National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015

Part 1—Preliminary

1 Name

This is the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015.

3 Authority

This instrument is made under subsection 22XS(1) of the National Greenhouse and Energy Reporting Act 2007.

4 Definitions

In this instrument:

accelerated depreciation factor has the meaning given by subsection 37(6).

Act means the National Greenhouse and Energy Reporting Act 2007.

adverse conclusion has the meaning given by the National Greenhouse and Energy Reporting (Audit) Determination 2009.

amount includes a nil amount.

askm means available seat kilometres.

assessed cost impact, for a facility for a financial year, has the meaning given by section 36.

Australian accounting standards means the accounting standards in force under section 334 of the Corporations Act 2001.

Note: In 2023, the Australian accounting standards were accessible at http://www.aasb.gov.au.

best practice emissions intensity, for a production variable for a financial year, means the best practice emissions intensity (if any) specified, in t CO2‑e per unit of the production variable, in relation to the production variable in Schedule 1 as in force at:

(a) if the financial year is the financial year beginning on 1 July 2023—the end of the financial year; or

(b) otherwise—the start of the financial year.

best practice emissions intensity number, for a production variable for a financial year, means the number that is equal to the best practice emissions intensity for the production variable for that financial year.

Example: If the best practice emissions intensity for a tonne of glass in the financial year beginning on 1 July 2024 is 0.6 t CO2‑e per tonne of glass, the best practice emissions intensity number for a tonne of glass in that financial year is 0.6.

borrowing adjustment, for a facility for a financial year, has the meaning given by section 47.

borrowing adjustment determination means a determination made under section 50.

borrowing adjustment number, for a facility for a financial year: see subsection 50(3).

by‑product means a saleable output or other product that:

(a) results from a chemical or physical process undertaken by a facility other than for the purpose of producing the output; and

(b) will be disposed of, by sale or gift, without any further processing by the facility (other than further processing in accordance with standard industry practice); and

comparative production variable, for a related production variable, has the meaning given by paragraph 19(4)(b).

criminal activity means any activity that the Regulator has reasonable cause to believe involves the commission of an offence by one or more persons.

Darwin to Katherine network means the local distribution systems in items 1, 2 and 5 of Schedule 2 to the National Electricity (Northern Territory) (National Uniform Legislation) Act 2015 (NT) and any transmission or distribution system which is connected to those local distribution systems.

decision date, for an application under Part 3, has the meaning given by subsection 52(2).

default decline rate, for a financial year, has the meaning given by section 32.

default emissions intensity, for a production variable for a financial year, means the default emissions intensity specified, in t CO2‑e per unit of the production variable, in relation to the production variable in Schedule 1 as in force at the start of that financial year.

default emissions intensity number, for a production variable for a financial year, means the number that is equal to the default emissions intensity of the production variable.

Example: If the default emissions intensity for a tonne of glass in the financial year beginning on 1 July 2024 is 0.8 t CO2‑e per tonne of glass, the default emissions intensity number for a tonne of glass in that financial year is 0.8.

default emissions reduction contribution, for a financial year, has the meaning given by section 31.

designated electricity network means one of the following electricity networks:

(a) the interconnected national electricity system within the meaning of the National Electricity Law set out in the Schedule to the National Electricity (South Australia) Act 1996 (SA);

(b) the South West interconnected system within the meaning of section 3 of the Electricity Industry Act 2004 (WA);

(c) the North West interconnected system within the meaning of section 2 of the Electricity Transmission and Distribution Systems (Access) Act 1994 (WA);

(d) the Darwin to Katherine network;

(e) the Mount Isa–Cloncurry supply network within the meaning of section 10 of the Electricity—National Scheme (Queensland) Act 1997 (Qld).

designated historical information, about a historical production variable for a facility, has the meaning given by subsection 14(5).

details, in relation to a declaration under this instrument, includes:

(a) the type of declaration; and

(b) the facility to which the declaration relates; and

(d) the start and any end date of the declaration; and

(e) if the declaration is being varied—the nature of that variation.

due date, for an application under Part 3, has the meaning given by subsection 52(1).

dwtnmi means dead weight tonne nautical miles.

EBIT Guidelines has the meaning given by subsection 37(7).

eligible facility, for a financial year, has the meaning given by section 58B.

emissions intensity determination means:

(a) a determination made under section 19; or

(b) a successor determination.

emissions reduction contribution:

(a) for a regular facility for a financial year—has the meaning given by section 33; or

(b) for a trade‑exposed baseline‑adjusted facility for a financial year—has the meaning given by section 34.

existing facility has the meaning given by subsection 12(1).

facility‑specific emissions intensity number:

(a) of a historical production variable for a facility—has the meaning given by subsection 20(1); or

(b) of a related production variable for a facility—has the meaning given by subsection 20(5); or

first adjusted financial year, for a facility, has the meaning given by subsection 36(6).

grid‑connected electricity generator means a designated generation facility connected to a designated electricity network at any time during a financial year.

historical financial year has the meaning given by subsection 12(3).

historical production variable, for a facility, has the meaning given by subsection 12(2).

hypothetical baseline, of a facility for a financial year, has the meaning given by subsection 36(7).

identifying details has the meaning given by the NGER Regulations.

identifying information has the meaning given by the NGER Regulations.

input means:

(a) if the input relates to a landfill facility—a tonne of waste received by a landfill facility; and

(b) otherwise—anything that undergoes a chemical or physical process to produce an intermediate product or an output.

intermediate product means a product that:

(a) results from a chemical or physical process undertaken by a facility using one or more inputs; and

(b) is then used as an input for the production of an output at the same facility.

landfill facility means a facility for the disposal of solid waste as landfill, and includes a facility that is closed for the acceptance of waste.

legacy emissions has the meaning given by subsection 7(2).

limited assurance conclusion has the meaning given by the National Greenhouse and Energy Reporting (Audit) Determination 2009.

manufacturing facility: a facility is a manufacturing facility in a financial year if the primary production variable for the facility in the financial year is a manufacturing production variable.

manufacturing production variable means a production variable that is listed in the table in section 1 of Schedule 2.

multi‑year period declaration has the meaning given by subsection 65(1).

m3km means metres cubed kilometres.

national facility definition means the requirements for a transport facility applying as a result of a nomination under subregulation 2.19A(2) of the NGER Regulations.

new facility has the meaning given by subsection 29(2).

NGER (Measurement) Determination means the National Greenhouse and Energy Reporting (Measurement) Determination 2008.

NGER Regulations means the National Greenhouse and Energy Reporting Regulations 2008.

non‑commercial production variable, for a facility for a financial year, has the meaning given by subsection 12(5).

output means a product that is:

(a) if the output is from a transport facility—a transport service measured by service units; or

(b) if more than 25,000 megawatt hours of electricity is, or is to be, generated at the facility in a financial year—electricity generated at the facility; or

(c) otherwise—the last product resulting from a chemical or physical process undertaken by a facility using one or more inputs or intermediate products.

pkm means passenger kilometres.

pnmi means passenger nautical miles.

primary production variable, for a facility, means:

(a) if there is only one production variable for the facility—that production variable; or

(b) if there are 2 or more production variables for the facility—the production variable that is most significant for the operation of the facility, having primary regard to the share of revenue and covered emissions directly or indirectly attributable to that production variable.

production variable, for a facility, means a production variable that is applicable to the facility in accordance with Schedule 1.

production variable means a metric that is set out in a Part of Schedule 1.

qualified limited assurance conclusion has the meaning given by the National Greenhouse and Energy Reporting (Audit) Determination 2009.

qualified reasonable assurance conclusion has the meaning given by the National Greenhouse and Energy Reporting (Audit) Determination 2009.

quantity, of a production variable for a facility for a financial year, means the number of units of the production variable for the facility for that financial year.

Example: If a facility produces 500 tonnes of glass in a financial year, the quantity of tonnes of glass for that financial year is 500.

ratio of cost impacts, for a facility for a financial year, has the meaning given by section 35.

reasonable assurance conclusion has the meaning given by the National Greenhouse and Energy Reporting (Audit) Determination 2009.

regular facility: a facility that is not a trade‑exposed baseline‑adjusted facility in a financial year is a regular facility in that financial year.

related production variable, for a facility, has the meaning given by paragraph 19(4)(a).

relevant historical financial year, for a production variable, has the meaning given by subsection 20(3).

relevantly associated with has the meaning given by section 16.

responsible financial officer, of a responsible emitter for a facility, means any of the following:

(a) if the person with operational control of the facility is an individual—that person;

(b) a person who holds or performs the duties of the position of the chief executive officer, chief financial officer or chief operating officer for the person with operational control of the facility;

(c) a person who holds or performs the duties of a position with equivalent or similar responsibilities to a person with a position in paragraph (b);

(d) an individual employed by the person with operational control of the facility who:

(i) makes, or participates in making, decisions that affect the whole, or a substantial part, of the business or affairs of the person; or

(ii) has the capacity to significantly affect the person’s financial standing.

Safeguard Mechanism default prescribed unit price, for a financial year, has the meaning given by section 38.

Safeguard Mechanism document means the document of that name published on the Department’s website, as in force from time to time.

Note: In 2023, the document could be accessed from http://www.dcceew.gov.au.

sectoral‑baseline financial year means every financial year before the financial year beginning on the first 1 July after the Regulator has published a statement on its website that the total reported scope 1 emissions of all grid‑connected electricity generators exceeded 198,000,000 t CO2‑e emissions in the previous financial year based upon reports submitted to the Regulator at the time of the statement. The Regulator must take all reasonable steps to publish the statement at least 4 months before the start of the financial year which is not a sectoral‑baseline financial year.

Example: If the sum of reported emissions from each grid‑connected electricity generator was 210,000,000 t CO2‑e in 2020‑21, by 28 February 2022 the Regulator would publish a statement on its website and the financial year beginning 1 July 2022 would not be a sectoral‑baseline financial year and emissions of grid‑connected electricity generators would be covered emissions in that year.

service unit means a unit of measure related to a transport facility (such as askm, dwtnmi, m3km, pkm, pnmi, tkm, tnmi or vkt) determined and measured by the responsible emitter for the facility taking into account:

(a) standard industry practice; and

(b) existing measurement systems used by the responsible emitter.

shale gas extraction facility has the meaning given by section 54.

significant cost impact threshold, for a facility, has the meaning given by subsection 35(4).

successor determination means a determination made under section 24.

t CO2‑e means tonnes of carbon dioxide equivalence.

tkm means tonne kilometres.

tnmi means tonne nautical miles.

trade‑exposed baseline‑adjusted facility: a facility is a trade‑exposed baseline‑adjusted facility in a financial year if it is determined to be a trade‑exposed baseline‑adjusted facility in that financial year under section 42.

trade‑exposed production variable means a production variable that is listed in a table in Schedule 2.

transitional production variable, for a facility, has the meaning given by subsection 12(4).

transition proportion, for a financial year, has the meaning given by section 13.

vkt means vehicle kilometres travelled.

waste product means an output or other product that:

(a) results from a chemical or physical process undertaken by a facility other than for the purpose of producing the output; and

(b) will be disposed of without any further processing by the facility (other than further processing in accordance with standard industry practice); and

Part 2—Coverage

7 Covered emissions

(1) For section 22XI of the Act, the following scope 1 emissions of one or more greenhouse gases are not covered emissions for the purposes of the safeguard mechanism:

(a) emissions of one or more greenhouse gases in circumstances where the Minister has not determined, under subsection 10(3) of the Act:

(i) methods by which the amounts of the scope 1 emissions of the greenhouse gas are to be measured; or

(ii) criteria for methods by which the amounts of the scope 1 emissions of the greenhouse gas are to be measured;

(b) legacy emissions from the operation of a landfill facility;

(c) emissions of one or more greenhouse gases from the operation of a grid‑connected electricity generator in respect of a sectoral‑baseline financial year;

(d) if a facility is partly in Australia and partly in the Greater Sunrise special regime area—scope 1 emissions of greenhouse gases which occurred in the Greater Sunrise special regime area.

Note: A facility wholly in the Greater Sunrise special regime area is not subject to the safeguard provisions in accordance with subsection 6A(4) of the Act.

Legacy emissions

(2) For the purposes of subsection (1), if:

(a) an amount of greenhouse gas was emitted from the operation of a landfill facility; and

(b) waste was accepted by the landfill facility before 1 July 2016;

so much of the amount mentioned in paragraph (a) as is, under a determination under subsection 10(3) of the Act, taken to be attributable to waste accepted by the facility before 1 July 2016 is a legacy emission from the operation of the landfill facility.

Emissions not included as emissions from grid‑connected electricity generators

(3) For the purposes of paragraph (1)(c), emissions of one or more greenhouse gases from the operation of a grid‑connected electricity generator in respect of a sectoral‑baseline financial year do not include:

(a) fugitive emissions from coal mining (within the meaning of the NGER (Measurement) Determination); or

(b) emissions from fuel combustion for the purposes of coal mining; or

(c) emissions covered by Chapter 2 (fuel combustion) of the NGER (Measurement) Determination that are not for electricity generation or cogeneration.

8 Designated large facility threshold

For paragraph 22XJ(1)(b) of the Act, the specified number is 100,000.

Part 3—Baseline emissions number

Division 1—General

9 Baseline emissions number—main rule

(1) Unless otherwise provided, the provisions of this Part are made for the purposes of subsection 22XL(1) of the Act.

(2) The baseline emissions number for a facility for a financial year is ascertained in relation to the facility in accordance with Divisions 2 to 7 of this Part.

(3) Subsection (2) has effect subject to section 10.

10 Baseline emissions number—special rules

Minimum baseline

(1) The baseline emissions number for a facility for a financial year is 100,000 if:

(a) the baseline emissions number for the facility for the financial year that is ascertained in accordance with Divisions 2 to 7 of this Part is a number less than 100,000; and

(b) that number is not less than 100,000 merely because of a borrowing adjustment for the facility for the financial year.

Note: This means that the baseline emissions number for a facility for a financial year can be less than 100,000 if there is a sufficiently large borrowing adjustment for the facility for that financial year.

Zero baseline for shale gas extraction facilities

(2) The baseline emissions number for a facility for a financial year is zero if the facility is a shale gas extraction facility.

Zero baseline from 2050

(3) The baseline emissions number for a facility for a financial year that begins after 30 June 2049 is zero.

Division 2—Existing facilities

Subdivision A—Baseline emissions number for existing facility

11 Baseline emissions number for existing facility

(1) The baseline emissions number for an existing facility (other than a landfill facility) for a financial year is the number worked out using the following formula:

where:

ERC is the emissions reduction contribution for the facility for the financial year.

p is a production variable for the facility for the financial year.

h is the transition proportion for the financial year.

EI, in relation to a production variable for the facility for the financial year, is the default emissions intensity number of the production variable for the financial year.

Note: The default emissions intensity number of tonnes of reservoir carbon dioxide from new gas fields is zero (see section 35A of Schedule 1).

EIF, in relation to a production variable for the facility for the financial year, is:

(a) if an emissions intensity determination that applies in relation to the facility for the financial year specifies a facility‑specific emissions intensity number of the production variable—that number; or

(b) otherwise—0.

Q, in relation to a production variable for the facility for the financial year, is:

(b) otherwise—0.

EIB, in relation to a production variable for the facility for the financial year, is:

(a) if there is a best practice emissions intensity number for the production variable for the financial year—that number; or

(b) if there is no best practice emissions intensity number for the production variable for the financial year, and the production variable is a historical production variable for the facility—zero; or

Note: The best practice emissions intensity number of tonnes of reservoir carbon dioxide from new gas fields is zero (see section 35A of Schedule 1).

QB, in relation to a production variable for the facility for the financial year, is:

(b) otherwise—the quantity of the production variable for the facility for the financial year.

BA is the borrowing adjustment for the facility for the financial year.

(2) The number worked out using the formula in subsection (1) is to be rounded to the nearest whole number (rounding up if the first decimal place is 5 or more).

12 Meaning of existing facility

(1) A facility is an existing facility if there are one or more historical production variables or transitional production variables for the facility.

(2) A historical production variable, for a facility, is a production variable that:

(a) was applicable to the facility, in accordance with Schedule 1, at any time during a historical financial year; and

(b) was not a non‑commercial production variable for the facility for the historical financial year.

(3) A historical financial year is:

(a) the financial year beginning on 1 July 2017; or

(b) the financial year beginning on 1 July 2018; or

(d) the financial year beginning on 1 July 2020; or

(e) the financial year beginning on 1 July 2021.

(4) A transitional production variable, for a facility, is a production variable that:

(a) was not applicable to the facility, in accordance with Schedule 1, at any time during a historical financial year; and

(b) was applicable to the facility, in accordance with Schedule 1, at a time during the financial year beginning on 1 July 2022; and

(5) A non‑commercial production variable, for a facility for a financial year, is a production variable that, at a time during the financial year, was applicable to the facility, in accordance with Schedule 1, merely because of testing or piloting activities undertaken at the facility.

Subdivision B—Transition proportion

13 Transition proportion

The transition proportion for a financial year beginning on a day specified in column 1 of an item of the following table is the number specified in column 2 of that item.

Transition proportion
Item	Column 1 Financial year	Column 2 Transition proportion
1	1 July 2023	0.1
2	1 July 2024	0.2
3	1 July 2025	0.3
4	1 July 2026	0.4
5	1 July 2027	0.6
6	1 July 2028	0.8
7	1 July 2029 or a later 1 July	1

Subdivision C—Emissions intensity determination

14 Application for emissions intensity determination

(1) The responsible emitter for an existing facility may apply to the Regulator for an emissions intensity determination.

(2) The application must be made:

(a) in a manner and form approved, in writing, by the Regulator; and

(b) before the end of the due date for the application, unless the Regulator agrees to accept the application after that date.

Note 1: For the due date for the application, see section 52.

Note 2: For withdrawal of the application, see section 53.

(3) The application must specify:

(a) the first financial year in relation to which the determination would apply; and

(b) the historical production variables (if any) for the facility; and

(c) for each historical financial year—a calculation, in accordance with section 15, of the amount of covered emissions of greenhouse gases (in t CO2‑e) from the operation of the facility during the historical financial year; and

(d) the estimates and assumptions (if any) made in accordance with subsection 15(3); and

(e) the transitional production variables (if any) for the facility.

(4) For each historical production variable for the facility, the application must, to the extent reasonably practicable, include the designated historical information about the production variable.

(5) The following information is the designated historical information about a historical production variable for a facility:

(a) the quantity of the production variable in each historical financial year that is measured in accordance with any measurement requirements or procedures specified in Schedule 1 in relation to the production variable;

(b) the amount of covered emissions of greenhouse gases (in t CO2‑e) relevantly associated with the production variable in each historical financial year.

Note: See the definition of relevantly associated with in section 16.

(6) If the application does not include the designated historical information about a historical production variable for the facility, the application must include an explanation of why such information has not been included.

(7) If a greenhouse gas other than carbon dioxide comprises more than 1% of the covered emissions relevantly associated with a production variable for the facility in a particular historical financial year, the application must specify the amount of that gas (in t CO2‑e).

(8) The application may include a request for the determination to include a statement that:

(a) a particular production variable for the facility is a related production variable for the facility; and

(b) another specified production variable for the facility is the comparative production variable for that related production variable.

14A Application specifying primary steel as production variable may specify steelmaking production variables as historical production variables

(1) An application under section 14 for an emissions intensity determination that specifies primary steel as a production variable may also specify the following production variables (the steelmaking production variables) as historical production variables for the facility:

(a) the primary iron (steelmaking) production variable; and

(b) the ferrous feed (steelmaking) production variable.

Note: Section 19A applies to an application which specifies the steelmaking production variables as historical production variables.

(2) Despite paragraph 12(2)(b), the steelmaking production variables may be specified as historical production variables for a facility even if one or both of them was a non‑commercial production variable for the facility for a historical financial year.

(3) Despite paragraph 16(2)(b), covered emissions of greenhouse gases from the operation of a facility during a particular historical financial year that are of a particular kind may be attributed to both a steelmaking production variable and to the primary steel production variable.

(4) Despite paragraph 16(3)(d), covered emissions of greenhouse gases from the operation of a facility during a particular historical financial year may be attributed to both a steelmaking production variable and to the primary steel production variable.

Note: Emissions associated with the production of primary iron and continuously cast carbon steel products and ingots of carbon steel would also be relevantly associated with primary steel.

(5) In this Part:

continuously cast carbon steel products and ingots of carbon steel (manufacture of carbon steel from cold ferrous feed) production variable means the production variable in section 44 of Schedule 1.

ferrous feed (steelmaking) production variable means the production variable in section 44A of Schedule 1.

primary iron (steelmaking) production variable means the production variable in section 39A of Schedule 1.

primary iron production variable means the production variable in section 39 of Schedule 1.

primary steel production variable means the production variable in section 41 of Schedule 1.

steelmaking production variables has the meaning given by subsection (1).

15 Calculating an amount of covered emissions

(1) This section specifies requirements for the purposes of calculating an amount of covered emissions of greenhouse gases from the operation of a facility during a historical financial year.

(2) The amount must be calculated:

(a) in accordance with the NGER (Measurement) Determination; and

(b) using the Global Warming Potentials specified for the relevant greenhouse gas in regulation 2.02 of the NGER Regulations; and

(c) using the same method as the method (the most recent method) that was used in the most recent report provided to the Regulator relating to the greenhouse gas emissions from the operation of the facility.

(3) For the purposes of paragraph (2)(c), if:

(a) a report was provided to the Regulator relating to the greenhouse gas emissions from the operation of the facility during the historical financial year; and

(b) the report used a method other than the most recent method;

estimates and assumptions may be made for the purposes of using the most recent method to calculate the amount.

(4) In this section:

method has the same meaning as in the NGER (Measurement) Determination.

16 Covered emissions relevantly associated with a historical production variable

(1) Covered emissions of greenhouse gases from the operation of a facility during a particular historical financial year are relevantly associated with a historical production variable for the facility in that financial year if those emissions are attributed to the production variable for the financial year in accordance with subsection (2) or (3).

Emissions relevant to default emissions intensity

(2) Covered emissions of greenhouse gases from the operation of a facility during a particular historical financial year that are of a particular kind are attributed to a production variable for the facility for that financial year if:

(a) having regard to the Safeguard Mechanism document, covered emissions of that kind are relevant to the default emissions intensity of that production variable for that financial year; and

(b) those emissions are not attributed to another production variable in accordance with this section.

(2A) To avoid doubt, the Safeguard Mechanism document may specify that a particular kind of covered emissions is relevant to the default emissions intensity of a production variable notwithstanding that the specified kind of covered emissions was not taken into account when the default emissions intensity was calculated.

Emissions from minor emissions sources

(3) Covered emissions of greenhouse gases from the operation of a facility during a particular historical financial year are attributed to a production variable for the facility for that financial year if:

(a) the emissions come from a minor emissions source for the facility for the historical financial year; and

(b) the emissions fairly represent the actual emissions from the production of the production variable; and

(d) the emissions are not apportioned to another production variable for the facility for that financial year.

(4) In this section, a source of emissions is a minor emissions source for a facility in a historical financial year if the sum of the emissions from that source, and every other minor emissions source for the facility in that historical financial year, is less than 10% of the facility’s total covered emissions in that financial year.

17 Application must be accompanied by safeguard audit report

(1) This section is made for the purposes of subsection 22XQ(3) of the Act.

(2) An application for an emissions intensity determination by the responsible emitter for an existing facility must be accompanied by an audit report that meets the requirements of this section.

Note: Under subsection 75(1) of the Act, the Minister may determine requirements to be met by registered greenhouse and energy auditors in preparing for and carrying out safeguard audits.

Reasonable assurance matters

(3) The audit report must include a conclusion in relation to each of the following matters:

(a) whether, in all material respects, the application correctly specifies the historical production variables (if any) for the facility;

(b) if the application includes the designated historical information about a historical production variable for the facility for a historical financial year—whether, in all material respects, the application correctly specifies the quantity of the historical production variable in the historical financial year;

(c) whether, in all material respects, the application correctly specifies the amount of covered emissions for the facility in each historical financial year;

(d) whether, in all material respects, the application correctly specifies the transitional production variables (if any) for the facility.

Limited assurance matters

(4) The audit report must include a conclusion in relation to each of the following matters:

(a) if the application specifies one or more historical production variables for the facility—whether, in all material respects, the application correctly specifies the amount of covered emissions of greenhouse gases from the operation of the facility that are relevantly associated with each of those production variables;

(b) whether, in all material respects, calculations of amounts of covered emissions of greenhouse gases from the operation of the facility that are included in the application meet the requirements specified in section 15;

(c) if the application includes estimates and assumptions made in accordance with subsection 15(3)—whether, in all material respects, those estimates and assumptions are reasonable.

Previously audited matters

(5) Despite subsections (3) and (4), the audit report does not need to include a conclusion:

(a) about a matter in subsection (3) if the responsible emitter has previously given the Regulator an audit report that includes a reasonable assurance conclusion in relation to the matter; or

(b) about a matter in subsection (4) if the responsible emitter has previously given the Regulator an audit report that includes a limited assurance conclusion in relation to the matter.

(6) An audit report under this section must be the result of an audit which:

(a) was conducted in accordance with the relevant requirements for reasonable assurance engagements under the National Greenhouse and Energy Reporting (Audit) Determination 2009; and

(b) had an audit team leader who is registered as a Category 2 auditor under subregulation 6.25(3) of the NGER Regulations.

18 Consideration of application

(1) This section applies if the responsible emitter for an existing facility applies for an emissions intensity determination in accordance with this Subdivision.

(2) Subject to subsection (4), the Regulator must take all reasonable steps to decide the application under section 19 before the end of the decision date for the application.

Note: For the decision date for the application, see section 52.

(3) The Regulator may, by notice in writing, require the applicant to give the Regulator, within the period specified in the notice, such further information in relation to the application as the Regulator requires.

(4) The Regulator is not required to decide the application, and may cease considering whether to decide the application, if the applicant does not provide the required information within the period specified in the notice.

19 Emissions intensity determination

(1) If the responsible emitter for an existing facility applies for an emissions intensity determination in accordance with this Subdivision, the Regulator must decide to:

(a) make the determination; or

(b) refuse to make the determination.

