EXPLANATORY STATEMENT

Issued by authority of the Minister for Climate Change and Energy

National Greenhouse and Energy Reporting Act 2007

National Greenhouse and Energy Reporting (Measurement) Amendment (2026 Update) Determination 2026

Background

The National Greenhouse and Energy Reporting (NGER) scheme is Australia’s national system for reporting greenhouse gas emissions, energy consumption and energy production by Australian corporations.

The NGER scheme is a key data source which supports Australia’s international and domestic reporting obligations and informs domestic climate and energy policies. Emissions reported under the NGER scheme underpin the operation of the Safeguard Mechanism.

NGER scheme legislation includes the:

• National Greenhouse and Energy Reporting Act 2007 (the Act);
• National Greenhouse and Energy Reporting Regulations 2008; (the Regulations); and
• National Greenhouse and Energy Reporting (Measurement) Determination 2008 (the Measurement Determination).

Overview of the Measurement Determination

The Measurement Determination was made under section 10 of the Act, which provides for the Minister to determine methods, or criteria for methods, for the measurement of (a) greenhouse gas emissions; (b) the production of energy; and (c) the consumption of energy. It provides the technical detail of methods for the estimation of greenhouse gas emissions and for the production and consumption of energy within the NGER scheme.

Chapters 1 to 5 of the Measurement Determination provide methods for estimating ‘scope 1’ emissions, defined in Regulation 2.23 as the release of greenhouse gas into the atmosphere as a direct result of an activity or series of activities that constitute the facility. The structure of these Chapters reflects the framework of the 2006 Intergovernmental Panel on Climate Change (IPCC) Guidelines for National Greenhouse Gas Inventories, as adopted by the Parties to the United Nations Framework Convention on Climate Change (UNFCCC) and Paris Agreement, and includes emissions from:

• the combustion of fuel for energy;
• the extraction, production, flaring, processing and distribution of fossil fuels, and from carbon capture and storage;
• industrial processes where a mineral, chemical or metal product is formed using a chemical reaction that generates greenhouse gases as a by-product, as well as emissions of hydrofluorocarbons (HFCs) and sulphur hexafluoride (SF6) resulting from their use by certain industries; and
• waste disposal – either in landfill, biological treatment facilities, as management of wastewater or from waste incineration.

Section 1.10 of the Measurement Determination sets out the sources of scope 1 emissions which are reportable within the NGER scheme.

Chapter 6 of the Measurement Determination provides methods to estimate quantities of energy produced and consumed.

Chapter 7 of the Measurement Determination provides methods to estimate ‘scope 2’ emissions, defined in Regulation 2.24 as the release of greenhouse gas into the atmosphere as a direct result of one or more activities that generate electricity, heating, cooling or steam that is consumed by the facility but that do not form part of the facility.

Chapter 8 sets out rules for assessing the uncertainty associated with estimates of scope 1 emissions.

Schedule 1 sets out default energy content factors and emission factors applicable to fuels and energy commodities.

Schedule 2 sets out applicable standards and sampling frequency for determining technical parameters such as energy content and composition of solid fuels.

Schedule 3 sets out default carbon content factors for fuels, feedstocks, products and carbonates.

Schedule 4 sets out ‘matters to be identified’ (MTBI) which must be reported in relation to estimates of emissions made under the NGER scheme. These matters provide information relevant to the use of the estimation methods set out in the Measurement Determination, allowing for the conduct of assurance of emissions estimates and providing important data used in the preparation of Australia’s National Greenhouse Accounts.

The NGER scheme is regularly reviewed by the Department of Climate Change, Energy, the Environment and Water (the department) for opportunities to improve the accuracy of estimates while being cognisant of reporting burden.

Methods of measurement

The Measurement Determination provides a hierarchy of emissions estimation methods to accommodate the circumstances of individual reporters: 

• Method 1 typically specifies the use of default emission factors to estimate emissions based on those used in Australia’s National Greenhouse Gas Inventory;
• Method 2, where available, is a facility-specific method, for example using industry sampling and Australian or international standards to provide more accurate estimates of emissions at facility level; 
• Method 3, where available, is a higher-level facility-specific method, for instance using additional Australian or international standards for sampling and analysis, or more granular facility-specific data;
• Method 4, where available, provides for direct monitoring of emissions, either on a continuous or periodic basis.

The Measurement Determination draws on existing estimation practices wherever possible, including through the use of data collected for commercial, taxation or other regulatory purposes, with the aim of maximising the use of readily validated data and minimising administrative burdens on reporters.

Purpose and operation

The National Greenhouse and Energy Reporting (Measurement) Amendment (2026 Update) Determination 2026 (the Update Determination) is part of the continuous improvement of Australia’s national greenhouse gas inventory and the related methods used for estimating emissions. Each year the department reviews and updates the NGER scheme as part of this improvement process and in response to feedback from users and other stakeholders. Every five years the annual update is also informed by the Climate Change Authority’s review of the NGER scheme. The Authority’s last review of the NGER scheme was delivered in December 2023.

Further details of the Update Determination are outlined in Attachment A.

The Update Determination is a legislative instrument for the purposes of the Legislation Act 2003.

A statement of the Update Determination’s compatibility with human rights is set out in Attachment B.

The Measurement Determination is exempt from sunsetting under Legislation (Exemptions and Other Matters) Regulation 2015 section 12, item 42A. This exemption is justified because the legislative instrument implements international reporting obligations under the United Nations Framework Convention on Climate Change and Paris Agreement and is scientific and technical in application. There would be limited benefit in sunsetting of this instrument because it is required on an ongoing basis for relevant persons to calculate their emissions estimates and for Australia to comply with its international reporting obligations.

The Update Determination will commence simultaneously with accompanying amendments to the Regulations made by the National Greenhouse and Energy Reporting Amendment (2026 Measures No. 1) Regulations 2026 (the Update Regulations).

Consultation

An exposure draft of the Update Determination and accompanying consultation paper were released for public consultation from 9 April to 8 May 2026. 40 submissions were received. Taking into account feedback from consultation, the proposed amendments were modified in the following ways:

• Renewable fuels: An additional certification scheme was recognised under the new rules for reporting scope 1 emissions from co-processed liquid fuels. The additional scheme is the International Sustainability and Carbon Certification ISCC PLUS certification scheme. Sustainability declarations for co-processed liquid fuel issued under this scheme will be recognised as an eligible certificate type for the 2026-27 and 2027-28 reporting years if they meet the eligibility conditions in the new rules.

• Fugitive emissions from coal mines: The requirement for open-cut coal mines to use the current Australian Standard for gas desorption testing under Method 2 to support estimation of fugitive emissions from coal extraction was delayed until 1 July 2027. The delayed application of the standard AS3980:2016 provides time to resolve issues identified through the public consultation that could inadvertently lower emission estimates through misapplication of gas model development requirements relating to the low gas zone and carbonaceous strata. This work will be undertaken through the Method 2 review and also provides the opportunity to develop additional guidance on other aspects of the standard to improve its application to Method 2, ahead of 1 July 2027. The amendment will also clarify that gas data collected using AS3980-1999 prior to 1 July 2027 may continue to be used for Method 2 after 1 July 2027.
• Fugitive emissions from oil and gas:
  • Amendments were added to enable greater use of facility-specific measurement information in the application of Method 3 for the estimation of fugitive methane emission emissions (other than venting and flaring) from natural gas liquefaction, storage and transfer.
  • Amendments were added to make clear when methods for estimating fugitive emissions from oil and natural gas flaring activities should be applied.
  • Additional requirements for gas measurement devices used in landfill walkover or scanning surveys were added, including that they must be calibrated in accordance with manufacturers’ standards and need to be calibrated specifically to methane, rather than the broader category of hydrocarbons.
• Waste:
  • The approach for landfill walkover/scanning surveys was updated, replacing prescribed transect widths with specified spatial resolutions. Reporters must now achieve spatial resolutions of 16m2 for the representative zone and 4m2 in areas of elevated emissions.
  • The method for estimating fugitive emissions from landfill gas wells was refined. Key updates include:
    • updating the parameter Qlostz to ensure it only reflects emissions from above-surface well infrastructure, not subject to oxidation;
    • including a pressure-based provision, allowing reporters to assume zero emissions from above-surface infrastructure where measured internal pressure is below atmospheric pressure;
    • incorporating emissions from the well base into calculation of other surface emissions, ensuring they are subject to oxidation;
    • reducing the default gas flow rate from 3.5 kg/hr to 2.9 kg/hr per well, representing combined emissions from both above-surface infrastructure and the well base;
    • amending the equation in Section 5.15 to subtract Qlostz from CH4genz (pre-oxidation), adding it at the post oxidation stage, ensuring no double counting and enabling clear isolation of emissions from above-surface well infrastructure. 
  • The method to estimate total gas collected in each representative zone has been updated to allow the use of centrally located flow and gas composition meters, rather than requiring direct measurement at each well. In addition, reporting frequency was revised from monthly to annual.
  • The requirement to re-calculate the adjusted methane generation constant has been updated to require re-calculation each year (previously every three years).
  • The requirements for representative zones to have intermediate or final cover, and for waste to remain undisturbed for 12 months, have been removed.

