allow transportation for processing. Before compression, minimal processing of the gas stream may occur to allow efficient transportation of the gas. Partial processing of the gas, such as partial acid gas removal or separation of natural gas liquids, may also occur. The unprocessed natural gas is transported by pipeline to a separate downstream facility for processing, or may be transferred for processing within the same facility which produces multiple outputs.

The liquid components may undergo a treatment stage where bulk gases and water are removed. Following such processing, the liquids are transported either with the gas or separately to the same or a different facility for processing. Partial processing of the crude oil/condensate, such as some additional gas removal, may occur. However, the crude oil/condensate produced as an output from this partial processing does not meet the standard defined in the crude oil and condensate production variable (for example, it is not stabilised and is not of a saleable quality), and hence remains unprocessed crude oil/condensate.

The activity may include the re-injection of produced fluids (liquid hydrocarbon or water and gas), where the re-injection is undertaken for the purpose of either safely disposing of by‑product or for the purposes of secondary or tertiary hydrocarbon recovery. This activity does not include gas re-injection into a natural or constructed reservoir and subsequent gas withdrawal as a storage facility operated to meet variations in gas supply and demand.

The activity does not apply to production from facilities that only extract and process crude oil into stabilised crude oil, as this is intended to be covered by the stabilised crude oil (extraction and stabilisation) production variable.

The outputs of the activity are GJ of unprocessed natural gas and unstabilised crude oil/condensate. The measurement of this output is expected to be conducted so that it does not include any GJ of unprocessed natural gas or unstabilised crude oil/condensate that are consumed within the activity. The measurement of the production variable is as GJ of unprocessed natural gas and unstabilised crude oil/condensate that are transported, as a gas and/or liquid, away from the activity.

The activity does not include the downstream processing of the natural gas or the crude oil/condensate and other associated liquids.

21.3.        Inclusions

For the purposes of calculating the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility should be included:

• The use of machinery, equipment and processes for the activity as described in the activity definition, including, for example:

• machinery used to move materials within and as part of the activity, including machinery required to lift the crude oil from the petroleum reservoir if required;
• control rooms, laboratories, and maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• on-site processing and/or disposal of waste materials, such as wastewater, from the activity;
• machinery used for secondary or tertiary enhanced oil recovery, such as chemical or water injection, gas injection, carbon dioxide enhanced oil recovery;

• partial treatment of the produced hydrocarbon stream that can be subsequently transported to a downstream facility for processing, using processes including, for example:

• bulk water removal (such as emissions associated with the separation of water from the extracted natural gas or crude oil and flaring of entrained hydrocarbons in this water);
• separation of gas from liquids;
• injection of additives such as corrosion inhibitor to allow efficient transportation of the gas or liquid;
• removal of sulphur compounds;
• removal of reservoir CO2 (the separated reservoir CO2 is not included and must be reported separately, but the emissions associated with the process of separating the reservoir CO2 are included);

• any flaring, leaks or venting of greenhouse gases associated with the activity, except reservoir CO2;
• the short-term buffer storage of hydrocarbon liquids produced in the extraction activity, where the volume of that buffer storage is designed specifically to allow efficient loading into transportation systems, such as tankers or pipelines, at a frequency and rate determined by the facility’s off-take requirements;
• field compression of the unprocessed natural gas and/or pumping of unstabilised crude oil and condensate associated with the gathering of the fluids upstream of any treatment carried out as part of the activity;
• compression of the unprocessed natural gas and/or pumping of unstabilised crude oil and condensate to transfer the fluids to the downstream activity boundary;
• the supply of utilities such as, but not limited to, compressed air, nitrogen, steam and water where these are used in support of the activity and within the activity boundaries;
• the regeneration of any catalysts or solvents, if the regeneration is undertaken within the activity;
• recovery/capture and use of waste heat/energy within the activity; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

21.4.        Exclusions

For the purposes of calculating the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility should be excluded:

• reservoir CO2 that is separated from the hydrocarbon stream as part of the extraction activity, as reservoir CO2 is reported under its own production variable;
• processes which do not occur within the facility; and
• on-site electricity generation.

21.5.        Multiple production variables from the same facility

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

22.                     Stabilised crude oil or condensate (stabilisation only)

22.1.        Production variable definition

1. Total gigajoules of the crude oil and condensate that:

(a)            are a mixture of hydrocarbons that are liquid at atmospheric pressure (101.325 kilopascals) and ambient temperature; and

(b)            can be safely stored and transported at atmospheric pressure and ambient temperature; and

(c)            are produced as part of carrying on the crude oil or condensate stabilisation activity at the facility; and

(d)            are not consumed in carrying on the crude oil or condensate stabilisation activity; and

(e)            are of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of crude oil or condensate stabilisation through the physical transformation of either or both of unstabilised crude oil and condensate, which may be a mixture of liquids and gases, into stabilised crude oil and condensate that:

(a)            is in a liquid state; and

(b)            has a vapour pressure of less than 101.325 kilopascals; and

(c)            is safe to store and transport at atmospheric pressure and ambient temperature.

3.       The activity in subsection (2) is the crude oil or condensate stabilisation activity.

22.2.        Scope of the activity

This production variable applies to facilities that produce stabilised crude oil or condensate, typically as one of multiple hydrocarbon products. It does not apply to facilities that extract the well fluid and subsequently produce stabilised crude oil or condensate as the only saleable hydrocarbon product. These facilities should use the stabilised crude oil (extraction and stabilisation) production variable.

The production of stabilised crude oil or condensate is the separation of crude oil or condensate from a mixture that may contain crude oil, condensate, natural gas and non-hydrocarbon components, in a liquid and/or mixed liquid and gaseous state on entering the activity, into crude oil or condensate that is stable in a liquid state at atmospheric pressure and ambient temperature, and that is in a liquid state on leaving the activity.

The activity involves the stabilisation of unstabilised crude oil and/or condensate, which is taken from a crude oil or natural gas extraction activity or from an alternative source such as an unstabilised crude oil or condensate pipeline. It may include a feed treatment stage where bulk water is removed. Following such processing, the predominantly liquid mixture is stabilised by removing some of the dissolved light hydrocarbon and non-hydrocarbon components to reduce the vapour pressure, for example by passing it through several stages of separation at increasingly lower pressures, or via a stabilisation (distillation) column.

Hydrocarbons contained in the unstabilised crude oil and/or condensate stream may be processed into other products, such as processed natural gas, ethane and LPG. However, the processing steps unique to these other products are not part of the activity.