(2) The Regulator must not make the determination unless:

(a) the audit report that accompanies the application includes:

(i) a reasonable assurance conclusion, or a qualified reasonable assurance conclusion, in relation to each of the matters specified in subsection 17(3); and

(ii) a limited assurance conclusion, or a qualified limited assurance conclusion, in relation to each of the matters specified in subsection 17(4); and

(b) the Regulator is reasonably satisfied, having regard to any matter the Regulator considers relevant, that:

(i) the information included in the application is correct; and

(ii) any explanation in the application of why the designated historical information about a historical production variable for the facility has not been included in the application is reasonable; and

(iii) calculations of amounts of covered emissions of greenhouse gases from the operation of the facility that are included in the application meet the requirements specified in section 15; and

(iv) any estimates and assumptions made in accordance with subsection 15(3) and included in the application are reasonable.

(3) The determination must be in writing and must specify:

(a) the facility‑specific emissions intensity number of:

(i) any historical production variable for the facility; and

(ii) any transitional production variable for the facility; and

(iii) any related production variable for the facility; and

(b) the first financial year in relation to which the determination applies.

(4) The determination may state that:

(a) a particular production variable for the facility is a related production variable for the facility; and

(b) another specified production variable for the facility is the comparative production variable for that related production variable.

Note: See Subdivision D (related production variables).

(5) The determination:

(a) comes into force on the first day of the financial year specified for the purposes of paragraph (3)(b); and

(b) applies in relation to the facility for that financial year and each subsequent financial year.

Note: See subsection 22XQ(2) of the Act (commencement of determination).

(6) If the Regulator makes the determination, the Regulator must:

(a) notify the applicant for the determination that the Regulator has made the determination; and

(b) publish the determination on the Regulator’s website.

(7) If the Regulator decides to refuse to make the determination, the Regulator must give the applicant for the determination a written notice of the decision that includes the Regulator’s reasons for the decision.

19A Emissions intensity determination in relation to application specifying steelmaking production variables as historical production variables

(1) This section applies if an application under section 14 for an emissions intensity determination specifies the steelmaking production variables as historical production variables, and the Regulator decides under subsection 19(1) to make the determination.

(2) The following production variables are taken to be historical production variables for the facility:

(a) the primary iron production variable; and

(b) the continuously cast carbon steel products and ingots of carbon steel (manufacture of carbon steel from cold ferrous feed) production variable.

(3) Subparagraph 19(3)(a)(i) applies to the production variables mentioned in subsection (2) instead of the steelmaking production variables.

Note: Subparagraph 19(3)(a)(i) requires a determination to specify the facility‑specific emissions intensity number of any historical production variable for the facility.

(4) For the purpose of subsection 19(3)(a)(i), the Regulator must consider the designated historical information included in the application:

(a) in relation to the primary iron (steelmaking) production variable—as if that information was instead in relation to the primary iron production variable; and

(b) in relation to the ferrous feed (steelmaking) production variable—as if that information was instead in relation to the continuously cast carbon steel products and ingots of carbon steel (manufacture of carbon steel from cold ferrous feed) production variable.

20 Facility‑specific emissions intensity number

Historical production variables

(1) The facility‑specific emissions intensity number, of a historical production variable for a facility, is the number that is ascertained by dividing the total number of tonnes of carbon dioxide equivalence of covered emissions relevantly associated with the production variable in the relevant historical financial years for the production variable by the total quantity of the production variable in those financial years.

(2) The Regulator may round the facility‑specific emissions intensity number of a historical production variable for a facility to 4 or more significant figures if the Regulator considers it appropriate to do so.

(3) If the condition specified in column 1 of an item of the following table is satisfied in relation to a historical production variable specified in an application for an emissions intensity determination, each of the historical financial years specified in column 2 of that item is a relevant historical financial year for that production variable.

Relevant historical financial year
Item	Column 1 Condition	Column 2 Relevant historical financial year
1	The application includes the designated historical information about all 5 historical financial years for the historical production variable	Each of the 3 historical financial years that is not: (a) the historical financial year with the highest emissions intensity for the historical production variable; or (b) the historical financial year with the lowest emissions intensity for the historical production variable
2	The application includes the designated historical information about only 4 historical financial years for the historical production variable	Each of the 2 historical financial years that is not: (a) the historical financial year with the highest emissions intensity for the historical production variable; or (b) the historical financial year with the lowest emissions intensity for the historical production variable
3	The application includes the designated historical information about only 3 historical financial years for the historical production variable	Each of the 2 historical financial years that is not the historical financial year with the highest emissions intensity for the historical production variable
4	The application includes the designated historical information about only 2 historical financial years for the historical production variable	The historical financial year with the lowest emissions intensity for the historical production variable
5	The application includes the designated historical information about only 1 historical financial year for the historical production variable	That historical financial year

(4) For the purposes of items 1, 2, 3 and 4 of the table in subsection (3), the emissions intensity of a historical production variable for a historical financial year is ascertained by dividing the emissions relevantly associated with the production variable in the historical financial year by the quantity of the production variable in that financial year.

Related production variables

(5) The facility‑specific emissions intensity number, of a related production variable for a facility, is:

(a) if the related production variable is tonnes of reservoir carbon dioxide from new gas fields—zero; or

(b) otherwise—the same as the facility‑specific emissions intensity number of the comparative production variable for the related production variable.

Transitional production variables

(6) The facility‑specific emissions intensity number, of a transitional production variable for a facility, is the number that is equal to the default emissions intensity number of the production variable:

(a) if the production variable was applicable to the facility at any time during a historical financial year—for that financial year; or

(b) otherwise—for the financial year beginning on 1 July 2022.

Note: Subsections 91(2) and 92(2) modify the operation of this provision where the transitional production variable for the facility is run‑of‑mine coal, reservoir carbon dioxide from existing gas fields, natural gas throughput, or lithium hydroxide.

Subdivision D—Related production variables

21 Statement about related production variable when emissions intensity determination is made

(1) This section applies if:

(a) the Regulator decides to make an emissions intensity determination in relation to a facility; and

(b) the application for the determination includes a request for the determination to state that:

(i) a particular production variable for the facility is a related production variable for the facility; and

(ii) another specified production variable for the facility is the comparative production variable for that related production variable.

(2) The Regulator must decide to:

(a) include the statement in the determination; or

(b) refuse to include the statement in the determination.

(3) The Regulator must not include the statement in the determination unless satisfied that the particular production variable and the other production variable meet the requirements of section 23.

22 Statement about related production variable when emissions intensity determination is already in force

(1) If an emissions intensity determination is in force in relation to a facility, the responsible emitter for the facility may apply, in writing, to the Regulator to vary the determination to include a statement that:

(a) a particular production variable for the facility is a related production variable for the facility; and

(b) another specified production variable for the facility is the comparative production variable for that related production variable.

(2) The Regulator must decide to:

(a) make the variation; or

(b) refuse to make the variation.

(3) The Regulator must not make the variation unless satisfied that the particular production variable and the other production variable meet the requirements of section 23.

Notification of decision etc.

(4) If the Regulator makes the variation, the Regulator must notify the applicant of the variation and publish the emissions intensity determination, as varied, on the Regulator’s website.

(5) If the Regulator decides not to make the variation, the Regulator must give the applicant a written notice of the decision that includes the Regulator’s reasons for the decision.

When variation applies

(6) A variation under this section applies in relation to the financial year in which the application for the variation was made and each subsequent financial year.

23 Requirements for statement about related production variable

(1) A particular production variable for a facility and another production variable for the facility meet the requirements of this section if any of subsections (2), (3) or (4) apply.

(2) This subsection applies if:

(a) the particular production variable:

(i) is not a historical production variable for the facility; or

(ii) is a historical production variable for the facility but it was not reasonably practicable for the application for the determination to include the designated historical information about that production variable; and

(b) the particular production variable is substantially similar to the other production variable; and

(c) the particular production variable and the other production variable are measured using the same units or mutually convertible units; and

(d) the facility’s production of the particular production variable does not involve the installation of new equipment that is likely to increase the facility’s capacity to increase the total quantity of the particular production variable and the other production variable by more than 20% (relative to that quantity in the last financial year before the equipment is installed) in any of the years to which the determination is to apply.

(3) This subsection applies if:

(a) the particular production variable:

(i) is not a historical production variable for the facility; or

(b) the particular production variable is the hot‑rolled long products (cold ferrous feed) production variable and the other production variable is the hot‑rolled long products produced at primary steel manufacturing facilities production variable.

(4) This subsection applies if:

(a) the particular production variable:

(i) is not a historical production variable for the facility; or

(b) the particular production variable is the hot‑rolled flat products (cold ferrous feed) production variable and the other production variable is the hot‑rolled flat products produced at primary steel manufacturing facilities production variable.

(5) In this section:

hot‑rolled flat products (cold ferrous feed) production variable means the production variable in section 46 of Schedule 1.

hot‑rolled flat products produced at primary steel manufacturing facilities production variable means the production variable in section 43 of Schedule 1.

hot‑rolled long products (cold ferrous feed) production variable means the production variable in section 45 of Schedule 1.

hot‑rolled long products produced at primary steel manufacturing facilities production variable means the production variable in section 42 of Schedule 1.

Subdivision E—Successor determination

24 Successor determination for restructured facility

(1) This section applies if an activity, or a series of activities, that constitutes a facility (the original facility) in relation to which an emissions intensity determination is in force:

(a) ceases to constitute the original facility; and

(b) either:

(i) begins to constitute one or more other facilities; or

(ii) becomes included in the activity, or series of activities, that constitutes another facility.

Note: See the definition of facility in section 9 of the Act.

(2) The Regulator may make a determination in relation to a facility covered by paragraph (1)(b) (a successor facility) in accordance with the process set out in section 25.

(3) The determination must be in writing and must specify:

(a) the facility‑specific emissions intensity number of:

(i) any historical production variable for the successor facility that was also a historical production variable for the original facility; and

(ii) any related production variable for the successor facility that was also a related production variable for the original facility; and

(iii) any transitional production variable for the successor facility that was also a transitional production variable for the original facility; and

(b) the first financial year in relation to which the determination applies.

(4) In making the determination, the Regulator may have regard to any matter the Regulator considers relevant.

(5) The determination:

(a) comes into force on the first day of the financial year specified for the purposes of paragraph (3)(b); and

(b) applies in relation to the successor facility for that financial year and each subsequent financial year.

Note: See subsection 22XQ(2) of the Act (commencement of determination).

25 Process for making successor determination

(1) If the Regulator proposes to make a successor determination in relation to a facility, the Regulator must notify the responsible emitter for the facility in writing that the Regulator proposes to do so.

(2) The notice must:

(a) specify:

(i) the facility‑specific emissions intensity number of any production variable for the facility that would be specified in the determination; and

(ii) the first financial year in relation to which the determination would apply; and

(b) invite the responsible emitter to provide a written response to the proposed determination within the period specified in the notice.

(3) The notice may request that the responsible emitter provide the Regulator with specified information that the Regulator considers relevant to the proposed determination.

(4) Within 30 days after the end of the period specified in the notice, the Regulator must consider the responsible emitter’s response (if any) to the proposed determination and decide to:

(a) make the determination; or

(b) not make the determination.

(5) If the Regulator makes the determination, the Regulator must:

(a) notify the responsible emitter that the Regulator has made the determination; and

(b) publish the determination on the Regulator’s website.

Subdivision F—Variation by Regulator of emissions intensity determination

26 Variation by Regulator of emissions intensity determination

(1) Subject to subsection (4), if an emissions intensity determination is in force in relation to a facility, the Regulator may vary, in accordance with the process set out in section 28, a facility‑specific emissions intensity number specified in the determination if satisfied that:

(a) the amount of covered emissions of greenhouse gases from the operation of the facility during a historical financial year differs by at least 1% from the amount specified in the application for the determination; and

(b) the difference is due to:

(i) a relevant regulatory change that came into force after the determination was made; or

(ii) a different method being used, after the determination was made, to report the facility’s emissions in accordance with the Act; or

(iii) a change of activities at the facility after the determination was made.

(2) The variation:

(a) comes into force on the first day of the first financial year in which:

(i) the relevant regulatory change came into force; or

(ii) the different method was used; or

(iii) the change of activities occurred; and

(b) applies in relation to the facility for that financial year and each subsequent financial year.

Note: See subsection 22XQ(2) of the Act (commencement of determination).

(3) If, under this section, the Regulator varies an emissions intensity determination that is in force in relation to a facility, the Regulator must:

(a) notify the responsible emitter for the facility of the variation; and

(b) publish the determination, as varied, on the Regulator’s website.

(4) The Regulator must not vary the determination if the difference referred to in paragraph (1)(a) is due to an increase in the emissions intensity of a production variable for the facility resulting from a lower method being used instead of a higher method, after the determination was made, to report the facility’s emissions in accordance with the Act.

(5) This section does not limit subsection 33(3) of the Acts Interpretation Act 1901.

(6) In this section:

higher method has the same meaning as in the NGER (Measurement) Determination.

lower method has the same meaning as in the NGER (Measurement) Determination.

method has the same meaning as in the NGER (Measurement) Determination.

relevant regulatory change means:

(a) an amendment to the NGER Regulations, including a change to the Global Warming Potentials specified for a greenhouse gas in regulation 2.02 of the NGER Regulations; or

(b) an amendment to the NGER (Measurement) Determination; or

27 Request for information relevant to possible variation

If the Regulator is considering whether to vary a facility‑specific emissions intensity number specified in an emissions intensity determination that is in force in relation to a facility, the Regulator may, by written notice given to the responsible emitter for the facility, request that the responsible emitter provide the Regulator with specified information that the Regulator considers relevant to the variation.

28 Process for making variation

(1) If the Regulator proposes to vary a facility‑specific emissions intensity number specified in an emissions intensity determination that is in force in relation to a facility, the Regulator must notify the responsible emitter for the facility in writing that the Regulator proposes to do so.

(2) The notice must:

(a) specify the facility‑specific emissions intensity number of any production variable for the facility that would be specified in the determination as varied; and

(b) invite the responsible emitter to provide a written response to the proposed variation within the period specified in the notice.

(3) The notice may request that the responsible emitter provide the Regulator with specified information that the Regulator considers relevant to the proposed variation.

(4) Within 30 days after the end of the period specified in the notice, the Regulator must consider the responsible emitter’s response (if any) to the proposed variation, and any information obtained under section 27 that the Regulator considers relevant to the proposed variation, and decide to:

(a) make the variation; or

(b) not make the variation.

(5) The variation must be made before the end of the first 31 January after the first financial year in relation to which the variation is to apply.

(6) If the Regulator makes the variation, the Regulator must:

(a) notify the responsible emitter that the Regulator has made the variation; and

(b) publish the determination, as varied, on the Regulator’s website.

Division 3—New facilities

29 Baseline emissions number for new facility

(1) The baseline emissions number for a new facility (other than a landfill facility) for a financial year is the number worked out using the following formula:

where:

ERC is the emissions reduction contribution for the facility for the financial year.

p is a production variable for the facility for the financial year.

EIB, in relation to a production variable for the facility for the financial year, is:

(a) if there is a best practice emissions intensity number for the production variable for the financial year—that number; or

(b) otherwise—the default emissions intensity number for the production variable for the financial year.

Q, in relation to a production variable for the facility for the financial year, is the quantity of the production variable for the facility for the financial year.

BA is the borrowing adjustment for the facility for the financial year.

Note: The baseline emissions number for a new facility for a financial year would be the same if it were worked out using the formula in section 11.

(2) A facility is a new facility if there are no historical production variables or transitional production variables for the facility.

(3) The number worked out using the formula in subsection (1) is to be rounded to the nearest whole number (rounding up if the first decimal place is 5 or more).

Division 4—Landfill facilities

30 Baseline emissions number for landfill facility

(1) The baseline emissions number for a landfill facility for a financial year is the number worked out using the following formula:

where:

ERC is the emissions reduction contribution for the facility for the financial year.

NLCH4 is the number of tonnes of carbon dioxide equivalence of covered emissions of greenhouse gases that would be emitted by the facility if emissions were not captured, and oxidation did not occur, at the facility during the financial year.

CER (known as the capture efficiency rate) is 0.372.

OF is the oxidation factor specified in section 5.4 of the NGER (Measurement) Determination (as in force at the start of the financial year) for near surface methane in landfill.

BA is the borrowing adjustment for the facility for the financial year.

(2) The number worked out using the formula in subsection (1) is to be rounded to the nearest whole number (rounding up if the first decimal place is 5 or more).

Division 5—Emissions reduction contribution

Subdivision A—Default values

31 Default emissions reduction contribution

The default emissions reduction contribution for a financial year beginning on a day specified in column 1 of an item of the following table is the number specified in column 2 of that item.

Default emissions reduction contribution
Item	Column 1 Financial year	Column 2 Default emissions reduction contribution
1	1 July 2023	0.951
2	1 July 2024	0.902
3	1 July 2025	0.853
4	1 July 2026	0.804
5	1 July 2027	0.755
6	1 July 2028	0.706
7	1 July 2029	0.657
8	1 July 2030 or a later 1 July	The greater of: (a) the default emissions reduction contribution for the previous financial year minus 0.03285; and (b) 0

Note: Until the financial year beginning on 1 July 2030, the default emissions reduction contribution in column 2 declines by 0.049 (the default decline rate).

32 Default decline rate

The default decline rate for a financial year beginning on a day specified in column 1 of an item of the following table is the number specified in column 2 of that item.

Default decline rate
Item	Column 1 Financial year	Column 2 Default decline rate
1	1 July 2023	0.049
2	1 July 2024	0.049
3	1 July 2025	0.049
4	1 July 2026	0.049
5	1 July 2027	0.049
6	1 July 2028	0.049
7	1 July 2029	0.049
8	1 July 2030 or a later 1 July	0.03285

Subdivision B—Regular facilities

33 Emissions reduction contribution for regular facility

(1) If:

(a) a facility is a regular facility in a financial year; and

(b) the facility was not a trade‑exposed baseline‑adjusted facility in any previous financial year;

the emissions reduction contribution for the facility for the financial year is the default emissions reduction contribution for that financial year.

(2) If:

(a) a facility is a regular facility in a financial year (the relevant financial year); and

(b) the facility was a trade‑exposed baseline‑adjusted facility in a previous financial year;

the emissions reduction contribution for the facility for the relevant financial year is the number worked out using the following formula:

where:

ERCy is the emissions reduction contribution for the facility for the financial year ending immediately before the relevant financial year.

DR is the default decline rate for the relevant financial year.

(3) The number worked out using the formula in subsection (2) is to be rounded to 5 decimal places (rounding up if the sixth decimal place is 5 or more).

Subdivision C—Trade‑exposed baseline‑adjusted facilities

34 Emissions reduction contribution for trade‑exposed baseline‑adjusted facility

(1) If a facility is a trade‑exposed baseline‑adjusted facility in a financial year, the emissions reduction contribution for the facility for the financial year is the number worked out using the following formula:

where:

ERCy is:

(a) if the table in section 31 does not specify a default emissions reduction contribution for the previous financial year—1;

(b) otherwise—the emissions reduction contribution for the facility for the previous financial year.

DR is the default decline rate for the financial year.

RCI is the ratio of cost impacts for the facility for the financial year.

DRm (known as the minimum decline rate) is:

(a) if the facility is a manufacturing facility—0.01; or

(b) otherwise—0.02.

(2) The number worked out using the formula in subsection (1) is to be rounded to 5 decimal places (rounding up if the sixth decimal place is 5 or more).

35 Ratio of cost impacts

(1) If a facility is a trade‑exposed baseline‑adjusted facility in a financial year, the ratio of cost impacts for the facility for the financial year is worked out in accordance with this section.

(2) If the assessed cost impact for the facility for the financial year is equal to or greater than the significant cost impact threshold for the facility, the ratio of cost impacts for the facility for the financial year is 1.

(3) If the assessed cost impact for the facility for the financial year is less than the significant cost impact threshold for the facility, the ratio of cost impacts for the facility for the financial year is the number worked out using the following formula:

$Start formula start fraction CI subscript A minus CI subscript M over CI subscript S minus CI subscript M end fraction end formula$

where:

CIA is the assessed cost impact for the facility for the financial year.

CIM (known as the material cost impact threshold) is 0.03.

CIS is the significant cost impact threshold for the facility.

(4) The significant cost impact threshold for a facility is:

(a) if the facility is a manufacturing facility—0.10; or

(b) otherwise—0.08.

36 Assessed cost impact

Facilities that are not manufacturing facilities

(1) If a facility is not a manufacturing facility in a financial year, the assessed cost impact for the facility for the financial year is the number worked out using the following formula:

$Start formula start fraction P subscript SM times PE over RF end fraction end formula$

where:

PSM is the number of dollars in the Safeguard Mechanism default prescribed unit price for the first adjusted financial year for the facility.

PE is the number equal to the difference between:

(a) the amount of covered emissions of greenhouse gases (in t CO2‑e) from the operation of the facility during the first adjusted financial year for the facility; and

(b) the hypothetical baseline of the facility for the first adjusted financial year for the facility.

RF is the number of dollars in the revenue of the facility in the first adjusted financial year for the facility.

(2) For the purposes of calculating the revenue of the facility in the first adjusted financial year for the facility, any funding provided to the facility for that financial year under the Powering the Regions Fund must be excluded from that revenue.

(3) However, if the number of dollars in the revenue of the facility in the first adjusted financial year for the facility is less than or equal to zero, the assessed cost impact for the facility for the financial year is the significant cost impact threshold for the facility.

Manufacturing facilities

(4) If a facility is a manufacturing facility in a financial year, the assessed cost impact for the facility for the financial year is the number worked out using the following formula:

$Start formula start fraction P subscript SM times PE over EBIT end fraction end formula$

where:

PSM is the number of dollars in the Safeguard Mechanism default prescribed unit price for the first adjusted financial year for the facility.

PE is the number equal to the difference between:

(a) the amount of covered emissions of greenhouse gases (in t CO2‑e) from the operation of the facility during the first adjusted financial year for the facility; and

(b) the hypothetical baseline of the facility for the first adjusted financial year for the facility.

EBIT is the number of dollars that is equal to the earnings before interest and tax of the facility in the first adjusted financial year for the facility.

Note: See section 37 (earnings before interest and tax).

(5) However, if the number of dollars that is equal to the earnings before interest and tax of the facility in the first adjusted financial year for the facility is less than or equal to zero, the assessed cost impact for the facility for the financial year is the significant cost impact threshold for the facility.

First adjusted financial year

(6) The first adjusted financial year, for a facility, is:

(a) if the assessed cost impact for the facility is being worked out for the purposes of making or considering an application under section 39 for a determination that the facility is a trade‑exposed baseline‑adjusted facility in a particular financial year and the next 2 financial years—that particular financial year; or

(b) if:

(i) the facility is a trade‑exposed baseline‑adjusted facility in a financial year because of a determination in force under section 42; and

(ii) the assessed cost impact for the facility is being worked out for the purposes of working out the emissions reduction contribution for the facility for the financial year;

the first financial year in which the facility is a trade‑exposed baseline‑adjusted facility because of that determination.

Hypothetical baseline

(7) The hypothetical baseline of a facility for a financial year is:

(a) in the case where an application under section 39 for a determination that the facility is a trade‑exposed baseline‑adjusted facility in that financial year and the next 2 financial years is being made or considered—the number that is equal to what the baseline emissions number for the facility for that financial year would be if that determination were not to be made; or

(b) in the case where:

(i) the facility is a trade‑exposed baseline‑adjusted facility in a financial year because of a determination in force under section 42; and

(ii) the assessed cost impact for the facility is being worked out for the purposes of working out the emissions reduction contribution for the facility for the financial year;

the number that is equal to what the baseline emissions number for the facility for that financial year would be if that determination had not been made.

37 Earnings before interest and tax

(1) The earnings before interest and tax (the EBIT) of a facility for a financial year are to be worked out in accordance with this section.

(2) Subject to subsections (4) and (5), the EBIT of the facility for the financial year is to be calculated in accordance with:

(a) the Australian accounting standards as in force at the end of the financial year; and

(b) any EBIT Guidelines that are in force at that time.

(3) For the purposes of subsection (2), EBIT Guidelines prevail over the Australian accounting standards to the extent of any inconsistency.

Revenue to exclude PRF funding

(4) For the purposes of calculating the EBIT of the facility for the financial year, any funding provided to the facility for the financial year under the Powering the Regions Fund must be excluded from the facility’s revenue for the financial year.

Accelerated depreciation

(5) The EBIT of the facility for the financial year must be calculated using a depreciation schedule that specifies one of the following depreciation factors for each capital expense of the facility:

(a) 1.0;

(b) 1.1;

(6) The factors in paragraphs (5)(b) and (c) are accelerated depreciation factors.

EBIT Guidelines

(7) The Secretary may make written guidelines that relate to working out the earnings before interest and tax of a facility for a financial year. Guidelines made under this subsection are to be known as EBIT Guidelines.

(8) The EBIT Guidelines are to be published on the Department’s website.

38 Safeguard Mechanism default prescribed unit price

Before the end of each financial year beginning after 30 June 2023, the Secretary must publish on the Department’s website an estimate of the average price of a prescribed carbon unit during that financial year. The estimate is to be known as the Safeguard Mechanism default prescribed unit price for the financial year.

Subdivision D—Determination that a facility is a trade‑exposed baseline‑adjusted facility

39 Application for determination that a facility is a trade‑exposed baseline‑adjusted facility

(1) The responsible emitter for a facility may apply to the Regulator for a determination that the facility is a trade‑exposed baseline‑adjusted facility in a particular financial year (the first financial year) and the next 2 financial years.

(2) The application must be made:

(a) in a manner and form approved, in writing, by the Regulator; and

(b) before the end of the due date for the application, unless the Regulator agrees to accept the application after that date.

Note 1: For the due date for the application, see section 52.

Note 2: For withdrawal of the application, see section 53.

(3) The application must include the following information:

(a) if the facility was not a manufacturing facility in the first financial year—all of the following:

(i) subject to subsection 36(2), the revenue of the facility in the first financial year, calculated in accordance with:

(A) the Australian accounting standards as in force at the end of the first financial year; and

(B) any EBIT Guidelines that are in force at that time;

(ii) information about the assumptions made when working out that revenue;

(b) if the facility was a manufacturing facility in the first financial year—all of the following:

(i) the earnings before interest and tax (the EBIT) of the facility in the first financial year, calculated in accordance with section 37;

(ii) information about the assumptions made when working out the EBIT under that section;

(iii) each depreciation factor used in the depreciation schedule used for calculating the EBIT;

(iv) if the depreciation schedule used for calculating the EBIT uses an accelerated depreciation factor—an explanation for why the accelerated depreciation factor is used;

(i) the assessed cost impact for the facility for the first financial year;

(ii) information about the assumptions made when working out that assessed cost impact;

(d) the amount of covered emissions of greenhouse gases from the operation of the facility in the first financial year;

(e) the hypothetical baseline for the facility for the first financial year;

(f) the emissions reduction contribution, and the baseline emissions number, for the facility for the first financial year if:

(i) the determination were made; and

(ii) those numbers were worked out using the assessed cost impact for the facility for the first financial year;

(g) an estimate of the emissions reduction contribution for the facility for each of the next 2 financial years after the first financial year if the determination were made.