Submissions not requested to remain confidential are published on the Department’s consultation page, together with a statement of consultation outcomes.

Regulatory Impact

The regulatory impacts of amendments made by the Update Determination have been assessed as minor by the Office of Impact Assessment (ref OIA26-11647).

Summary of amendments

The Update Determination makes the following amendments to the Measurement Determination:

• Renewable fuels:
  • Introducing provisions for the reporting of scope 1 emissions from consumption of co-processed liquid fuels,
  • Adding bioLPG as a reportable fuel type,
  • Making a minor update to the definition of biomethane displacement ACCU in the renewable gas market-based reporting arrangements,
• Fugitive emissions from coal mines:
  • Updating the Australian Standard for gas desorption testing undertaken on or after 1 July 2027, under Method 2 for estimating emissions from the extraction of coal from open cut mines,
  • Making other minor technical updates to improve clarity,
• Fugitive emissions from oil and gas:
  • Making clear, including via a supporting interpretative Note, when flaring methods should be applied.
  • Updating Method 2A for flared emissions of methane and nitrous oxide from oil or gas exploration and development,
  • Expanding the availability of Method 2B (mass balance approach) for flared emissions from gas extraction and development sources,
  • Making minor editorial updates to Method 2B flaring note 2, available methods for flaring from natural gas production and Schedule 4 Part 2 matters to be identified (MTBI) to improve clarity,
  • Updating Method 2 for emissions from natural gas transmission to improve its usability and coverage of equipment types,
  • Adding an option to Method 3 for LNG leakage emissions that enables greater use of facility-specific measurement,
  • Updating Method 3 for emissions from natural gas distribution to account for hydrogen content,
  • Updating MTBI for Method 2 for emissions from produced water, for venting emissions from oil and gas activities, and for Method 1 for mud degassing in oil and gas exploration and development,
• Emissions of methane released from landfills:
  • Updating Method 2 to expand the range of eligible detection technologies, provide more specificity for measurement of emissions and remove the collection efficiency limit (CEL),
  • Making consequential changes to Method 1 following the changes to Method 2,
  • Updating default waste composition values in Method 1 to reflect modern disposal practices,
• Emissions from wastewater treatment:
  • Enabling reporting of zero emissions from managed aerobic ponds,
  • Updating emission factors for wastewater and sludge,
• Scope 2 emissions:
  • Updating emission factors for the 2026-27 reporting year,
  • Updating matters to be identified under Schedule 4,
• Other changes:
  • Adding new emission factors for liquid fuels combusted in Euro V and Euro VI trucks,
  • Updating the rules for assessing the uncertainty of methane and nitrous oxide emissions from combustion of liquid fuels estimated using method 2.

Documents incorporated by reference

The Measurement Determination specifies the use of technical standards in the measurement of emissions and energy. The prescription of technical standards, many of which are available only on a commercial basis, is a necessary part of technical regulatory regimes such as the NGER Scheme in order to achieve accurate and consistent measurement by regulated entities. Reporters meeting NGER reporting thresholds (specified by section 13 of the NGER Act) are corporate entities who regularly use such standards in their commercial activities and for other regulatory purposes.

Standards and other documents are incorporated consistently with section 14 of the Legislation Act 2003, and with subsection 10(4) of the NGER Act which allows the Measurement Determination to make provision by incorporating instruments as in force or existing at a particular time or from time to time. Subsection 1.9(4) of the Measurement Determination sets out a default rule that such documents are incorporated as in force on 1 January 2020. Section 1.17 of the Measurement Determination provides that if there is an inconsistency between Measurement Determination and a documentary standard, the Measurement Determination prevails to the extent of the inconsistency.

The Measurement Determination allows flexibility in the application of some standards. For example, sections 2.12, 2.24 and 2.26 allow the use of standards which are equivalent to those specified.

Section 1.9 of the Measurement Determination includes definitions of relevant categories of standards referenced in the Measurement Determination. These definitions are as follows:

• AS or Australian standard followed by a number (for example, AS 4323.1—1995) means a standard of that number issued by Standards Australia Limited and, if a date is included, of that date.
• ASTM followed by a number (for example, ASTM D6347/D6347M-99) means a standard of that number issued by ASTM International and, if a date is included, of that date.
• CEN/TS followed by a number (for example, CEN/TS 15403) means a technical specification (TS) of that number issued by the European Committee for Standardization and, if a date is included, of that date.
• GPA followed by a number means a standard of that number issued by the Gas Processors Association and, if a date is included, of that date.
• ISO followed by a number (for example, ISO 10396:2007) means a standard of that number issued by the International Organization of Standardization and, if a date is included, of that date.

Standards are available for purchase through commercial websites such as https://www.saiglobal.com/ or https://webstore.ansi.org/. Some standards are available through public libraries, such as the National Library of Australia. Interested persons may also enquire with the department to arrange a viewing of prescribed technical standards at the department’s offices in Canberra, by appointment.

Item 9 of the Update Determination retains existing provisions requiring analysis of gas and gas bearing strata in accordance with the ACARP Guidelines. Section 1.8 of the Measurement Determination defines the ACARP Guidelines to mean the document entitled Guidelines for the Implementation of NGER Method 2 or 3 for Open Cut Coal Mine Fugitive GHG Emissions Reporting (C20005), published by the Australian Coal Association Research Program in December 2011. A copy of the ACARP Guidelines may be obtained free of charge by emailing anne@acarp.com.au.

Item 9 adds a new subsection 3.25(2) to the Measurement Determination providing that, for gas desorption testing undertaken on or after 1 July 2027, a reference to the minimum requirements in Australian Standard (AS) 3980-1999 in section 2 of the ACARP Guidelines is taken to be a reference to the minimum requirements for gas desorption testing set out in Australian Standard AS3980:2016 “Determination of gas content of coal and carbonaceous material – Direct desorption method”. As for other standards prescribed by the Measurement Determination, this standard may be purchased via commercial websites or may be viewed by appointment at the department’s offices in Canberra.

Item 16 of the Update Determination incorporates provisions of the 2021 API Compendium as part of Method 2 for estimating fugitive emissions from natural gas transmission (other than flaring). The 2021 API Compendium is incorporated by other existing provisions of the Measurement Determination, and is defined in section 1.8 of the Measurement Determination as the document entitled Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry, published in November 2021 by the American Petroleum Institute. It can be accessed free of charge on the website of the American Petroleum Institute at https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf.

Item 48 of the Update Determination retains an existing incorporation of the document Siting, design, operation and rehabilitation of landfills (Publication 788.3), published by the Environment Protection Authority Victoria in August 2015. This document is incorporated as in force or existing from time to time and is available free of charge on the website of Environment Protection Authority Victoria: https://www.epa.vic.gov.au/7883-siting-design-operation-and-rehabilitation-landfills. The document was previously incorporated by subsection 5.16(2) of the Measurement Determination.

Items 62, 69 and 86 of the Update Determination update references to the document Landfill site plan and verification requirements (methods 2 and 3), which is incorporated by existing provisions of the Measurement Determination. This document is available free of charge on the website of the Clean Energy Regulator: https://cer.gov.au/document/landfill-site-plan-and-verification-requirements-methods-2-and-3.

Item 77 of the Update Determination incorporates the list of gas measurement technologies accepted under the United States Environmental Protection Agency’s Advanced Methane Technology Alternative Test Method program. This list of technologies is available free of charge on the website of the United States Environmental Protection Agency: https://www.epa.gov/emc/oil-and-gas-alternative-test-methods.

Item 92 removes an outdated hyperlink reference to the location of the Renewable Power Percentage (RPP) published by the Clean Energy Regulator and incorporated into the market-based method for calculating scope 2 emissions in section 7.4. The RPP remains accessible free of charge on the website of the Clean Energy Regulator: https://cer.gov.au/schemes/renewable-energy-target/renewable-energy-target-liability-and-exemptions/renewable-power-percentage. 

Renewable fuels

Reporting of emissions from consumption of co-processed liquid fuels

The Update Determination introduces arrangements for reporting scope 1 emissions from the consumption of co-processed liquid fuels.

A co-processed liquid fuel is a liquid fuel produced through to the simultaneous processing of fossil fuel feedstocks and biomass feedstocks in the same refinery processing unit (Figure 1).

Figure 1: Simplified depiction of co-processing

Note: This is a simplified example for illustrative purposes only. It shows a single co-processed product and does not show losses.

