Federal Register of Legislation - Australian Government

Primary content

Determinations/Other as made
This determination amends the National Greenhouse and Energy Reporting (Measurement) Determination 2009.
Administered by: Industry, Science, Energy and Resources
Registered 29 Jun 2020

National Greenhouse and Energy Reporting (Measurement) Amendment (2020 Update) Determination 2020

I, Angus Taylor, Minister for Energy and Emissions Reduction, make the following instrument.

Dated     15 June 2020

Angus Taylor

Minister for Energy and Emissions Reduction


 

 

  

Contents

1  Name. ...................................................................................................................................... 3

2  Commencement........................................................................................................................ 3

3  Authority.................................................................................................................................. 3

4  Schedules................................................................................................................................. 3

Schedule 1—Amendments                                                                                           4

National Greenhouse and Energy Reporting (Measurement) Determination 2009                 4


 

1  Name

                   This is the National Greenhouse and Energy Reporting (Measurement) Amendment (2020 Update) Determination 2020.

2  Commencement

             (1)  Each provision of this instrument specified in column 1 of the table commences, or is taken to have commenced, in accordance with column 2 of the table. Any other statement in column 2 has effect according to its terms.

 

Commencement information

Column 1

Column 2

Column 3

Provisions

Commencement

Date/Details

1.  The whole of this instrument

1 July 2020.

1 July 2020

Note:          This table relates only to the provisions of this instrument as originally made. It will not be amended to deal with any later amendments of this instrument.

             (2)  Any information in column 3 of the table is not part of this instrument. Information may be inserted in this column, or information in it may be edited, in any published version of this instrument.

3  Authority

                   This instrument is made under subsection 10(3) of the National Greenhouse and Energy Reporting Act 2007.

4  Schedules

                   Each instrument that is specified in a Schedule to this instrument is amended or repealed as set out in the applicable items in the Schedule concerned, and any other item in a Schedule to this instrument has effect according to its terms.

Schedule 1Amendments

National Greenhouse and Energy Reporting (Measurement) Determination 2009

[1]           Section 1.8

Insert in the appropriate alphabetical position:

GWPmethane means the Global Warming Potential of methane.

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

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

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

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

Note:          Such pipelines can operates at high or low pressures

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

                     (a)  compressors;

                     (b)  generators;

                     (c)  dehydrators;

                     (d)  storage vessels;

                     (e)  acid gas removal units;

                      (f)  engines;

                     (g)  boilers;

                     (h)  heaters;

                      (i)  flares;

                      (j)  separation and processing equipment;

                     (k)  associated storage or measurement vessels;

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

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

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

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

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

                     (c)  gas separation trains where the removal of acidic gases from unprocessed natural gas or coal seam methane occurs;

Note:          The separation includes one or more of the following: forced extraction of natural gas liquids, sulphur and carbon dioxide removal, fractionation of natural gas liquids, or the capture of CO2 separated from unprocessed natural gas and coal seam methane streams.

produced water means the water that is either:

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

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

[2]           Section 3.5 (definition of EFj)

Repeal the definition, substitute:

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

                     (a)  for a gassy mine—0.407;

                     (b)  for a non‑gassy mine—0.011.

[3]           Subsection 3.6(1) (paragraph (a) of the definition of γj)

Omit “25”, substitute “GWPmethane”.

[4]           Subsection 3.17(2)

Omit “0.017”, substitute “0.019”.

[5]           Section 3.20 (paragraphs (a) to (f) of the definition of EFj)

Repeal the paragraphs, substitute:

 (a) for a mine in New South Wales—0.061;

 (b)        for a mine in Victoria0.0003;

 (c) for a mine in Queensland0.023;

 (d)        for a mine in Western Australia0.023;

 (e) for a mine in South Australia0.0003;

 (f) for a mine in Tasmania0.019.

[6]           Subsection 3.21(1) (paragraph (a) of the definition of γj)

Omit “25”, substitute “GWPmethane”.

[7]           Subsection 3.44(2) (table)

Repeal the table, substitute:

 

Item

Fuel type (i)

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

 

CO2

CH4

N2O

1

Unprocessed gas flared

2.8

0.933

0.026

2

Crude oil

3.2

0.009

0.06

[8]           Subsections 3.46B(1) and (4) (paragraph (a) of the definition of γj)

Omit “25”, substitute “GWPmethane”.

[9]           Subsection 3.49(1) (definition of EF(l) ij)

Omit “1.4”, substitute “1.60”.