(3A) For the purposes of subsection (3)(a)(i), EBIT Guidelines prevail over the Australian accounting standards to the extent of any inconsistency.

(4) The application must include a declaration that the amount of covered emissions of greenhouse gases from the operation of the facility in the first financial year was not increased for the sole or substantial purpose of:

(a) achieving the result that the Regulator makes the determination; or

(b) achieving the result that the emissions reduction contribution for the facility for the first financial year and the next 2 financial years is higher than it would have been but for that increase.

(5) The application, and the declaration under subsection (4), must be signed by:

(a) if the responsible emitter is a body corporate—the chief financial officer (however described) of the responsible emitter; or

(b) otherwise—a person whose duties in relation to the responsible emitter are equivalent to those of the chief financial officer of a body corporate.

(6) The responsible emitter for a facility may make an application under this section even if the facility is already a trade‑exposed baseline‑adjusted facility in the first financial year.

40 Application must be accompanied by safeguard audit report

(1) This section is made for the purposes of subsection 22XQ(3) of the Act.

(2) An application for a determination that a facility is a trade‑exposed baseline‑adjusted facility must be accompanied by an audit report that meets the requirements of this section.

Note: Under subsection 75(1) of the Act, the Minister may determine requirements to be met by registered greenhouse and energy auditors in preparing for and carrying out safeguard audits.

Reasonable assurance matters

(3) The audit report must include a conclusion in relation to each of the following matters:

(a) whether, in all material respects, the information included in the application is correct;

(b) whether, in all material respects, the facility satisfies the criteria specified in subparagraphs 42(2)(a)(vi) and (vii).

(4) An audit report under this section must be the result of an audit which:

(a) was conducted in accordance with the relevant requirements for reasonable assurance engagements under the National Greenhouse and Energy Reporting (Audit) Determination 2009; and

(b) had an audit team leader who is registered as a Category 2 auditor under subregulation 6.25(3) of the NGER Regulations.

41 Consideration of application

(1) This section applies if the responsible emitter for a facility applies for a determination, in accordance with this Subdivision, that the facility is a trade‑exposed baseline‑adjusted facility.

(2) Subject to subsection (4), the Regulator must take all reasonable steps to decide the application before the end of the decision date for the application.

Note: For the decision date for the application, see section 52.

42 Determination that a facility is a trade‑exposed baseline‑adjusted facility

(1) If the responsible emitter for a facility applies for a determination, in accordance with this Subdivision, that the facility is a trade‑exposed baseline‑adjusted facility in a particular financial year (the first financial year) and the next 2 financial years, the Regulator must:

(a) make the determination; or

(b) refuse to make the determination.

(2) The Regulator must not make the determination unless:

(a) the Regulator is reasonably satisfied, having regard to any EBIT Guidelines in force at the end of the first financial year and any other matter the Regulator considers relevant, that:

(i) the information included in the application is correct; and

(ii) the borrowing adjustment for the facility for the first financial year is zero; and

(iii) the first financial year is not included in a multi‑year period declaration that is in force in relation to the facility; and

(iv) the number that is equal to the total number of tonnes of carbon dioxide equivalence of covered emissions of greenhouse gases from the operation of the facility during the first financial year is greater than the hypothetical baseline of the facility for that year; and

(v) the amount of covered emissions of greenhouse gases from the operation of the facility in the first financial year was not increased for the sole or substantial purpose of achieving a result mentioned in subsection 39(4); and

(vi) the primary production variable for the facility in the first financial year is a trade‑exposed production variable; and

(vii) the assessed cost impact for the facility for the first financial year is greater than 0.03 (known as the material cost impact threshold); and

(b) the audit report accompanying the application includes a reasonable assurance conclusion, or a qualified reasonable assurance conclusion, in relation to each of the matters specified in subsection 40(3).

(3) The determination must be in writing and comes into force on the first day of the first financial year.

Note: See subsection 22XQ(2) of the Act (commencement of determination).

(4) The determination must specify the emissions reduction contribution for the facility for the first financial year and the next 2 financial years.

Notification of decision etc.

(5) If the Regulator makes a determination under this section, the Regulator must:

(a) notify the applicant for the determination that the Regulator has made the determination; and

(b) publish the determination on the Regulator’s website.

(6) If the Regulator decides to refuse to make a determination under this section, the Regulator must give the applicant for the determination a written notice of the decision that includes the Regulator’s reasons for the decision.

Where previous determination has been revoked at request of responsible emitter

(7) This section has effect subject to section 46 (consequence of revocation at request of responsible emitter).

43 Determination where another determination is already in force

(1) The Regulator may make a determination under section 42 (the new determination) that a facility is a trade‑exposed baseline‑adjusted facility in a particular financial year and the next 2 financial years even if the facility is already a trade‑exposed baseline‑adjusted facility in that particular financial year because of another determination in force under that section.

(2) If the Regulator makes the new determination, the Regulator must revoke the other determination.

(3) This section does not limit subsection 33(3) of the Acts Interpretation Act 1901.

Subdivision E—Variation and revocation of determination that a facility is a trade‑exposed baseline‑adjusted facility

44 Variation on Regulator’s initiative

(1) This section applies if a facility is a trade‑exposed baseline‑adjusted facility in a particular financial year (the first financial year) and the next 2 financial years because of a determination in force under section 42.

(2) The Regulator may vary the determination in accordance with this section if the Regulator is satisfied that:

(a) the assessed cost impact for the facility for the first financial year was incorrectly calculated; or

(b) information provided to the Regulator in connection with the application for the determination was false or misleading in a material particular.

(3) If the Regulator proposes to vary the determination, the Regulator must notify the responsible emitter for the facility in writing that the Regulator proposes to do so.

(4) The notice must:

(a) specify what the emissions reduction contribution for the facility would be in the first financial year and the next 2 financial years if the variation were made; and

(b) invite the responsible emitter to provide a written response to the proposed variation within the period specified in the notice.

(5) Within 30 days after the end of the period specified in the notice, the Regulator must consider the responsible emitter’s response (if any) to the proposed variation and decide to:

(a) vary the determination; or

(b) not vary the determination.

(6) This section does not limit subsection 33(3) of the Acts Interpretation Act 1901.

Notification of decision etc.

(7) If the Regulator decides to vary the determination, the Regulator must:

(a) give the responsible emitter a written notice of the decision that includes the Regulator’s reasons for the decision; and

(b) publish the determination, as varied, on the Regulator’s website.

(8) If the Regulator decides not to vary the determination, the Regulator must notify the responsible emitter of that decision in writing.

45 Revocation at request of responsible emitter

(1) This section applies if a facility is a trade‑exposed baseline‑adjusted facility in a particular financial year and the next 2 financial years because of a determination in force under section 42.

(2) The responsible emitter for the facility may request that the Regulator revoke the determination.

(3) The request must be made, in writing, before the end of the first 31 October after one of the financial years mentioned in subsection (1).

(4) If the responsible emitter makes the request in accordance with subsection (3), the Regulator must:

(a) revoke the determination; and

(b) notify the responsible emitter, in writing, that the Regulator has done so.

(5) The revocation takes effect at the start of the financial year in which the request was made.

(6) This section does not limit subsection 33(3) of the Acts Interpretation Act 1901.

46 Consequence of revocation at request of responsible emitter

If:

(a) a facility is a trade‑exposed baseline‑adjusted facility in 3 financial years (the TEBA years) because of a determination in force under section 42; and

(b) the Regulator revokes that determination under section 45; and

(c) the responsible emitter for the facility applies under section 39 for another determination that the facility is a trade‑exposed baseline‑adjusted facility in a particular financial year (the first financial year) and the next 2 financial years;

the Regulator must not make the other determination unless the facility has been a regular facility for at least one financial year during the period:

(d) beginning at the start of the first of the TEBA years; and

(e) ending immediately before the start of the first financial year.

Division 6—Borrowing adjustment

47 Borrowing adjustment

Financial years ending before 1 July 2026

(1) The borrowing adjustment, for a facility for a financial year that ends before 1 July 2026, is the number worked out using the following formula:

where:

BD is:

(a) if a borrowing adjustment determination specifies a borrowing adjustment number for the facility for the financial year—that number; or

(b) otherwise—0.

BDP is:

(a) if a borrowing adjustment determination specified a borrowing adjustment number for the facility for the previous financial year—that number; or

(b) otherwise—0.

Financial years beginning on or after 1 July 2026

(2) The borrowing adjustment, for a facility for a financial year that begins on or after 1 July 2026, is the number worked out using the following formula:

where:

BD is:

(a) if a borrowing adjustment determination specifies a borrowing adjustment number for the facility for the financial year—that number; or

(b) otherwise—0.

BDP is:

(a) if a borrowing adjustment determination specified a borrowing adjustment number for the facility for the previous financial year—that number; or

(b) otherwise—0.

48 Application for borrowing adjustment determination

(1) The responsible emitter for a facility may apply to the Regulator for a borrowing adjustment determination for the facility for a financial year.

(2) The application must be made:

(a) in a manner and form approved, in writing, by the Regulator; and

(b) before the end of the due date for the application, unless the Regulator agrees to accept the application after that date.

Note 1: For the due date for the application, see section 52.

Note 2: For withdrawal of the application, see section 53.

(3) The application must specify a number as the proposed borrowing adjustment number for the facility for the financial year.

49 Consideration of application

(1) This section applies if the responsible emitter for an existing facility applies for a borrowing adjustment determination in accordance with section 48.

(2) Subject to subsection (4), the Regulator must take all reasonable steps to decide the application before the end of the decision date for the application.

Note: For the decision date for the application, see section 52.

50 Borrowing adjustment determination

(1) If the responsible emitter for a facility applies in accordance with section 48 for a borrowing adjustment determination for the facility for a financial year, the Regulator must decide to:

(a) make the determination; or

(b) refuse to make the determination.

(2) The Regulator must not make the determination unless the Regulator is satisfied that:

(a) the number proposed as the borrowing adjustment number in the application is not greater than 10% of the unadjusted baseline for the facility for the financial year; and

(b) no safeguard mechanism credit units have been issued in relation to the facility for the financial year; and

(d) the facility is likely to be a designated large facility in the financial year immediately following the financial year mentioned in subsection (1).

(3) A borrowing adjustment determination for a facility for a financial year must be in writing and must specify the borrowing adjustment number for the facility for the financial year.

(4) In this section, the unadjusted baseline for a facility for a financial year (the relevant financial year) is:

(a) if a borrowing adjustment determination specified a borrowing adjustment number for the facility for the previous financial year—the baseline emissions number for the facility for the relevant financial year worked out using that borrowing adjustment number; or

(b) otherwise—the baseline emissions number for the facility for the relevant financial year if the borrowing adjustment number for the facility for the relevant financial year were 0.

Notification of decision etc.

(5) If the Regulator makes a determination under this section, the Regulator must:

(a) notify the applicant for the determination that the Regulator has made the determination; and

(b) publish the determination on the Regulator’s website.

51 No borrowing adjustment for year included in multi‑year period declaration

(1) The Regulator must revoke a borrowing adjustment determination if:

(a) the determination specifies a borrowing adjustment number for a facility for a financial year; and

(b) the Regulator declares that, for the purposes of section 22XG of the Act, a specified period is a declared multi‑year period for the facility; and

(2) This section does not limit subsection 33(3) of the Acts Interpretation Act 1901.

Division 7—Miscellaneous

Subdivision A—Applications under this Part

52 Due date and decision date for applications

(1) The due date for an application under this Part that is specified in column 1 of an item of the following table is the day specified in column 2 of that item.

(2) The decision date for an application under this Part that is specified in column 1 of an item of the following table is the day specified in column 3 of that item.

Due date and decision date for applications
Item	Column 1 Application	Column 2 Due date	Column 3 Decision date
1	Application under section 14 for an emissions intensity determination that specifies the financial year beginning on 1 July 2023 as the first financial year to which the determination would apply	30 April 2024	The later of: (a) 31 January 2025; and (b) the day that is 60 days after the end of a period specified in any notice under subsection 18(3) in relation to the application
2	Application under section 14 for an emissions intensity determination that specifies a financial year beginning on 1 July 2024 or a later 1 July as the first financial year to which the determination would apply	The first 31 October after the end of the financial year	The day that is: (a) 60 days after the application is made; or (b) if a notice is given under subsection 18(3) in relation to the application—60 days after the end of the period specified in the notice
3	Application under section 39 for a determination that a facility is a trade‑exposed baseline‑adjusted facility in a particular financial year (the first financial year) and the next 2 financial years	The first 31 October after the end of the first financial year	The day that is: (a) 60 days after the application is made; or (b) if a notice is given under subsection 41(3) in relation to the application—60 days after the end of the period specified in the notice
4	Application under section 48 for a borrowing adjustment determination for a facility for a financial year	The first 28 February after the end of the financial year	The day that is: (a) 30 days after the application is made; or (b) if a notice is given under subsection 49(3) in relation to the application—30 days after the end of the period specified in the notice

53 Withdrawal of applications

At any time before the Regulator decides an application mentioned in column 1 of the table in section 52, the applicant may withdraw, in writing, the application.

Subdivision B—Shale gas extraction facilities

54 Meaning of shale gas extraction facility

(1) A facility is a shale gas extraction facility if:

(a) the activity, or the series of activities, that constitutes the facility is or includes the extraction of gas from a geological formation by means of processes that include hydraulic fracturing; and

(b) more than 90% of the gas extracted from the geological formation is shale gas; and

(c) emissions from the extraction and use of gas from the geological formation would likely exceed 100 million tonnes of carbon dioxide equivalence in total if the formation were fully exploited.

(2) A facility is also a shale gas extraction facility if:

(a) the activity, or the series of activities, that constitutes the facility is the exploration of a geological formation that contains shale gas; and

(b) processes that include hydraulic fracturing would be needed to extract gas from the formation; and

(c) emissions from the extraction and use of gas from the geological formation would likely exceed 100 million tonnes of carbon dioxide equivalence in total if the formation were fully exploited.

Part 3A—Safeguard mechanism credit units

Division 1—General

55 Purpose and application of Part

(1) Unless otherwise provided, the provisions of this Part are made for the purposes of subsection 22XNA(2) of the Act.

(2) This Part applies in relation to financial years, and declared multi‑year periods, that begin after 30 June 2023.

Division 2—Issuing safeguard mechanism credit units

56 Issuing safeguard mechanism credit units for a financial year

Application for safeguard mechanism credit units

(1) The responsible emitter for a facility may apply to the Regulator to issue safeguard mechanism credit units to the responsible emitter in relation to the facility for a particular financial year.

Issue of safeguard mechanism credit units

(2) The Regulator must consider the application as soon as reasonably practicable after receiving it, and if the Regulator:

(a) is satisfied of the matters specified in subsection (3); and

(b) has no evidence to suggest that the quantity of a production variable for the facility for the financial year, or the covered emissions of greenhouse gases from the operation of the facility in the financial year, have been inaccurately reported to the Regulator;

the Regulator must:

(i) subsection (4); or

(ii) if the responsible emitter was the responsible emitter for the facility on a number of days in the financial year that is less than 365—subsections (4) and (5);

the number of units to be issued; and

(d) decide to issue that number of units to the responsible emitter.

Note: See also section 58A (identifying safeguard mechanism credit units with a financial year etc.).

Matters of which the Regulator must be satisfied

(3) The following matters are specified:

(a) the baseline emissions number for the facility for the financial year is greater than the sum of:

(i) the number of tonnes of carbon dioxide equivalence of covered emissions of greenhouse gases from the operation of the facility during the financial year; and

(ii) the number of Australian carbon credit units (if any) by which the net emissions number for the facility for the financial year is increased under subsection 22XK(4) of the Act;

(b) the facility is not a landfill facility;

(d) no borrowing adjustment determination specifies a borrowing adjustment number for the facility for the financial year;

(e) the financial year is not included in a declared multi‑year period for the facility.

Number of safeguard mechanism credit units to be issued

(4) The number of units to be issued is worked out using the following formula:

where:

BEN is the baseline emissions number for the facility for the financial year that would be ascertained in accordance with Part 3 if subsection 10(1) had not been enacted.

Note: Subsection 10(1) provides for a minimum baseline emissions number of 100,000.

E is the number of tonnes of carbon dioxide equivalence of covered emissions of greenhouse gases from the operation of the facility during the financial year.

Increase is the number of Australian carbon credit units (if any) by which the net emissions number for the facility for the financial year is increased under subsection 22XK(4) of the Act.

(5) If the responsible emitter was the responsible emitter for the facility on a number of days (the relevant number) in the financial year that is less than 365, the number of units to be issued is worked out using the following formula:

$Start formula SMC times start fraction RN over 365 end fraction end formula$

where:

SMC means the number worked out using the formula in subsection (4).

RN means the relevant number.

57 Issuing safeguard mechanism credit units for a declared multi‑year period

Application for safeguard mechanism credit units

(1) The responsible emitter for a facility may apply to the Regulator to issue safeguard mechanism credit units to the responsible emitter in relation to the facility for a particular declared multi‑year period for the facility.

Issue of safeguard mechanism credit units

(2) The Regulator must consider the application as soon as reasonably practicable after receiving it, and if the Regulator:

(a) is satisfied of the matters specified in subsection (3); and

(b) has no evidence to suggest that the quantity of a production variable for the facility for a financial year included in the declared multi‑year period, or the covered emissions of greenhouse gases from the operation of the facility in the declared multi‑year period, have been inaccurately reported to the Regulator;

the Regulator must:

(d) decide to issue that number of units to the responsible emitter.

Note: See also section 58A (identifying safeguard mechanism credit units with a financial year etc.).

Matters of which the Regulator must be satisfied

(3) The following matters are specified:

(a) the baseline emissions number for the facility for the declared multi‑year period is greater than the sum of:

(i) the number of tonnes of carbon dioxide equivalence of covered emissions of greenhouse gases from the operation of the facility during each financial year included in the declared multi‑year period; and

(ii) the number of Australian carbon credit units (if any) by which the net emissions number for the facility for the declared multi‑year period is increased under subsection 22XK(4) of the Act;

(b) the facility is not a landfill facility;

(c) the facility is a designated large facility, or an eligible facility, for each of the financial years included in the declared multi‑year period;

(d) no borrowing adjustment determination specifies a borrowing adjustment number for the facility for a financial year included in the declared multi‑year period.

Number of safeguard mechanism credit units to be issued

(4) The number of units to be issued is worked out using the following formula:

where:

t is a financial year included in the declared multi‑year period.

BEN, in relation to a financial year included in the declared multi‑year period, is the baseline emissions number for the facility for the financial year that would be ascertained in accordance with Part 3 if subsection 10(1) had not been enacted.

Note: Subsection 10(1) provides for a minimum baseline emissions number of 100,000.

E, in relation to a financial year included in the declared multi‑year period, is the number of tonnes of carbon dioxide equivalence of covered emissions of greenhouse gases from the operation of the facility during the financial year.

Increase, in relation to a financial year included in the declared multi‑year period, is the number of Australian carbon credit units (if any) by which the net emissions number for the facility for the financial year is increased under subsection 22XK(4) of the Act.

58 Application requirements

(1) An application for safeguard mechanism credit units by a responsible emitter under subsection 56(1) or 57(1) must be in writing and must:

(a) specify the Registry account kept by the responsible emitter in which, if the Regulator decides to issue the units, the Regulator must make an entry for the units; and

(b) include an acknowledgement that the Regulator may require the relinquishment of safeguard mechanism credit units issued on false or misleading information or as a result of fraudulent conduct.

Note: For the requirement to relinquish safeguard mechanism credit units in certain circumstances, see sections 22XNE and 22XNF of the Act.

(2) At any time before the Regulator decides the application, the responsible emitter may, in writing, withdraw the application.

Division 3—Timing etc. of issue of safeguard mechanism credit units

58A Identifying safeguard mechanism credit units with a financial year etc.

Identifying safeguard mechanism credit units with a financial year

(1) For the purposes of subsection 22XNC(2) of the Act:

(a) if the Regulator decides to issue a safeguard mechanism credit unit to a person in relation to a facility for a financial year—the Regulator must identify the unit with that financial year; or

(b) if the Regulator decides to issue a safeguard mechanism credit unit to a person in relation to a facility for a declared multi‑year period for the facility—the Regulator must identify the unit with the most recent financial year included in that declared multi‑year period.

When safeguard mechanism credit units are to be issued for financial years

(2) If:

(a) the responsible emitter for a facility applies under subsection 56(1) to the Regulator to issue safeguard mechanism credit units to the responsible emitter in relation to the facility for a particular financial year; and

(b) the application is made before the first 31 January after the end of the financial year; and

(c) the Regulator decides to issue safeguard mechanism credit units to the responsible emitter in relation to the facility for the financial year;

the Regulator must issue those units on a day that is as close to that 31 January as is reasonably practicable.

When safeguard mechanism credit units are to be issued for declared multi‑year periods

(3) If:

(a) the responsible emitter for a facility applies under subsection 57(1) to the Regulator to issue safeguard mechanism credit units to the responsible emitter in relation to the facility for a particular declared multi‑year period for the facility; and

(b) the application is made before the first 31 January after the end of the declared multi‑year period; and

(c) the Regulator decides to issue safeguard mechanism credit units to the responsible emitter in relation to the facility for the declared multi‑year period;

the Regulator must issue those units on a day that is as close to that 31 January as is reasonably practicable.

Division 4—Eligible facilities

58B Meaning of eligible facility

(1) A facility is an eligible facility, for a financial year (the current financial year), if:

(a) the facility was a designated large facility for another financial year (the last covered financial year); and

(b) the facility has not been a designated large facility for any of the financial years beginning after the last covered financial year; and

(d) the facility was a designated large facility in at least:

(i) 3 historical financial years; or

(ii) 2 of the financial years in the period of 4 financial years immediately preceding the last covered financial year; and

(e) subsection (3) applies to the facility for the current financial year.

(2) A facility is also an eligible facility, for the current financial year, if:

(a) the current financial year begins after 30 June 2028; and

(b) the facility was a designated large facility for at least 3 of the financial years in the period of 5 financial years immediately preceding the current financial year; and

(3) This subsection applies to a facility for the current financial year if:

(a) either:

(i) an emissions intensity determination applies in relation to the facility for the current financial year; or

(ii) the facility is a new facility; and

(b) no Australian carbon credit units attributable to the avoidance of covered emissions of greenhouse gases from the operation of the facility were issued under the Carbon Credits (Carbon Farming Initiative) Act 2011 in the current financial year or the previous financial year, in respect of an eligible offsets project that reduced covered emissions of greenhouse gases from the operation of the facility.

(4) A facility is also an eligible facility, for the current financial year, if:

(a) the facility was a designated large facility for another financial year (the last covered financial year); and

(b) the facility has not been a designated large facility for any of the financial years beginning after the last covered financial year; and

(i) the last year for which safeguard mechanism credits were not issued to a person in relation to the facility; and

(ii) the financial year 3 years after the last covered financial year; and

(d) the facility was a designated large facility in at least:

(i) 3 historical financial years; or

(ii) 2 of the financial years in the period of 4 financial years immediately preceding the last covered financial year; and

(e) subsection (3) applies to the facility for the current financial year; and

(f) no safeguard mechanism credits have been issued to a person in relation to the facility for the financial year after the last covered financial year.

Part 4—Compliance

Division 1—Exemption declarations

59 Operation of this Division

For subsections 22XE(2), (3) and (4) of the Act, this Division provides for an exemption declaration to be issued in relation to a facility for a monitoring period.

60 Application

(1) The responsible emitter for a facility may apply to the Regulator for an exemption declaration for the facility for a monitoring period.

(2) The application must:

(a) be given in a manner and form approved, in writing, by the Regulator; and

(b) specify the facility and monitoring period for which an exemption declaration is sought; and

(i) why an exemption declaration should be made; and

(ii) if the application relates to criminal activity—the reasonableness of the steps the responsible emitter took:

(A) before the criminal activity occurred, to mitigate risks that criminal activity could result in an excess; and

(B) after the criminal activity occurred, to mitigate the likelihood of an excess as a result of the criminal activity; and

(iii) if the application relates to a natural disaster—the reasonableness of the steps the responsible emitter took:

(A) before the natural disaster occurred, to mitigate risks that a natural disaster could result in an excess; and

(B) after the natural disaster occurred, to mitigate the likelihood of an excess as a result of the natural disaster; and

(iv) any other factors that have significantly impacted the covered emissions of the facility over the monitoring period.

(3) An application under subsection (1) must be given to the Regulator no later than the first 31 October after the end of a monitoring period for which the exemption declaration is sought.

(4) The responsible emitter for the facility may, by written notice to the Regulator, withdraw an application at any time before the Regulator makes a decision on the application.

61 Further information

(1) The Regulator may, by written notice given to an applicant, require the applicant to give the Regulator, within the period specified in the notice, further information in connection with the application.

(2) If the applicant breaches the requirement, the Regulator may, by written notice given to the applicant:

(a) refuse to consider the application; or

(b) refuse to take any action, or any further action, in relation to the application.

62 Issue of exemption declaration

Scope

(1) This section applies if an application under section 60 has been made for an exemption declaration for a facility for a monitoring period.

Issue of exemption declaration

(2) If the Regulator is satisfied that:

(a) disregarding subsections 22XK(2) and (3) of the Act, the net emissions number for the facility for the monitoring period exceeds the baseline emissions number for the facility for the monitoring period; and

(b) that excess is the direct result of either or both of the following:

(i) a natural disaster;

(ii) criminal activity; and

(i) had, before the criminal activity occurred, taken reasonable steps to mitigate risks that criminal activity could result in an excess; and

(ii) has, after the criminal activity occurred, taken reasonable steps to mitigate the likelihood of an excess as a result of the criminal activity; and

(iii) the responsible emitter was not complicit in the criminal activity; and

(d) if the excess relates to a natural disaster—the responsible emitter:

(i) had, before the natural disaster occurred, taken reasonable steps to mitigate risks that a natural disaster could result in an excess; and

(ii) has, after the natural disaster occurred, taken reasonable steps to mitigate the likelihood of an excess as a result of the natural disaster;

the Regulator must issue an exemption declaration for the facility for the monitoring period.