The carbon content of co-processed fuel is a mixture of fossil carbon and biogenic carbon. Consistent with international reporting rules, under the NGER scheme, biogenic carbon fuels are assigned a scope 1 carbon dioxide (CO2) emission factor of zero. This reflects the fact that combustion of biogenic carbon fuels releases carbon which was absorbed by its biogenic source materials from the atmosphere during their life. Consistent with this approach, combustion of the biogenic carbon fraction of a co-processed fuel results in zero reportable scope 1 CO2 emissions. Emissions of methane (CH4) and nitrous oxide (N2O) released during combustion of co-processed liquid fuels are the same as those released during combustion of their fossil fuel equivalents.

Co-processing is an attractive route to produce lower scope 1 emissions fuels because it can leverage existing refinery infrastructure, transport and storage facilities, instead of requiring new, dedicated infrastructure to produce 100% biomass fuel. Typically, only minor or moderate modifications are required to introduce alternative feedstocks into existing refinery infrastructure. Further, in many cases, co-processed fuels are “drop-in” fuels that are not subject to biofuel blend limits because they have nearly identical properties to fuels produced from purely fossil fuel feedstocks.

Co-processed fuels are technically distinct from blended fuels. Blended fuels are produced by blending or mixing two or more neat, separately produced fuels to a desired ratio. Co-processing, however, results in a single finished fuel product (for example, co-processed diesel), a fraction of which is biomass derived. Blending of biomass and fossil derived fuels is not considered co-processing.

Certificate-backed reporting approach

Item 7 adds a new Part 2.8 to the Measurement Determination which sets out rules for reporting consumption and emissions from co-processed liquid fuels. These rules take a ‘certificate-backed’ reporting approach.

New section 2.73 provides for reporters to determine the amount of co-processed liquid fuel consumed at a facility in reporting year based on eligible co-processed liquid fuel certificates for the fuel. This is the case even if the facility does not physically consume all the co-processed liquid fuel represented by the certificates, because of it having been mixed with other consignments of fuel in shared or co-mingled storage and distribution infrastructure. Any co-processed liquid fuel consumed at a facility that is not covered by eligible co-processed liquid fuel certificates must be reported as the relevant fossil fuel equivalent (see item 7, subsections 2.73(5) and 2.73(6)).

Reportable co-processed liquid fuels are co-processed aviation kerosene, co-processed diesel and co-processed LPG. These fuels will be added as reportable fuel types via an amendment to the Regulations that will commence at the same time as these amendments to the Measurement Determination.

Linking co-processed liquid fuel certificates into the NGER scheme improves the integrity and transparency of low emissions claims. It provides assurance to government, the public and NGER scheme reporters that the co-processed liquid fuel whose scope 1 emissions attributes are being reported has indeed been produced domestically and that the biogenic carbon fraction of the co-processed fuel has been determined and assigned in accordance with defined rules. It also provides a streamlined, transparent and auditable framework for transferring and reporting product attributes throughout the supply chain, including through shared and co-mingled infrastructure.

Two types of certificates are recognised (see subsection 2.73(2)):

• Product Guarantee of Origin certificates (PGOs), registered under the Guarantee of Origin (GO) scheme.
• Sustainability Declarations, issued under the International Sustainability and Carbon Certification ISCC PLUS scheme (ISCC PLUS SDs).

PGOs operate as a record of the origin and use of a product. They capture the actual emissions of a product across its lifecycle and other attributes that can be used to underpin environmental claims. The ISCC PLUS scheme is a global, voluntary certification scheme designed to verify and track sustainability attributes associated with alternative feedstocks and products derived from those feedstocks, including biomass feedstocks and biomass-derived fuels. Under ISCC PLUS, the primary transaction document used to transfer attributes through the supply chain is a Sustainability Declaration (SD). A SD accompanies the transfer of certified material and records the sustainability attributes allocated to that material under the applicable ISCC PLUS chain-of-custody method. A downstream recipient may rely on the SD to make claims regarding the sustainability attributes of the fuel received. For both PGOs and ISCC PLUS SDs, the only attribute carried by the certificate that is relevant for NGER scheme scope 1 emissions reporting purposes is the biogenic carbon content of the fuel represented by the certificate.

Both certificate types can be used to underpin reporting of co-processed liquid fuel consumption and associated emissions, subject to the time limit on ISCC PLUS SD recognition (see subsection 2.73(4)) and the additional eligibility requirements in subsections 2.73(2) and (3).

Recognition of ISCC PLUS SDs is an interim arrangement for the 2026-27 and 2027-28 reporting years only (see subsection 2.73(4)), unless a PGO production pathway for co-processed liquid fuels has not been determined by the Minister under the Future Made in Australia (Guarantee of Origin) Act 2024 by the end of the 2027-28 reporting year. Recognising ISCC PLUS SDs provides an additional certification pathway for this period, increasing flexibility in how co-processed liquid fuel consumption may be evidenced under the NGER scheme. This flexibility is intended to support near-term production and consumption of co-processed liquid fuel before PGOs become available, and to provide a reasonable transition period for producers and supply chains to become familiar with the PGO certification, register PGO profiles and start generating PGO certificates. Provided a pathway has been determined by the Minister, PGO certificates will become the only eligible certificate for domestically produced co-processed liquid fuel for reports submitted for the 2028-29 reporting year onward. If a pathway has not been determined by the Minister by the end of the 2027-28 reporting year, the department intends that ISCC PLUS SDs would continue to be an eligible certificate until a PGO pathway is determined. In this scenario, the time limit on ISCC PLUS SD recognition could be extended by amending subsection 2.73(4).

There are two common requirements that a PGO and ISCC PLUS SD must meet to be eligible for NGER scheme scope 1 emissions reporting purposes:

• the co-processed liquid fuel represented by the certificate must have reached its delivery gate (for PGOs) or been dispatched (for ISCC PLUS SDs) within the 24-month period immediately preceding the end of the reporting year (see subparagraphs 2.73(2)(a)(ii) and 2.73(2)(b)(ii), known as the temporal link requirement).
• there must be a connection between the location or entity listed on the certificate as the consumer or recipient of the fuel covered by the certificate (see subparagraphs 2.73(2)(a)(iii) and 2.73(2)(b)(iii)).

The temporal link requirement helps to ensure the attributes of co-processed liquid fuel are reported within a reasonable timeframe after the fuel was delivered or dispatched to the market. This is important for maintaining the accuracy and utility of NGER scheme data by ensuring reporting occurs close to when the physical emissions will have occurred. The information required to verify the temporal link requirement will be recorded on PGOs and ISCC PLUS SDs.

In addition to these common requirements, the Update Determination includes specific eligibility requirements for PGOs and ISCC PLUS SDs.

For a PGO to be eligible, the PGO must be completed after the start of the reporting year and prior to the submission of the report for the facility for the reporting year (see subparagraph 2.73(2)(a)(i)). A registered PGO is completed if consumption information has been added to it in accordance with section 59 of the Future Made in Australia (Guarantee of Origin) Act 2024 (the ‘GO Act’). A condition equivalent to this does not apply to ISCC PLUS SDs because ISCC PLUS SDs do not undergo a ‘completion event’ in the same way that PGOs do. An ISCC PLUS SD accompanies the delivery of physical material to which certified biomass attributes have been assigned. Those attributes are taken to have been consumed during the same period in which the physical material to which the ISCC PLUS SD is attached is consumed.

For an ISCC PLUS SD to be eligible, it must represent co-processed liquid fuel produced in Australia at a processing unit certified under the International Sustainability and Carbon Certification ISCC PLUS scheme (see subparagraph 2.73(2)(b)(i)). For the purposes of this requirement, ‘processing unit’ refers to the refinery at which co-processing occurs. While ISCC PLUS is a global, jurisdiction-agnostic scheme, this requirement limits the NGER scheme recognition of ISCC PLUS SDs to domestically produced co-processed liquid fuels. This requirement reflects the primary intent of recognising ISCC PLUS SDs, which is to support near-term domestic production and consumption of co-processed liquid fuel until PGO certificates become available.

An additional condition on ISCC PLUS SD eligibility applies where an ISCC PLUS SD specifies that the mass balance free attribution chain of custody approach has been used to assign biogenic carbon attributes to the co-processed liquid fuel it represents (see subsection 2.73(3)). It is mandatory for the chain of custody approach used to be listed on an ISCC PLUS SD. Mass balance free attribution is one chain of custody approach that can be applied under the ISCC PLUS certification scheme. It allows the free allocation of biogenic carbon attributes between one or more different co-processed outputs on a bookkeeping basis, provided that the total quantity of biogenic attributes allocated does not exceed the total quantity physically present across all outputs produced by the system. The bookkeeping allocation does not necessarily need to reflect the physical distribution of biogenic carbon to each individual output.