It is intended that alternative forms of production that do not require the feed treatment stage would be considered to fit within the activity definition, so long as at least stabilisation of crude oil and/or condensate takes place at the facility.

The outputs of the activity are GJ of crude oil or condensate. The measurement of this output is to be conducted so that it does not include any GJ of crude oil or condensate that are consumed during the activity. The measurement of the production variable is as GJ of crude oil or condensate of saleable quality that are transported, as a liquid, away from the facility where the crude oil or condensate was stabilised.

The activity does not include the upstream extraction or production of unstabilised crude oil and condensate to feed the activity. Further, the activity does not include the downstream processing of the stabilised crude oil including refining into petroleum products such as petrol, jet fuel, diesel, lubrication oil, bitumen or other refinery products. The activity also does not include transportation of the stabilised crude oil to downstream users or processors.

22.3.        Inclusions

For the purposes of developing the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of machinery, equipment and processes for the physical transformation described in the activity definition, including, for example:

• machinery used to move materials within and as part of the activity;
• control rooms, laboratories, and maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described; unless the by-product is being reported as a separate production variable, in which case, refer to section 22.5;
• on-site processing and/or disposal of waste materials, such as wastewater, from the activity;

• recovery/capture and use of waste heat/energy within the activity;
• the treatment of the feed stream that is subsequently transformed into stabilised crude oil or condensate, using processes including, for example:

• bulk water removal (such as emissions associated with the separation of water from the natural gas and flaring of entrained hydrocarbons in this water);
• stabilisation, being the process of removing some of the dissolved light hydrocarbon and non-hydrocarbon components from crude oil and/or condensate to reduce its vapour pressure, for example by passing it through several stages of separators at increasingly lower pressures; or via a stabilisation (distillation) column;
• dehydration;
• desalting;
• removal of sulphur compounds;

• any flaring, leaks or venting of greenhouse gases associated with the activity, except reservoir CO2;
• the short-term buffer storage of stabilised crude oil or condensate where the volume of that buffer storage is designed specifically to allow efficient loading into transportation systems, such as tankers, at a frequency and rate determined by the facility’s off-take requirements;
• the supply of utilities such as, but not limited to, compressed air, nitrogen, steam and water where these are used in support of the activity and within the activity boundaries;
• the regeneration of any catalysts or solvents, if the regeneration is undertaken within the activity;
• the loading of the stabilised crude oil or condensate (by pumping) into a medium of transportation such as tankers, pipelines or to a piece of equipment which will consume the stabilised crude oil or condensate, if the pumps are included within the facility for the purpose of NGER; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

22.4.        Exclusions

For the purposes of calculating the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility should be excluded:

• the processing or transfer of other products such as processed natural gas, ethane or LPG;
• processes which do not occur within the facility; and
• on-site electricity generation.

22.5.        Multiple production variables from the same facility

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

The method for determining the amount of emissions to be apportioned to each reported production variable may be one of the following options:

1. Apportion emissions from the activity to each production variable using a whole-of-activity mass balance method that assigns emissions at each step to the associated material stream, tracked through the activity to its transportation out of the activity location. For example, for a crude oil and condensate (processing) activity that also produces processed natural gas:

• apportion emissions from the processing steps between the two production variables, using a mass balance method;
• apportion the emissions from facility activities such as generation of utilities, venting and flaring, treatment of waste streams, between the two production variables, using a mass balance method;
• apportion the emissions from remaining, general facility activities such as the control rooms, laboratories, and maintenance workshops between the two production variables, in the ratio of the amount of that production variable produced, for example on an energy basis, unless there is another justifiable basis.

2. Apportion all emissions unique to the crude oil and condensate processing activity to the crude oil and condensate (processing) production variable. Similarly, apportion all emissions unique to other production variables produced at the same facility to the relevant production variable. Apportion all emissions involved in processing steps prior to the separation of crude oil and condensate amongst the various production variables on an energy basis, unless there is another justifiable basis. That is:

• apportion all emissions from the pre-processing, such as bulk water and gas separation, amongst the various production variables in the ratio of the amount of each production variable produced, for example on an energy basis, unless there is another justifiable basis;
• apportion all emissions from the crude oil and/or condensate stabilisation unit operation, such as the series of separators or stabilisation column, to the crude oil and condensate (processing) production variable;
• apportion all emissions from the further processing of the crude oil and condensate, such as desalting (if that process is carried out) and pumping to storage, to the crude oil and condensate (processing) production variable;
• apportion all emissions from activities such as generation of utilities, venting and flaring, treatment of waste streams, associated with the crude oil and condensate stabilisation process and the further processing of the crude oil and condensate to the crude oil and condensate (processing) production variable;
• apportion all emissions from the processing of each of the other production variables, (for example dehydration, dew point control and compression if another production variable was processed natural gas), to the relevant production variable;
• apportion all emissions from activities such as generation of utilities, venting and flaring, treatment of waste streams, associated with each of the other production variables, to the relevant production variable;
• apportion the emissions from remaining, general facility activities such as general utilities, the control rooms, laboratories, and maintenance amongst the various production variables in the ratio of the amount of each production variable produced, for example on an energy basis, unless there is another justifiable basis.

23.                     Stabilised crude oil (integrated extraction and stabilisation)

23.1.        Definition

1. Total gigajoules of the crude oil that:

(a)            are a mixture of hydrocarbons that are liquid at atmospheric pressure (101.325 kilopascals) and ambient temperature; and

(b)            can be safely stored and transported at atmospheric pressure and ambient temperature; and

(c)            are produced as part of carrying on the integrated crude oil extraction and stabilisation activity at the facility; and

(d)            are not consumed in carrying on the integrated crude oil extraction and stabilisation activity; and

(e)            are of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that:

(a)            conducts both of the following activities:

(i)        the extraction of a hydrocarbon stream from a naturally occurring petroleum reservoir;

(ii)      the crude oil or condensate stabilisation activity; and

(b)            has stabilised crude oil as its only saleable hydrocarbon product.

3.       The activity in subsection (2) is the integrated crude oil extraction and stabilisation activity.

4.       However, the metric in subsection (1) is not applicable to a facility using another oil and gas production variable in Schedule 2 (other than the reservoir CO2 production variable).

23.2.        Scope of the activity

This production variable applies to facilities that both extract the well fluid and subsequently produce stabilised crude oil as the only saleable hydrocarbon product.