Timing

(3) The Regulator must take all reasonable steps to ensure that a decision is made on the application:

(a) if the Regulator requires the applicant to give further information under subsection 61(1) in relation to the application—within 60 days after the applicant gave the Regulator the information; or

(b) otherwise—within 60 days after the application was made.

Notification

(4) As soon as practicable after making an exemption declaration, the Regulator must:

(a) provide written notice of the declaration to the responsible emitter for the facility covered by the declaration; and

(b) publish the details of the declaration on its website.

Refusal

(5) If the Regulator decides to refuse to issue an exemption declaration, the Regulator must give written notice of the decision to the applicant.

63 Revocation of exemption declaration because of false or misleading information

(1) If the Regulator is satisfied that:

(a) information provided to the Regulator by the responsible emitter in connection with the making of an exemption declaration was false or misleading in a material particular; and

(b) the Regulator would not have been satisfied of the matters set out in subsection 62(2) if the false or misleading information had not been provided;

the Regulator may revoke the exemption declaration with effect from at least 30 days after the notification of a decision under this section.

(2) Before the Regulator revokes an exemption declaration, the Regulator must provide a written notice to the responsible emitter for the facility for the monitoring period covered by the exemption declaration:

(a) stating that it intends to revoke the exemption declaration in relation to the facility under this section; and

(b) seeking any comments by a date specified in the notice.

(3) The Regulator must consider any comments received by the date specified in the notice and use all reasonable endeavours to revoke or decide not to revoke the exemption declaration no later than 30 days after the date specified in the notice.

(4) As soon as practicable after revoking an exemption declaration, the Regulator must:

(a) provide written notice of the decision to the responsible emitter for the facility for the monitoring period covered by the exemption declaration; and

(b) publish the details of the revocation of the exemption declaration on its website.

(5) To avoid doubt, a decision to revoke an exemption declaration under this section is a reviewable decision under section 56 of the Act.

Division 2—Declared multi‑year periods

64 Operation of this Division

For subsection 22XG(5) of the Act, this Division provides for the declaration of a specified period as a declared multi‑year period for a facility.

65 Application

(1) The responsible emitter for a facility may apply to the Regulator for declaration of a specified period as a declared multi‑year period for a facility (a multi‑year period declaration).

(2) However, an application may not be made if the proposed declared multi‑year period would overlap with an existing declared multi‑year period for the facility.

(3) The application must:

(a) be given in a manner and form approved, in writing, by the Regulator; and

(b) specify the facility and declared multi‑year period for which the declaration is sought; and

(c) specify the amount of covered emissions (in t CO2‑e) emitted, or reasonably likely to be emitted, for the proposed first financial year of the declared multi‑year period; and

(d) include a declaration that the responsible emitter will:

(i) during the multi‑year period, conduct one or more activities to reduce the emissions intensity of the production variables for the facility; and

(ii) as a result of conducting that activity or those activities, be reasonably likely to prevent an excess emissions situation from existing in relation to the facility for the multi‑year period; and

(e) include a plan setting out how conducting that activity or those activities is reasonably likely to enable the responsible emitter to reduce the net emissions number for the facility for the multi‑year period; and

(f) include a summary of the plan; and

(g) if the responsible emitter is aware of any risks they will breach section 22XF of the Act at the end of the declared multi‑year period—provide an explanation of those risks; and

(h) be signed by a responsible financial officer for the responsible emitter or a person authorised by a responsible financial officer for the responsible emitter.

Note: The Regulator is required to publish a summary included in an application for the purpose of paragraph (3)(f): see paragraph 72(1)(d).

(4) An application under subsection (1) must be given to the Regulator no later than the first 15 November after the end of the proposed first financial year of the declared multi‑year period.

(5) The responsible emitter for the facility may, by written notice to the Regulator, withdraw an application at any time before the Regulator makes a decision on the application.

66 Further information

(2) If the applicant breaches the requirement, the Regulator may, by written notice given to the applicant:

(a) refuse to consider the application; or

(b) refuse to take any action, or any further action, in relation to the application.

67 Making of multi‑year period declaration

Scope

(1) This section applies if an application under section 65 has been made for a multi‑year period declaration for a facility.

Making of multi‑year period declaration

(2) If the Regulator is satisfied the facility’s covered emissions (in t CO2‑e) for the proposed first financial year of the declared multi‑year period are greater than the baseline emissions number with respect to that facility, it may make a multi‑year period declaration for the facility having regard to:

(a) whether the responsible emitter has previously breached section 22XF of the Act; and

(b) whether the Regulator considers that there is a significant risk the responsible emitter will breach section 22XF of the Act after the end of the declared multi‑year period; and

(c) whether the Regulator considers that the responsible emitter is likely to experience financial stress in, or immediately after, the declared multi‑year period; and

(ca) whether the Regulator considers that the plan mentioned in paragraph 65(3)(e) is likely to reduce the facility’s covered emissions below the facility’s baseline emissions number for the declared multi‑year period; and

(d) such other matters (if any) as the Regulator considers relevant.

(3) If the Regulator decides to make a multi‑year period declaration, it must specify a declared multi‑year period for the facility that is:

(a) 2 financial years; or

(b) 3 financial years; or

(d) 5 financial years.

(3A) The Regulator must not make a multi‑year period declaration with an end date later than 30 June 2030.

Timing

(4) The Regulator must take all reasonable steps to ensure that a decision is made on the application by the later of:

(a) 31 January after the end of the proposed first financial year of the declared multi‑year period; and

(b) if the Regulator requires the applicant to give further information under subsection 66(1) in relation to the application—60 days after the applicant gives the Regulator the information.

Notification

(5) As soon as practicable after making a multi‑year period declaration, the Regulator must:

(a) provide written notice of the declaration to each responsible emitter for the facility in the period covered by the declaration; and

(b) publish the details of the declaration on its website.

Refusal

(6) If the Regulator decides not to make a multi‑year period declaration, the Regulator must give written notice of the decision to the applicant.

68 Variation or revocation of multi‑year period declaration on request

(1) The responsible emitter for a facility may apply to the Regulator to:

(a) reduce the length of the declared multi‑year period in a multi‑year period declaration by 1 or more years, down to a minimum of 2 years; or

(b) extend the length of a declared multi‑year period in a multi‑year period declaration by 1 or more years, up to a maximum of 5 years; or

(2) The application must:

(a) be given in a manner and form approved, in writing, by the Regulator; and

(b) specify the facility and multi‑year period declaration to be varied or revoked; and

(d) if the variation or revocation would impact the length of a monitoring period for a person other than the applicant—include the written consent of that person to the making of the application.

(3) After considering an application which complies with subsection (1) and (2), the Regulator may vary or revoke the multi‑year period declaration as requested by the applicant.

Note: See also section 90 (Regulator must not extend multi‑year period declaration in force before 1 July 2023).

Notification

(4) As soon as practicable after varying or revoking a multi‑year period declaration, the Regulator must:

(a) provide written notice of the decision to the responsible emitter for the facility for the declared multi‑year period covered by the multi‑year period declaration; and

(b) publish the details of the variation or revocation of the multi‑year period declaration on its website.

Refusal

(5) If the Regulator decides not to vary or revoke a multi‑year period declaration, the Regulator must give written notice of the decision to the applicant.

(6) To avoid doubt, a decision to decide to vary or revoke, or decide not to vary or revoke, a multi‑year period declaration under this section is a reviewable decision under section 56 of the Act.

69 Revocation of multi‑year period declaration because of false or misleading information

(1) If, during a declared multi‑year period, the Regulator becomes satisfied that:

(a) information provided to the Regulator by the responsible emitter in connection with the making of the multi‑year period declaration for the declared multi‑year period was false or misleading in a material particular; and

(b) the Regulator would not have made the multi‑year period declaration if the false or misleading information had not been provided;

the Regulator may revoke the multi‑year period declaration with effect from at least 30 days after the notification of the decision under this section.

(2) Before the Regulator revokes the multi‑year period declaration, the Regulator must provide a written notice to each responsible emitter for the facility for the declared multi‑year period:

(a) stating that it intends to revoke the multi‑year period declaration in relation to the facility under this section; and

(b) seeking any comments by a date specified in the notice.

(3) The Regulator must consider any comments received by the date specified in the notice and use all reasonable endeavours to revoke or decide not to revoke the multi‑year period declaration no later than 30 days after the date specified in the notice.

(4) As soon as practicable after revoking a multi‑year period declaration, the Regulator must:

(a) provide written notice of the decision to each responsible emitter for the facility for the declared multi‑year period; and

(b) publish the details of the revocation of the multi‑year period declaration on its website.

(5) To avoid doubt, a decision to revoke a multi‑year period declaration under this section is a reviewable decision under section 56 of the Act.

69A Explanation of performance against plan for avoiding an excess emissions situation at end of declared multi‑year period

(1) This section applies if:

(a) under subsection 65(1), a responsible emitter for a facility applied for a multi‑year period declaration on or after the day this section commences; and

(b) under section 67, the Regulator made a multi‑year declaration for the facility.

(2) By the first 31 October after the end of the last financial year of the declared multi‑year period, the responsible emitter must submit to the Regulator a written explanation describing how the facility performed against its plan provided for the purposes of paragraph 65(3)(e).

Note: The Regulator is required to publish an explanation given under this section: see paragraph 72(1)(e).

69B Variation of multi‑year period declaration where emissions are not being reduced

(1) The Regulator may vary a multi‑year period declaration that is in force in relation to a facility to reduce the number of financial years included in the declaration if the Regulator is satisfied that:

(a) the responsible emitter for the facility is not implementing, or is unable to implement, the plan given to the Regulator in accordance with paragraph 65(3)(e); and

(b) the number of tonnes of carbon dioxide equivalence of covered emissions of greenhouse gases from the operation of the facility during the multi‑year period is likely to exceed the baseline emissions number for the facility for the period.

(2) If the Regulator decides to vary the declaration, the Regulator must vary the declaration so that it ceases to be in force at the end of the financial year in which the Regulator becomes satisfied of the matters in subsection (1).

(3) If the Regulator is considering whether to vary, under this section, a multi‑year period declaration that is in force in relation to a facility, the Regulator may, by written notice given to the responsible emitter for the facility, request that the responsible emitter provide, within the period specified in the notice, the Regulator with specified information that the Regulator considers relevant to the potential variation.

(4) This section does not limit subsection 33(3) of the Acts Interpretation Act 1901.

Division 3—Notification and publication requirements

70 Operation of this Division

For subsection 22XP(2) and paragraph 22XS(1)(b) of the Act, this Division provides for the issue of advisory notices and other information publication requirements.

71 Advisory notices

(1) The Regulator must notify the responsible emitter for a designated large facility as soon as practicable after:

(a) the net emissions number for the facility is increased under subsection 22XK(4) of the Act; or

(b) deemed surrender occurs under subsection 22XN(6) of the Act in relation to the facility.

(2) A notification under paragraph (1)(a) must include the unique identification numbers for each Australian carbon credit unit that has resulted in the increase in the net emissions number for the facility.

(3) The Regulator may notify the responsible emitter for a facility of any of the following:

(a) the number that the Regulator considers is the net emissions number of the facility;

(b) that an offsets report has been submitted which attributes abatement to the facility;

(c) any other matters relating to the safeguard provisions that the Regulator considers appropriate to provide notification.

(4) At the request of the responsible emitter for a facility, the Regulator may provide the responsible emitter with any reports relating to the facility under the Act relevant to the making or variation of an emissions intensity determination under this instrument.

72 Publication

(1) The Regulator must publish on its website and keep up‑to‑date the following information relating to the safeguard mechanism:

(a) in respect of each facility that is a designated large facility, or an eligible facility, for a financial year:

(i) the responsible emitter for the facility; and

(ii) whether or not the facility is a grid‑connected electricity generator; and

(iii) the current baseline emissions number for the facility; and

(iv) the baseline emissions number for each financial year that the facility is a designated large facility or an eligible facility (as the case may be); and

(v) the covered emissions of the facility for each financial year that the facility is a designated large facility or an eligible facility (as the case may be); and

(vi) if the facility is a grid‑connected electricity generator—the covered emissions for each financial year after 1 July 2016 calculated on the basis that no financial year is a sectoral‑baseline financial year; and

(vii) the net emissions number for each monitoring period that applies to the facility; and

(viii) the number of prescribed carbon units surrendered under subsection 22XN(1) of the Act for each monitoring period that applies to the facility; and

(ix) if a multi‑year period declaration applies to the facility—the start date and end date of the declared multi‑year period for the facility; and

(x) the start date and end date of any monitoring period for which an exemption declaration has been made in relation to the facility; and

(xi) any increase in the net emissions number under subsection 22XK(4) of the Act or deemed surrender under subsection 22XN(6); and

(xii) if there is an emissions reduction contribution for the facility for a financial year (the facility‑specific ERC) that is different from the default emissions reduction contribution for that financial year—the facility‑specific ERC; and

(xiii) if there is a borrowing adjustment number for the facility for a financial year—that borrowing adjustment number; and

(xiv) if a number of safeguard mechanism credit units is issued to the responsible emitter for the facility for a financial year—the number of safeguard mechanism credit units issued to the responsible emitter for that financial year;

(b) in respect of any excess emissions situations resulting in a breach of section 22XF of the Act:

(i) the responsible emitter for the excess emissions situation; and

(ii) when the excess emissions situation started; and

(iii) if the excess emissions situation no longer exists—the date when the excess emissions situation ended;

(c) the covered emissions of each grid‑connected electricity generator for each financial year after 1 July 2016 calculated on the basis that no financial year is a sectoral‑baseline financial year;

(d) in respect of each application for a declaration of a specified period as a declared multi‑year period for a facility, the summary mentioned in paragraph 65(3)(f);

(e) each explanation submitted to the Regulator under subsection 69A(2).

Note: The publication of certain types of information is subject to section 25 of the Act.

(2) The information required to be published under paragraph (1)(c) and subparagraphs (1)(a)(v) and (vi) need not be published until information is published in respect of the relevant financial year under section 24 of the Act.

(3) The information required to be published under subparagraphs (1)(a)(vii) and (viii) need not be published until after the first 1 April following the end of the relevant monitoring period.

(4) If the total amount of covered emissions of greenhouse gases from the operation of a designated large facility during a financial year is set out in a report under this Act for the financial year, the Regulator must publish on its website by the first 15 April after the end of the financial year, the methods used by the facility to estimate each source of fugitive methane emissions from the following for the financial year:

(a) coal mining activities; and

(b) oil and natural gas activities.

Division 4—Net emissions number

72A Excess surrender situation

(1) This section applies if a person surrendered a number of prescribed carbon units for the purpose of reducing the net emissions number for a facility for a period (the relevant period).

(2) There is taken to be an excess surrender situation of the person in relation to the facility for the relevant period if:

(a) the person surrendered some or all of those units because of an error on the part of the Regulator; or

(b) all of the following apply:

(i) the person surrendered some or all of those units because of an error on the part of the person or another person;

(ii) the error concerned the amount of covered emissions of greenhouse gases from the operation of the facility, or the quantity of a production variable for the facility, during the relevant period;

(iii) the Regulator required a report under the Act to be resubmitted because of the error;

(iv) the Regulator is satisfied that the error was made in good faith.

(3) Units are taken to be covered by the excess surrender situation if:

(a) they were surrendered by the person because of an error mentioned in subsection (2); and

(b) the person, by written notice given to the Regulator, requests that those units be surrendered for the purpose of reducing the net emissions number for the facility for the financial year (the next financial year) starting immediately after the relevant period; and

(4) For the purposes of subsection 22XK(3) of the Act, section 22XK of the Act has effect as if:

(a) the person had not surrendered the units covered by the excess surrender situation for the purpose of reducing the net emissions number for the facility for the relevant period; and

(b) the person:

(i) had surrendered those units for the purpose of reducing the net emissions number for the facility for the next financial year; and

(ii) had done so on the later of the first day of the next financial year and the day the notice was given to the Regulator.

72B Circumstances in which subsection 22XK(4) of the Act does not apply

For the purposes of subsection 22XK(5) of the Act, if a facility is a designated large facility, the net emissions number for the facility for a period is not increased under subsection 22XK(4) of the Act by a number of Australian carbon credit units if those units are not attributable to the avoidance of covered emissions of greenhouse gases from the operation of the facility during the period.

Division 5—Surrender of prescribed carbon units

72C Requirements for surrender of prescribed carbon units

(1) For the purposes of paragraph 22XN(1)(b) of the Act, this section creates requirements for a surrender by a person of prescribed carbon units for the purposes of reducing the net emissions number for a facility for a period.

No ACCUs surrendered

(2) The surrender meets the requirements of this section if none of the prescribed carbon units are Australian carbon credit units.

Total number of ACCUs surrendered less than 30% of baseline emissions number

(3) The surrender also meets the requirements of this section if:

(a) some or all of the prescribed carbon units are Australian carbon credit units; and

(b) the total number of:

(i) those Australian carbon credit units; and

(ii) any Australian carbon credit units that were previously surrendered for the purposes of reducing the net emissions number for the facility for the period;

is less than 30% of the baseline emissions number for the facility for the period.

Total number of ACCUs surrendered equal to or greater than 30% of baseline emissions number (with explanation)

(4) The surrender also meets the requirements of this section if:

(a) some or all of the prescribed carbon units are Australian carbon credit units; and

(b) the surrender causes the total number of:

(i) those Australian carbon credit units; and

(ii) any Australian carbon credit units that were previously surrendered for the purposes of reducing the net emissions number for the facility for the period;

to be equal to or greater than 30% of the baseline emissions number for the facility for the period; and

(c) the responsible emitter for the facility gives the Regulator, in accordance with subsection (5), a written explanation of why more carbon abatement was not undertaken at the facility during the period.

Explanation requirements

(5) A written explanation of why more carbon abatement was not undertaken at a facility during a period must:

(a) be given to the Regulator in the form approved, in writing, by the Regulator; and

(b) address the following matters:

(i) whether limitations in available technologies affected the level of carbon abatement undertaken at the facility during the period;

(ii) whether there are barriers, including regulatory barriers, to undertaking carbon abatement at the facility; and

(d) identify any information included in the explanation that is commercially sensitive.

Publication of explanation

(6) The Regulator must publish an explanation given to the Regulator in accordance with paragraph (5)(a) on the Regulator’s website as soon as practicable after receiving it. The published explanation must not include any commercially sensitive information identified in accordance with paragraph (5)(d).

72D Requirements for period for which net emissions number is reduced by surrendering units

For the purposes of paragraph 22XN(1)(c) of the Act, the registered holder of one or more prescribed carbon units may surrender any or all of those units for the purposes of reducing the net emissions number for a facility for a period if the period meets the following requirements:

(a) the period is a monitoring period for the facility in relation to the responsible emitter for the facility;

(b) the period commenced before the surrender is made.

72E Circumstances in which subsection 22XN(6) of the Act does not apply

(1) This section is made for the purposes of subsection 22XN(7) of the Act.

Contracts entered into after 30 March 2023

(2) Subsection 22XN(6) of the Act does not apply in relation to a carbon abatement contract entered into after 30 March 2023 (otherwise than by way of novation).

Units not attributable to the avoidance of covered emissions

(3) Australian carbon credit units are not taken under subsection 22XN(6) of the Act to have been surrendered for the purpose of reducing the net emissions number for a facility for a period if those units are not attributable to the avoidance of covered emissions of greenhouse gases from the operation of the facility during the period.

Carbon abatement contract does not refer to a particular eligible offsets project

(4) Subsection 22XN(6) of the Act does not apply in circumstances where units that:

(a) were issued in respect of a particular eligible offsets project; and

(b) are covered by paragraph 22XN(6)(c) of the Act;

are purchased by the Commonwealth under a carbon abatement contract that does not refer to that particular project.

Part 5—Registration, reporting and record‑keeping

Division 1A—Voluntary registration

72F Registration of eligible facilities

For the purposes of paragraph 15B(3A)(a) of the Act, a person who has operational control of an eligible facility for a financial year may apply, in accordance with section 15B of the Act, to be registered under the Act.

Division 1—Registration applications

73 Operation of this Division

For paragraph 15B(4)(c) of the Act, this Division provides for information to accompany an application to register under section 15B of the Act.

74 Application requirements

(1) An application under section 15B of the Act must set out the following information:

(a) the applicant’s name and trading name (if any);

(b) which section of the Act the applicant is applying under;

(d) if a personal identification number has been issued by the Regulator to the applicant—the applicant’s personal identification number;

(e) if the applicant is a subsidiary of a controlling corporation registered under the Act—a statement to that effect, and the identifying details of the controlling corporation.

(2) The application must also set out the identifying information for the applicant if that information has not previously been given to the Regulator.

Division 2—Reporting

75 Operation of this Division

For paragraph 22XB(2)(b) of the Act, this Division provides for information to be set out in a report under section 22XB of the Act.

76 Required information

(1) A report under section 22XB of the Act must set out:

(a) the identifying information for the responsible emitter providing the report; and

(b) the information required by Subdivisions 4.4.2 and 4.4.3 and regulations 4.04A and 4.27 of the NGER Regulations as if the person was a corporation to which those subdivisions and regulations 4.04A and 4.27 applied; and

(d) any information required under section 77.

Reporting quantities of production variables used to calculate baseline emissions number

(2) A report provided under section 22XB of the Act by a person who is the responsible emitter for a facility during the whole or a part of a financial year must also set out the information that would be required to be provided by the person under regulation 4.23C of the NGER Regulations if the person were a corporation to whom Division 4.4A of those regulations applied in relation to the facility for the financial year.

77 Reporting a change in principal activity for facility

(1) This section applies in relation to a report provided to the Regulator under section 22XB of the Act if the principal activity for a facility that has been included in a report under the Act stops being the principal activity for the facility for a period of at least 24 months.

(2) The responsible emitter for the facility must identify a new principal activity for the facility and the industry sector to which the principal activity is attributable in accordance with Subdivisions 2.4.2 and 2.4.3 of the NGER Regulations.

(3) The report for the reporting year that includes the last day of the period mentioned in subsection (1) must include the industry sector to which the new principal activity is attributable.

(4) The responsible emitter must record the new principal activity and the date that the principal activity changed.

(5) In this regulation, principal activity, in relation to a facility, means the activity that:

(a) results in the production of a product or service that is produced for sale on the market; and

(b) produces the most value for the facility out of any of the activities forming part of the facility.

Division 3—Record‑keeping

78 Form of records

(1) This section applies to records mentioned in subsection 22XC(1) of the Act.

(2) For paragraph 22XC(3)(b) of the Act, the records must be kept in a form that is easily and quickly accessible for inspection and audit.

Note: This may be in an electronic or hard copy format.

Division 4—Other information about the safeguard mechanism

78A Audit of regulatory reports for facilities with high emissions

Audit required under section 74AA of the Act if emissions exceed 1 Mt CO2‑e

(1) For the purposes of paragraph 74AA(1)(c) of the Act, the condition, in relation to a report that a person is required to provide under section 19, 22G, 22X or 22XB of the Act for a financial year in relation to one or more facilities, is that the amount of covered emissions of greenhouse gases from the operation of any of those facilities during the financial year exceeds 1 million tonnes of carbon dioxide equivalence.

Reasonable assurance conclusion for amounts exceeding 1 Mt CO2‑e

(2) For the purposes of subsection 74AA(3) of the Act, the report for an audit, under subsection 74AA(2) of the Act, of a report (the regulatory report) in relation to one or more facilities must include:

(a) a reasonable assurance conclusion; or

(b) a qualified reasonable assurance conclusion;

as to whether, in all material respects, the quantities specified in the regulatory report that relate to the following are correct:

(d) production variables for those facilities.

Part 6—Application and transitional provisions

Division 1—Application and transitional provisions relating to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment Rule (No. 1) 2019

79 Applications for calculated‑emissions baseline determination before commencement

Unless the applicant elects otherwise in writing, an application under section 22 received before the commencement of the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment Rule (No. 1) 2019 (the amendment rule) must be determined as if the amendment rule had not commenced.

80 Applications for declared multi‑year period before commencement

Unless the applicant elects otherwise in writing, an application under section 65 received before the commencement of the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment Rule (No. 1) 2019 (the amendment rule) must be determined as if the amendment rule had not commenced.

Division 2—Application and transitional provisions relating to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Extended Transition) Rule 2020

81 Baseline emissions number if calculated‑emissions baseline determination expired on 30 June 2019

If a calculated‑emissions baseline determination for a facility expired on 30 June 2019 and no other baseline determination applies to the financial year beginning on 1 July 2019, the baseline emissions number for the facility for the financial year beginning on 1 July 2019 is taken to be the baseline emissions number of the calculated‑emissions baseline determination.

Division 3—Application and transitional provisions relating to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Additional Prescribed Production Variables) Rule 2020

82 Default emissions intensities for financial year beginning on 1 July 2019

If a default emissions intensity is being used in relation to a baseline emissions number for the financial year beginning on 1 July 2019, the default emissions intensity is to be determined as the value in force immediately before the commencement of Schedule 2 of the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Additional Prescribed Production Variables) Rule 2020.

83 Default emissions intensities and calculated‑emissions baseline determinations for financial year beginning on 1 July 2020

(1) If a default emissions intensity is being used in relation to a baseline emissions number for the financial year beginning on 1 July 2020, the default emissions intensity is to be determined as the value in force immediately after the commencement of Schedule 2 of the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Additional Prescribed Production Variables) Rule 2020.

Note: This applies instead of subsection 44(3B) for the financial year beginning on 1 July 2020.

(2) If a calculated‑emissions baseline determination is in force for the financial year beginning 1 July 2020 and was not updated under section 56 to reflect the change in carbon dioxide equivalence, the Regulator must update that determination under section 56 based on the values of any relevant default emissions intensities in force immediately after the commencement of Schedule 2 of the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Additional Prescribed Production Variables) Rule 2020.

84 Calculated‑emissions baseline determinations applying from 1 July 2019

(1) If a calculated‑emissions baseline determination for a facility is made commencing from 1 July 2019 using the carbon dioxide equivalence of greenhouse gases in force on 1 July 2020 for an estimated emissions intensity, the responsible emitter for the facility may apply to the Regulator to adjust the baseline emissions number for the financial year beginning on 1 July 2019 to apply the carbon dioxide equivalence of the relevant greenhouse gases as in force on 1 July 2019.