In addition to fuels, some co-processing pathways also produce non-fuel outputs. Non-fuel co-processed outputs include all co-processed outputs that are, or end-up in, materials that are used or traded as non-fuel products: for example, co-processed propylene that ends up in a polypropylene plastic product. The intent of subsection 2.73(3) is to prohibit the attribution of biogenic carbon physically contained in non-fuel co-processed outputs to co-processed fuel outputs. Where an ISCC PLUS SD specifies that a mass balance free attribution approach has been used, it must be accompanied by a written statement from the co-processed liquid fuel producer confirming that any biogenic carbon contained in non-fuel co-processed outputs was treated as a loss and deducted from the mass balance before the remaining biogenic carbon was allocated to fuel outputs. This approach preserves the flexibility to allocate biogenic carbon attributes between co-processed fuel outputs in response to market demand, while ensuring scope 1 emissions reported under the NGER scheme accurately reflect the aggregate physical emissions from combustion of the co-processed fuel outputs. The requirement to provide a written statement when mass balance free attribution has been used applies even if the processing unit does not produce any non-fuel co-processed outputs.

Despite not being included as an explicit requirement in the Update Determination itself, by leveraging PGOs and ISCC PLUS SDs, the NGER scheme adopts each scheme’s requirements to maintain a reasonable physical link between the co-processed liquid fuel and its attributed biomass content. The GO scheme requires that a product must be able to reasonably pass from its delivery gate to the consumption location listed on the PGO certificate for the fuel. The ISCC PLUS scheme has broadly analogous mass balance chain of custody rules for transferring attributes represented by an ISCC PLUS SD through the downstream supply chain. Book and claim is not an allowed chain of custody under ISCC PLUS. This requirement balances the need for high integrity, traceable claims to the scope 1 emissions attributes of individual co-processed liquid fuels consignments, while still providing flexibility in the production, supply and consumption of co-processed liquid fuels through shared and co-mingled infrastructure. The proposed amendments are not intended to facilitate book and claim style reporting of the emissions from consuming co-processed liquid fuel. Equivalent reasonable physical link requirements apply in the existing NGER scheme market-based reporting arrangements for renewable gases and renewable liquid fuels (see section 2.67B and 2.67C of the Measurement Determination).

Calculating emissions from co-processed liquid fuels

Only the biogenic carbon fraction of a co-processed liquid fuel should be reported with a scope 1 CO2 emission factor of zero. In general, the scope 1 CO2 emission factor for an amount of co-processed liquid fuel is given by the equation:

Where:

EFCoPro,CO2 is the scope 1 CO2 emission factor for the co-processed liquid fuel

EFFossil is the scope 1 CO2 emission factor for the fuel based on its carbon content as if the co-processed fuel were its pure fossil fuel equivalent

FF is the fossil carbon fraction for the co-processed liquid fuel

Items 101 and 105-110 of the Update Determination add scope 1 CO2 emission factors for co-processed aviation kerosene, co-processed diesel and co-processed LPG in this general form. These items also specify scope 1 CH4 and N2O emission factors for the fuels, which are the same as their fossil fuel equivalents.

To support the CO2 emission factors, the Update Determination introduces a new section 2.74 setting out how to calculate the fossil carbon fraction, FF, of an amount of co-processed liquid fuel. The fossil carbon fraction of an amount of co-processed liquid fuel is equal to one minus the term BFassigned. Where reporting of co-processed liquid fuel consumption is underpinned by PGOs, BFassigned is the assigned biogenic carbon fraction recorded on the PGO (see paragraph (a) of the definition of BFassigned). The assigned biogenic carbon fraction will be listed on PGO certificates for co-processed liquid fuel as a ‘product specific attribute’ to support NGER scheme scope 1 emissions reporting. ISCC PLUS SDs do not list an assigned biogenic carbon fraction in the same way that PGOs will. Where reporting of co-processed liquid fuel consumption is underpinned by ISCC PLUS SDs, BFassigned is:

• Subparagraph (b)(i): The fraction of total fuel covered by the ISCC PLUS SD that is certified biomass, calculated based on the information listed on the ISCC PLUS SD; or
• Subparagraph (b)(ii): 1, if the ISCC PLUS SD is only issued for the certified biomass component of the co-processed liquid fuel.

The options given by subparagraphs (b)(i) and (ii) are intended to cover all possible ISCC PLUS SD formats. Subparagraph (b)(i) would apply where the ISCC PLUS SD is issued for a total quantity of fuel, only part of which carries certified biomass attributes. Subparagraph (b)(ii) would apply in the more common scenario where ISCC PLUS SDs are only issued for the quantity of fuel carrying certified biomass attributes. This reflects the function of the SD within the ISCC PLUS chain-of-custody framework, which is to transfer the claimable certified share of a product, rather than describe the full physical fuel shipment.

Reporters must calculate the fossil carbon fraction of co-processed liquid fuel in accordance with section 2.74 – they cannot sample and analyse the fuel they physically consume to determine the physical biogenic carbon content as this would introduce a risk of double counting biomass attributes already reported under certificate-backed reporting arrangements.

Importantly, reporters need to calculate the fossil carbon fraction of the co-processed liquid fuel consumed at a facility on a certificate-by-certificate basis. For example, if in a reporting year a person reports having consumed an amount of co-processed liquid fuel represented by multiple PGO certificates, each with a different assigned biogenic carbon content, the person will need to calculate the fossil carbon fraction, and therefore CO2 emissions, from each certificate’s worth of fuel individually. Similarly, if a person reports having consumed multiple amounts of a co-processed liquid fuel at a facility, underpinned by a mix of PGOs and ISCC PLUS SDs, the person will need to calculate the fossil carbon fraction of each amount using the appropriate information on each certificate type.

If a single batch of co-processed liquid fuel is covered by both PGOs and ISCC PLUS SDs, those instruments must not be used in a way that leads to double counting of the scope 1 emission benefits of the fuel. The GO and ISCC PLUS schemes include their own requirements intended to help prevent double counting. For example, the ISCC PLUS System Document titled ISCC PLUS 203 – 2 CHAIN OF CUSTODY includes additional assurance requirements that apply if a company is simultaneously certified under ISCC PLUS and other certification schemes. These requirements include declarations from high-level company members and additional audit scrutiny.

New matters to be identified for fuel combustion sources

Item 116 of the Update Determination adds new matters to be identified in relation to fuel combustion sources. The items require reporters who report using the new certificate-backed arrangements for co-processed liquid fuels to identify the eligible certificates used to underpin their reporting. In addition:

• for reporting underpinned by ISCC PLUS SDs, reporters must also provide a copy of the full ISCC PLUS SD document and, if relevant, the accompanying written statement required under subsection 2.73(3).
• for reporting underpinned by PGOs, reporters must also identify the average assigned biogenic carbon fraction for each co-processed liquid fuel type they report having consumed.

Provision of these items will provide greater visibility over the use of the arrangements and better enable the Regulator to reconcile and verify reported emissions.  

Reporting of emissions from consumption of bioLPG

The Update Determination specifies various parameters for bioLPG, including an energy content factor and emission factors, in terms of kg CO2-e/GJ, for scope 1 emissions of CO2, CH4 and N2O.

BioLPG is a biomass-derived fuel with nearly identical chemical and physical properties to conventional liquified petroleum gas (LPG). It is a ‘drop-in’ fuel suitable for use a direct substitute for LPG. BioLPG will be added as a new reportable fuel type via an amendment to the Regulations that will commence at the same time as these amendments to the Measurement Determination.

BioLPG has the same technical parameters as LPG except is assigned a scope 1 CO2 emission factor of zero (see items 99, 103 and 108). This approach is consistent with international reporting rules and the treatment of other biogenic fuel types under the NGER scheme. It reflects the fact that combustion of bioLPG releases carbon which was absorbed by its biogenic source materials from the atmosphere during their life.

Adding bioLPG as a fuel type enables reporting of its consumption – both as pure bioLPG and blends with LPG, determined in accordance with section 2.67 of the Measurement Determination – and for NGER scheme reports to reflect the associated reduction in emissions.

Minor update to the definition of biomethane displacement ACCU in the renewable gas market-based reporting arrangements

Item 6 of the Update Determination makes a minor update to the definition of biomethane displacement ACCU in subsection 2.67C(6) of the Measurement Determination to cover Australian carbon credit units (ACCUs) issued for displacement abatement resulting from eligible offsets projects covered by the ACCU method titled Carbon Credits (Carbon Farming Initiative— Reducing Methane Emissions from Landfill Gas) Methodology Determination 2025 (the ‘2025 LFG method’).

Section 2.67C of the Measurement Determination provides a ‘market-based’ approach for determining the amount of a renewable gas in a blended gaseous fuel received from a natural gas network.  It provides for reporters to determine that the blended gas they receive from the natural gas network and consume at a facility in a reporting year contains an amount of renewable gas, as represented by eligible renewable gas certificates retired or completed by them or on their behalf.