The extraction of crude oil is the production of a fluid stream that is predominantly liquid from a naturally occurring petroleum reservoir, which may also contain water and/or non-hydrocarbon components, and transportation of the fluid stream to the processing facility (which is part of the same facility) for processing.

The processing of the fluid stream into stabilised crude oil is the separation of crude oil from the fluid stream, which was a mixture that may contain crude oil, natural gas and non-hydrocarbon components, in a liquid and/or mixed liquid and gaseous state on entering the process, into crude oil that is stable in a liquid state at atmospheric pressure and ambient temperature, and that is in a liquid state on leaving the activity.

The activity involves the extraction of crude oil from a naturally occurring petroleum reservoir, which could include an unconventional source, such as a shale oil deposit. The produced fluid may also include natural gas, water, CO2 and other non-hydrocarbon gases.

The activity may include a feed treatment stage where bulk gases and water are removed from the well stream. Following such processing, the predominantly liquid mixture is stabilised by removing some of the dissolved light hydrocarbon and non-hydrocarbon components to reduce the vapour pressure, for example by passing it through several stages of separation at increasingly lower pressures, or via a stabilisation (distillation) column.

Gases contained in the unstabilised crude oil stream are disposed of, for example by use as fuel, flaring, or compression for injection into a petroleum reservoir, and hence have not been reported as a separate production variable. The water contained in the unstabilised crude oil stream is treated as required, for example by desalination; and disposed of, for example by discharge to the environment, reinjection or evaporation.

It is intended that alternative forms of extraction and stabilisation that do not require the removal of water would be considered to fit within the activity definition, so long as at least stabilisation of crude oil takes place at the facility.

This activity does not include crude oil refining. The activity is also not satisfied where the crude oil being produced by the facility has a vapour pressure higher than atmospheric pressure at ambient temperature. The activity is also not satisfied by a facility that does stabilisation but not extraction, as the output from such a facility is stabilised crude oil and condensate (stabilisation only).

The outputs of the activity are GJ of crude oil. The measurement of this output is to be conducted so that it does not include any GJ of crude oil that are consumed within the facility. The measurement of the production variable is as GJ of crude oil that are transported, as a liquid, away from the facility where the crude oil was stabilised.

The activity does not include the downstream processing of the stabilised crude oil including refining into petroleum products such as petrol, jet fuel, diesel, lubrication oil, bitumen or other refinery products. The activity also does not include transportation of the stabilised crude oil to downstream users or processors, after the point of transfer into the crude oil tanker or pipeline.

23.3.        Inclusions

For the purposes of developing the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of machinery, equipment and processes for the extraction and physical transformation described in the activity definition, including, for example:

• machinery used to move materials within and as part of the activity, including machinery required to lift the crude oil from the petroleum reservoir if required;
• control rooms, laboratories, and maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity, such as compression of gas to be reinjected into the reservoir, or are necessary for the activity to proceed as described;
• on-site processing and/or disposal of waste materials, such as gases and wastewater;
• the injection of fluids (liquid hydrocarbon or water and gas) for the purposes of secondary or tertiary hydrocarbon recovery;

• recovery/capture and use of waste heat/energy within the activity;
• field pumping of the well fluid associated with the gathering of the fluid upstream of processing;
• the treatment of the well fluid that is subsequently transformed into stabilised crude oil, using processes including, for example:

• bulk gas and water removal (such as emissions associated with the separation of water from the crude oil and flaring of entrained hydrocarbons in this water);
• stabilisation, being the process of removing some of the dissolved light hydrocarbon and non-hydrocarbon components from crude oil to reduce its vapour pressure, for example by passing it through several stages of separators at increasingly lower pressures; or via a stabilisation (distillation) column;
• dehydration;
• desalting;
• removal of sulphur compounds;
• removal of reservoir CO2 (the separated reservoir CO2 is not included and must be reported separately, but the emissions associated with the process of separating the reservoir CO2 are included);

• any flaring, leaks or venting of greenhouse gases associated with the activity, except reservoir CO2;
• the short-term buffer storage of stabilised crude oil where the volume of that buffer storage is designed specifically to allow efficient loading into transportation systems, such as tankers, at a frequency and rate determined by the facility’s off-take requirements;
• the supply of utilities such as, but not limited to, compressed air, nitrogen, steam and water where these are used in support of the activity and within the activity boundaries;
• the regeneration of any catalysts or solvents, if the regeneration is undertaken within the activity;
• the loading of the stabilised crude oil (eg by pumping) into a medium of transportation such as tankers or pipeline, or to a piece of equipment which will consume the stabilised crude oil, if such loading equipment is included within the facility for the purpose of NGER; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

23.4.        Exclusions

For the purposes of calculating the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility should be excluded:

• reservoir CO2 that is separated from the crude oil mixture as part of the extraction and processing activity, as reservoir CO2 is reported under its own production variable;
• processes which do not occur within the facility; and
• on-site electricity generation.

23.5.        Multiple production variables from the same facility

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable.

The stabilised crude oil (extraction and stabilisation) production variable does not allow for the use of other production variables, except for reservoir CO2 and electricity. If other hydrocarbon products identified as production variables are produced by the activity, the separate production variables of stabilised crude oil and condensate (stabilisation only), along with the other applicable production variables, such as unprocessed or processed natural gas, must be used.

24.                     Processed natural gas (processing only)

24.1.        Production variable definition

1. Gigajoules of processed natural gas that:

(a)            are produced as part of carrying on the natural gas processing activity at the facility; and

(b)            are not consumed in carrying on the natural gas processing activity; and

(c)            are of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of processing natural gas through the physical transformation of unprocessed natural gas, which may be a mixture of gases and liquids, into processed natural gas (the natural gas processing activity).

Definition of processed natural gas

Where ‘processed natural gas’ means a substance that:

• is in a gaseous state at standard temperature and pressure; and
• consists of:

(a)            naturally occurring hydrocarbons; or

(b)            a naturally occurring mixture of hydrocarbons and non-hydrocarbons; and

• is mainly methane; and
• has been:

(a)            injected into a natural gas transmission pipeline; or

(b)            supplied to a third party for injection into a natural gas transmission pipeline; or

(c)            supplied to a downstream user after processing the substance to an agreed specification, such that the gas has at least the following qualities:

(i)      water content of 150 mg/Sm3 or less;

(ii)    inert gases (including carbon dioxide) of 12 molar per cent or less;

(iii)  hydrocarbon cricondentherm of 10 °C or lower;

(iv)  sulphur content (including any sulphur from odourant) of 60 mg/Sm3 or less.