(2) After considering an application under subsection (1), the Regulator may amend the determination in respect of the financial year beginning on 1 July 2019.

(3) An application under subsection (1) must be given in a manner and form approved, in writing, by the Regulator and can be made before the making of the determination.

Division 4—Application and transitional provisions relating to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Prescribed Production Variables Update) Rule 2021

85 Determination of estimated emission intensity and production variable

(1) If a calculated‑emissions baseline determination for a facility is made using one or more estimated emissions intensities for one or more production variables, the responsible emitter for the facility may apply to the Regulator to determine the equivalent estimated emissions‑intensities and prescribed (annually adjusted) production variables from Schedule 2 for the facility.

(2) After considering an application under subsection (1), the Regulator may make a determination of the equivalent estimated emissions‑intensities and prescribed (annually adjusted) production variables from Schedule 2 for the facility if it is practicable to do so.

(3) If the Regulator makes a determination under subsection (2):

(a) that estimated emissions‑intensity and prescribed (annually adjusted) production variable must be used in place of the original estimated emissions‑intensity and production variable in making a production‑adjusted baseline determination;

(b) if a production‑adjusted baseline determination has already been made at the time of the determination under subsection (2), update that determination to reflect the new estimated emissions‑intensity and prescribed (annually adjusted) production variable with effect from the start of the financial year during which the determination under subsection (2) is made.

(4) An application under subsection (1) must be:

(a) given in a manner and form approved, in writing, by the Regulator; and

(b) made before 1 July 2024.

(5) As soon as practicable after making a determination or amending a determination under paragraph (3)(b), the Regulator must:

(a) provide written notice of the decision to the responsible emitter for the facility of the determination; and

(b) publish the details of the determination on its website.

(6) If the Regulator decides not to make a determination under subsection (2), the Regulator must give written notice of the decision to the applicant.

(7) A decision to make, or refuse to make, a determination under this section is a reviewable decision under section 56 of the Act.

86 Updated emissions intensity for certain changes to NGER (Measurement) Determination

(1) This section applies to a calculated‑emissions baseline determination or production‑adjusted baseline determination for a facility that:

(a) is made using one or more estimated emissions intensities for one or more production variables; and

(b) the estimated emissions‑intensities take into account emissions reported, or to be reported, under Division 3.3 of the NGER (Measurement) Determination as in force before 1 July 2021; and

(c) the Regulator considers that amendments made by the National Greenhouse and Energy Reporting (2021 Update) Determination 2021 impact the estimated emissions intensity by more than 1%.

(2) After consulting with the responsible emitter for the facility to which a determination covered by this section applies, the Regulator must amend the determination to take account of the National Greenhouse and Energy Reporting (2021 Update) Determination 2021 (with effect from no earlier than 1 July 2021).

(3) For subsection (2), the Regulator must take into account the use of method 2 under subsection 2.27 if satisfied that method will be used on an ongoing basis to report emissions from the facility.

(4) As soon as practicable after amending a determination, the Regulator must:

(a) provide written notice of the decision to the responsible emitter for the facility of the determination; and

(b) publish the details of the determination on its website.

Division 5—Application, saving and transitional provisions relating to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Reforms) Rules 2023

87 Application provisions

(1) The amendment of section 7 made by the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Reforms) Rules 2023 applies in relation to emissions of one or more greenhouse gases from the operation of a grid‑connected electricity generator in respect of a sectoral‑baseline financial year that begins after 30 June 2023.

(2) Part 3, as substituted by the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Reforms) Rules 2023, applies in relation to the ascertainment of the baseline emissions number for a facility for a financial year that begins after 30 June 2023.

(3) Sections 72B and 72D, and subsection 72E(3), as inserted by the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Reforms) Rules 2023, apply in relation to a period beginning after 30 June 2022.

(4) Section 72C, as inserted by the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Reforms) Rules 2023, applies, on and after 1 July 2023, in relation to a period beginning before, on or after that day.

88 Saving provisions

(1) Despite the repeal of Part 3 of this instrument by the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Reforms) Rules 2023, that Part, as in force immediately before 1 July 2023, continues to apply, on and after that day, in relation to the ascertainment of the baseline emissions number for a facility for a financial year that ends on or before 30 June 2023.

(2) However, for the ascertainment of the baseline emissions number for a facility for the financial year beginning on 1 July 2022, Part 3, as continued in force under subsection (1), applies as if the following were omitted:

(a) subsection 26A(6) (criteria for a transitional calculated baseline);

(b) subparagraphs 40(1)(ab)(i) and (ii) (criteria for a production‑adjusted baseline determination);

(3) Despite the repeal of Part 3 of this instrument by the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Reforms) Rules 2023, a determination made under that Part that is in force immediately before 1 July 2023 continues to apply, on and after that day, in relation to the ascertainment of the baseline emissions number for a facility for a financial year that ends on or before 30 June 2023.

89 Updated end date for declared multi‑year periods ending after 30 June 2024

(1) This section applies to a declared multi‑year period in a multi‑year period declaration in force immediately before this section commences.

(2) If the end date of the declared multi‑year period is a date later than 30 June 2024, the end date is taken to be 30 June 2024.

90 Regulator must not extend multi‑year period declaration in force before 1 July 2023

(1) This section applies in relation to a declared multi‑year period in a multi‑year period declaration in force immediately before this section commences.

(2) Despite subsection 68(3), the Regulator must not extend the length of the declared multi‑year period.

Division 6—Application, saving and transitional provisions relating to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Production Variables Update) Rules 2023

91 Application and transitional provisions

(2) For subsection 20(6), if the transitional production variable for the facility is specified in column 1 of an item of the following table, the facility‑specific emissions intensity number is taken to be the number specified in column 2 of that item.

Item	Column 1 Transitional production variable	Column 2 Facility‑specific emissions intensity number
1	Run‑of‑mine coal	0.0653 t CO2‑e per tonne of run‑of‑mine coal
2	Reservoir carbon dioxide from existing gas fields	0.928 t CO2‑e per tonne of reservoir carbon dioxide
3	Natural gas throughput	0.000518 t CO2‑e per gigajoule of natural gas

Note: The number applies regardless of whether the production variable was applicable to the facility at any time during a historical financial year, or otherwise.

Division 7—Application, saving and transitional provisions relating to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Production Variables Update) Rules 2024

92 Application and transitional provisions

(1) If a default emissions intensity is being used in relation to a baseline emissions number for the financial year beginning on 1 July 2023, the default emissions intensity is to be determined as the value in force immediately after the commencement of Schedule 1 to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Production Variables Update) Rules 2024.

(2) For subsection 20(6), if the transitional production variable for the facility is lithium hydroxide, the facility‑specific emissions intensity number is taken to be 3.26 CO2‑e per tonne of lithium hydroxide monohydrate.

Division 8—Application, saving and transitional provisions relating to the National Greenhouse and Energy Reporting Legislation Amendment (Best Practice Emissions Intensities Update) Instrument 2024

93 Application and transitional provisions

(1) If a best practice emissions intensity is being used in relation to a baseline emissions number for the financial year beginning on 1 July 2023 or 1 July 2024, the best practice emissions intensity is to be determined as the value in force immediately after the commencement of Schedule 1 to the National Greenhouse and Energy Reporting Legislation Amendment (Best Practice Emissions Intensities Update) Instrument 2024.

(2) If a default emissions intensity is being used in relation to a baseline emissions number for the financial year beginning on 1 July 2024, the default emissions intensity is to be determined as the value in force immediately after the commencement of Schedule 1 to the National Greenhouse and Energy Reporting Legislation Amendment (Best Practice Emissions Intensities Update) Instrument 2024.

(3) Despite subsection 92(1), if a default emissions intensity for the gaseous hydrogen production variable in section 99 of Schedule 1 is being used in relation to a baseline emissions number for the financial year beginning on 1 July 2023, the default emissions intensity is to be determined as the value in force immediately after the commencement of Schedule 1 to the National Greenhouse and Energy Reporting Legislation Amendment (Best Practice Emissions Intensities Update) Instrument 2024.

Schedule 1—Production variables

Note: See the definition of production variable in section 4.

Part 1—Preliminary

1 Purpose

This Schedule sets out production variables.

2 Structure

(1) Each Part of the Schedule sets out:

(a) one or more metrics, each of which is a production variable; and

(b) the units relevant to those metrics; and

(2) The default emissions intensity is specified in t CO2‑e per unit of the production variable.

(3) A Part may also set out:

(a) measurement requirements or procedures relevant to the application of the metrics; and

(b) for paragraphs 4.23C(2)(b) and 4.23D(3)(b) of the NGER Regulations, requirements for supporting information to be included in a report under the Act about the calculation of the amount of the production variables for a financial year.

(4) The emissions relevant to the development of each production variable and the calculation of its default emissions intensity are explained in the Safeguard Mechanism document.

3 Definitions

In this Schedule:

ANZSIC industry classification and code means an industry classification and code for that classification published in the Australian and New Zealand Standard Industrial Classification (ANZSIC), 2006 and as in force on the commencement of the National Greenhouse and Energy Reporting (Safeguard Mechanism) Amendment (Prescribed Production Variables) Rule 2020.

Note: In 2020, the classification and code could be accessed from http://www.abs.gov.au.

ASTM followed by a number (for example, ASTM D6347/D6347M‑99) means a standard of that number issued by ASTM International and, if a date is included, of that date.

Note: ASTM means the American Society for Testing and Materials, see http://www.astm.org.

AS or Australian standard followed by a number (for example, AS 4323.1—1995) means a standard of that number issued by Standards Australia Limited and, if a date is included, of that date.

saleable quality—see section 4 of this Schedule.

4 Meaning of saleable quality

(1) In this Schedule, saleable quality is intended to have its ordinary meaning as understood by participants in the relevant market, subject to subsections (2) to (5).

(2) A product is taken to be of saleable quality if it is produced to a level at which it would ordinarily be considered by participants in the relevant market:

(a) to be the output of a process carried on as part of the relevant activity the constitutes the facility; and

(b) to have a commercial value as that output.

Note: On this basis, the output may meet particular industry standards or specifications (either general specifications or those set by particular customers). It may also meet internal standards by which it can be used by the firm as part of another process conducted by the firm.

Note: Outputs that are of saleable quality do not need to be sold in the year of production. Therefore, an output that is produced and entered on an inventory can be of saleable quality.

(3) A sub‑standard product that is discarded is taken not to be of saleable quality.

(4) A product that is recycled back into the same activity at a facility to produce a new output is taken to be of saleable quality only once.

Examples:

Metal that is re‑melted in the same equipment in which it was produced.

Paper that is re‑inputted into a paper making process.

(5) Material that is scrapped or lost before it is packaged as a product that is of saleable quality:

(a) is taken not to be of saleable quality; and

(b) is taken not to be included in an amount of product that is of saleable quality that is to be counted for the purpose of calculating the amount of a production variable produced in a financial year.

Part 2—Bulk flat glass

5 Bulk flat glass

(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).

(3) The default emissions intensity is 0.774 t CO2‑e per tonne of bulk flat glass.

Part 3—Glass containers

6 Glass containers

(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).

(3) The default emissions intensity is 0.593 t CO2‑e per tonne of glass containers.

Part 4—Aluminium

7 Aluminium

(1) 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

(2) 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) The default emissions intensity is 1.94 t CO2‑e per tonne of primary aluminium.

Part 5—Alumina

8 Alumina

(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).

(3) The default emissions intensity is 0.545 t CO2‑e per tonne of alumina and alumina equivalent tonnes of alumina trihydrate.

Part 6—Ammonia production

9 Ammonia production

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

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

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

(2) 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).

(3) The default emissions intensity is 1.87 t CO2‑e per tonne of 100% equivalent anhydrous ammonia.

(4) The best practice emissions intensity is 1.26 t CO2‑e per tonne of 100% equivalent anhydrous ammonia.

Part 7—Ammonium nitrate production

10 Ammonium nitrate

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

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

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

(2) 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).

(3) The default emissions intensity is 0.315 t CO2‑e per tonne of 100% equivalent ammonium nitrate.

Part 8—Urea production

11 Carbamide (urea)

(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

(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.

(4) The default emissions intensity is 0.566 t CO2‑e per tonne of 100% equivalent carbamide.

(5) The best practice emissions intensity is 0.306 t CO2‑e per tonne of 100% equivalent carbamide.

Part 9—Ammonium phosphate production

12 Monoammonium phosphate

(1) Tonnes of monoammonium phosphate ((NH4)H2PO4) products that:

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

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

(d) are of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing 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 monoammonium phosphate.

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

(4) The default emissions intensity is 0.088 t CO2‑e per tonne of monoammonium phosphate products.

12A Diammonium phosphate

(1) Tonnes of diammonium phosphate ((NH4)2HPO4) products that:

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

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

(d) are of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing diammonium 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 diammonium phosphate.

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

(4) The default emissions intensity is 0.078 t CO2‑e per tonne of diammonium phosphate products.

Part 9A—Phosphoric acid

12B Phosphoric acid

(1) Kilolitres of 100% equivalent phosphoric acid (H3PO4) that:

(a) are contained in solution where the concentration of phosphoric acid is greater than 70% by weight; and

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

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing phosphoric acid through the transformation of phosphate-bearing minerals (the phosphoric acid production activity).

(3) The metric in subsection (1) is not applicable to a facility which further processes the phosphoric acid into monoammonium phosphate or diammonium phosphate.

(4) The best practice emissions intensity is 0.114 t CO2‑e per kilolitre of 100% equivalent phosphoric acid.

Part 10— Sodium cyanide

13 Sodium cyanide

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

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

(b) of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing sodium cyanide through:

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

(b) the chemical transformation of that hydrogen cyanide (HCN) and caustic soda to produce sodium cyanide (NaCN).

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

(4) The default emissions intensity is 0.899 t CO2‑e per tonne of 100% equivalent sodium cyanide.

Part 11—Synthetic rutile

14 Synthetic rutile

(1) Tonnes of synthetic rutile that:

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

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

(d) are of saleable quality.

(2) 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:

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

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

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

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

(4) The default emissions intensity is 1.15 t CO2‑e per tonne of synthetic rutile.

Part 12—White titanium dioxide pigment

15 White titanium dioxide pigment

(1) Tonnes of white titanium dioxide (TiO2) pigment that:

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

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

(d) are of saleable quality.

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

(2) 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);

(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.

(3) 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.

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

(5) The default emissions intensity is 1.68 t CO2‑e per tonne of white titanium dioxide pigment.

Part 13—Production variables related to coal mining

Division 1—Definitions

16 Definitions

(1) In this Part, 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.

(2) In this Part, 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:

(a) coal production;

(b) active mine ventilation, including the operation of ventilation fans at the mine.

Division 2— Run‑of‑mine coal

17 Run‑of‑mine coal

(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 conducts the activity of coal mining.

(3) The default emissions intensity is the average of:

(a) 0.0653 t CO2‑e; and

(b) the facility‑specific emissions intensity number for the facility

per tonne of run‑of‑mine coal.

(4) The best practice emissions intensity is 0.00592 t CO2‑e per tonne of run‑of‑mine coal.

Division 3—Decommissioned underground mines

19 Fugitive emissions from decommissioned underground mines

(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.

Part 14—Iron ore

20 Iron ore

(1) Tonnes of run‑of‑mine 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.

(2) 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.

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

(4) The default emissions intensity is 0.00476 t CO2‑e per tonne of run‑of‑mine iron ore.

(5) The best practice emissions intensity is 0.00188 t CO2‑e per tonne of run‑of‑mine iron ore.

Part 15—Manganese ore

21 Manganese ore

(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.

(4) The default emissions intensity is 0.0217 t CO2‑e per tonne of manganese ore.

(5) The best practice emissions intensity is 0.0204 t CO2‑e per tonne of manganese ore.

Part 16—Bauxite

22 Bauxite

(1) Tonnes of bauxite product that:

(a) is produced as part of carrying on the bauxite 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 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.

(4) The default emissions intensity is 0.00401 t CO2‑e per tonne of bauxite.

Part 17—Heavy metal concentrate (mineral sands mining)

23 Heavy metal concentrate

(1) 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

(2) 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.

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

Note: The default emissions intensity for this production variable is yet to be calculated and specified in the Schedule.

Part 17A—Lithium ore

23A Lithium ore

(1) Tonnes of lithium ore that:

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

(b) are of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that undertakes lithium ore mining activity through the physical extraction of lithium bearing minerals.

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

(4) The default emissions intensity is 0.0151 t CO2‑e per tonne of lithium ore.

(5) The best practice emissions intensity is 0.0105 t CO2‑e per tonne of lithium ore.

Part 18—Run‑of‑mine metal ore

24 Run‑of‑mine metal ore

(1) 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

(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, iron ore or lithium ore production variable.

(2) 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.

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

(4) The default emissions intensity is 0.00859 t CO2‑e per tonne of run‑of‑mine metal ore.

(5) The best practice emissions intensity is 0.00247 t CO2‑e per tonne of run‑of‑mine metal ore.

Part 19—Production variables related to the oil and gas industry

Division 1—Definitions

25 Definitions

(1) In this Part:

liquefied petroleum gas means:

(a) liquid propane; or

(b) liquid butane; or

(d) a liquid mixture of propane and other hydrocarbons that consists mainly of propane; or

(e) a liquid mixture of butane and other hydrocarbons that consists mainly of butane; or

(f) a liquid mixture of propane, butane and other hydrocarbons that consists mainly of propane and butane.

processed natural gas means a substance that:

(a) is in a gaseous state at standard temperature and pressure; and

(b) consists of:

(i) naturally occurring hydrocarbons; or

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

(d) has been:

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

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

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

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

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

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

Division 2—Oil and gas extraction

26 Extracted oil and gas

(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

(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.

(5) The default emissions intensity is 0.000376 t CO2‑e per gigajoule of products covered by subsection (1) and (2).

(6) The best practice emissions intensity is 0.0000360 t CO2‑e per gigajoule of products covered by subsection (1) and (2).

Division 3—Stabilisation of crude oil and condensates

27 Stabilised crude oil or condensate (stabilisation only)

(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

(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

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

(4) The default emissions intensity is 0.00121 t CO2‑e per gigajoule of crude oil and condensate.

(5) The best practice emissions intensity is 0.000320 t CO2‑e per gigajoule of crude oil and condensate.

Division 4—Integrated extraction and stabilisation of crude oil

28 Stabilised crude oil (integrated extraction and stabilisation)

(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.

(5) The default emissions intensity is 0.00384 t CO2‑e per gigajoule of crude oil.

(6) The best practice emissions intensity is 0.000356 t CO2‑e per gigajoule of crude oil.

Division 5—Natural gas processing

29 Processed natural gas (processing only)

(1) Gigajoules of the 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

(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).

(3) The default emissions intensity is 0.00159 t CO2‑e per gigajoule of processed natural gas.

(4) The best practice emissions intensity is 0.000243 t CO2‑e per gigajoule of processed natural gas.

Division 6—Integrated natural gas extraction and processing

30 Processed natural gas (integrated extraction and processing)

(1) Gigajoules of the 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

(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 production variable in this Part (other than the reservoir carbon dioxide production variables in sections 35 and 35A of Schedule 1 or the processed natural gas (processing only) production variable in section 29 of Schedule 1).

(5) The default emissions intensity is 0.00275 t CO2‑e per gigajoule of processed natural gas.

(6) The best practice emissions intensity is 0.000394 t CO2‑e per gigajoule of processed natural gas.

Division 7—Liquefied natural gas from unprocessed natural gas

31 Liquefied natural gas (from unprocessed natural gas)

(1) Gigajoules of the 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 unprocessed natural gas liquefaction activity at the facility; 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 this Schedule.

(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 default emissions intensity is 0.00414 t CO2‑e per gigajoule of liquefied natural gas.

(5) 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.

(6) The best practice emissions intensity is 0.000876 t CO2‑e per gigajoule of liquefied natural gas.

Division 8—Liquefied natural gas from processed natural gas

32 Liquefied natural gas (from processed natural gas)

(1) Gigajoules of the 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

(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 this Schedule.

(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 default emissions intensity is 0.00401 t CO2‑e per gigajoule of liquefied natural gas.

(5) 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.

(6) The best practice emissions intensity is 0.000633 t CO2‑e per gigajoule of liquefied natural gas.

Division 9—Ethane

33 Ethane

(1) Gigajoules of ethane that:

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

(b) are in a gaseous state; and

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

(e) are not produced in carrying on the petroleum refining activity in section 97 of this Schedule; and

(f) are 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.

(4) The default emissions intensity is 0.00767 t CO2‑e per gigajoule of ethane.

(5) The best practice emissions intensity is 0.00321 t CO2‑e per gigajoule of ethane.

Division 10—Liquefied petroleum gas

34 Liquefied petroleum gas

(1) Gigajoules of liquefied petroleum gas that:

(a) are in a liquid state; and

(b) are produced as part of carrying on the liquefied petroleum gas production activity at the facility; and

(d) are not produced in carrying on the petroleum refining activity in section 97 of this Schedule; and

(e) are of saleable quality.

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

(a) conducts the activity of liquefied petroleum gas production through the separation of propane and butane fractions from a mixture of hydrocarbons to produce liquefied petroleum gas that is in a liquid state (the liquefied petroleum gas production activity); and

(b) includes another activity covered by this Part.

(4) The default emissions intensity is 0.00180 t CO2‑e per gigajoule of liquefied petroleum gas.

(5) The best practice emissions intensity is 0.000420 t CO2‑e per gigajoule of liquefied petroleum gas.

Division 11—Reservoir carbon dioxide

35 Reservoir carbon dioxide from existing gas fields

(1) Tonnes of reservoir carbon dioxide that:

(a) were separated in an acid gas removal unit from natural gas, crude oil mixtures or products produced from extracted hydrocarbons that are not covered extracted hydrocarbons as part of one of the following activities:

(i) the oil and gas extraction activity;

(ii) the integrated crude oil extraction and stabilisation activity;

(iii) the natural gas processing activity;

(iv) the integrated natural gas extraction and processing activity;

(v) the processed natural gas liquefaction activity;

(vi) the unprocessed natural gas liquefaction activity; and

(b) when separated, consist of a mixture that is overwhelmingly carbon dioxide (CO2) and may contain incidental associated substances derived from the source material and capture and separation processes; and

(d) were not imported as a carbon dioxide stream from another facility.

(2) The metric in subsection (1) is applicable to a facility that separates reservoir carbon dioxide from natural gas, crude oil mixtures or products produced from extracted hydrocarbons as part of one of the following activities:

(a) the oil and gas extraction activity;

(b) the integrated crude oil extraction and stabilisation activity;

(d) the integrated natural gas extraction and processing activity;

(e) the processed natural gas liquefaction activity;

(f) the unprocessed natural gas liquefaction activity.

(3) The default emissions intensity is 0.928 t CO2‑e per tonne of reservoir carbon dioxide.

(4) The best practice emissions intensity is 0.0200 t CO2‑e per tonne of reservoir carbon dioxide.

35A Reservoir carbon dioxide from new gas fields

(1) Tonnes of reservoir carbon dioxide that:

(a) were separated in an acid gas removal unit from natural gas, crude oil mixtures or products produced from covered extracted hydrocarbons as part of one of the following activities:

(i) the oil and gas extraction activity;

(ii) the integrated crude oil extraction and stabilisation activity;

(iii) the natural gas processing activity;

(iv) the integrated natural gas extraction and processing activity;

(v) the processed natural gas liquefaction activity;

(vi) the unprocessed natural gas liquefaction activity; and

(d) were not imported as a carbon dioxide stream from another facility.

(a) the oil and gas extraction activity;

(b) the integrated crude oil extraction and stabilisation activity;

(d) the integrated natural gas extraction and processing activity;

(e) the processed natural gas liquefaction activity;

(f) the unprocessed natural gas liquefaction activity.

Covered extracted hydrocarbons

(3) Extracted hydrocarbons are covered extracted hydrocarbons if they:

(a) originate from a field (other than a field that is covered by subsection (4)) in respect of which the commercial extraction of hydrocarbons was not undertaken before 1 July 2023; and

(b) are used as an input in the unprocessed natural gas liquefaction activity or the processed natural gas liquefaction activity (whether or not they are processed at a natural gas processing facility to produce pipeline gas beforehand); and

(4) A field is covered by this subsection if, before 1 July 2023, the field, or part of the field, was included in an area in which the commercial extraction of hydrocarbons was occurring in accordance with a licence (however described) granted under a law of the Commonwealth, a State or a Territory.

Emissions intensities

(5) The default emissions intensity is zero t CO2‑e per tonnes of reservoir carbon dioxide.

(6) The best practice emissions intensity is zero t CO2‑e per tonnes of reservoir carbon dioxide.

Part 20—Production variables related to steel manufacturing

Division 1—Definitions

36 Definitions

(1) In this Part, the activity of manufacture of carbon steel from cold ferrous feed is the physical and chemical transformation of cold ferrous feed (such as ferrous scrap, hot briquetted iron, pig iron and flat iron) by heating and melting into liquid steel and the subsequent casting of the liquid steel:

(a) to produce 1 or more of the following:

(i) continuously cast carbon steel products;

(ii) ingots of carbon steel;

(iii) hot‑rolled carbon steel products, which commenced hot rolling at a temperature above 800 °C; and

(b) where the carbon steel products or ingots are not produced as part of carrying on the primary steel manufacturing activity at the facility.

Example: The use of an electric arc furnace to produce carbon steel from cold ferrous feed.

(2) In this Part, the activity of hot‑rolled long products is the hot‑rolling of continuously cast carbon steel products (originally produced from a primary steel manufacturing activity or manufacture of carbon steel from cold ferrous feed activity) into carbon steel long products that:

(a) are in coils or straight lengths; and

(b) are generally produced in rod, bar and structural (section) mills; and

(c) generally have a cross sectional shape such as I, T, Y, U, V, H, C, L, square, rectangular, round, flat, hexagonal, angle, channel, structural beam profile or rail profile.

(3) In this Part, the activity of hot‑rolled flat products is the hot‑rolling of continuously cast carbon steel products (originally produced from a primary steel manufacturing activity or manufacture of carbon steel from cold ferrous feed activity) into carbon steel flat products that:

(a) are flat in profile, such as plate and hot‑rolled coil; and

(b) are generally produced in hot strip mills and plate mills; and

(d) are generally less than 150 mm in thickness.

(4) In this Part:

carbon steel means material that:

(a) contains by mass more iron (Fe) than any other single element; and

(b) has a carbon (C) concentration less than 2%.

coke oven coke means the solid product obtained from the carbonisation of coal (principally coking coal) or other materials at a high temperature and includes coke breeze and foundry coke.