[10]         Subsection 3.49(2) (table)

Repeal the table, substitute:

 

Item

Equipment type (k)

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

 

CH4

1

Internal floating tank

1.12 × 10-6

2

Fixed roof tank

5.60 × 10-6

3

Floating tank

4.27 × 10-6

[11]         Subsection 3.52(2) (table)

Repeal the table, substitute:

 

Item

Fuel type (i)

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

 

CO2

CH4

N2O

1

Unprocessed gas flared

2.8

0.933

0.026

2

Crude oil

3.2

0.009

0.060

[12]         Section 3.59 (definition of EFij)

Omit “8.7”, substitute “9.74”.

[13]         Section 3.63 (definition of EFij)

Omit “8.5”, substitute “9.47” and omit “1.5”, substitute “1.73”.

[14]         Subsection 3.67(2) (table)

Repeal the table, substitute:

 

Item

fuel type (i)

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

 

CO2

CH4

N2O

1

gas

2.7

0.133

0.026

[15]         Subsection 3.72(1) (definition of EF(l) ij)

Omit “1.2”, substitute “1.60”.

[16]         Subsection 3.72(2) (table)

Repeal the table, substitute:

 

Item

Equipment type (k)

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

1

Internal floating tank

1.12 × 10-6

2

Fixed roof tank

5.60 × 10-6

3

Floating tank

4.27 × 10-6

[17]         Section 3.76 (definition of EFij)

Omit “10.4”, substitute “11.6”.

[18]         Subsection 3.80(3) (table)

Repeal the table, substitute:

 

Item

State

Unaccounted for gas (a)%

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

 

UAGp

CO2

CH4

1

NSW and ACT

2.2

0.8

437

2

VIC

3.0

0.9

435

3

QLD

1.7

0.8

423

4

WA

2.9

1.1

408

5

SA

4.9

0.8

437

6

TAS

0.2

0.9

435

7

NT

2.2

0.0

352

[19]         Subsection 3.81A(3) (table)

Repeal the table, substitute:

Item

State

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

 

CO2

CH4

1

NSW and ACT

0.8

437

2

VIC

0.9

435

3

QLD

0.8

423

4

WA

1.1

408

5

SA

0.8

437

6

TAS

0.9

435

7

NT

0.0

352

[20]         Subsection 3.85(2) (table)

Repeal the table, substitute:

 

Item

fuel type (i)

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

 

CO2

CH4

N2O

1

gas

2.7

0.133

0.026

[21]         Section 3.91 (paragraph (a) of the definition of γj)

Omit “25”, substitute “GWPmethane”.

[22]         Section 3.92 (paragraph (a) of the definition of γj)

Omit “25”, substitute “GWPmethane”.

[23]         Subsection 4.47(2)

Repeal the table, substitute:

Item

Plant type (k)

Emission factor of nitrous oxide
(tonnes CO2‑e per tonne of nitric acid production)

1

Atmospheric pressure plants

1.33

2

Medium pressure combustion plant

1.86

3

High pressure plant

2.39

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

[24]         Section 4.85 (definition of EFij)

Omit “0.30”, substitute “0.27”.

[25]         Section 4.89 (definition of EFij)

Omit “0.07”, substitute “0.06”.

[26]         Subsections 5.4(1) and 5.4(3) (definition of γ)

Omit “25”, substitute “GWPmethane”.

[27]         Subsection 5.4B(3)

Repeal the equation, substitute:

 

[28]         Subsection 5.4B(3) (definition of 25)

Repeal the definition.

[29]         Section 5.4D

Repeal the equation, substitute:

 

[30]         Section 5.4D (definition of 25)

Repeal the definition.

[31]         Subsections 5.15(1) and 5.15(4) (definition of γ)

Omit “25”, substitute “GWPmethane”.

[32]         Subsection 5.15A(3)

Repeal the equation, substitute:

 

[33]         Subsection 5.22(2)

Repeal the table, substitute:

 

Emission factor for type of gas and biological treatment

Item

Biological treatment

Emission factor

tonnes CO2‑e/tonne of waste treated

 

 

Methane

Nitrous Oxide

1

Composting at the facility

0.021

0.025

2

Anaerobic digestion at the facility

0.028

0

[34]         Subsection 5.22B(1) (definition of γ)

Omit “25”, substitute “GWPmethane”.

[35]         Subsections 5.25(1) and 5.25(3) (definition of γ)

Omit “25”, substitute “GWPmethane”.

[36]         Subsection 5.26(1) (definition of γ)

Omit “25”, substitute “GWPmethane”.

[37]         Subsection 5.26(2) (definitions of EFslijz and EFwijz)

Omit “6.3”, substitute “7.0”.

[38]         Subsection 5.31(6)

Omit “4.9”, substitute “2.082”.

[39]         Subsection 5.31(7)

Repeal the table, substitute:

 

Item

Discharge environment

EFdisij

1

Enclosed waters

2.082

2

Estuarine waters

1.026

3

Open coastal waters (ocean and deep ocean)

0.0

[40]         Subsections 5.42(1) and 5.42(3) (definition of γ)

Omit “25”, substitute “GWPmethane”.