24.2.        Scope of the activity

This production variable applies to facilities that produce processed natural gas, typically as one of multiple hydrocarbon products. It does not apply to facilities that extract the unprocessed natural gas and subsequently produce processed natural gas as the only saleable hydrocarbon product. These facilities should use the processed natural gas (production and processing) production variable.

The processing of natural gas is the treatment of an unprocessed natural gas stream, which may contain some hydrocarbon and/or non-hydrocarbon liquids, to produce a gaseous stream for injection into a natural gas transmission pipeline, or for supply to another downstream user with a specification meeting the requirements of the processed natural gas definition.

The activity involves the receipt of unprocessed natural gas from a facility (which may be the same facility) conducting the activity of natural gas extraction, and processing it to a quality suitable for injection into a natural gas transmission pipeline or for supply to a downstream user with a specification meeting the requirements of the processed natural gas definition. The processing may involve separation from hydrocarbon and/or non-hydrocarbon liquids, dehydration, acid gas removal, mercury removal, and any other processes required to bring the gas to pipeline quality or the user specification meeting the requirements of the processed natural gas definition. Compression of the gas to allow injection into the pipeline is also included in the activity, if the equipment used for compression is included within the facility for the purpose of reporting under the NGER scheme.

The inputs of the activity are a stream of unprocessed natural gas that may contain gas, crude oil, condensate, natural gas liquids and non-hydrocarbon components, in a gaseous, liquid and/or mixed liquid and gaseous state.

The outputs of the activity are GJ of processed natural gas injected into the natural gas transmission pipeline or supplied to a downstream user with a specification meeting the requirements of the processed natural gas definition. The measurement of this output is expected to be conducted so that it does not include any GJ of processed natural gas that are consumed within the activity.

The activity does not include the upstream extraction or production of unprocessed natural gas to feed the activity. Further, the activity also does not include transportation of the processed natural gas, from the point where it is injected into a natural gas transmission pipeline, to downstream users or processors.

24.3.        Inclusions

For the purposes of developing the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of machinery, equipment and processes for the physical transformation described in the activity definition, including, for example:

• machinery used to move materials within and as part of the activity;
• control rooms, laboratories, and maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described; unless the by-product is being reported as a separate production variable, in which case, refer to section 24.5 below;
• on-site processing and/or disposal of waste materials, such as wastewater, from the activity;

• recovery/capture and use of waste heat/energy within the activity;
• treatment of the unprocessed natural gas stream that is subsequently transformed into processed natural gas, using processes including, for example:

• bulk water removal (such as emissions associated with the separation of water from the natural gas and flaring of entrained hydrocarbons in this water);
• separation of gas from liquids;
• removal of sulphur compounds;
• removal of reservoir CO2 (the separated reservoir CO2 is not included and must be reported separately, but the emissions associated with the process of separating the reservoir CO2 are included);
• mercury removal;
• dehydration, for example by glycol absorption and/or molecular sieves;
• removal of ethane and heavier hydrocarbons;
• odourisation of the processed natural gas;

• any flaring, leaks or venting of greenhouse gases associated with the activity, except reservoir CO2;
•  the supply of utilities such as, but not limited to, compressed air, nitrogen, steam and water where these are used in support of the activity and within the activity boundaries;
• the regeneration of any catalysts or solvents, if the regeneration is undertaken within the activity;
• compression of the gas process stream (as part of or subsequent to the processing activity), including where the processed gas is then injected into a gas transmission pipeline and the compression contributes to the gas reaching the required pressure for transmission, if such equipment is included within the facility for the purpose of NGER; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

24.4.        Exclusions

For the purposes of calculating the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility should be excluded:

• reservoir CO2 that is separated from the natural gas mixture as part of the processing activity, as reservoir CO2 is reported under its own production variable;
• the processing or transfer of other production variables such as ethane and/or LPG, or crude oil and condensate (processed) (if hydrocarbon liquids separated from the natural gas stream are incorporated into a crude oil or condensate stream);
• processes which do not occur within the facility; and
• on-site electricity generation.

24.5.        Multiple production variables from the same facility

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

The method for determining the amount of emissions to be apportioned to each reported production variable may be one of the following options:

1. Apportion emissions from the activity to each production variable using a whole-of-activity mass balance method that assigns emissions at each step to the associated material stream, tracked through the activity to its transportation out of the activity location. For example, for a processed natural gas activity that also produces ethane:

• apportion emissions from the processing steps between the two production variables, using a mass balance method
• apportion the emissions from facility activities such as generation of utilities, venting and flaring, treatment of waste streams, between the two production variables, using a mass balance method
• apportion the emissions from remaining, general facility activities such as the control rooms, laboratories, and maintenance workshops between the two production variables, in the ratio of the amount of that production variable produced, for example on an energy basis, unless there is another justifiable basis.

2.  Apportion all emissions unique to the processed natural gas activity to the processed natural gas production variable. Similarly, apportion all emissions unique to other production variables produced at the same facility to the relevant production variable. Apportion all emissions involved in processing steps prior to the separation of natural gas amongst the various production variables on an energy basis, unless there is another justifiable basis. For example, for a processed natural gas activity that also produces ethane and/or liquefied petroleum gas:

• apportion all emissions from the pre-processing, such as bulk water separation, amongst the various production variables in the ratio of the amount of each production variable produced, for example on an energy basis, unless there is another justifiable basis
• apportion all emissions from processed natural gas production and further gas processing unit operations to the processed natural gas production variable
• apportion all emissions from activities such as generation of utilities, venting and flaring, treatment of waste streams, associated with the production of processed natural gas to the processed natural gas production variable
• apportion all emissions from the ethane production unit operations, such as the fractionation step that produced the ethane and/or liquefied petroleum gas, to the ethane/liquefied petroleum gas production variable
• apportion all emissions from the further processing of the ethane/liquefied petroleum gas, such as further CO2 removal and compression to storage or the facility discharge pipeline, to the ethane/liquefied petroleum gas production variable
• apportion all emissions from activities such as generation of utilities, venting and flaring, treatment of waste streams, associated with each of the other production variables, to the relevant production variable
• apportion the emissions from remaining, general facility activities such as general utilities, the control rooms, laboratories, and maintenance amongst the various production variables in the ratio of the amount of each production variable produced, for example on an energy basis, unless there is another justifiable basis.