Division 2—Coke oven coke

37 Coke oven coke

(1) Tonnes of coke oven coke on a dry weight basis that:

(a) are produced as part of the coke oven coke manufacturing activity at the facility; and

(b) are of saleable quality; and

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of carbonisation of coal (principally coking coal) through the coke oven coke manufacturing process.

(3) The activity in subsection (2) is the coke oven coke manufacturing activity.

(4) The default emissions intensity is 0.465 t CO2‑e per tonne of coke oven coke.

Division 3—Lime manufacturing

38 Lime (steel manufacturing)

(1) Tonnes of lime on a dry weight basis that:

(a) are produced as part of the lime manufacturing activity at the facility;

(b) are of saleable quality; and

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

(a) either:

(i) the primary iron production activity; or

(ii) the primary steel manufacturing activity; and

(b) the physical and chemical transformation of either or both limestone or dolomite into lime (including burnt lime, burnt dolomite, or both).

(3) The activity in subsection (2) is the lime manufacturing activity.

(4) The default emissions intensity is 0.785 t CO2‑e per tonne of lime.

Division 4—Primary iron

39 Primary iron

(1) Subject to subsection (4), tonnes of metallic iron products, excluding any gangue, that:

(a) are produced as part of carrying on the primary iron production activity at the facility; and

(b) are exported from the facility; and

Example: The facility produces 100,000 tonnes of metallic iron products that meet the requirements of this subsection. 10% of the metallic iron products consists of gangue, in the form of non‑ferrous impurities such as silica (SiO2) and aluminium oxide (Al2O3), corresponding to 10,000 tonnes of gangue in total. No coke oven coke is used in the production process, so subsection (4) does not apply. As such, the metric is 90,000 tonnes.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of the physical and chemical processing of iron feed material into a crude iron product suitable for export from the facility.

Examples: Pig iron, hot briquetted iron, direct reduced iron and cast iron are each a crude iron product that may be suitable for export from a facility.

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

Example: The production of crude iron products from iron ore pellets using direct reduction.

(4) For subsection (1), if the amount of coke oven coke imported into the facility to produce the metallic iron products is equal to or greater than 5% of the total amount of coke oven coke consumed in carrying on the primary iron production activity, then tonnes of metallic iron products are given by the following equation:

metallic iron products = Qp + (1 – 0.108 c) Qi

where:

Qp is the quantity of metallic iron products, in tonnes, that meet the requirements of subsection (1) and are not produced using coke oven coke imported into the facility.

c is:

(a) if the facility is using a production process that uses coke oven coke and requires less than 0.4 tonnes of coke oven coke to produce a tonne of metallic iron products for the majority of its iron production—the number of tonnes of coke oven coke required to produce a tonne of metallic iron products for the facility, divided by 0.468; or

(b) otherwise—1.

Qi is the quantity of metallic iron products, in tonnes, that meet the requirements of subsection (1) and are produced using coke oven coke imported into the facility.

Note 1: Qp may or may not have been produced with coke oven coke.

Note 2: Qp and Qi do not need to be directly measured; they can be calculated from the consumed ratio of coke oven coke imported into the facility to coke oven coke used to produce metallic iron products that meet the requirements in subsection (1), multiplied by the quantity of iron produced using coke oven coke.

Example: Assume that a facility produces 10,000 tonnes of metallic iron products that are exported from the facility and are of saleable quality, using coke oven coke, as part of carrying on the primary iron production activity at the facility. Assume that all the metallic iron products are 2% gangue and that 10% of the metallic iron products are made using imported coke. Assume the facility requires 0.4 or more tonnes of coke oven coke to produce a tonne of metallic iron products for the majority of its iron production.

Because the metallic iron products are 2% gangue, the facility therefore produces 9,800 tonnes of metallic iron products that meet the requirements of subsection (1) and, as such, Qp = 90% × 9,800 = 8,820; and Qi = 10% × 9,800 = 980. The metric, in tonnes, is therefore equal to 8,820 + (1 – 0.108) × 980, or 9,694.16.

(5) The default emissions intensity is 2.08 t CO2‑e per tonne of metallic iron products.

(6) The best practice emissions intensity is 1.77 t CO2‑e per tonne of metallic iron products.

Division 4A—Primary iron (steelmaking)

39A Primary iron (steelmaking)

(1) This section applies for the purposes of sections 14A and 19A.

(2) Subject to subsection (5), tonnes of metallic iron products, excluding any gangue, that are produced as part of carrying on the primary iron (steelmaking) production activity at the facility.

(3) The metric in subsection (2) is applicable to a facility that conducts the activity of the physical and chemical processing of iron containing feeds into a crude iron product suitable for use by the facility for manufacturing primary steel.

(4) The activity in subsection (3) is the primary iron (steelmaking) production activity.

(5) For subsection (2), if the amount of coke oven coke imported into the facility to produce the metallic iron products is equal to or greater than 5% of the total amount of coke oven coke consumed in carrying on the primary iron (steelmaking) production activity, then tonnes of metallic iron products are given by the following equation:

metallic iron products = Qp + 0.892 Qi

where:

Qp is the quantity of metallic iron products, in tonnes, that meet the requirements of subsection (2) and are not produced using coke oven coke imported into the facility.

Qi is the quantity of metallic iron products, in tonnes, that meet the requirements of subsection (2) and are produced using coke oven coke imported into the facility.

Note 1: Qp may or may not have been produced with coke oven coke.

Note 2: Qp and Qi do not need to be directly measured; they can be calculated from the consumed ratio of coke oven coke imported into the facility to coke oven coke used to produce metallic iron products that meet the requirements in subsection (2), multiplied by the quantity of iron produced using coke oven coke.

Example 1: The facility produces 100,000 tonnes of metallic iron products that meet the requirements in subsection (2), all of which are produced using coke oven coke. The metallic iron products do not include any gangue. The facility uses 7,000 tonnes of imported coke oven coke and 63,000 tonnes of coke oven coke produced at the facility to make the metallic iron products, so that 70,000 tonnes of coke oven coke is used to make the metallic iron products in total. As such, the amount of coke oven coke imported into the facility to produce the metallic iron products is 10% of the total amount of coke oven coke, so this subsection applies. The amount of coke oven coke produced by the facility is 90% of the total amount of coke oven coke consumed in carrying on the primary iron (steelmaking) production activity.

Qp and Qi are calculated by multiplying these proportions by the total amount of metallic iron products produced using coke oven coke. As such, Qp = 90% × 100,000 = 90,000; and Qi = 10% × 100,000 = 10,000. The metric, in tonnes, is therefore equal to 90,000 + 0.892 × 10,000, or 98,920.

Example 2: Assume that a facility produces 100,000 tonnes of metallic iron products that meet the requirements in subsection (2), using coke oven coke. Assume that 10% of the metallic iron products are made using imported coke oven coke (like Example 1). Assume that the metallic iron products are 2% gangue.

The facility therefore produces 98,000 tonnes of metallic iron products that meet the requirements of subsection (2) and, as such, Qp = 90% × 98,000 = 88,200; and Qi = 10% × 98,000 = 9,800. The metric, in tonnes, is therefore equal to 88,200 + 0.892 × 9,800, or 96,941.6.

Division 5—Iron ore pellets

40 Iron ore pellets

(1) Tonnes of iron ore pellets on a dry weight basis that:

(a) are produced as part of the iron ore pellets manufacturing activity at the facility; and

(b) are exported from the facility; and

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of manufacturing iron ore pellets.

(3) The activity in subsection (2) is the iron ore pellets manufacturing activity.

(4) The default emissions intensity is 0.0526 t CO2‑e per tonne of iron ore pellets.

(5) The best practice emissions intensity is 0.0501 t CO2‑e per tonne of iron ore pellets.

Division 6—Continuously cast carbon steel products and ingots of carbon steel from primary steel manufacturing

41 Primary Steel

(1) Subject to subsections (4) and (5), tonnes of continuously cast carbon steel products and ingots of carbon steel that:

(a) are produced as part of carrying on the primary steel manufacturing 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 continuously cast carbon steel products and ingots of carbon steel through the physical and chemical transformation of iron feed material (which may include, but is not solely comprised of, cold ferrous feed) into crude carbon steel products and hot-rolled carbon steel products.

(3) The activity in subsection (2) is the primary steel manufacturing activity.

Examples: Smelting iron ore in a blast furnace to make pig iron, and then making carbon steel from the pig iron and added scrap metal using a basic oxygen furnace.

Making direct reduced iron from iron ore using direct reduction, and then making carbon steel from the iron using an electric arc furnace.

Note: Cold ferrous feed, such as scrap metal, can be used as a co-input in the primary steel manufacturing activity. Steel produced on a production line where cold ferrous feed is the only iron feed material does not meet the definition of the primary steel manufacturing activity, and therefore section 44 is applicable.

(4) For subsection (1), if the amount of coke oven coke imported into the facility to produce the continuously cast carbon steel products and ingots of carbon steel is equal to or greater than 5% of the total amount of coke oven coke consumed in carrying on the primary steel manufacturing activity, then tonnes of continuously cast carbon steel products and ingots of carbon steel are given by the following equation:

Tonnes of continuously cast carbon steel products and ingots of carbon steel = Qp + (1 – 0.1 c) Qi

where:

Qp is the quantity of continuously cast carbon steel products and ingots of carbon steel that meet the requirements of subsection (1) and are not produced using coke oven coke imported into the facility.

c is:

(a) if the facility is using a production process that uses coke oven coke and requires less than 0.4 tonnes of coke oven coke to produce a tonne of continuously cast carbon steel products and ingots of carbon steel for the majority of its steel production—the number of tonnes of coke oven coke required to produce a tonne of continuously cast carbon steel products and ingots of carbon steel for the facility, divided by 0.446; or

(b) otherwise—1.

Qi is the quantity of continuously cast carbon steel products and ingots of carbon steel that meet the requirements of subsection (1) and are produced using coke oven coke imported into the facility.

Note 1: Qp may or may not have been produced with coke oven coke.

Note 2: Qp and Qi do not need to be directly measured; they can be calculated from the consumed ratio of coke oven coke imported into the facility to coke oven coke used to produce continuously cast carbon steel products and ingots of carbon steel that meet the requirements in subsection (1), multiplied by the quantity of steel produced using coke oven coke.

Example: A facility produces 100,000 tonnes of continuously cast carbon steel products and ingots of carbon steel that meet the requirements in subsection (1). 50,000 tonnes of products were produced using an electric arc furnace process that does not use coke oven coke, 45,000 tonnes were produced using coke oven coke produced at the facility, and 5,000 tonnes were produced using coke oven coke imported to the facility. Assume the facility requires 0.4 or more tonnes of coke oven coke to produce a tonne of continuously cast carbon steel products and ingots of carbon steel for the majority of its steel production. The amount of coke oven coke imported into the facility to produce the continuously cast carbon steel products and ingots of carbon steel is 10% of the total amount of coke oven coke consumed in carrying on the primary steel manufacturing activity. The metric is equal to 95,000 + (1 – 0.1) × 5,000, or 99,500 tonnes.

(5) For subsection (1), if more than 35% (by mass) of the total iron ore feed and cold ferrous feed that is used as an input to the primary steel manufacturing activity is comprised of cold ferrous feed, then the tonnes of continuously cast carbon steel products and ingots of carbon steel are given by the following equation:

Tonnes of continuously cast carbon steel products and ingots of carbon steel = (100% – CFFadj%) × Q

where:

CFFadj% is the percentage (by mass) of the total iron ore feed and cold ferrous feed used as an input to the primary steel manufacturing activity that is comprised of cold ferrous feed, minus 35%.

Q is tonnes of continuously cast carbon steel products and ingots of carbon steel that meet the requirements of subsection (1), taking into account any adjustments resulting from subsection (4).

Example: A facility produces steel from 60,000 tonnes of iron ore feed and 40,000 tonnes of cold ferrous feed. From this feed, 90,000 tonnes of steel are produced. Therefore, 40% of the total feed to steelmaking comes from cold ferrous feed (i.e. 40,000 / (40,000 + 60,000)), meaning that the adjustment in subsection (5) is required. CFFadj% is equal to 5% (i.e. 40% - 35%), and it follows that 95% (i.e. 100% ‑ 5%) of the steel manufactured by the facility meets the metric in subsection (1), assuming no adjustment was required by subsection (4), the metric is 95% x 90,000 = 85,500 tonnes.

Note 1: If, as a result of subsection (5), there is any steel produced at the facility that is not counted towards the metric in subsection (1), such as 4,500 tonnes in the example above, this steel meets the metric in subsection 44(3).

(6) In subsection (5), cold ferrous feed does not include cold ferrous feed produced by the facility.

(7) The default emissions intensity is 2.07 t CO2‑e per tonne of continuously cast carbon steel products and ingots of carbon steel.

Division 7—Hot‑rolled long products produced at primary steel manufacturing facilities

42 Hot‑rolled long products produced at primary steel manufacturing facilities

(1) Tonnes of hot‑rolled carbon steel long products that:

(a) are produced as part of carrying on the hot‑rolled long products activity at the facility; and

(b) are in coils or straight lengths; and

(d) generally have a cross sectional shape such as I, T, Y, U, V, H, C, L, square, rectangular, round, flat, hexagonal, angle, channel, structural beam profile or rail profile; and

(e) are of saleable quality.

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

(a) conducts the hot‑rolled long products activity; and

(b) manufactures the hot‑rolled carbon steel long products from continuously cast carbon steel products produced as part of carrying on the primary steel manufacturing activity at the facility.

(3) The default emissions intensity is 0.101 t CO2‑e per tonne of hot‑rolled carbon steel long products.

Division 8—Hot‑rolled flat products produced at primary steel manufacturing facilities

43 Hot‑rolled flat products produced at primary steel manufacturing facilities

(1) Tonnes of hot‑rolled carbon steel flat products that:

(a) are produced as part of carrying on the hot‑rolled carbon steel flat products activity at the facility; and

(b) are flat in profile, such as plate and hot‑rolled coil; and

(d) are generally greater than 600 mm in width; and

(e) are generally less than 150 mm in thickness; and

(f) are of saleable quality.

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

(a) conducts the hot‑rolled flat products activity; and

(b) manufactures the hot‑rolled carbon steel flat products from continuously cast carbon steel products produced as part of carrying on the primary steel manufacturing activity at the facility.

(3) The default emissions intensity is 0.000358 t CO2‑e per tonne of hot‑rolled carbon steel flat products.

Division 9—Continuously cast carbon steel products and ingots of carbon steel from manufacture of carbon steel from cold ferrous feed

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

(1) Subject to subsection (3), tonnes of continuously cast carbon steel products and ingots of carbon steel that:

(a) are produced as part of carrying on:

(i) the manufacture of carbon steel from cold ferrous feed activity at the facility; or

(ii) if subsection 41(5) applies to the facility – the primary steel manufacturing activity at the facility; and

(b) are of saleable quality.

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

(a) conducts the activity of the manufacture of carbon steel from cold ferrous feed; or

(b) if subsection 41(5) applies to the facility – conducts the primary steel manufacturing activity.

(3) For subsection (1), if subsection 41(5) applies to the facility, then tonnes of continuously cast carbon steel products and ingots of carbon steel are given by the following equation:

Qa + (Qb – Qc)

where:

Qa is tonnes of continuously cast carbon steel products and ingots of carbon steel that are produced as part of carrying on the manufacture of carbon steel from cold ferrous feed activity at the facility.

Qb is tonnes of continuously cast carbon steel products and ingots of carbon steel that meet the requirements of subsection 41(1), taking into account any adjustments resulting from subsection 41(4) (but not taking into account any adjustments resulting from subsection 41(5)).

Qc is tonnes of continuously cast carbon steel products and ingots of carbon steel calculated in accordance with subsection 41(5).

Example: In the example for subsection 41(5), a facility manufactured 90,000 tonnes of continuously cast carbon steel products and ingots of carbon steel from iron ore feed and cold ferrous feed. Given cold ferrous feed in this example exceeded 35% of total feed, 85,500 tonnes are considered produced from the primary steel manufacturing activity. Therefore, the remaining 4,500 tonnes of continuously cast carbon steel products and ingots of carbon steel is considered to meet the metric in subsection (1).

(4) The default emissions intensity is 0.0981 t CO2‑e per tonne of continuously cast carbon steel products and ingots of carbon steel.

Division 9A—ferrous feed (steelmaking)

44A Ferrous feed (steelmaking)

(1) This section applies for the purposes of sections 14A and 19A.

(2) Tonnes of continuously cast carbon steel products and ingots of carbon steel that:

(a) are produced as part of carrying on the primary steel manufacturing activity at the facility; and

(b) are of saleable quality.

(3) The metric in subsection (2) is applicable to a facility that conducts the activity of the physical and chemical transformation of ferrous feed (such as ferrous scrap, hot briquetted iron, molten pig iron and flat iron) into liquid carbon steel and the subsequent casting of the liquid carbon steel to produce continuously cast carbon steel products and ingots of carbon steel.

Note: The ferrous feed used to produce the carbon steel products or ingots may or may not be cold ferrous feed.

(4) The activity in subsection (3) is the activity of manufacture of carbon steel from ferrous feed (steelmaking) production activity.

Division 10—Hot‑rolled long products (cold ferrous feed)

45 Hot‑rolled long products (cold ferrous feed)

(1) Tonnes of hot‑rolled carbon steel long products that:

(a) are produced as part of carrying on the hot‑rolled long products activity at the facility; and

(b) are in coils or straight lengths; and

(d) generally have a cross sectional shape such as I, T, Y, U, V, H, C, L, square, rectangular, round, flat, hexagonal, angle, channel, structural beam profile or rail profile; and

(e) are of saleable quality.

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

(a) conducts the hot‑rolled long products activity; and

(b) either:

(i) manufactures the hot‑rolled carbon steel long products from continuously cast carbon steel products produced as part of carrying on the manufacture of carbon steel from cold ferrous feed at the facility; or

(ii) is a stand‑alone hot‑rolling mill.

(3) The default emissions intensity is 0.0750 t CO2‑e per tonne of hot‑rolled carbon steel long products.

Division 11—Hot‑rolled flat products (cold ferrous feed)

46 Hot‑rolled flat products (cold ferrous feed)

(1) Tonnes of hot‑rolled carbon steel flat products that:

(a) are produced as part of carrying on the hot‑rolled carbon steel flat products activity at the facility; and

(b) are flat in profile, such as plate and hot‑rolled coil; and

(d) are generally greater than 600 mm in width; and

(e) are generally less than 150 mm in thickness; and

(f) are of saleable quality.

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

(a) conducts the hot‑rolled flat products activity; and

(b) either:

(i) manufactures the hot‑rolled carbon steel flat products from continuously cast carbon steel products produced as part of carrying on the manufacture of carbon steel from cold ferrous feed at the facility; or

(ii) is a stand‑alone hot‑rolling mill.

Note: The default emissions intensity for this production variable is yet to be calculated and specified in the Schedule.

Division 13—Treated steel flat products

47A Treated steel flat products

(1) Tonnes of treated steel flat products that:

(a) are produced as part of carrying on the treated steel flat products activity at the facility; and

(b) are flat in profile, such as plate and coil; and

(d) have involved the pickling and cold‑rolling of hot‑rolled steel coil; and

(e) have been treated with one or a combination of the following processes:

(i) annealing;

(ii) metal coating;

(iii) painting; and

(f) are of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of transforming hot‑rolled steel coil, using a combination of physical or chemical processes, into treated steel flat products that:

(a) are flat in profile, such as plate and coil; and

(b) have involved the pickling and cold‑rolling of hot‑rolled steel coil; and

(i) annealing;

(ii) metal coating;

(iii) painting.

(3) The activity in subsection (2) is the treated steel flat products activity.

(4) The default emissions intensity is 0.144 t CO2‑e per tonne of treated steel flat products.

Part 21—Production variables related to rail transport

Division 1—Definitions

48 Definitions

(1) In this Part, the activity of rail transport is the use of technology to power rolling stock to transport passengers or freight on a rail system.

(2) In this Part:

bulk freight includes goods that consist of large quantities of homogenous product that is generally non‑containerised and conveyed in wagons, such as iron ore, coal and grain.

dedicated line includes:

(a) a line that only services the rail transport needs of a single business enterprise or corporate group; and

(b) a vertically integrated rail system:

(i) where the rail infrastructure manager and the user of the rail system is under common control or part of a common corporate group; and

(ii) that wholly or predominantly serves the rail transport needs of a single business enterprise or corporate group.

freight includes a saleable good.

net‑tonne‑kilometre means the unit of measure representing the movement over a distance of one kilometre of one tonne of freight. The weight of the rolling stock (such as tractive vehicle and rail car) is excluded.

passenger‑kilometre means the unit of measure representing the movement over a distance of one kilometre of one passenger.

Division 2—Rail transport of bulk freight on a dedicated line

49 Net‑tonne‑kilometres of bulk freight on a dedicated line

(1) Net‑tonne‑kilometres of bulk freight that:

(a) result from carrying on the rail transport activity at the facility; and

(b) is transported by rail:

(i) only using a dedicated line; or

(ii) using a dedicated line for over 70% of the journey.

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

(a) conducts the activity of rail transport; and

(b) transports bulk freight by rail wholly or partly on one or more dedicated lines; and

(3) The default emissions intensity is 5.29 × 10‑6 t CO2‑e per net‑tonne‑kilometre of bulk freight.

(4) The net‑tonne‑kilometres must be measured consistently with relevant industry practice.

Division 3—Rail transport of bulk freight on a non‑dedicated line

50 Net‑tonne‑kilometres of bulk freight on a non‑dedicated line

(1) Net‑tonne‑kilometres of bulk freight that:

(a) result from carrying on the rail transport activity at the facility; and

(b) is transported by rail; and

(i) does not use a dedicated line; or

(ii) uses a dedicated line for 70% or less of the journey.

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

(a) conducts the activity of rail transport; and

(b) transports bulk freight by rail wholly or partly on one or more non‑dedicated lines; and

(3) The default emissions intensity is 1.63 × 10‑5 t CO2‑e per net‑tonne‑kilometre of bulk freight.

(4) The net‑tonne‑kilometres must be measured consistently with relevant industry practice.

Division 4—Rail transport of non‑bulk freight

51 Net‑tonne‑kilometres of non‑bulk freight

(1) Net‑tonne‑kilometres of freight that:

(a) result from carrying on the rail transport activity at the facility; and

(b) is transported by rail; and

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

(a) conducts the activity of rail transport; and

(b) transports freight that is not bulk freight; and

(3) The default emissions intensity is 2.05 × 10‑5 t CO2‑e per net‑tonne‑kilometre of freight.

(4) The net‑tonne‑kilometres must be measured consistently with relevant industry practice.

Division 5—Rail passenger transport

52 Passenger‑kilometres of rail passenger transport

(1) Passenger‑kilometres that result from carrying on the rail transport activity at the facility.

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

(a) conducts the activity of rail transport; and

(b) transports passengers; and

(3) The default emissions intensity is 7.12 × 10‑5 t CO2‑e per passenger‑kilometre.

(4) The passenger‑kilometres must be measured consistently with relevant industry practice.

Part 22—Air transport

53 Revenue‑tonne‑kilometres of air transport

(1) Revenue‑tonne‑kilometres of air transport that:

(a) result from carrying on the air transport activity at the facility; and

(b) relate to the covered emissions of the facility.

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

(a) transports passengers and freight by air (the air transport activity); and

(b) is in the air and space transport ANZSIC industry classification and code 490.

(3) The default emissions intensity is 0.00112 t CO2‑e per revenue‑tonne‑kilometre.

(4) In this section:

freight‑tonne‑kilometre means the unit of measure representing the movement of a tonne of freight over the distance of one kilometre calculated by multiplying the total tonnes of freight on a flight by the distance flown.

passenger‑tonne‑kilometre means the unit of measure representing the movement of a revenue‑generating passenger over the distance of one kilometre calculated by assuming each passenger and baggage on a flight total 90 kilograms and multiplying by the distance flown.

revenue‑tonne‑kilometre means the sum of passenger‑tonne‑kilometres and freight‑tonne‑kilometres.

Part 23—Production variables related to road transport

Division 1AA—Definitions

53A Definitions

In this Part:

bulk freight is the transport of goods that:

(a) consist of one or more of:

(i) large quantities of a homogenous product; and

(ii) product in shipping containers; and

(iii) uniform types of packaged goods such as bags, pallets and drums; and

(b) are conveyed in road tankers (including ISO tankers), side tipping vehicles, skeletal and flat top trailers, and other road registered vehicles used for carrying bulk materials; and

cubic tonne is the volume of the freight item (generally height × width × depth) multiplied by a cubic conversion factor (for nominal or actual density) to derive an equivalent net weight.

cubic‑tonne‑kilometre means the unit of measure representing the movement over a distance of one kilometre of one cubic tonne of freight.

deadweight tonne is a tonne of the carrying capacity of the vehicle including fuel, driver and passengers, provisions and freight, but not including the weight of the prime mover and trailer.

deadweight‑tonne‑kilometre means the unit of measure representing the movement of a deadweight tonne over a distance of one kilometre.

freight includes a saleable good or transported service (such as crane hire) transported in a road‑registered vehicle.

net‑tonne‑kilometre means the unit of measure representing the movement over a distance of one kilometre of one net tonne of freight.

net tonne, of freight, is the mass of the freighted goods, excluding the mass of the prime mover, trailer, fuel, driver, passengers and provisions.

non‑bulk freight is the transport of packaged and pallet loads of freight, that is not bulk freight or specialised and heavy haulage, in vehicles with carrying capacity greater than 4.5 tonnes.

non‑bulk (temperature‑controlled) freight is the transport of non‑bulk freight in temperature controlled conditions, such as by refrigeration, in vehicles with carrying capacity greater than 4.5 tonnes where the power for the temperature control equipment is derived from the drive train.

specialised and heavy haulage is the transportation of either or both of specialised equipment and loads in excess of 200 tonnes on road‑registered vehicles that is not bulk freight.

specialised equipment includes:

(a) platform low loaders and trailing equipment capable of carrying loads in excess of 200 tonnes; and

(b) crane and rigging services and lift and shift operations; and

(d) equipment for port discharge; and

(e) machines for sleeper transport and positioning; and

(f) equipment and machinery used for transferring freight between the road transport vehicle and another form of transport (such as rail or shipping); and

(g) other similar equipment.

