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

Dated     15 June 2020

Angus Taylor

 

 

  

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Note:          This table relates only to the provisions of this instrument as originally made.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                   Each instrument that is specified in a Schedule to this instrument is amended or repealed as set out in the applicable items in the Schedule concerned, and any other item in a Schedule to this instrument has effect according to its terms.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 1—Amendments

National Greenhouse and Energy Reporting (Measurement) Determination 2009

[1]           Section 1.8

Insert in the appropriate alphabetical position:

GWP_methane 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 EF_j)

Repeal the definition, substitute:

EF_j 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 γ_j)

Omit “25”, substitute “GWP_methane”.

[4]           Subsection 3.17(2)

Omit “0.017”, substitute “0.019”.

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

Repeal the paragraphs, substitute:

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

 (b)        for a mine in Victoria—0.0003;

 (c) for a mine in Queensland—0.023;

 (d)        for a mine in Western Australia—0.023;

 (e) for a mine in South Australia—0.0003;

 (f) for a mine in Tasmania—0.019.

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

Omit “25”, substitute “GWP_methane”.

[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 γ_j)

Omit “25”, substitute “GWP_methane”.

[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 EF_ij)

Omit “8.7”, substitute “9.74”.

[13]         Section 3.63 (definition of EF_ij)

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 CO2‑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 EF_ij)

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 γ_j)

Omit “25”, substitute “GWP_methane”.

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

Omit “25”, substitute “GWP_methane”.

[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 EF_ij)

Omit “0.30”, substitute “0.27”.

[25]         Section 4.89 (definition of EF_ij)

Omit “0.07”, substitute “0.06”.

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

Omit “25”, substitute “GWP_methane”.

[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 “GWP_methane”.

[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 “GWP_methane”.

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

Omit “25”, substitute “GWP_methane”.

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

Omit “25”, substitute “GWP_methane”.

[37]         Subsection 5.26(2) (definitions of EF_slijz and EF_wijz)

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 “GWP_methane”.

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

 

Item	Fuel combusted		Energy content factor GJ/t		Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
					CO2		CH4	N2O
1	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 2—Fuel combustion—gaseous fuels

 

Item	Fuel combusted	Energy content factor (GJ/m3 unless otherwise indicated)	Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
			CO2	CH4	N2O
17	Natural gas distributed in a pipeline	39.3 × 10‑3	51.4	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 4—Fuel combustion—fuels for transport energy purposes

Division 4.1—Fuel combustion—fuels for transport energy purposes

 

Item		Fuel combusted	Energy content factor (GJ/kL unless otherwise indicated)	Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
				CO2	CH4	N2O
53	Gasoline (other than for use as fuel in an aircraft)		34.2	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 4.2—Fuel combustion—liquid fuels for transport energy purposes for post‑2004 vehicles

 

Item	Fuel combusted		Energy content factor GJ/kL		Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
					CO2		CH4	N2O
64	Gasoline (other than for use as fuel in an aircraft)	34.2		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 4.3—Fuel combustion—liquid fuels for transport energy purposes for certain trucks

 

Item	Fuel type	Heavy vehicles design standard	Energy content factor GJ/kL	Emission factor kg CO2‑e/GJ (relevant oxidation factors incorporated)
				CO2	CH4	N2O
68	Diesel oil	Euro iv 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 6—Indirect (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