25.                     Processed natural gas (integrated extraction and processing)

25.1.        Production variable definition

1. Gigajoules of processed natural gas that:

(a)            are produced as part of carrying on the integrated natural gas extraction and processing activity at the facility; and

(b)            are not consumed in carrying on the integrated natural gas extraction and processing activity; and

(c)            are of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that:

(a)            conducts both of the following activities:

(i)        the extraction of a hydrocarbon stream that is predominantly gas from a naturally occurring petroleum reservoir;

(ii)      the natural gas processing activity; and

(b)            has processed natural gas as its only saleable hydrocarbon product.

3.       The activity in subsection (2) is the integrated natural gas extraction and processing activity.

4.       However, the metric in subsection (1) is not applicable to a facility using another oil and gas production variable in Schedule 2 (other than the reservoir CO2 production variable).

Definition of processed natural gas

Where ‘processed natural gas’ means a substance that:

• is in a gaseous state at standard temperature and pressure; and
• consists of:

(a)            naturally occurring hydrocarbons; or

(b)            a naturally occurring mixture of hydrocarbons and non-hydrocarbons; and

• is mainly methane; and
• has been:

(a)            injected into a natural gas transmission pipeline; or

(b)            supplied to a third party for injection into a natural gas transmission pipeline; or

(c)            supplied to a downstream user after processing the substance to an agreed specification, such that the gas has at least the following qualities:

(i)      water content of 150 mg/Sm3 or less;

(ii)    inert gases (including carbon dioxide) of 12 molar per cent or less;

(iii)  hydrocarbon cricondentherm of 10 °C or lower;

(iv)  sulphur content (including any sulphur from odourant) of 60 mg/Sm3 or less.

25.2.        Scope of the activity

This production variable applies to facilities that both extract unprocessed natural gas and subsequently produce processed natural gas as the only saleable hydrocarbon product.

The extraction of natural gas is the production of a fluid stream that is predominantly gaseous from a naturally occurring petroleum reservoir, which may also contain water and/or non-hydrocarbon components, in a gaseous and/or mixed liquid and gaseous state, and transportation of the fluid stream for processing within the same integrated facility.

The processing of natural gas is the treatment of the extracted natural gas stream to produce a gaseous stream for injection into a natural gas transmission pipeline or for supply to another downstream user with a specification meeting the requirements of the processed natural gas definition.

The activity involves the extraction of natural gas from a naturally occurring petroleum reservoir. The produced fluid may also include water, CO2 and other non-hydrocarbon gases. The produced stream may undergo a treatment stage where water is separated from the gas stream. The gas stream may then be compressed to allow transportation to a downstream location for processing, which is part of the same integrated facility.

The processing involves transforming the natural gas into a quality suitable for injection into a natural gas transmission pipeline, or for supply to another downstream user with a specification meeting the requirements of the processed natural gas definition. The processing may involve separation from water, dehydration, and any other processes required to bring the gas to pipeline quality or the user specification meeting the requirements of the processed natural gas definition. Compression of the gas to allow injection into the pipeline is included in the activity, if the equipment used for compression was included within the facility for the purpose of National Greenhouse and Energy Reporting (NGER).

The outputs of the activity are GJ of processed natural gas injected into a natural gas transmission pipeline or supplied to another downstream user with a specification meeting the requirements of the processed natural gas definition. The measurement of this output is expected to be conducted so that it does not include any GJ of processed natural gas that are consumed within the facility. The measurement of the production variable is as GJ of processed natural gas that are transported, as a gas, away from the facility where the natural gas was processed.

The activity does not include transportation of the processed natural gas, from the point where it is injected into a natural gas supply pipeline, to downstream users or processors.

25.3.        Inclusions

For the purposes of developing the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of machinery, equipment and processes for the extraction and physical transformation described in the activity definition, including, for example:

• machinery used to move materials within and as part of the activity;
• control rooms, laboratories, and maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• on-site processing and/or disposal of waste materials, such as wastewater, from the activity;

• field compression of the unprocessed natural gas associated with the gathering of the gas upstream of processing;
• compression of the gas process stream (as part of or subsequent to the processing activity), including where the processed gas is then injected into a gas transmission pipeline and the compression contributes to the gas reaching the required pressure for transmission, if such equipment is included within the facility for the purpose of NGER;
• recovery/capture and use of waste heat/energy within the activity;
• treatment of the unprocessed natural gas stream that is subsequently transformed into processed natural gas, using processes including, for example:

• bulk water removal (such as emissions associated with the separation of water from the natural gas and flaring of entrained hydrocarbons in this water);
• removal of sulphur compounds;
• removal of reservoir CO2 (the separated reservoir CO2 is not included and must be reported separately, but the emissions associated with the process of separating the reservoir CO2 are included);
• dehydration, for example by glycol absorption and/or molecular sieves;
• mercury removal;
• odourisation of the processed natural gas;

• any flaring, leaks or venting of greenhouse gases associated with the activity, except reservoir CO2;
• the regeneration of any catalysts or solvents, if the regeneration is undertaken within the activity;
• the supply of utilities such as, but not limited to, compressed air, nitrogen, steam and water where these are used in support of the activity and within the activity boundaries; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

25.4.        Exclusions

For the purposes of calculating the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility should be excluded:

• reservoir CO2 that is separated from the natural gas mixture as part of the extraction and/or processing activities, as reservoir CO2 is reported under its own production variable;
• processes which do not occur within the facility; and
• on-site electricity generation.

25.5.        Multiple production variables from the same facility

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable.

The processed natural gas (extraction and processing) production variable does not allow for the use of multiple production variables from the same activity, except for reservoir CO2 and electricity. If other hydrocarbon products identified as production variables are produced in the activity, the separate production variables of unprocessed natural gas and processed natural gas must be used, along with the other production variable(s).

26.                     Liquefied natural gas (from unprocessed natural gas)

26.1.        Production variable definition

1. Gigajoules of liquefied natural gas that:

(a)            have a methane (CH4) content by mass of 70% or more; and

(b)            are produced as part of carrying on the unprocessed natural gas liquefaction activity at the facility; and

(c)            are in a liquid state; and

(d)            have been loaded onto a transport vessel, tanker or other transportation system; and

(e)            are of saleable quality; and

(f)            have not been counted as part of the liquefied natural gas production variable in section 32 of Schedule 2 (liquefied natural gas from processed natural gas).