Among other things, subsection 2.67C(5) sets limits on the eligibility of renewable gas certificates for NGER reporting purposes if those certificates represent biomethane in respect of which biomethane displacement ACCUs have been created and used in certain ways. Including the 2025 LFG method in the definition of biomethane displacement ACCU helps to control the risk of double counting that could arise if a biomethane producer registered under the method creates both biomethane displacement ACCUs and renewable gas certificates in respect of a single unit of biomethane and a facility covered by the Safeguard Mechanism:

• uses the renewable gas certificate under the market-based arrangements to report biomethane consumption (instead of natural gas consumption), and
• also meets their Safeguard obligation by surrendering the associated biomethane displacement ACCU.

For more information about the market-based reporting arrangements for biomethane and hydrogen, see the Explanatory Statement to the National Greenhouse and Energy Reporting (Measurement) Amendment (2025 Update) Determination 2025. 

Coal mine fugitive emissions

Clarification of definitions for gassy and non-gassy underground mines

Items 2 and 3 in Schedule 1 of the Update Determination amends the definitions of “gassy mines” and “non-gassy mines” in section 1.8 of the Measurement Determination that are used to classify underground coal mines for the purpose of estimating fugitive emissions. To support application of the definitions consistent with their original intent, the research on which the definitions were based and the standard industry practice for measuring methane content in ventilation air, the amendment clarifies that the threshold for classification is based on the volume of methane in the mine’s return ventilation.

Clarification of equation for coal mine waste gas flaring

Item 8 in Schedule 1 of the Update Determination amends the definition of EFk  in section 3.15 of the Measurement Determination. Section 3.15 prescribes Method 2 for estimating emissions of carbon dioxide released from coal mine waste gas flaring. To support interpretation of section 3.15 consistent with its original intent, the amendment clarifies that EFk is the emissions factor of carbon dioxide for the quantity of the methane flared. This clarification also supports consistency with the definition for EFkj in section 3.15A, which refers to the emission factors for methane or nitrous oxide in the methane flared.

Updating Method 2 for open cut coal mines to use the current Australian Standard for gas desorption testing

Items 9 and 10 in Schedule 1 of the Update Determination amends section 3.25 of the Measurement Determination in relation to its minimum requirements for gas desorption testing to support Method 2 for estimating fugitive emissions from the extraction of coal from open cut coal mines. That section had required facilities to undertake gas desorption testing in accordance with the Australian Coal Industry’s Research Program (ACARP) Guidelines. Section 2 of the ACARP Guidelines requires facilities to use Australian Standard AS3980-1999. The Update Determination amends section 3.25 of the Measurement Determination to require the application of the most recent standard AS3980:2016 as it relates to gas desorption testing undertaken on or after 1 July 2027. The delayed application of the updated standard AS3980:2016 provides time to resolve issues identified through the public consultation that could inadvertently lower emission estimates through misapplication of gas model development requirements relating to the low gas zone and carbonaceous strata. This work will be undertaken through the Method 2 review and also provides the opportunity to develop additional guidance on other aspects of the standard to improve its application to Method 2,ahead of 1 July 2027.

Gas desorption data obtained from testing in accordance with standard AS3980-1999 cited in section 2 of the ACARP Guidelines prior to 1 July 2027 may continue to be used for Method 2 after 1 July 2027. The amendment is not intended to have retrospective effect. This is consistent with legislation principles and avoids the potential for perverse compliance outcomes.

Oil and gas fugitive emissions

Clarification of flaring methods

Items 10, 11, 14, 15, 20, 24, 29, 34, 35, 40 and 45 in Schedule 1 of the Update Determination amend sections 3.41A, 3.42, 3.47(1), 3.62, 3.83, 3.88A, 3.88E, 3.88I, 3.88K, 3.88O, and 3.88S of the Measurement Determination. The amendments are not intended to change the application of the method. They are intended to clarify the existing intent that:

• methods for estimating fugitive emissions from oil and natural gas flaring activities should only be applied where the fuel passing through a flare is combusted, with an appropriate venting method applied where the fuel is not combusted; and,
• fuel passing through a flare without combustion does not include fuel that fails to combust during ordinary flaring. This is because emissions resulting from incomplete combustion are treated as part of flaring and are not considered venting.

Consistent with the original intent, there are no specific prescribed technologies or processes that must be used by a facility operator to determine when a flare is not combusting fuel and the duration of that period. Based on current industry experience, technologies and processes to make those determinations can include, but are not limited to:

• operator audio, visual or olfactory (AVO) checks,
• engineering process knowledge incorporating mass balance or measured gas composition,
• flare tip surveillance such as vibration, thermal, acoustic, optical or spectroscopic signatures,
• cameras, video or other sensing equipment and associated software models including:
  • visual, optical, thermal imaging,
  • pilot Flame Presence Monitoring – such as ultraviolet or infrared sensors,
  • continuous parameter monitoring systems,
  • optical gas imaging (OGI) camera,
• auto-igniters, flame front generators, or
• thermocouples.

Consistent with the original intent, there is no prescribed frequency for applying technologies and processes to determine when a flare is not combusting fuel and the duration of that period. The general principles in section 1.13 of the Measurement Determination should be applied such that any determinations should result in estimates that are not systemically over- or under- estimations of the true value. In addition, as with all methods in the Measurement Determination, the general principles in section 1.19 should be applied. Any determinations should be well documented, adhering to record keeping obligations under the NGER Act. These records might include, but are not limited to, the following examples:

• instrumentation and control system data,
• pilot flame monitoring records,
• operational logs and incident records,
• maintenance and inspection records,
• visual and remote monitoring records,
• environmental and emissions monitoring records, or
• engineering design documentation and redundancy systems information.

Update to Method 2A for flared emissions of methane and nitrous oxide from oil or gas exploration and development

Item 13 in Schedule 1 of the Update Determination amends the formula in section 3.45A Method 2A—oil or gas exploration and development (flared methane or nitrous oxide emissions) of the Measurement Determination. That section had defined a single equation that was applied to both the estimation of methane and nitrous oxide emissions from flaring. It applied relevant emissions factors for each gas as well as a constant oxidation factor. The amendment separates the single equation into two equations. The equation for estimating methane emissions retains the oxidation factor, while the equation for estimating nitrous oxide emissions does not include the oxidation factor.

Removing the oxidation factor from the nitrous oxide equation improves alignment with the process by which nitrous oxide is produced in flaring. That is, the production of nitrous oxide from flaring primarily depends on the flare temperature and the quantity of nitrogen-containing compounds within the flare gas, rather than the quantity of material combusted. The amendment will improve the accuracy of nitrous oxide emission estimation; supporting emissions reporting under the NGER scheme and Safeguard Mechanism, and in turn, international emissions reporting.

Expansion of flaring Method 2B for gas extraction and development sources

Items 12, 25-28, 30-33, 36-39 and 41-44 in Schedule 1 of the Update Determination amends the following subdivisions of the Measurement Determination to provide an additional option for estimating fugitive emissions from five oil and natural gas flaring sources.

• Subdivision 3.3.2.2—Oil or gas exploration and development (emissions that are flared),
• Subdivision 3.3.9B.2—Natural gas gathering and boosting (emissions that are flared),
• Subdivision 3.3.9C.2—Natural gas processing (emissions that are flared),
• Subdivision 3.3.9E.2—Natural gas storage (emissions that are flared), and
• Subdivision 3.3.9F.2—Natural gas liquefaction, storage and transfer (emissions that are flared).

The additional option is Method 2B, a mass balance-based approach to fugitive emission estimation. Method 2B was first developed to more accurately estimate emissions from a given facility’s natural gas production flaring activities, while minimising reported barriers to uptake of higher order methods for this emissions source largely relating to requirements to sample gas composition at the flare point and associated costs.

Method 2B was introduced into the Measurement Determination as part of the 2024 NGER scheme updates[1] through section 3.87B Method 2B—Natural gas production mass balance approach (flared methane and carbon dioxide emissions). It was then made available in the natural gas transmission and distribution gas segments as part of the 2025 NGER scheme updates[2].

By extending the availability of Method 2B to a further five oil and natural gas flaring sources, the Update Determination is intended to increase the accuracy of emissions estimated for these sources by enabling NGER reporters to apply a high order method that better reflects facility-specific oil and natural gas flaring activities. Items 117, 126, 128, 130 and 132 in Schedule 1 of the Update Determination introduce matters to be identified (MTBI) where Method 2B is used for each of the above sources. They correspond to MTBI from Items 3 and 4 of Schedule 4, Part 2, Source 2U (Offshore natural gas production—flaring) and reflect information that reporters would need to gather to estimate emissions from these sources. The MTBI will support effective regulatory assessment under the NGER scheme, including the completeness of reporting, and compilation of Australia’s national greenhouse gas inventory consistent with international emissions reporting requirements.

Minor editorial update to Method 2B flaring note 2

Item 23 in Schedule 1 of the Update Determination makes an editorial correction to Note 2 under section 3.87B, Method 2B—Natural gas production mass balance approach (flared methane and carbon dioxide emissions). It inserts the word “estimate” after “If this method is used to”. This is intended to improve the readability and clarity of Note 2 and does not alter the regulatory intent or impact of the method.