[41]         Subsection 5.42(6)

Omit “6.3”, substitute “7.0”.

[42]         Subsection 5.42(7)

Omit “6.3”, substitute “7.0”.

[43]         After section 9.12

                   Insert:

9.13  Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2020 Update) Determination 2020

                   The amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2020 Update) Determination 2020 apply in relation to:

                     (a)  the financial year starting on 1 July 2020; and

                     (b)  later financial years.

[44]         Parts 1 to 4 of Schedule 1

Repeal the Parts, substitute:

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

 

Item

Fuel combusted

Energy content factor

GJ/t

Emission factor

kg CO2‑e/GJ

(relevant oxidation factors incorporated)

CO2

CH4

N2O

1

Bituminous coal

27.0

90.0

0.04

0.2

1A

Sub‑bituminous coal

21.0

90.0

0.04

0.2

1B

Anthracite

29.0

90.0

0.04

0.2

2

Brown coal

10.2

93.5

0.02

0.3

3

Coking coal

30.0

91.8

0.03

0.2

4

Coal briquettes

22.1

95.0

0.08

0.2

5

Coal coke

27.0

107.0

0.03

0.2

6

Coal tar

37.5

81.8

0.03

0.2

7

Solid fossil fuels other than those mentioned in items 1 to 5

22.1

95.0

0.08

0.2

8

Industrial materials and tyres that are derived from fossil fuels, if recycled and combusted to produce heat or electricity

26.3

81.6

0.03

0.2

9

Non‑biomass municipal materials, if recycled and combusted to produce heat or electricity

10.5

87.1

0.8

1.0

10

Dry wood

16.2

0.0

0.1

1.1

11

Green and air dried wood

10.4

0.0

0.1

1.1

12

Sulphite lyes

12.4

0.0

0.08

0.5

13

Bagasse

9.6

0.0

0.3

1.1

14

Biomass municipal and industrial materials, if recycled and combusted to produce heat or electricity

12.2

0.0

0.8

1.0

15

Charcoal

31.1

0.0

5.3

1.0

16

Primary solid biomass fuels other than those mentioned in items 10 to 15

12.2

0.0

0.8

1.0

Note:          Energy content and emission factors for coal products are measured on an as combusted basis. The energy content for black coal and coking coal (metallurgical coal) is on a washed basis.

Part 2Fuel combustion—gaseous fuels

 

Item

Fuel combusted

Energy content factor

(GJ/m3 unless otherwise indicated)

Emission factor

kg CO2‑e/GJ

(relevant oxidation factors incorporated)

CO2

CH4

N2O

17

Natural gas distributed in a pipeline

39.3 × 10‑3

51.4

0.1

0.03

18

Coal seam methane that is captured for combustion

37.7 × 10‑3

51.4

0.2

0.03

19

Coal mine waste gas that is captured for combustion

37.7 × 10‑3

51.9

4.6

0.3

20

Compressed natural gas that has reverted to standard conditions

39.3 × 10‑3

51.4

0.1

0.03

21

Unprocessed natural gas

39.3 × 10‑3

51.4

0.1

0.03

22

Ethane

62.9 × 10‑3

56.5

0.03

0.03

23

Coke oven gas

18.1 × 10‑3

37.0

0.03

0.05

24

Blast furnace gas

4.0 × 10‑3

234.0

0.03

0.02

25

Town gas

39.0 × 10‑3

60.2

0.04

0.03

26

Liquefied natural gas

25.3 GJ/kL

51.4

0.1

0.03

27

Gaseous fossil fuels other than those mentioned in items 17 to 26

39.3 × 10‑3

51.4

0.1

0.03

28

Landfill biogas that is captured for combustion (methane only)

37.7 × 10‑3

0.0

6.4

0.03

29

Sludge biogas that is captured for combustion (methane only)

37.7 × 10‑3

0.0

6.4

0.03

30

A biogas that is captured for combustion, other than those mentioned in items 28 and 29 (methane only)

37.7 × 10‑3

0.0

6.4

0.03

 

 

 

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

                                                                                                                                                        

Item

Fuel combusted

Energy content factor

(GJ/kL unless otherwise indicated)

Emission factor

kg CO2‑e/GJ

(relevant oxidation factors incorporated)