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of liquefying unprocessed natural gas through the physical transformation of unprocessed natural gas into liquefied natural gas that:

(a)            has a methane content by mass of 70% or more; and

(b)            is in a liquid state on leaving the facility.

3.       The activity in subsection (2) is the unprocessed natural gas liquefaction activity.

4.       The quantity of the metric in subsection (1) may be evidenced by a bill of lading relating to the transport of liquefied natural gas from the facility.

26.2.        Scope of the activity

The production of LNG from unprocessed natural gas is the physical transformation of unprocessed natural gas, which is in a gaseous state on entering the activity, to LNG which has a methane content by mass of 70 per cent or more and that is in a liquid state on leaving the activity.

The activity involves the processing and subsequent liquefaction of unprocessed natural gas that was taken from, or is a part of, a facility that undertakes the oil and gas extraction activity. The activity may include the removal of CO2, hydrogen sulphide, water, other contaminants, LPGs, ethane and heavier hydrocarbons, and the liquefaction (through compression and temperature reduction) of the resulting methane rich gas stream to liquefied natural gas at a temperature of approximately -162oC.  The facility processing unprocessed natural gas to liquefied natural gas may also undertake activities such as producing stabilised condensate, processed natural gas and LPG.  The production of these other aforementioned production variables are not part of the activity.

This activity does not include the undertaking of natural gas extraction, or through LNG regasification. The activity is also not satisfied where the product is in a gaseous state on leaving the facility or has a concentration of methane (CH4) that is less than 70 per cent with respect to mass.

The inputs of the activity include unprocessed natural gas in a gaseous state, which is predominantly methane, from a facility (which could be the same facility) conducting the activity of natural gas extraction. The stream may contain hydrocarbon and/or non-hydrocarbon liquids as well as the naturally occurring gaseous phase.

The outputs of the activity are GJ of LNG where the concentration of methane is equal to or greater than 70 per cent with respect to mass. The measurement of this output is expected to be conducted so that it does not include any GJ of LNG that boil off in conveying the LNG to a transportation vessel or storage facility.

The activity does not include the upstream extraction of the natural gas or transportation of the unprocessed natural gas to the boundary of the facility conducting the activity of LNG production from unprocessed natural gas. Further, the activity does not include the downstream processing of the LNG including transportation, distribution or regasification, or the processing of any by-products from the production of LNG including condensate, processed natural gas and LPG.

26.3.        Inclusions

For the purposes of developing the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within and as part of the activity;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described; unless the by-product is being reported as a separate production variable, in which case, refer to section 26.5 below;
• on-site processing and/or disposal of waste materials from the activity;

• recovery/capture and use of waste heat/energy within the activity;
• the treatment of the unprocessed natural gas feed, including:

• bulk water removal (such as emissions associated with the separation of water from the natural gas and flaring of entrained hydrocarbons in this water);
• separation of gas from liquid;
• removal of sulphur compounds;
• removal of reservoir CO2 (the separated reservoir CO2 is not included and must be reported separately, but the emissions associated with the process of separating the reservoir CO2 are included);
• removal of mercury and any other impurities;
• dehydration, for example by glycol absorption and/or molecular sieves;
• removal of ethane and heavier hydrocarbons;
• liquefaction of the natural gas to produce LNG;

• any flaring, leaks or venting of greenhouse gases associated with the activity, except reservoir CO2;
•  the short-term buffer storage of LNG where the volume of that buffer storage is designed specifically to allow efficient loading into the transportation system, such as ocean going tankers, at a frequency and rate determined by the facility’s off-take requirements;
• the supply of utilities such as, but not limited to, compressed air, nitrogen, steam and water where these are used in support of the activity and within the activity boundaries;
• the regeneration of any catalysts or solvents, if the regeneration is undertaken within the activity;
• the loading of the LNG into a medium of transportation such as ocean going tankers or a pipeline (by pumping), if the pumps are included within the facility for the purpose of NGER; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

26.4.        Exclusions

For the purposes of calculating the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility should be excluded:

• reservoir CO2 that is separated from the feed stream as part of the processing activity, as reservoir CO2 is reported under its own production variable;
• the processing or transfer of other production variables such as processed natural gas, ethane and/or LPG, or crude oil/condensate (processing) (if hydrocarbon liquids separated from the natural gas stream are incorporated into a crude oil or condensate stream);
• processes which do not occur within the facility; and
• on-site electricity generation.

26.5.        Multiple production variables from the same facility

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

The method for determining the amount of emissions to be apportioned to each reported production variable may be one of the following options:

1. Apportion emissions from the activity to each production variable using a whole-of-activity mass balance method that assigns emissions at each step to the associated material stream, tracked through the activity to its transportation out of the activity location. For example, for an LNG production activity that also produces processed natural gas:

• apportion emissions from the processing steps between the two production variables, using a mass balance method
• apportion the emissions from facility activities such as generation of utilities, venting and flaring, treatment of waste streams, between the two production variables, using a mass balance method
• apportion the emissions from remaining, general facility activities such as the control rooms, laboratories, and maintenance workshops between the two production variables, in the ratio of the amount of that production variable produced, for example on an energy basis, unless there is another justifiable basis.

2.       Apportion all emissions unique to the LNG production activity to the LNG from unprocessed natural gas production variable. Similarly, apportion all emissions unique to other production variables produced at the same facility to the relevant production variable. Apportion all emissions involved in processing steps prior to the separation of the LNG stream from the natural gas stream amongst the various production variables on an energy basis, unless there is another justifiable basis. For example, for an LNG production facility that also produces processed natural gas:

• apportion all emissions from the pre-processing, such as bulk water separation, amongst the various production variables in the ratio of the amount of each production variable produced, for example on an energy basis, unless there is another justifiable basis
• apportion all emissions from the natural gas processing to the quality required for liquefaction to the LNG production variable
• apportion all emissions from the LNG liquefaction unit operation to the LNG production variable
• apportion all emissions from activities such as generation of utilities, venting and flaring, treatment of waste streams, associated with the production of LNG to the LNG production variable
• apportion all emissions from the further processing of the natural gas to a standard that meets the definition of the processed natural gas production variable, such as odourisation and compression, to the processed natural gas production variable
• apportion all emissions from activities such as generation of utilities, venting and flaring, treatment of waste streams, associated with the production of processed natural gas to the processed natural gas production variable
• apportion the emissions from remaining, general facility activities such as general utilities, the control rooms, laboratories, and maintenance amongst the various production variables in the ratio of the amount of each production variable produced, for example on an energy basis, unless there is another justifiable basis.