Division 1—Passenger road transport

54 Vehicle‑kilometres of passenger road transport

(1) Vehicle‑kilometres of passenger road transport that result from carrying on the road passenger transport activity at the facility.

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

(a) transports passengers by road in registered vehicles (the road passenger transport activity); and

(b) is in the passenger road transport ANZSIC industry classification and code 462.

(3) The default emissions intensity is 0.00164 t CO2‑e per vehicle‑kilometre.

(4) In this section:

vehicle‑kilometre means the unit of measure representing the movement of a vehicle over the distance of one kilometre.

Division 2—Non‑bulk freight road transport

54A Cubic‑tonne‑kilometres of non‑bulk freight

(1) Cubic‑tonne‑kilometres of non‑bulk freight that:

(a) result from carrying on the non‑bulk freight road transport activity at the facility; and

(b) are not counted for another production variable in this Part.

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

(a) transports non‑bulk freight by road in registered vehicles that do not control the temperature of the freight (the non‑bulk freight road transport activity); and

(b) is in the road freight transport ANZSIC industry classification and code 461.

(3) The default emissions intensity is 0.000094 t CO2‑e per cubic‑tonne‑kilometre of non‑bulk freight.

(4) The cubic‑tonne‑kilometres must be measured consistently with relevant industry practice.

Division 3—Non‑bulk (temperature controlled) freight road transport

54B Cubic‑tonne‑kilometres of non‑bulk freight

(1) Cubic‑tonne‑kilometres of non‑bulk (temperature controlled) freight that:

(a) result from carrying on the non‑bulk (temperature controlled) freight road transport activity at the facility; and

(b) are not counted for another production variable in this Part.

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

(a) transports non‑bulk (temperature controlled) freight by road in registered vehicles that control the temperature of the freight (the non‑bulk (temperature controlled) freight road transport activity); and

(b) is in the road freight transport ANZSIC industry classification and code 461.

(3) The default emissions intensity is 0.000110 t CO2‑e per cubic‑tonne‑kilometre of non‑bulk (temperature controlled) freight.

(4) The cubic‑tonne‑kilometres must be measured consistently with relevant industry practice.

Division 4—Specialised and heavy haulage road transport

54C Deadweight‑tonne‑kilometres of specialised and heavy haulage

(1) Deadweight‑tonne‑kilometres of specialised and heavy haulage that:

(a) result from carrying on the specialised and heavy haulage road transport activity at the facility; and

(b) are not counted for another production variable in this Part.

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

(a) transports specialised and heavy haulage by road in registered vehicles (the specialised and heavy haulage road transport activity); and

(b) is in the road freight transport ANZSIC industry classification and code 461.

(3) The default emissions intensity is 0.000044 t CO2‑e per deadweight‑tonne‑kilometre of specialised and heavy haulage.

(4) The deadweight‑tonne‑kilometres must be measured consistently with relevant industry practice.

Division 5—Bulk freight road transport

54D Net‑tonne‑kilometres of bulk freight

(1) Net‑tonne‑kilometres of bulk freight that:

(a) result from carrying on the bulk freight road transport activity at the facility; and

(b) are not counted for another production variable in this Part.

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

(a) transports bulk freight by road in registered vehicles (the bulk freight transport activity); and

(b) is in the road freight transport ANZSIC industry classification and code 461.

(3) The net‑tonne‑kilometres must be measured consistently with relevant industry practice.

(4) The default emissions intensity is 0.000078 t CO2‑e per net‑tonne‑kilometre of bulk freight.

(5) The best practice emissions intensity is 0.0000395 t CO2‑e per net‑tonne‑kilometre of bulk freight.

Part 24—Production variables related to water transport

Division 1—Mixed passenger and freight water transport

55 Deadweight‑tonne‑kilometres of mixed passenger and freight water transport

(1) Deadweight‑tonne‑kilometres of water transport that:

(a) result from carrying on the mixed passenger and freight water transport activity at the facility; and

(b) relate to the covered emissions of the facility.

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

(a) transports passengers and freight by water (the mixed passenger and freight water transport activity); and

(b) is in the water freight transport or water passenger transport ANZSIC industry classification and codes 481 or 482.

(3) The default emissions intensity is 1.04 × 10‑4 t CO2‑e per operational deadweight‑tonne‑kilometre.

(4) The relevant kilometres must be measured:

(a) using the actual distance travelled and recorded on a ship for a voyage; or

(b) by using an internationally accepted standard distance between the two ports on a voyage

(5) In this section:

operational deadweight tonne is a tonne of the cargo, passengers, fuel, dry provisions, supplies and other things carried on board a ship for a voyage, but not including the ship itself.

deadweight‑tonne‑kilometre means the unit of measure representing the movement of an operational deadweight tonne over the distance of one kilometre.

Division 2—Bulk freight water transport

55A Net‑tonne‑kilometres of bulk freight water transport

(1) Net‑tonne‑kilometres of bulk freight water transport that:

(a) result from carrying on the bulk freight water transport activity at the facility; and

(b) relate to the covered emissions of the facility; and

(c) are not counted for the mixed passenger and freight water transport production variable in section 55 of this Schedule.

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

(a) transports bulk freight by water (the bulk freight water transport activity); and

(b) is in the water freight transport ANZSIC industry classification and code 481.

(3) The default emissions intensity is 5.39 × 10‑6 t CO2‑e per net tonne‑kilometre.

(4) The relevant kilometres must be measured:

(a) using the actual distance travelled and recorded on a ship for a voyage; or

(b) by using an internationally accepted standard distance between the two ports on a voyage.

(5) In this section:

net‑tonne‑kilometres, of bulk freight water transport, are the tonnes of the bulk freight carried on board a ship for a voyage multiplied by the kilometres of the laden voyage.

Part 25—Wastewater handling (domestic and commercial)

56 COD removed from wastewater (domestic and commercial)

(1) Tonnes of COD removed, calculated in accordance with subsection (4).

(2) The metric in subsection (1) is applicable to a facility whose primary activity is the handling of either or both of domestic or commercial wastewater and which reports emissions under Division 5.3 of the NGER (Measurement) Determination.

(3) The default emissions intensity is 0.513 t CO2‑e per tonne of COD removed.

(4) For paragraph (1), COD removed is given by the following equation:

COD removed = CODmeasured entering – (CODin effluent leaving site + CODin sludge leaving site)

where:

CODmeasured entering is the COD entering the site measured consistently with the requirements in Division 5.3 of the NGER (Measurement) Determination.

CODin effluent leaving site is the COD leaving the site measured consistently with the requirements in Division 5.3 of the NGER (Measurement) Determination.

CODin sludge leaving site is COD in sludge leaving the site measured consistently with the requirements in Division 5.3 of the NGER (Measurement) Determination.

(5) In this section:

COD or chemical oxygen demand means the total material available for chemical oxidation (both biodegradable and non‑biodegradable) measured in tonnes.

56A Nitrogen removed from wastewater (domestic and commercial)

(1) Tonnes of nitrogen removed, calculated in accordance with subsection (4).

(3) The default emissions intensity is 4.48 t CO2‑e per tonne of nitrogen removed.

(4) For paragraph (1), nitrogen removed is given by the following equation:

nitrogen removed = Nmeasured entering – (Nin effluent leaving site + Nin sludge leaving site)

where:

Nmeasured entering is the nitrogen entering the site measured consistently with the requirements in Division 5.3 of the NGER (Measurement) Determination.

Nin effluent leaving site is the nitrogen leaving the site measured consistently with the requirements in Division 5.3 of the NGER (Measurement) Determination.

Nin sludge leaving site is the nitrogen in sludge leaving the site measured consistently with the requirements in Division 5.3 of the NGER (Measurement) Determination.

Part 26—Electricity generation

57 Electricity generation

(1) Megawatt hours of electricity that:

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

(b) if electricity generation is the only production variable applicable to the facility—are exported from the facility; and

(i) are not used by the vehicle’s propulsion system; or

(ii) are not both generated by a vehicle’s propulsion system and used by or on the vehicle for purposes unrelated to propulsion.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of electricity generation (the electricity generation activity).

(3) The default emissions intensity is 0.539 t CO2‑e:

(a) if paragraph (1)(b) does not apply—per megawatt hour of electricity generated; and

(b) if paragraph (1)(b) applies—per megawatt hour of electricity exported from the facility.

(4) The megawatt hours of electricity under subsections (1) and (3) must:

(a) if a meter is available to measure the electricity—be metered; and

(b) if a meter is not available to measure the electricity—be calculated in a verifiable way in accordance with industry practice; and

(c) if some or all of the electricity is exported to a designated electricity network—be measured consistently with the requirements applicable to the designated electricity network; and

(d) if paragraph (b) applies and the electricity is exported to a designated electricity network—be measured in accordance with the requirements for the export of electricity into the designated electricity network.

(5) The best practice emissions intensity is 0.236 t CO2‑e:

(a) if paragraph (1)(b) does not apply—per megawatt hour of electricity generated; and

(b) if paragraph (1)(b) applies—per megawatt hour of electricity exported from the facility.

Part 27—Natural gas distribution

58 Petajoule‑kilometres of natural gas distribution

(1) Petajoule‑kilometres of natural gas:

(a) delivered to customers as part of carrying on the natural gas distribution activity at the facility; and

(b) that is not lost or consumed as part of carrying on the natural gas distribution activity; and

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of transporting natural gas through natural gas distribution pipelines to customers (the natural gas distribution activity) and reports emissions under Division 3.3.8 of the NGER (Measurement) Determination.

(3) The default emissions intensity is 0.196 t CO2‑e per petajoule‑kilometre.

(4) The energy content of natural gas:

(a) must be measured as the higher heating value energy content; and

(b) may include the energy content of hydrogen included in the natural gas so long as the natural gas mixture meets applicable standards for gas within the network (such as Australian Standard 4564:2020).

Note: In 2020, AS 4564 was available from http://www.standards.org.au.

(5) In this section:

natural gas has the meaning given by the NGER Regulations.

natural gas distribution pipelines mean pipelines for the conveyance of natural gas that report emissions under Division 3.3.8 of the NGER (Measurement) Determination.

petajoule‑kilometre means the multiplication of:

(a) the total energy content, in petajoules, of natural gas delivered to customers by means of a natural gas distribution pipelines which are part of the facility; and

(b) the total length, in kilometres, of the natural gas distribution pipelines used to deliver natural gas to customers as part of the facility as at the end of the relevant financial year.

Note: Natural gas distribution pipelines not used in the delivery of natural gas to customers are not included in these kilometres.

Part 28—Natural gas transmission

Division 1—Definitions

59 Definitions

(1) In this Part:

natural gas has the meaning given by the NGER Regulations.

natural gas transmission pipeline means a pipeline for the conveyance of natural gas or plant condensate that reports emissions under Division 3.3.7 of the NGER (Measurement) Determination.

(2) In this Part the activity of natural gas transmission is the transport of natural gas or plant condensate through natural gas transmission pipelines to customers or distribution networks.

Note: Customers could include large industrial facilities, liquefied natural gas stations or natural gas processing stations.

Division 2—Natural gas transmission production variables

60 Kilometres of natural gas transmission pipelines

(1) Kilometres of natural gas transmission pipelines used to deliver natural gas or plant condensate to customers or distribution networks as part of carrying on the natural gas transmission activity at the facility.

(2) The metric in subsection (1) is applicable to a facility that conducts the natural gas transmission activity and reports emissions under Division 3.3.7 of the NGER (Measurement) Determination.

(3) The default emissions intensity is 11.62 t CO2‑e per kilometre.

(4) The kilometres of the natural gas transmission pipelines must not be greater than the kilometres of pipelines reported under section 3.76 of the NGER (Measurement) Determination for the same financial year.

61 Natural gas throughput

(1) Gigajoules of natural gas that are received by the facility as part of carrying on the natural gas transmission activity at the facility.

(2) The metric in subsection (1) is applicable to a facility that conducts the natural gas transmission activity and reports emissions under Division 3.3.7 of the NGER (Measurement) Determination.

(3) The default emissions intensity is 0.000518 t CO2‑e per gigajoule of natural gas.

Part 29—Clinker, lime and cement production

Division 1—Definitions

62 Definitions

(1) In this Part:

cement means any hydraulic cement, including general purpose and blended cements, meeting the minimum requirements for such cements set out in AS 3972—2010 or any other specific contract and export specifications.

Note: In 2020, AS 3972—2010 was available from http://www.standards.org.au.

Portland cement clinker means the Portland cement clinker resulting from clinker production which:

(a) has a concentration of calcium silicates equal to or greater than 60% by mass; and

(b) has a concentration of magnesium oxide (MgO) equal to or less than 4.5% by mass; and

supplementary cementitious material means any mineral additive to cement which meets the minimum requirements for such additives set out in any of Australian Standards AS 3582.1:2016, AS 3582.2:2016, AS 3582.3:2016 or AS 3582.4:2022, or any other specific contract and export specifications.

Note: In 2023, each of the Australian Standards was available from http://www.standards.org.au.

(2) In this Part the activity of clinker production is the physical and chemical transformation of:

(a) either or both of calcium carbonate compounds (limestone (CaCO3)) and other calcium carbonate (CaCO3) feedstocks; and

(b) any of the following:

(i) clay;

(ii) clay mixed with 1 or more feedstocks that contain 1 or more of the following:

(A) silicon dioxide (SiO2);

(B) iron (Fe);

(iii) 1 or more feedstocks that, when combined, contain all of the following:

(A) silicon dioxide (SiO2);

(B) iron (Fe);

that are fused together at a temperature above 1000 °C into Portland cement clinker.

Division 2—Clinker and cement production variables

63 Clinker not used by facility to make cement

(1) Tonnes of Portland cement clinker on a dry weight basis that:

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

(b) is exported from the facility or allocated for export from the facility (whether the export will occur within or after the reporting year); and

(d) is of saleable quality.

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

(a) conducts the clinker production activity at the facility; and

(b) if the metric in section 64 of this Schedule is applicable to the facility—also uses that production variable.

(3) The default emissions intensity is 0.841 t CO2‑e per tonne of Portland cement clinker.

64 Cement produced from clinker and supplementary cementitious material

(1) Combined:

(a) tonnes of cement on a dry weight basis that is:

(i) produced as part of carrying on the cement production activity at the facility; and

(ii) attributable to Portland cement clinker produced as part of carrying on the clinker production activity at the facility in accordance with subsection (5); and

(iii) of saleable quality; and

(b) tonnes of supplementary cementitious material (other than supplementary cementitious material added as part of carrying on the cement production activity at the facility) that is:

(i) supplied by a related entity; and

(ii) added to any amount of cement covered by paragraph (a).

(2) In this section, related entity means any of the following:

(a) the responsible emitter for the facility;

(b) an entity within the same corporate group as the responsible emitter;

(i) for which the chief executive officer is also the chief executive officer of the responsible emitter; and

(ii) which has substantially the same operating, health and safety, and environmental policies as the responsible emitter.

(d) a joint venture entity of which the responsible emitter or a member of the responsible emitter’s corporate group has at least 50% ownership.

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

(a) conducts the clinker production activity at the facility; and

(b) conducts the activity of producing cement through the physical transformation of Portland cement clinker into cement through a process of comminution or blending with gypsum or other additives (the cement production activity); and

(4) The default emissions intensity is 0.708 t CO2‑e per tonne of cement and supplementary cementitious material.

(5) For paragraph (1)(a), cement is attributable to Portland cement clinker produced as part of carrying on the clinker production activity at the facility in accordance with the following equation:

where:

Cea is the cement attributable to Portland cement clinker produced as part of carrying on the clinker production activity at the facility, in tonnes.

Cef is the total amount of cement produced at the facility (f) in the reporting year, in tonnes, that is of saleable quality.

Clf is the amount of Portland cement clinker, in tonnes, produced as part of carrying on the clinker production activity at the facility (f) in the reporting year and used, or intended to be used, to produce cement at the facility, not including any tonnes of Portland cement clinker counted for the metric in section 63 of this Schedule.

Cli is the amount of Portland cement clinker, in tonnes, not covered by Clf and imported in the reporting year to produce cement at the facility (whether or not the Portland cement clinker was produced in or outside of Australia).

(6) For paragraph 4.23C(2)(b) of the NGER Regulations, the following information must be included in a report under the Act in calculating the amount of the production variable for a reporting year:

(a) the total amount of Portland cement clinker produced at a facility in the reporting year (whether or not it is used, exported from the facility or stockpiled);

(b) the value of each variable in the equation in subsection (5);

(c) the total amount of supplementary cementitious material in a reporting year which satisfies paragraph 64(1)(b) of this Schedule;

(d) evidence demonstrating the amount in paragraph (c) was added to cement covered by paragraph 64(1)(a) of this Schedule;

(e) if the supplementary cementitious material was provided by an entity other than the responsible emitter for the facility, evidence to show the entity was a related entity.

Division 3—Lime

65 Lime

(1) Tonnes of lime on a dry weight basis that:

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

(b) has a concentration of either or both of calcium oxide (CaO) and magnesium oxide (MgO) equal to or greater than 60% by mass; and

(d) is of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing lime through the physical and chemical transformation, through the calcining process, of calcium and magnesium sources (such as calcium carbonate (CaCO3) and magnesium carbonate (MgCO3)) into lime that has a concentration of either or both of calcium oxide (CaO) and magnesium oxide (MgO) equal to or greater than 60% by mass (the lime production activity).

(3) The default emissions intensity is 1.13 t CO2‑e per tonne of lime.

Part 30—Non‑metallic mineral quarrying

66 Quarried rock

(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

(i) of saleable quality at the mine; or

(ii) 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 production variable mentioned in Parts 13 to 18 of this Schedule.

(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 non‑metallic 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.

(4) The default emissions intensity is 0.00292 t CO2‑e per tonne of quarried rock.

(5) The best practice emissions intensity is 0.00237 t CO2‑e per tonne of quarried rock.

Part 31—Silicon

67 Silicon

(1) Tonnes of silicon (Si) that:

(a) has a concentration of silicon equal to or greater than 98% by mass; and

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

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing silicon through the chemical transformation of silica (silicon dioxide (SiO2)) to produce silicon with a concentration of silicon equal to or greater than 98% by mass, conducted in accordance with the overall chemical equation:

SiO2(s) + 2C(s) → Si(s) + 2CO(g)

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

(4) The default emissions intensity is 1.92 t CO2‑e per tonne of silicon.

Part 32—Lead bullion

68 Lead bullion

(1) Tonnes of lead bullion that:

(a) has a concentration of lead (pb) equal to or greater than 99% by mass; and

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

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing lead bullion through the chemical transformation of concentrated mineralised lead compounds, with or without additional lead bearing secondary materials, into lead bullion (the lead bullion production activity).

(3) The default emissions intensity is 0.955 t CO2‑e per tonne of lead bullion.

Part 33—Refined lead

69 Refined lead

(1) Tonnes of refined lead that:

(a) have a concentration of lead (Pb) equal to or greater than 99.97% by mass; and

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

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing refined lead through the chemical transformation of concentrated mineralised lead compounds, with or without additional lead bearing secondary materials, into refined lead (the refined lead production activity).

Note: 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.

(3) The default emissions intensity is 2.79 t CO2‑e per tonne of refined lead.

Part 34—Zinc in fume

70 Zinc in fume

(1) Tonnes of zinc in fume that:

(a) has a concentration of zinc (Zn) equal to or greater than 60% by mass; and

(b) is produced as part of carrying on the zinc in fume production activity at the facility; and

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing zinc in fume through the chemical transformation in a slag fumer of zinc‑containing residues and wastes to produce zinc in fume (the zinc in fume production activity).

(3) The default emissions intensity is 3.82 t CO2‑e per tonne of zinc in fume.

Part 35—Caustic calcined magnesia

71 Caustic calcined magnesia

(1) Tonnes of caustic calcined magnesia that:

(a) has a minimum magnesium oxide (MgO) content of 75% by mass; and

(b) is burned between 650°C and 1200°C; and

(d) is of saleable quality.

Note: Due to the definition of saleable quality, inputs that are transformed into saleable magnesia which is then re‑calcined are only counted once.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing caustic calcined magnesia through the physical and chemical transformation of magnesite (magnesium carbonate (MgCO3)) in a furnace into caustic calcined magnesia (the magnesia production activity).

Note: Caustic calcined magnesia may also be transformed into deadburned magnesia and electrofused magnesia at the facility, which involves burning or fusing at higher temperatures than in paragraph (1)(b).

(3) The default emissions intensity is 1.51 t CO2‑e per tonne of caustic calcined magnesia.

Part 36—Copper anode

72 Copper anode

(1) Tonnes of copper anode that:

(a) has a concentration of copper (Cu) between 99% and 99.9% by mass on an annual average basis; and

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

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing copper anode through the physical and chemical transformation of copper sulphide concentrates in a smelter, with or without secondary inputs such as copper scrap, to produce copper anodes (the copper anode production activity).

Note: Copper anode is often an input into the production of copper cathode at the same facility.

(3) The default emissions intensity is 0.677 t CO2‑e per tonne of copper anode.

(4) The best practice emissions intensity is 0.455 t CO2‑e per tonne of copper anode.

Part 37—Manganese sinter

73 Manganese sinter

(1) Tonnes of manganese sinter that:

(a) has a minimum concentration of manganese (Mn) of 40% by mass; and

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

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing manganese sinter through the physical and chemical transformation of small particles of manganese ore by sintering into manganese sinter (the manganese sinter production activity).

Note: Manganese sinter is often an input into an electric arc furnace.

(3) The default emissions intensity is 0.242 t CO2‑e per tonne of manganese sinter.

Part 38—Ferromanganese alloy

74 Ferromanganese alloy

(1) Tonnes of ferromanganese alloy that:

(a) has a minimum concentration of manganese (Mn) of 67% by mass; and

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

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing ferromanganese through the physical and chemical transformation of manganese ore or sinter into ferromanganese alloy (the ferromanganese production activity).

(3) The default emissions intensity is 1.30 t CO2‑e per tonne of ferromanganese alloy.

Part 39—Silicomanganese alloy

75 Silicomanganese alloy

(1) Tonnes of silicomanganese alloy that:

(a) has a minimum concentration of manganese (Mn) of 60% by mass; and

(b) has a minimum concentration of silicon (Si) of 12% by mass; and

(d) is of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing silicomanganese through the physical and chemical transformation of one or more of manganese ore, manganese sinter and ferromanganese slag produced at the facility into silicomanganese alloy (the silicomanganese production activity).

(3) The default emissions intensity is 1.70 t CO2‑e per tonne of silicomanganese alloy.

Part 40—Nickel manufacturing

Division 1—Definitions

76 Definitions

(1) In this Part:

intermediate nickel products means any of the following:

(a) nickel matte;

(b) mixed nickel‑cobalt hydroxide precipitate that has a concentration of nickel between 20% and 47% (inclusive) by mass;

(d) basic nickel carbonate (Ni3(CO3)(OH)4) that has a concentration of nickel between 40% and 45% (inclusive) by mass;

(e) crude nickel sulphate that has a concentration of nickel equal to or greater than 21% by mass.

imported intermediate nickel products, for a facility, means an intermediate nickel product not produced at the facility.

nickel bearing inputs means any of the following:

(a) mineralised nickel ores (including laterite or sulphide ores);

(b) nickel sulphide concentrates;

(d) low grade nickel waste products that require equivalent processing to mineralised nickel ores.

primary nickel products means any of the following:

(a) basic nickel carbonate (Ni3(CO3)(OH)4) that has a concentration of nickel equal to or greater than 50% by mass;

(b) nickel oxide (NiO) that has a concentration of nickel equal to or greater than 78% by mass;

(d) other nickel products that have a concentration of nickel equal to or greater than 98% by mass.

(2) In this Part the activity of nickel manufacturing is the physical and chemical transformation of either or both of:

(a) nickel bearing inputs into intermediate nickel products or primary nickel products; and

(b) intermediate nickel products into primary nickel products.

Division 2—Nickel production variables

77 Primary nickel products from nickel bearing inputs

(1) Tonnes of 100% equivalent nickel that:

(a) is contained within primary nickel products that:

(i) are produced from nickel bearing inputs as part of carrying on the nickel manufacturing activity at the facility; and

(ii) are of saleable quality; and

(b) has not been counted in relation to the intermediate nickel product production variable at the facility.

(2) The metric in subsection (1) is applicable to a facility that conducts the nickel manufacturing activity

(3) The default emissions intensity is 8.78 t CO2‑e per tonne of 100% equivalent nickel.

(4) The best practice emissions intensity is 3.78 t CO2‑e per tonne of 100% equivalent nickel.

78 Primary nickel products from imported intermediate nickel products

(1) Tonnes of 100% equivalent nickel contained within primary nickel products that:

(a) are produced from imported intermediate nickel products as part of carrying on the nickel manufacturing activity at the facility; and

(b) are of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the nickel manufacturing activity.

(3) The default emissions intensity is 2.52 t CO2‑e per tonne of 100% equivalent nickel.

(4) The best practice emissions intensity is 2.29 t CO2‑e per tonne of 100% equivalent nickel.

79 Intermediate nickel products from nickel bearing inputs

(1) Tonnes of 100% equivalent nickel contained within intermediate nickel products that:

(a) are produced from nickel bearing inputs as part of carrying on the nickel manufacturing activity at the facility; and

(b) are not, and are not intended to be, transformed into primary nickel products at the facility; and

(2) The metric in subsection (1) is applicable to a facility that conducts the nickel manufacturing activity.

(3) The default emissions intensity is 1.76 t CO2‑e per tonne of 100% equivalent nickel.

(4) The best practice emissions intensity is 1.48 t CO2‑e per tonne of 100% equivalent nickel.

Part 41—Pulp and paper production

Division 1—Definitions

80 Definitions

In this Part:

newsprint manufacturing activity—see section 84.

packaging and industrial paper manufacturing activity—see section 82.

printing and writing paper manufacturing activity—see section 83.

pulp production activity—see section 85.

tissue paper manufacturing activity—see section 81.

Division 2—Tissue paper

81 Tissue paper

(1) Tonnes of rolls of uncoated tissue paper that:

(a) has a grammage range of 13 g/m2 to 75 g/m2; and

(b) has a moisture content in the range of 4% to 11% by mass; and

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

(e) is produced as part of carrying on the tissue paper manufacturing activity at the facility; and

(f) is of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing rolls of uncoated tissue paper through the physical or chemical transformation of pulp into rolls of uncoated tissue paper that:

(a) has a grammage range of 13 g/m2 to 75 g/m2; and

(b) has a moisture content in the range of 4% to 11% by mass; and

(d) is of saleable quality.