Minor editorial update to available methods for flaring from natural gas production

Items 21 and 22 in Schedule 1 of the Update Determination makes editorial corrections in the Note in Subdivision 3.3.9A.10—Natural gas production (emissions that are flared), Section 3.85T Available methods. The Note previously incorrectly referenced:

• Section 3.85 Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas treatment processes. The Note is corrected to reference section 3.86 Method 1—gas flared from natural gas production,
• No Method 2 for emissions of nitrous oxide or methane. As per subsection 3.85T(1)(b) and (c), there is a Method 1, 2A and 2B available for estimating methane and both a Method 1 and 2A available for estimating nitrous oxide emissions. The Note is corrected to remove the incorrect reference to there being no Method 2 available.

This amendment does not alter the regulatory intent or impact of the method.

Update of matters to be identified for Method 2 for fugitive emissions from produced water

Item 121 in Schedule 1 of the Update Determination amends the matters to be identified (MTBI) under Schedule 4, Part 2, Source 2L to capture the megalitres of net produced water. It corrects an oversight relating to the 2024 NGER Amendments[3]. In those amendments, section 3.73NB Method 2—produced water (other than emissions that are vented or flared) was updated to specify that the quantity of produced water should be reported in net terms to account for reinjection activities. However, the corresponding MTBI under Schedule 4, Part 2, Source 2L, Item 2 were not updated to reflect this amendment.

The Update Determination amendment is intended to improve the accuracy of the MTBI, aligning it with the associated method, and does not alter the regulatory intent. Previously, the MTBI was calculated separately using a different basis (gross throughput instead of net throughput), which required an additional calculation. This change reduces regulatory burden on reporters because the MTBI now uses the same throughput figure that is used to calculate emissions.

Improvement to Method 2 for emissions from natural gas transmission

Item 16 in Schedule 1 of the Update Determination amends the equation defined in section 3.77 Method 2—natural gas transmission (other than flaring), with consequential updates to the associated matters to be identified MTBI (Item 122 in Schedule 1 of the Update Determination). Item 16 also updates references to the American Petroleum Compendium in section 3.77.

The equation is clarified by requiring emission estimation based on the sum of emissions calculated by distance and emissions calculated by equipment. This replaces the previous unworkable requirement to combine two units (time and throughput mass) to calculate emissions. Based on the amended equation, the MTBI for this method are updated in Part 2 of Schedule 4, Source 2N – Natural gas transmission (other than flaring). References to the 2009 Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry published by the American Petroleum Institute (2009 API Compendium) are replaced with references to the 2021 Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry published by the American Petroleum Institute (2021 API Compendium). Section 3.77 used emissions factors sourced from Table 6-6 and Table 6-9 of the 2009 API Compendium. It contains two emissions factor unit categories:

• Distance-based: tonnes gas type j per km per hour,
• Equipment-based: tonnes gas type j per equipment type per hour.

Table 7-46 and Table 7-47 of the 2021 API Compendium contain the same distance- and equipment-based unit categories.

A comparison of the 2009 and 2021 API Compendiums is presented in the table below. Emission factors for equipment types cited in the 2009 API Compendium are the same in the 2021 API Compendium. Five additional equipment types, with associated emission factors, are included in the 2021 API Compendium – highlighted in the table below.

Table 1: Comparison of fugitive emissions factors for natural gas transmission and storage equipment from the 2009 and 2021 API Compendiums

Notes:

1.       There were no changes to units between the 2009 and 2021 API Compendiums
2.       2009 API Compendium
3.       2021 API Compendium

These amendments are intended to improve the usability of the existing method and do not change its regulatory intent. By updating the method to reference the 2021 API Compendium, NGER reporters will have access to an additional five equipment type emission factors, allowing them to more accurately reflect their facility operations in applying the method. Updating the associated MTBI supports effective regulatory assessment under the NGER scheme, including the completeness of reporting, and compilation of Australia’s national greenhouse gas inventory consistent with international emissions reporting requirements.

Addition of an option to Method 3 for LNG leakage emissions that enables greater use of facility-specific measurement

Items 17 and 18 of the Update Determination amend subsection 3.78J(1) Method 3 of the Measurement Determination for estimating fugitive methane emission emissions (other than venting and flaring) from natural gas liquefaction, storage and transfer.

That method required the use of component-specific emission factors set out in subsections 3.78J(2) and (3), which are based on Table 13 of the American Petroleum Institute 2015 Liquefied Natural Gas (LNG) Operations Consistent Methodology for Estimating Greenhouse Gas Emissions[4] and assume methane is a 0.934 (93.4%) share of the gas process stream. The amendments provide the option of adjusting those factors based on the measured share of methane in the gas process stream per component by volume. If there is variation in gas compositions between process streams with the same component types, these components can be treated as separate components. Measurement must be in accordance with Division 2.3.3 and the principles in section 1.13 of the Measurement Determination.

The amendments do not remove the option to use the emission factors set out in subsections 3.78J(2) and (3) that assume methane is a 0.934 (93.4%) share of the gas process stream. In such instances, 0.934 would be applied to both the numerator and the denominator used to determine the share of methane in the gas process stream (Sᵢⱼ / SDᵢⱼ), resulting in no adjustment to the emission factors. By providing the option to use a measured methane share, the amendments support emissions estimates that better reflect facility-specific circumstances, and thereby, improved fugitive emissions estimation.

Update of Method 3 for emissions from natural gas distribution to account for hydrogen content

Item 19 of the Update Determination amends section 3.82A Method 3 of the Measurement Determination for estimating fugitive emissions from natural gas distribution other than emissions that are flared. That section’s emission estimation formula had applied to the total terajoules of gas sales during the reporting year. When gas sales included a hydrogen component injected into the gas network, this would result in the method calculating any hydrogen losses as methane losses. Doing so would inadvertently and systematically over-estimate methane emissions for this source.

Item 19 revises the formula to refer to the total terajoules of hydrocarbon sales during the year, rather than total terajoules of gas sales over that period, thereby excluding hydrogen (which is not a hydrocarbon). This approach enables reporters to apply Method 3 in a manner that appropriately accounts for hydrogen content in sold gas by removing it from the throughput used in emissions calculations.

To capture the energy content that is not sourced from hydrocarbons (e.g. hydrogen), Item 124 in Schedule 1 of the Update Determination adds matters to be identified (MTBI) of “terajoules of utility sales that are not hydrocarbons”. This amendment provides the department and other NGER data users with clear visibility of hydrogen volumes transported through Australian natural gas distribution pipelines. Improved transparency of hydrogen use will support more accurate monitoring of trends in gas composition and decarbonisation efforts. It will also assist the department and the Clean Energy Regulator to reconcile and validate reported data more effectively, strengthening analytical capability and supporting robust compliance and assurance processes.

Hydrogen is not a reportable greenhouse gas under the UNFCCC and Paris Agreement. The Intergovernmental Panel on Climate Change (IPCC) Guidelines supporting those international reporting requirements do not provide a global warming potential value for hydrogen based on the mandatory 100-year time horizon that would support voluntary reporting. The IPCC is considering hydrogen as part of its work to develop a methodology report on short-lived climate forces[5]. The information to be reported under Item 124 in Schedule 1 of the Update Determination will assist the department’s consideration of the IPCC’s final report when it becomes available.

Update of matters to be identified (MTBI) for venting emissions from oil and gas activities

Items 118, 119, 125, 127, 129 and 131 in Schedule 1 of the Update Determination amend the matters to be identified (MTBI) for sources of venting emissions from oil and gas activities in Schedule 4, Part 2, of the Measurement Determination so they are consistent with those MTBI defined in Schedule 4, Part 2, Sources 2R and 2S. These changes apply to:

• Source 2E—Oil or gas exploration and development (other than flaring),
• Source 2F—Crude oil production,
• Source 2V—Natural gas gathering and boosting—venting,
• Source 2X—Natural gas processing—venting,
• Source 2ZA—Natural gas storage—venting, and
• Source 2ZC—Natural gas liquefaction, storage and transfer—venting.

Information required under the amended MTBI are expected to be available from information already gathered by reporters to estimate emissions from these sources. These amendments support compilation of Australia’s national greenhouse gas inventory consistent with international emissions reporting requirements and effective regulatory assessment under the NGER scheme, including the completeness of reporting. 

Establishment of additional matters to be identified (MTBI) for Method 1 for mud degassing in oil and gas exploration and development

Item 118 in Schedule 1 of the Update Determination adds the requirement to report the following MTBI that are used for calculating fugitive emissions via the application of section 3.46AC Method 1— emissions from system upsets, accidents and deliberate releases from process vents— mud degassing:

• the number of drilling days for:
  • offshore well mud degassing by:
    • water-based mud,
    • oil-based mud,
    • synthetic mud,
  • onshore well mud degassing by:
    • water-based mud,
    • oil-based mud,
    • synthetic mud.