CO2

CH4

N2O

31

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

38.8

13.9

0.0

0.0

32

Petroleum based greases

38.8

3.5

0.0

0.0

33

Crude oil including crude oil condensates

45.3 GJ/t

69.6

0.08

0.2

34

Other natural gas liquids not covered by another item in this table

46.5 GJ/t

61.0

0.08

0.2

35

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

34.2

67.4

0.2

0.2

36

Gasoline for use as fuel in an aircraft

33.1

67.0

0.2

0.2

37

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

37.5

68.9

0.01

0.2

38

Kerosene for use as fuel in an aircraft

36.8

69.6

0.02

0.2

39

Heating oil

37.3

69.5

0.03

0.2

40

Diesel oil

38.6

69.9

0.1

0.2

41

Fuel oil

39.7

73.6

0.04

0.2

42

Liquefied aromatic hydrocarbons

34.4

69.7

0.03

0.2

43

Solvents if mineral turpentine or white spirits

34.4

69.7

0.03

0.2

44

Liquefied petroleum gas

25.7

60.2

0.2

0.2

45

Naphtha

31.4

69.8

0.01

0.01

46

Petroleum coke

34.2 GJ/t

92.6

0.08

0.2

47

Refinery gas and liquids

42.9 GJ/t

54.7

0.03

0.03

48

Refinery coke

34.2 GJ/t

92.6

0.08

0.2

49

Petroleum based products other than:

(a) petroleum based oils and petroleum based greases mentioned in items 31 and 32; and

(b) the petroleum based products mentioned in items 33 to 48.

34.4

69.8

0.02

0.1

50

Biodiesel

34.6

0.0

0.08

0.2

51

Ethanol for use as a fuel in an internal combustion engine

23.4

0.0

0.08

0.2

52

Biofuels other than those mentioned in items 50 and 51

23.4

0.0

0.08

0.2

Part 4Fuel combustion—fuels for transport energy purposes

Division 4.1Fuel combustion—fuels for transport energy purposes

 

Item

Fuel combusted

Energy content factor

(GJ/kL unless otherwise indicated)

Emission factor

kg CO2‑e/GJ

(relevant oxidation factors incorporated)

CO2

CH4

N2O

53

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

34.2

67.4

0.6

1.6

54

Diesel oil

38.6

69.9

0.1

0.4

55

Gasoline for use as fuel in an aircraft

33.1

67.0

0.06

0.6

56

Kerosene for use as fuel in an aircraft

36.8

69.6

0.01

0.6

57

Fuel oil

39.7

73.6

0.08

0.5

58

Liquefied petroleum gas

26.2

60.2

0.7

0.6

59

Biodiesel

34.6

0.0

0.8

1.7

60

Ethanol for use as fuel in an internal combustion engine

23.4

0.0

0.8

1.7

61

Biofuels other than those mentioned in items 59 and 60

23.4

0.0

0.8

1.7

62

Compressed natural gas that has reverted to standard conditions (light duty vehicles)

39.3 × 10‑3 GJ/m3

51.4

7.3

0.3

63

Compressed natural gas that has reverted to standard conditions (heavy duty vehicles)

39.3 × 10‑3 GJ/m3

51.4

2.8

0.3

63A

Liquefied natural gas (light duty vehicles)

25.3

51.4

7.3

0.3

63B

Liquefied natural gas (heavy duty vehicles)

25.3

51.4

2.8

0.3

Division 4.2Fuel combustion—liquid fuels for transport energy purposes for post‑2004 vehicles

 

Item

Fuel combusted

Energy content factor

GJ/kL

Emission factor

kg CO2‑e/GJ

(relevant oxidation factors incorporated)

CO2

CH4

N2O

64

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

34.2

67.4

0.02

0.2

65

Diesel oil

38.6

69.9

0.01

0.5

66

Liquefied petroleum gas

26.2

60.2

0.5

0.3

67

Ethanol for use as fuel in an internal combustion engine

23.4

0.0

0.2

0.2

Division 4.3Fuel combustion—liquid fuels for transport energy purposes for certain trucks

 

Item

Fuel type

Heavy vehicles design standard

Energy content factor

GJ/kL

Emission factor

kg CO2‑e/GJ

(relevant oxidation factors incorporated)

CO2

CH4

N2O

68

Diesel oil

Euro iv or higher

38.6

69.9

0.07

0.4

69

Diesel oil

Euro iii

38.6

69.9

0.1

0.4

70

Diesel oil

Euro i

38.6

69.9

0.2

0.4

[45]         Part 6 of Schedule 1

Repeal the Part, substitute:

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

  

 

Indirect (scope 2) emissions factors from consumption of electricity purchased or lost from grid

Item

Column 1

State, Territory or grid description

Column 2

Emission factor
kg CO2‑e/kWh

77

New South Wales and Australian Capital Territory

0.81

78

Victoria

0.98

79

Queensland

0.81

80

South Australia

0.43

81

South West Interconnected System in Western Australia

0.68

82

Tasmania

0.17

83

Northern Territory

0.62