(3) The activity in subsection (2) is the tissue paper manufacturing activity.

(4) The default emissions intensity is 0.448 t CO2‑e per tonne of rolls of uncoated tissue paper.

Division 3—Packaging and industrial paper

82 Packaging and industrial paper

(1) Tonnes of rolls of packaging and industrial paper that:

(a) is produced from wholly or partially unbleached input fibre; and

(b) has a grammage range of 30 g/m2 to 500 g/m2; and

(d) is uncoated; and

(e) is generally useable as a packaging or industrial paper, including products such as kraft liner, recycled or multiply liner, medium, sack and bag paper, wrapping paper, plasterboard liner, horticultural paper and building paper; and

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

(g) is produced as part of carrying on the packaging and industrial paper manufacturing activity at the facility; and

(h) is of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing rolls of packaging and industrial paper through physical or chemical transformation of pulp into packaging and industrial paper that:

(a) is produced from wholly or partially unbleached input fibre; and

(b) has a grammage range of 30 g/m2 to 500 g/m2; and

(d) is uncoated; and

(f) is of saleable quality.

(3) The activity in subsection (2) is the packaging and industrial paper manufacturing activity.

(4) The default emissions intensity is 0.166 t CO2‑e per tonne of rolls of packaging and industrial paper.

Division 4—Printing and writing paper

83 Printing and writing paper

(1) Tonnes of rolls of coated or uncoated printing and writing paper that:

(a) is produced from 100% bleached or brightened input fibre; and

(b) has a grammage range of 42 g/m2 to 350 g/m2; and

(d) is generally useable as a printing and writing paper product, including products such as offset paper, copy paper, laser printing paper, magazine paper, filing card paper, manilla, book printing paper, envelope paper, forms paper, scholastic paper, cheque paper and security paper; and

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

(f) is produced as part of carrying on the printing and writing paper manufacturing activity at the facility; and

(g) is of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing rolls of coated or uncoated printing and writing paper through physical or chemical transformation of pulp into rolls of coated or uncoated printing and writing paper that:

(a) is produced from 100% bleached or brightened input fibre; and

(b) has a grammage range of 42 g/m2 to 350 g/m2; and

(e) is of saleable quality.

(3) The activity in subsection (2) is the printing and writing paper manufacturing activity.

(4) The default emissions intensity is 0.443 t CO2‑e per tonne of rolls of coated or uncoated printing and writing paper.

Division 5—Newsprint

84 Newsprint

(1) Tonnes of rolls of coated or uncoated newsprint that:

(a) has a grammage range of 30 g/m2 to 80 g/m2; and

(b) has a moisture content range of 4% to 11% by mass; and

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

(e) is produced as part of carrying on the newsprint manufacturing activity at the facility.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing rolls of coated or uncoated newsprint through the chemical and physical transformation, using an integrated process, of any or all of woodchips, sawdust, wood pulp and recovered paper into rolls of coated or uncoated newsprint that:

(a) has a grammage range of 30 g/m2 to 80 g/m2; and

(b) has a moisture content range of 4% to 11% by mass; and

(3) The activity in subsection (2) is the newsprint manufacturing activity.

(4) The default emissions intensity is 0.706 t CO2‑e per tonne of rolls of coated or uncoated newsprint.

Division 6—Pulp

85 Pulp

(1) Tonnes of wet or dry pulp that:

(a) is generally useable in one or more of:

(i) paper manufacturing;

(ii) packaging and cardboard manufacturing;

(iii) newsprint manufacturing;

(iv) tissue paper manufacturing;

(v) the production of sanitary products (such as a fluff pulp layer in sanitary products); and

(b) is measured according to ordinary measurement rules applicable in the industry; and

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

(e) is not used in the newsprint manufacturing activity at the same facility.

Note: The quantity of pulp is generally converted to an air dried basis by adjusting the relevant tonnes to their mass with a moisture content of 10% (without drying the relevant wet pulp product).

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing pulp through the physical or chemical transformation of any or all of wood chips, sawdust, wood pulp and recovered paper into wet or dry pulp that is generally usable in one or more of the following:

(a) paper manufacturing;

(b) packaging and cardboard manufacturing;

(d) tissue paper manufacturing;

(e) the production of sanitary products (such as a fluff pulp layer in sanitary products).

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

(4) The default emissions intensity is 0.0501 t CO2‑e per tonne wet or dry pulp.

Part 42—Ethylene and polyethylene production

86 Ethene (ethylene)

(1) Tonnes of 100% equivalent ethene (ethylene (C2H4)) that is contained within ethene that:

(a) has a concentration of ethene equal to or greater than 99% by mass; and

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

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing ethene (ethylene (C2H4)) through the chemical transformation of hydrocarbons to produce ethene that has a concentration of ethene equal to or greater than 99% by mass (the ethene production activity).

(3) The default emissions intensity is 1.79 t CO2‑e per tonne of 100% equivalent ethene.

87 Polyethylene

(1) Tonnes of pelletised polyethylene that:

(a) has a standard density equal to or greater than 0.910 g/cm3; and

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

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing polyethylene through the chemical transformation ethene (ethylene (C2H4)) to produce polyethylene with a standard density equal to or greater than 0.910 g/cm3 (the polyethylene production activity).

(3) The default emissions intensity is 0.125 t CO2‑e per tonne of pelletised polyethylene.

(4) In this section:

standard density, for polyethylene, means the density of polyethylene moulded to a thickness of 1.9 mm using Procedure C of Annex A1 to ASTM D4703‑16 (2016).

Note: In 2021, the standard could be accessed from http://www.astm.org.

87A Exported steam related to the ethene production activity

(1) Gigajoules of steam that:

(a) are generated at the facility by heating water; and

(b) are transferred or exported to another facility:

(i) as part of a commercial arrangement requiring the transfer of steam to the other facility; and

(ii) for use at the other facility.

(2) The metric in subsection (1) is applicable to a facility that conducts the ethene production activity.

(3) The gigajoules of steam in subsection (1) must be:

(a) measured consistently with the NGER (Measurement) Determination, including the principles in section 1.13 and reporting requirements under the NGER Regulations; and

(b) calculated as total steam exported for a reporting period; and

Note: The amount of gigajoules of a mass of steam at a particular temperature and pressure can be calculated by multiplying the specific steam enthalpy corresponding to that temperature and pressure by the mass of that steam.

(4) The default emissions intensity is 0.0879 t CO2‑e per gigajoule of steam.

(5) In this section:

ethene production activity has the same meaning as in subsection 86(2).

Part 43—Wheat based products

88 Wheat protein products (dried gluten)

(1) Tonnes of the following products produced as part of carrying on the wheat protein products production activity at the facility that meet the requirements of subsection (2):

(a) vital wheat gluten;

(b) devitalised wheat gluten;

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

(a) do not have a moisture content that exceeds 10% (as a gravimetric water content); and

(b) for vital and devitalised wheat gluten, have at least 80% crude protein (on a dry solids basis, where nitrogen content is multiplied by 6.25); and

(c) for solubilised wheat proteins, have at least 60% crude protein (on a dry solids basis, where nitrogen content is multiplied by 6.25); and

(d) exclude added vitamins, minerals, amino acids and optional ingredients on a dry weight basis; and

(e) are of saleable quality.

(3) The metric in subsection (1) is applicable to a facility that conducts the activity of producing wheat protein products by the physical and chemical transformation of wheat into one or more of the products listed in subsection (1) that meet the requirements in subsection (2).

(4) The activity in subsection (3) is the wheat protein products production activity.

(5) The default emissions intensity is 0.360 t CO2‑e per tonne of products covered by subsections (1) and (2).

89 Dried wheat starch

(1) Tonnes of the following products produced as part of carrying on the dried wheat starch production activity at the facility that meet the requirements of subsection (2):

(a) dried wheat starch;

(b) modified and resistant starches.

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

(a) have a moisture content of no more than 13% (as a gravimetric water content); and

(b) have a protein content of no more than 0.35% (on a dry solids basis, where nitrogen content is multiplied by 5.7); and

(c) for unmodified dried wheat starch covered by paragraph (1)(a), have a Brabender peak viscosity of no less than 500 Brabender units at 8% solids (on a dry solids basis) when measured in accordance with standard industry practices; and

(d) are of saleable quality.

(3) The metric in subsection (1) is applicable to a facility that conducts the activity of producing dried wheat starch through the removal of non‑starch fractions of the wheat flour by physical and chemical transformation of wheat into one of the products listed in subsection (1) that meet the requirements in subsection (2).

(4) The activity in subsection (3) is the dried wheat starch production activity.

(5) The default emissions intensity is 0.084 t CO2‑e per tonne of products covered by subsections (1) and (2).

90 Wheat based glucose

(1) Tonnes of the following products produced as part of carrying on the wheat based glucose production activity at the facility that meet the requirements of subsection (2):

(a) wheat based glucose syrup;

(b) maltodextrin.

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

(a) for wheat based glucose syrup, is produced from wheat to a total solids percentage of between 67% to 84%; and

(b) for wheat based glucose syrup, has a dextrose equivalent content of not less than 20% (expressed as D‑glucose on a dry weight basis); and

(i) may be dried to a moisture content that does not exceed 10% (as a gravimetric water content); and

(ii) has a dextrose equivalent content of between 10% and 20% (expressed as D‑glucose on a dry weight basis); and

(d) are of saleable quality.

(3) The metric in subsection (1) is applicable to a facility that conducts the activity of producing wheat based glucose through the physical and chemical transformation of wheat starch into one of the products listed in subsection (1) that meet the requirements in subsection (2).

(4) The activity in subsection (2) is the wheat based glucose production activity.

(5) The default emissions intensity is 0.371 t CO2‑e per tonne of products covered by subsections (1) and (2).

91 Wheat based dried distillers grain

(1) Tonnes of wheat based dried distillers grain that are produced as part of carrying on the wheat based dried distillers grain production activity at the facility to meet the following requirements:

(a) are a minimum of 88% dry matter on a dry solids basis; and

(b) are a minimum of 20% crude protein (on a dry solids basis, where nitrogen is multiplied by 6.25); and

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing wheat based dried distillers grain through the physical and chemical transformation of the non‑fermentable residues of wheat starch products from the production of ethanol, where the residues are dried under heat, into wheat based dried distillers grain.

(3) The activity in subsection (2) is the wheat based dried distillers grain production activity.

(4) The default emissions intensity is 0.374 t CO2‑e per tonne of wheat based dried distillers grain.

Part 44—Ethanol

92 Ethanol—95

(1) Kilolitres of ethanol produced as part of carrying on the ethanol—95 production activity at the facility that meet the requirements of subsection (2).

(2) The requirements for ethanol to be included in subsection (1) are the ethanol:

(a) is produced with a minimum 95% ethanol content by volume; and

(b) is not further processed into ethanol—absolute or beverage grade ethanol covered by sections 93 and 94 or otherwise included in those production variables; and

(3) The metric in subsection (1) is applicable to a facility that conducts the activity of producing ethanol through the physical and chemical transformation of feedstocks into ethanol that meet the requirements in subsection (2).

(4) The activity in subsection (3) is the ethanol—95 production activity.

(5) The default emissions intensity is 0.367 t CO2‑e per kilolitre of ethanol covered by subsections (1) and (2).

93 Ethanol—absolute

(1) Kilolitres of ethanol produced as part of carrying on the ethanol—absolute production activity at the facility that meet the requirements of subsection (2).

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

(a) is produced with a minimum 99% ethanol content by volume; and

(b) is not further processed into beverage grade ethanol covered by section 94 or otherwise included in the ethanol production variables under sections 92 or 94; and

(4) The activity in subsection (3) is the ethanol—absolute production activity.

(5) The default emissions intensity is 0.706 t CO2‑e per kilolitre of ethanol covered by subsections (1) and (2).

94 Beverage grade ethanol

(1) Kilolitres of ethanol produced as part of carrying on the beverage grade ethanol production activity at the facility that meet the requirements of subsection (2).

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

(a) would otherwise be eligible as ethanol—95 or ethanol—absolute, but is not included in the tonnes of those products under section 92 or 93; and

(b) has been processed to a higher degree of purity than ordinarily required for ethanol—95 or ethanol—absolute, to a standard for use in beverages and other forms of human consumption; and

(3) The metric in subsection (1) is applicable to a facility that produces beverage grade ethanol through the physical and chemical transformation of feedstocks into ethanol that meets the requirements in subsection (2).

(4) The activity in subsection (3) is the beverage grade ethanol production activity.

(5) The default emissions intensity is 1.070 t CO2‑e per kilolitre of ethanol covered by subsections (1) and (2).

Part 45—Production variables related to sugar production

95 Raw sugar

(1) Tonnes of raw sugar that:

(a) is produced as part of carrying on the raw sugar manufacturing activity at the facility; and

(b) is generally useable in sugar refining activities; and

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of manufacturing raw sugar through the physical or chemical transformation of sugar cane or other plant matter into raw sugar that:

(a) is generally useable in sugar refining activities; and

(b) is of saleable quality.

(3) The activity in subsection (2) is the raw sugar manufacturing activity.

(4) The default emissions intensity is 0.0311 t CO2‑e per tonne of raw sugar.

96 Exported steam related to the raw sugar manufacturing activity

(1) Gigajoules of steam that:

(a) is generated at a sugar mill by heating water; and

(b) is transferred or exported to another facility for use at that facility.

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

(a) conducts the raw sugar manufacturing activity; and

(b) is structured such that energy (including steam and with or without the export of electricity) is intended to be the only output from the facility for a portion of the year under ordinary operating conditions, such as a facility with a seasonal output which exports energy year‑round.

(3) The gigajoules of steam exported must be:

(a) measured consistently with the NGER (Measurement) Determination, including the principles in section 1.13 and reporting requirements under the NGER Regulations; and

(b) calculated as total steam exported for a reporting period; and

(4) The default emissions intensity is 0.0490 t CO2‑e per gigajoule of steam.

Part 46—Petroleum refining

97 Petroleum refinery feedstocks

(1) Kilolitres of the following substances that are used in carrying on the activity of petroleum refining at the facility in accordance with subsection (2):

(a) stabilised crude petroleum oil at 15 °C and 1 atmosphere; and

(b) condensate at 15 °C and 1 atmosphere; and

(d) liquid synthetic hydrocarbons at 15 °C and 1 atmosphere; and

(e) alcohol feedstocks at 15 °C and 1 atmosphere; and

(f) waste or recycled material that has undergone pyrolysis; and

(g) eligible petroleum feedstocks at 15 °C and 1 atmosphere; and

(h) bio‑crude or bio‑intermediates produced from thermochemical processes.

(2) A substance mentioned in paragraphs (1)(a) to (h) is used in carrying on the activity of petroleum refining if the substance is, or is to be, refined:

(a) by 1 or both of the processes mentioned in paragraphs (3)(a) and (b); and

(b) into either of the following:

(i) 1 or more petroleum products mentioned in paragraphs (3)(c) and (d);

(ii) other by‑products that result from carrying on the petroleum refining activity.

(3) The metric in subsection (1) is applicable to a facility that conducts the activity of petroleum refining through the chemical and physical transformation of stabilised crude petroleum oil, which may be supplemented with 1 or more of condensate, biogenic oils, liquid synthetic hydrocarbons, alcohol feedstocks, waste or recycled material that has undergone pyrolysis, eligible petroleum feedstocks or bio‑crude or bio‑intermediates produced from thermochemical processes, to produce a range of refined petroleum products through the following processes:

(a) the distillation of stabilised crude petroleum oil, condensate, tallow, vegetable oil and other petroleum feedstocks;

(b) the adjustment of the molecular weight and structure of hydrocarbons (such as that which occurs through catalytic or hydro‑cracking, steam or catalytic reforming, polymerisation, isomerisation or alkylation);

(c) the blending of products from distillation and adjustment of molecular weight and structure to produce Australian and international standard diesel, jet fuel and unleaded petrol;

(d) the production of 2 or more of the following refinery products saleable in Australian or international markets:

(i) hydrogen;

(ii) ethane;

(iii) propane;

(iv) refinery grade propylene;

(v) polymer grade propylene;

(vi) liquefied petroleum gas;

(vii) butane;

(viii) naphtha;

(ix) aviation gasoline;

(x) before oxygenate blend;

(xi) kerosene;

(xii) heating oil;

(xiii) solvents;

(xiv) lubricant base stocks;

(xv) leaded petrol;

(xvi) waxes;

(xvii) bitumen.

(4) However, the metric in subsection (1) is not applicable to a facility unless:

(a) each of the processes mentioned in paragraphs (3)(a) to (d) are conducted within the year at the facility; and

(b) the combined volume of diesel, jet fuel, unleaded petrol, lubricant base stocks and bitumen at 15 °C and 1 atmosphere produced from stabilised crude petroleum, condensate, biogenic oils, liquid synthetic hydrocarbons, alcohol feedstocks, waste or recycled material that has undergone pyrolysis, eligible petroleum feedstocks and bio‑crude or bio‑intermediates produced from thermochemical processes is equal to or greater than 75% of the total kilolitres of stabilised crude petroleum, condensate, biogenic oils, liquid synthetic hydrocarbons, alcohol feedstocks, waste or recycled material that has undergone pyrolysis, eligible petroleum feedstocks and bio‑crude or bio‑intermediates produced from thermochemical processes used in the year at the facility.

(5) The activity in subsection (3) is the petroleum refining activity.

(6) The default emissions intensity is:

(a) if the facility is, for the financial year, in compliance with all fuel quality standards requirements that apply to unleaded petrol refined by the facility—0.148 t CO2‑e per kilolitre of the substances mentioned in paragraphs (1)(a) to (1)(h);

(b) otherwise—0.138 t CO2‑e per kilolitre of the substances.

Note: A fuel quality standards requirement only applies to unleaded petrol refined by a facility if the requirement has come into force. Paragraph (b) applies if no fuel quality standards requirements apply to unleaded petrol refined by a facility.

(7) For subsection (6), a facility is taken to be in compliance with a fuel quality standards requirement for a financial year if:

(a) the facility complies with the requirement for the duration of the financial year; or

(b) the facility begins to comply with the requirement at any time during the financial year, and remains in compliance with the requirement for the remainder of the financial year.

(8) In this section:

condensate has the same meaning as in the Excise Act 1901.

eligible petroleum feedstocks means any 1 or more of the following that were not produced through the conduct of the petroleum refining activity carried on at another facility in Australia:

(a) catalytic cracker feedstocks that are processed in the catalytic cracker in carrying on the petroleum refining activity and have a density of 0.84 to 0.98 kg/L at 15 °C and 1 atmosphere;

(b) hydro‑cracker unit feedstocks that are processed in the hydro‑cracking unit in carrying on the petroleum refining activity and have a density of 0.84 to 0.98 kg/L at 15 °C and 1 atmosphere;

(c) reformer unit feedstocks that are used to produce reformate in carrying on the petroleum refining activity and have a density of 0.6 to 0.80 kg/L at 15 °C and 1 atmosphere;

(d) alkylation unit feedstocks that are used to produce alkylate in carrying on the petroleum refining activity and have a density of 0.55 to 0.62 kg/L at 15 °C and 1 atmosphere;

(e) bitumen feedstocks that are used to produce bitumen in carrying on the petroleum refining activity and have a density greater than or equal to 0.95 kg/L at 15 °C and 1 atmosphere;

(f) lubricant base stock feedstocks that are used to produce lubricant base stocks in carrying on the petroleum refining activity and have a density of 0.84 to 0.98 kg/L at 15 °C and 1 atmosphere.

fuel quality standards requirement: each of the following is a fuel quality standards requirement:

(a) if a determination made under section 21 of the Fuel Quality Standards Act 2000 specifies a requirement in relation to the maximum sulfur content of petrol refined from the substance of not more than 10mg/kg—that requirement;

(b) if a determination made under section 21 of the Fuel Quality Standards Act 2000 specifies a requirement in relation to the maximum level of aromatics in petrol refined from the substance that applies in relation to a day on or after 1 July 2025—that requirement.

stabilised crude petroleum oil has the meaning given in the Australian Taxation Office Interpretative Decision, ATO ID 2008/154, published on 18 November 2008.

Note: In 2023, the decision could be accessed from http://www.ato.gov.au.

unleaded petrol means all grades of unleaded petrol meeting Australian or international standards, including standard unleaded petrol, premium unleaded petrol and other proprietary forms of unleaded petrol.

Part 47—Lithium hydroxide

98 Lithium hydroxide

(1) Tonnes of lithium hydroxide monohydrate (LiOH.H2O) that:

(a) have a concentration of lithium hydroxide monohydrate equal to or greater than 98.9% by weight; and

(b) are produced as part of carrying on the lithium hydroxide refining production activity at the facility; and

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing lithium hydroxide monohydrate that has a concentration of lithium hydroxide monohydrate equal to or greater than 98.9% by weight (the lithium hydroxide refining production activity).

(3) The default emissions intensity is 3.26 t CO2-e per tonne of lithium hydroxide monohydrate.

(4) The best practice emissions intensity for the production variable is 3.15 t CO2-e per tonne of lithium hydroxide monohydrate.

Part 48—Hydrogen

99 Gaseous hydrogen

(1) Tonnes of gaseous hydrogen (H2(g)) that:

(a) are in a gaseous state; and

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

(d) are not consumed in carrying on the liquefied hydrogen production activity in section 100 of this Schedule; and

(e) have not been counted as part of the liquefied hydrogen production variable in section 100 of this Schedule.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing gaseous hydrogen through:

(a) the physical and chemical transformation of feedstocks that contain hydrogen to produce gaseous hydrogen; or

(b) the physical and chemical transformation of water (H2O) to gaseous hydrogen through electrolysis.

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

(4) The default emissions intensity is 9.01 t CO2‑e per tonne of gaseous hydrogen.

(5) The best practice emissions intensity is 7.13 t CO2‑e per tonne of gaseous hydrogen.

100 Liquefied hydrogen

(1) Tonnes of liquified hydrogen (H2(l)) that:

(a) are in a liquid state; and

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

(c) are produced using gaseous hydrogen that was produced by carrying on the gaseous hydrogen production activity at the facility; and

(d) are of saleable quality; and

(e) have been loaded onto a pipeline, transport vessel, tanker or other transportation system.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing liquified hydrogen through the physical transformation of gaseous hydrogen (H2(g)) into liquefied hydrogen that is in a liquid state on leaving the facility.

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

(4) The best practice emissions intensity is 7.13 t CO2‑e per tonne of liquefied hydrogen.

Part 49—Mine rehabilitation

101 Mine rehabilitation

(1) Total gigajoules of energy input that:

(a) are used for the purpose of mine rehabilitation; and

(b) have not been counted for another production variable at the facility.

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

(a) that undertakes mine rehabilitation within the facility by conducting any of the following activities (the rehabilitation activities):

(i) haulage of material;

(ii) shaping and contouring of landforms;

(iii) revegetation;

(iv) management of tailings and wastewater;

(v) associated activities such as dust suppression;

(b) where the rehabilitation activities:

(i) are in excess of those required for the mine’s normal operation; and

(ii) are not associated with on‑site electricity generation; and

(iii) do not fall within the scope of any other production variable in this Schedule.

Examples: Mine rehabilitation of an entire pit.

Mine rehabilitation ramping up as production drops towards mine closure.

Mine rehabilitation at the end of a mine’s life following cessation of production.

(3) The activity in subsection (2) is the mine rehabilitation activity.

(4) The default emissions intensity is 0.0702 t CO2‑e per gigajoule of energy input to the mine rehabilitation activity.

(5) The best practice emissions intensity for the production variable is 0.0702 t CO2‑e per gigajoule of energy input to mine rehabilitation activity.

(6) Without limitation, the quantity of the metric in subsection (1) may be evidenced by:

(a) third party contracts; or

(b) fuel purchase receipts; or

(d) evidence of an activity scheduled in an approved mining and rehabilitation plan relating to the mine rehabilitation activity.

Part 50—Biofuels

102 Definitions

In this Part:

biofuel has the same meaning as in the NGER Regulations.

biofuel feedstocks means non‑fossilised and biodegradable organic material originating from plants, animals or micro‑organisms, including:

(a) products, by‑products, residues and waste from industry (such as the agriculture and forestry industries); and

(b) non‑fossilised and biodegradable organic components of commercial, industrial, construction, demolition, and municipal waste.

Examples: Soybean oil, canola oil, technical corn oil, palm fatty acid distillate, pongamia pinnata, used cooking oil, tall oil, spent bleaching earth oil, brassica carinata, tallow, POME oil and empty fruit bunches.

biofuel production activity means the production of a biofuel through the physical and chemical transformation of biofuel feedstocks.

Examples: Gasification, Fischer‑Tropsch synthesis, hydrothermal conversions and hydroprocessing.

renewable aviation kerosene has the same meaning as in the NGER Regulations.

renewable diesel has the same meaning as in the NGER Regulations.

103 Renewable aviation kerosene

(1) Kilolitres of renewable aviation kerosene that:

(a) are produced through the biofuel production 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 renewable aviation kerosene through a biofuel production activity.

(3) The best practice emissions intensity is 0.717 t CO2‑e per kilolitre of renewable aviation kerosene.

104 Renewable diesel

(1) Kilolitres of renewable diesel that:

(a) are produced through the biofuel production 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 renewable diesel through a biofuel production activity.

(3) The best practice emissions intensity is 0.704 t CO2‑e per kilolitre of renewable diesel.

Part 51—Rare earth processing

105 Definitions

In this Part:

Primary rare earth elements means praseodymium (Pr), neodymium (Nd), terbium (Tb), and dysprosium (Dy).

Primary rare earth oxides means:

(a) oxides of primary rare earth elements; or

(b) mixtures of one or more primary rare earth elements and oxides of primary rare earth elements.

Separated primary rare earth products means semi-separated or individual primary rare earth compounds.

106 Rare earth processing

(1) Tonnes of total primary rare earth oxide equivalent contained in separated primary rare earth products that:

(a) have weight by weight primary rare earth oxide greater than 90%; and

(b) are suitable quality and concentration as an input to a metallisation process (including via electrolysis); and

(c) are produced as part of carrying on the separated primary rare earth products production activity at the facility; and

(d) are of saleable quality.

(2) The metric in subsection (1) is applicable to a facility that conducts the activity of producing separated primary rare earth products through the transformation of metal ore (the separated primary rare earth products production activity).

(3) The best practice emissions intensity is 20.1 t CO2‑e per tonne of total primary rare earth oxide.

Schedule