Information required under the MTBI are expected to be available from information already gathered by reporters to estimate emissions from this source. This amendment supports compilation of Australia’s national inventory consistent with international emissions reporting requirements, in particular the requirement for time-series consistent emissions data. It also supports effective regulatory assessment under the NGER scheme.

Minor editorial update to Schedule 4 Part 2

Item 123 in Schedule 1 of the Update Determination makes a minor editorial change to the Schedule 4, Part 2 tables for Source 2P—Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared) and Source 2Q—Natural gas distribution (other than flaring). The amendments correct the numbering of the items listed in both tables so that they are sequential, to improve consistency and clarity.

Waste

Updates to Division 5.2.3  - Method 2 for the estimation of methane released from landfills

Method 2 allows reporters to incorporate site measurements obtained using flux boxes to calibrate the first order decay (FOD) model parameters to local conditions. However, despite this calibration, the previous Method 2 remained subject to a collection efficiency limit.

The Update Determination makes amendments to Method 2 to strengthen site measurement processes, improve the accuracy of FOD model calibration, and support consistent implementation. In particular, refinements to measurement practices and technology requirements improve the accuracy of the FOD model calibration, enabling the removal of the current limit on collection efficiency under Method 2. The department anticipates the amendments will result in improved uptake of Method 2.

The amendments respond to stakeholder feedback, technology advancements, and the objective of improving accuracy and transparency.

The amendments apply to several elements of the current Method 2 as outlined below. Broadly, the method is designed to be undertaken according to the following steps:

1.       Site plan: Prepare a site plan of the landfill, consistent with CER guidance.
2.       Sub-facility zones: Identify sub-facility zones with homogenous characteristics.
3.       Representative zone/s: Select a representative zone in each sub-facility zone, in which methane flux will be determined. Ensure each representative zone is representative of the sub-facility zone.
4.       Independent verification: Independent expert verifies that the boundaries of the representative zone/s are appropriate for obtaining accurate and representative estimates of methane generation.
5.       Methane collected in representative zone: Determine methane collected in each representative zone.
6.       Methane generated but not collected: Estimate emissions of methane generated in the representative zone that is not collected by wells.
7.       Walkover or scanning survey: Identify areas of low and elevated emissions and emissions from landfill gas collection wells.
8.       Placement of flux boxes or chambers: Flux boxes or chambers are placed in each representative zone in areas and at landfill gas wells identified to have elevated emissions during the walkover or scanning survey.
9.       Methane flow rate calculation: determine total annual methane flow in each representative zone using a default methane flow rate for low emissions areas and measurements taken at step 8 for areas identified to have elevated emissions.
10.   Flux box measurement: Use estimates taken in step 9 to iteratively calibrate the methane generation constants for each waste type. 
11.   Apply generation constant in FOD model: Apply calibrated generation constants for each waste type for the estimation of methane generation at each site.

Removal of the collection efficiency limit (CEL)

Under the former Method 2, net landfill methane emissions were calculated using measured methane collection data and modelled methane generation (calibrated using site-specific data from flux boxes). If methane collection exceeded the CEL, reportable emissions were increased to maintain collection efficiency equal to the CEL. 

Stakeholder feedback noted that the application of the CEL in Method 2 could create an unintended incentive for landfills to restrict methane collection to avoid exceeding the CEL.

Item 61 of the Update Determination removes the CEL from Method 2, by removing relevant provisions in Sections 5.15A, 5.15B and 5.15C. Item 48 relocates the previous Section 5.15C (calculation of a CEL) to Method 1 in Section 5.4(5), where the CEL continues to apply. Sections 5.15A and 5.15B (calculation of opening and closing stock when methane generation exceeds the CEL) have not been moved to Method 1, as relevant provisions already exist.

Addition of a ‘suitably qualified person’

The Update Determination allows activities currently restricted to an ‘independent expert’ to also be undertaken by a ‘suitably qualified person’. Item 4 defines ‘suitably qualified person’ in relation to an operator of a landfill, as a person who holds a relevant qualification in a field applicable to the estimation or monitoring of landfill gas.

The amendment broadens the range of people able to undertake relevant activities, while preserving assurance through qualifications and method requirements (e.g. provision of site plans, independent expert reports).

Section 5.17F - Introduction of an emissions rate detection limit (kg/hr) for the walkover/ scanning survey

Item 79 of the Update Determination introduces an emissions rate detection limit (kg/hr), alongside existing concentration-based limits (ppm), for the walkover/scanning survey element of the method only (i.e. emissions detection, not quantification).

This recognises that there are multiple technology platforms suitable for detection (including continuous monitoring systems and fixed or drone mounted methane sensors), where they meet specified quality criteria (US EPA Alternative Test Methods for scanning, continuous monitoring, and super-emitter detection). The quantification of emissions generated by landfills under Method 2 will continue to be conducted using flux boxes or chambers.

Section 5.17F – Simplify emissions categories and update emissions thresholds for the walkover/scanning surveys

Item 79 of the Update Determination replaces the existing four emission level categories (low, intermediate, elevated and high) with two categories (low and elevated). For concentration-based limits, the point of measurement for areas of low and elevated surface emissions is required to be 50mm from the surface of the landfill.

For areas identified in the low emissions category, the default flux rate of 0.01g CH4 per square meter per hour is unchanged. Areas identified to have elevated methane emissions during a scanning survey are required to be quantified using a flux box or chamber survey.

In addition, two emission level categories were added (low and elevated emissions from wells), to reflect methane emissions from landfill gas wells, including above-surface gas collection infrastructure and the well-ground interface.

For all emission categories, the threshold between low and elevated emissions has been amended from 50 to 25 parts per million.

A comparison of the former and updated thresholds and estimation requirements is provided below

Table 2: Former and amended thresholds for landfill emissions categories

Notes: (a) The kg/h threshold is used only for detection categorisation in scanning surveys; quantification remains by flux box/chamber. (b) The reduced ppm threshold reflects improved precision of newer detection technologies.

Section 5.17F – Transect density for walkover/scanning surveys

Item 76 of the Update Determination increases the spatial density of measurements required in each representative zone during walkover/scanning surveys, while reducing the density required in areas of elevated methane emissions. This improves spatial accuracy for initial detection, while moderating effort in intensive follow up areas. 

Importantly, the update shifts from prescriptive transect spacing to outcome-based spatial resolution, improving flexibility and enabling the use of deployable sensors and varied survey methods.

Table 3: Former and amended spatial density for walkover/scanning surveys

Sections 5.15, 5.17F – Incorporate requirement to account for fugitive emissions from landfill gas wells

The Update Determination adds provisions that enable accounting of fugitive emissions (methane collected but not combusted) from landfill gas wells. This responds to industry feedback that accounting for emissions (and subsequent emission reductions) from this source was not possible under the former methodology.

Item 55 of the Update Determination updates the general equation in subsection 5.15(1)(b) to add the parameter Qlostz, as follows:

Ejz = [CH4genz – Qlostz – γ(Qcapz+ Qflaredz + Qtrz)] x (1 − OF) + Qlostz

Item 57 of the Update Determination defines the parameter Qlostz as “the quantity of methane in landfill gas lost from above-surface gas collection infrastructure (including wellheads, seals and valves) that is not subject to oxidation, from a sub-facility zone during the reporting year, measured in CO2-e tonnes”.

Item 80 of the Update Determination provides default methane gas flow rates to estimate the emissions of methane from landfill gas wells. The following gas flow rates are applied:

• If a scanning or walkover survey detects emissions from landfill gas wells of less than or equal to 25 ppm or less than or equal to1kg/hr within the representative zone, a methane gas flow rate of 0 kg methane/hr/well CH4 is assigned (no emissions).
• If a scanning or walkover survey detects emissions from landfill gas wells of greater than 25 ppm or greater than 1kg/hr within the representative zone:
  • determine the methane emissions flow rate from above-surface landfill gas well infrastructure:

-          if measured internal pressure is less than atmospheric, apply a flow rate of zero;

-          if not, use a calibrated vent bag or similar to measure the volumetric gas flow rate.

• Determine the methane emissions from the base of the landfill gas well using a flux box or chamber.
• Alternatively, apply a methane gas flow rate of 2.9 kg methane/hr/ well, representing total emissions from both the above-surface gas well infrastructure and the base of the well.

Total methane generated, collected and lost through above-surface well infrastructure in each representative zone must be calculated by multiplying the number of wells in each representative zone by the appropriate gas flow rate.

Total methane generated, collected and lost through the surface at the base of the landfill gas well are measured using flux box/chambers and incorporated with other elevated surface emissions measurements.

This amendment responds to stakeholder feedback that Method 2 did not explicitly allow for fugitive emissions from landfill gas wells, limiting calibration accuracy, recognition of emission reductions activities and well maintenance. It also clarifies that emissions from above-surface well infrastructure are not subject to oxidation.