27.                     Liquefied natural gas (from processed natural gas)

27.1.        Production variable definition

1. Gigajoules of liquefied natural gas that:

(a)            have a methane content by mass of 70% or more; and

(b)            are produced as part of carrying on the processed natural gas liquefaction activity at the facility; and

(c)            are in a liquid state; and

(d)            have been loaded onto a transport vessel, tanker or other transportation system; and

(e)            are of saleable quality; and

(f)            have not been counted as part of the liquefied natural gas production variable in section 31 of Schedule 2 (liquefied natural gas from unprocessed natural gas).

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of liquefying processed natural gas through the physical transformation of processed natural gas into liquefied natural gas that:

(a)            has a methane content by mass of 70% or more; and

(b)            is in a liquid state on leaving the facility.

3.       The activity in subsection (2) is the processed natural gas liquefaction activity.

4.       The quantity of the metric in subsection (1) may be evidenced by a bill of lading relating to the transport of liquefied natural gas from the facility.

27.2.        Scope of the activity

The production of LNG from processed natural gas is the physical transformation of processed natural gas, which is in a gaseous state on entering the activity, to LNG that has a methane content by mass of 70 per cent or more and that is in a liquid state on leaving the activity.

The activity involves the processing and subsequent liquefaction of processed natural gas that is taken from a natural gas pipeline. The activity may include the removal of CO2, hydrogen sulphide, water, other contaminants, LPGs, ethane and heavier hydrocarbons, and liquefaction (through compression and temperature reduction) of the resulting methane rich gas stream to liquefied natural gas at a temperature of approximately -162oC. 

This activity does not include the undertaking of natural gas extraction and processing, or through LNG regasification. The activity is also not satisfied where the natural gas being processed is in a gaseous state on leaving the activity or has a concentration of methane (CH4) that is less than 70 per cent with respect to mass.

The outputs of the activity are GJ of LNG where the concentration of methane is equal to or greater than 70 per cent with respect to mass. The measurement of this output is expected to be conducted so that it does not include any GJ of LNG that boil off in conveying the LNG to a transportation vessel or storage facility.

The activity does not include the upstream extraction or processing of the natural gas for injection into the natural gas pipeline that feeds the LNG production activity. Further, the activity does not include the downstream processing of the LNG including transportation, distribution or regasification.

27.3.        Inclusions

For the purposes of developing the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of machinery, equipment and processes for the physical and/or chemical transformation described in the activity definition, including, for example:

• machinery used to move materials within and as part of the activity;
• control rooms, laboratories, maintenance workshops;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described;
• on-site processing and/or disposal of waste materials from the activity;

• recovery/capture and use of waste heat/energy within the activity;
• the treatment of the processed natural gas feed, if any, including:

• removal of sulphur compounds;
• removal of reservoir CO2 (the separated reservoir CO2 is not included and must be reported separately, but the emissions associated with the process of separating the reservoir CO2 are included);
• further dehydration, for example by molecular sieves;
• removal of mercury and any other impurities;
• removal of ethane and heavier hydrocarbons;
• liquefaction of the natural gas to produce LNG;

• any flaring, leaks or venting of greenhouse gases associated with the activity, except for reservoir CO2;
• the short-term buffer storage of LNG where the volume of that buffer storage is designed specifically to allow efficient loading into the transportation system, such as ocean going tankers, at a frequency and rate determined by the facility’s off-take requirements;
• the supply of utilities such as, but not limited to, compressed air, nitrogen, steam and water where these are used in support of the activity and within the activity boundaries;
• the regeneration of any catalysts or solvents, if the regeneration is undertaken within the activity;
• the loading of the LNG into a medium of transportation such as ocean going tankers or a pipeline (by pumping), if the pumps are included within the facility for the purpose of NGER; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

27.4.        Exclusions

For the purposes of calculating the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility should be excluded:

• reservoir CO2 that is separated from the feed stream as part of the processing activity, as reservoir CO2 is reported under its own production variable;
• processes which do not occur within the facility; and
• on-site electricity generation.

27.5.        Multiple production variables from the same facility

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

28.                     Ethane

28.1.        Production variable definition

1. Gigajoules of the ethane that:

(a)            has an ethane content by mass of 95% or more; and

(b)            is in a gaseous state; and

(c)            is produced as part of carrying on the ethane production activity at the facility; and

(d)            is not consumed in carrying on the ethane production activity; and

(e)            is of saleable quality.

2.       The metric in subsection (1) is applicable to a facility that conducts the activity of ethane production through the separation of ethane from a mixture of hydrocarbons to produce ethane that:

(a)            has an ethane content by mass of 95% or more; and

(b)            is in a gaseous state.

3.       The activity in subsection (2) is the ethane production activity.

28.2.        Scope of the activity

The production of ethane gas is the separation and purification of ethane from a stream containing a mixture of hydrocarbons and non-hydrocarbons, into an ethane product that is gaseous on leaving the activity.

The activity involves the production of ethane from a processing plant. Examples of these types of facilities include natural gas processing facilities or natural gas liquids recovery facilities.

Ethane is produced in an activity that also produces processed natural gas and/or LPG. The activity may also produce other products, so emissions must be apportioned in a justifiable manner amongst the relevant production variables, as per the guidelines in section 28.4.

The process involves the pre-treatment of the mixed hydrocarbon stream, for example by dehydration (water removal) and removal of bulk CO2 and other impurities; partial liquefaction of the mixed hydrocarbon inlet stream by cooling it to cryogenic temperatures; then fractionation (distillation) to separate the gaseous methane from ethane and heavier hydrocarbons; then further fractionation to remove ethane from the propane and heavier hydrocarbons.

Following separation of the ethane from the mixed hydrocarbon stream, the ethane may be purified, for example by further removal of CO2. The ethane is then compressed for transfer into storage or a pipeline.

As described above, hydrocarbons contained in the hydrocarbon inlet stream may also be processed into other products, such as processed natural gas and LPG. The processing steps unique to these other products are not part of the activity.

It is intended that alternative forms of production that do not require the feed treatment stage would be considered to fit within the activity definition, so long as at least the separation from other hydrocarbons and non-hydrocarbons, purification if required, and transfer of ethane takes place at the facility.

This activity does not include the undertaking of natural gas processing, LPG production or crude oil refining. The activity is also not satisfied through the undertaking of ethane production that does not produce ethane that is equal to or greater than 95 percent with respect to mass, and is transported away from the facility. The further refining of ethane into other chemicals is not considered part of this activity.

The inputs of the activity include a hydrocarbon stream that may also contain some non-hydrocarbons. This stream may be processed or unprocessed natural gas, coal seam gas, or other mixtures of hydrocarbons and non-hydrocarbons, sourced from activities such as natural gas processing and LNG production facilities or from an alternative source such as crude oil stabilisation.

The outputs of the activity are GJ of ethane in a gaseous state. The measurement of this output is to be conducted so that it does not include any GJ of ethane that are consumed within the facility. The measurement of the production variable is as GJ of ethane that are transported, in a gaseous state, away from the facility where the ethane was produced.

The activity does not include the upstream extraction or production of the mixed hydrocarbon stream that feeds the activity. Further, the activity does not include transportation of the gaseous ethane to downstream users or processors.

28.3.        Inclusions

The ethane production activity is carried out at processing plants that undertake a range of activities and report a range of production variables. Emissions from machinery or activities that are not solely related to the ethane production activity must be apportioned amongst the relevant production variables from the facility, as per the guidelines in section 28.5. Where inclusions are listed below, they are emissions that could be included, provided the rules of apportionment are followed.

For the purposes of developing the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility are included:

• the use of machinery, equipment and processes for the physical transformation described in the activity definition, including, for example:

• machinery used to move materials within and as part of the activity;
• machinery used to create non-electrical energy for use in the activity;
• the processing of by-products where they involve the recovery of materials for re-use within the activity or are necessary for the activity to proceed as described; unless the by-product is being reported as a separate production variable, in which case, refer to section 28.5;
• on-site processing and/or disposal of waste materials from the activity;

• recovery/capture and use of waste heat/energy within the activity;
• the regeneration of any catalysts or solvents used, if the regeneration is undertaken within the activity;
• the treatment of the hydrocarbon stream to produce ethane, using processes including, for example:

• pretreatment of the mixed hydrocarbon stream by removing impurities such as water, sulphur compounds and mercury (if required);
• removal of reservoir CO2 (the separated reservoir CO2 is not included and must be reported separately, but the emissions associated with the process of separating the reservoir CO2 are included);
•  cooling of the mixed hydrocarbon stream to cryogenic temperature so it is partially liquefied, for example using refrigeration and/or turbo-expansion;
• separation of the gaseous methane from the feed stream using fractionation (distillation);
• heating the remaining mixed hydrocarbon stream, then removing the ethane by fractionation;
• removal of any impurities from the ethane stream;

• any flaring, leaks or venting of greenhouse gases associated with the activity, except reservoir CO2;
• the short-term buffer storage of ethane where the volume of that buffer storage is designed specifically to allow efficient loading into transportation systems, at a frequency and rate determined by the facility’s off-take requirements;
• the supply of utilities such as, but not limited to, refrigeration, compressed air, nitrogen, steam and water where these are used in support of the activity and within the activity boundaries;
• the transfer of the ethane (by compression) into a medium of transportation such as a pipeline or to a piece of equipment outside the facility which will consume the ethane, if such transfer equipment is included within the facility for the purpose of NGER; and
• other incidental, ancillary or supporting processes which are not included in another default or estimated emissions intensity value.

28.4.        Exclusions

For the purposes of calculating the default emissions intensity value and the estimated (site‑specific) emission intensity value for this production variable, scope 1 emissions from the following processes at the facility should be excluded:

• reservoir CO2 that is separated as part of the processing activity, as reservoir CO2 is reported under its own production variable;
• the processing or transfer of other production variables such as processed natural gas, and/or LPG, as the emissions from other production variables from the activity must be apportioned as per the guidance provided below;
• processes which do not occur within the facility; and
• on-site electricity generation.

28.5.        Multiple production variables from the same facility

It is intended that all scope 1 NGER-reported emissions from a facility can be assigned to a production variable. Where a facility produces multiple products, emissions must be apportioned in a justifiable manner, making sure no emissions are counted more than once and the total emissions counted cannot be more than the total emissions from the facility.

The method for determining the amount of emissions to be apportioned to each production variable may be one of the following options:

1. Apportion emissions from the activity to each production variable using a whole-of-activity mass balance method that assigns emissions at each step to the associated material stream, tracked through the activity to its transportation out of the activity location. For example, for a natural gas processing plant that produces ethane as one of two or more production variables:

• apportion emissions from the processing steps amongst all the production variables, using a mass balance method;
• apportion the emissions from facility activities such as generation of utilities, venting and flaring, treatment of waste streams, amongst all the production variables, using a mass balance method;
• apportion the emissions from remaining, general facility activities such as the control rooms, laboratories, and maintenance workshops amongst all the production variables, in the ratio of the amount of that production variable produced, for example on an energy basis, unless there is another justifiable basis.

2.       Apportion all emissions unique to the production of ethane to the ethane production variable. Similarly, apportion all emissions unique to other production variables produced at the same facility to the relevant production variable. Apportion all emissions involved in processing steps prior to the separation of ethane amongst the various production variables on an energy basis, unless there is another justifiable basis. For example, for a natural gas processing plant that produces ethane as one of two or more production variables:

• apportion all emissions from the pre-processing, such as bulk water separation and bulk CO2 removal, amongst the various production variables in the ratio of the amount of each production variable produced, for example on an energy basis, unless there is another justifiable basis;
• apportion all emissions from processed natural gas production and further processed natural gas processing unit operations to the processed natural gas production variable;
• apportion all emissions from activities such as generation of utilities, venting, flaring, and treatment of waste streams, associated with the production of processed natural gas to the processed natural gas production variable;
• apportion all emissions from the ethane production unit operations, such as the fractionation step that produced the ethane, to the ethane production variable;
• apportion all emissions from the further processing of the ethane, such as further CO2 removal and compression to storage or the facility discharge pipeline, to the ethane production variable;
• apportion all emissions from activities such as generation of utilities, venting and flaring, treatment of waste streams, associated with the production of ethane, to the ethane production variable;
• apportion all the emissions from the production and further processing of other production variables, such as LPG, to the respective production variable, being LPG for this example;
• apportion all emissions from activities such as generation of utilities, venting and flaring, treatment of waste streams, associated with each of the other production variables, to the relevant production variable;
• apportion the emissions from remaining, general facility activities such as general utilities, the control rooms, laboratories, and maintenance amongst the various production variables in the ratio of the amount of each production variable produced, for example on an energy basis, unless there is another justifiable basis.