Section 5.17D – Streamline method for measuring volume of gas collected

Item 70 of the Update Determination aligns the approach for estimating total gas collected with that used in other parts of Method 2, allowing reporters to use centrally located flow and gas composition meters at flares, gensets and other key infrastructure, rather than measuring each well individually throughout the reporting year.

Item 71 of the Update Determination reduces the frequency of data collection from monthly to yearly.

These amendments respond to stakeholder feedback on the resource intensity of the previous approach, particularly for large sites with high numbers of wells, and addresses practical constrains such as limited accessibility and monthly variability.

Sections 5.17H, 5.17K, 5.17L – Clarify the process for site measurements and emission estimation

Items 81, 85 and 86 of the Update Determination add provisions to clarify that:

• For each measurement event, the gas flow rate of each flux box or chamber in the representative zone/s must be measured using the equation in 5.17H(2)
• The measurement of emissions by flux box or chamber must be undertaken at least 4 times over a 12-month period, with no less than 2 and no more than 4 months between successive measurements.  
• The total gas flow rate for each representative zone must be worked out using geospatial interpolation methods. Guidance on relevant techniques, such as arithmetic mean or kriging mean will be provided in the Landfill site plan and verification requirements (methods 2 and 3) document, available at www.cer.gov.au.
• For each measurement event, the gas flow rate in each representative zone must be calculated as the average of the summed measurements taken in each measurement event.

Throughout Method 2 – Improved clarity on application of method

The Update Determination clarifies the frequency of measurement activities by specifying that:

• Representative zones: there must be one representative zone in each sub facility zone,
• Point of measurement (scanning): the point of measurement for handheld measurement devices must be 50mm from the landfill surface for scanning surveys, aligning with Victorian and New South Wales EPA guidance,
• Adjusted methane decay constant (kiadj): must be re-calculated if either of the following apply:

• it has not been worked out in the current reporting year
• if, after calibration, measured collection exceeds modelled generation (collection efficiency exceeds 100%).

Updates to Division 5.2.2 Method 1 – updates to estimation of emissions of methane released from landfills

Section 5.4 – Consequential amendments – relocation of CEL provisions from Method 2

Item 48 of the Update Determination relocates the collection efficiency limit (CEL) provisions from Section 5.15C (Method 2) to Section 5.4(5) (Method 1). This does not change the application of the CEL in Method 1, only the location and numbering of provisions. A number of additional minor amendments to method 1 to improve method clarity and accuracy are made.

Section 5.11 – Updated waste mix default compositions

The department commissioned a review of solid waste composition in 2025 and has incorporated the findings into an update of the default waste mix compositions to reflect updated waste collection practices such as food and garden organics source separation.

Items 52 to 53 of the Update Determination update the default waste stream percentages in Section 5.11, for the following waste streams:   

• Municipal solid waste Class I,
• Municipal solid waste Class II,
• Commercial and industrial waste.

This amendment responds to stakeholder feedback that the former default waste stream percentages were becoming outdated, having last been reviewed in 2014. The amendment also ensures alignment between the Measurement Determination and the National Greenhouse Accounts.  

Section 5.12 – Update to fraction of degradable organic carbon dissimilated (DOCf ) value for wood

Item 54 of the Update Determination corrects the DOCf value for wood, revising it from 0.23 to 0.10. This update ensures consistency between the Measurement Determination and the National Greenhouse Accounts (National Inventory and NGA Factors).

Updates to estimation of emissions of methane released from wastewater treatment

Subsections 5.23(1) and 5.40(1) – Update to enable reporting of zero emissions from managed aerobic ponds 

Item 88 of the Update Determination responds to feedback regarding ambiguity in the application provisions for reporters utilising managed aerobic ponds. The former wording was not clear as to how these provisions applied where managed aerobic treatment systems were utilised to such an extent that methane generation was completely avoided and there are no emissions.

The update clarifies that the relevant Parts apply in circumstances where emissions are avoided through the use of managed aerobic treatment systems. Furthermore, it confirms that no emissions threshold is required for the inclusion of this activity under the determination (ie. zero emissions should still be reported).  

Subsection 5.25(5)  – Update to emission factor for wastewater and sludge (EFwij and EFslij)

Items 89 and 90 of the Update Determination correct the default emission factor (EF) for wastewater and sludge, which is based on Equation 6.2 of the 2006 IPCC Guidelines (0.25 kg CH₄ per kg COD).

In NGER, the EF is expressed in CO₂-e by applying the IPCC Assessment Report 4 global warming potential (GWP) for methane (25). This results in:

0.25 kg CH4/ kg COD x 25 = 6.3 kg CO2-e/kg COD.

The update applies the IPCC Assessment Report 5 GWP value for methane (28), making the calculation:

0.25 kg CH4/ kg COD x 28 = 7.0 kg CO2-e/kg COD.

Updating the GWP ensures consistency with the national inventory and the latest IPCC guidance and Paris Agreement. Additionally, minor formatting updates are proposed as tracked below:

Updates to wastewater EFs are summarised below:

• EFwij is the default methane emission factor for wastewater with a value of 7.0 tonnes CO2-e per tonne COD.
• EFslij is the default methane emission factor for sludge with a value of 7.0 tonnes CO2-e per tonne COD (sludge).

Scope 2 emissions from consumption of electricity

Proposed Scope 2 emission factors for the 2026-27 NGER reporting year

The Update Determination updates scope 2 location- and market-based emission factors for the 2026-27 reporting year based on on-grid generation and emissions in the preceding reporting year.

Emissions estimates used in the calculation of scope-2 emission factors include methane produced by the decomposition of organic matter in water storage dams associated with hydroelectric generation. Revisions to these estimates have been made to incorporate higher resolution data that can reflect changes in average water surface levels across different years. This results in a reduction of around 9% for the Tasmanian location-based emission factor, reflecting lower water storage level conditions than previously accounted for. 

Update to matters to be identified under Schedule 4

Item 2 of Part 7 of Schedule 4 of the Measurement Determination currently states that when any of Method A1, A2 or B is used, information on the supplying generators is required in order to determine the scope 2 emissions of the supplied/consumed electricity when it is sourced from “other sources”. This is intended to mean off grid generators directly connected to the consuming facility .  

This information is not applicable or relevant to the consumption of electricity from the grid (with a known scope 2 emissions factor) using Method A1, or when derived using the Market Method B.

The Update Determination removes references to Method A1 and Method B in Item 2 of the table.

Other changes

Emission factors for Euro V and Euro VI diesel trucks

Item 110 of the Update Determination adds scope 1 emission factors for combustion of diesel in Euro V and Euro VI trucks. The inclusion of these factors reflects that Australia’s heavy vehicle emissions control standards are now, through ADR 80/04, at a Euro VI equivalent level (see Vehicle Standard (Australian Design Rule 80/04 – Emission Control for Heavy Vehicles) 2023).

CH4 and N2O scope 1 emission factors for Euro V and Euro VI trucks are derived based on factors available in the 2025 update to the EMEP/EEA air pollutant emission inventory guidebook 2023 and supporting appendix titled 1.A.3.b.i-iv Road Transport Appendix 4 Emission Factors 2025. The EMEP/EEA guidebook provides factors in terms of grams per kilometre (g/km) travelled for rigid and articulated trucks of different mass classes. Factors in terms of g/km were converted to kg CO2-e/GJ based on fuel consumption rates in the most recent Australian Bureau of Statistics Survey of Motor Vehicle Use. To derive technology-weighted factors for including in Division 4.3 of Schedule 1 of the Measurement Determination, representative factors for the rigid and articulated truck segments were weighted based on the proportion of light rigid, heavy rigid and articulated trucks in the Australian truck fleet, as reported in the Bureau of Infrastructure and Transport Research Economics Road Vehicles, Australia, January 2025 vehicle census.

The CH4 emission factor for Euro V and Euro VI trucks is lower than the Euro IV factor, whereas the N2O emission factor is higher. This is despite Euro V and Euro VI being more stringent vehicle emission standards than Euro IV. This reflects that Euro vehicle emission standards, and heavy vehicle emission control ADRs based on Euro standards, primarily set limits on emissions of oxides of nitrogen (NOx), total hydrocarbons (HC) and particulates. They do not set explicit limits on greenhouse gases such as CO2, CH4 and N2O. As explained in the EMEP/EEA guidebook, more sophisticated NOx emissions control technologies in Euro V and Euro VI vehicles can lead to higher N2O emissions.

Update to the rules for assessing the uncertainty of methane and nitrous oxide emissions from combustion of liquid fuels estimated using method 2

Item 96 and 97 of the Update Determination makes amendments to allow reporters who estimate scope 1 emissions of CH4 and N2O from liquid fuel combustion using method 2 to assess the uncertainty of those estimates in accordance with the rules for assessing the uncertainty of estimates made using method 1.

Formerly, reporters who estimated emissions of CH4 and N2O from liquid fuel combustion using method 2 were required to assess the uncertainty of these estimates manually using the Uncertainty Protocol in accordance with Part 8.4 of the Measurement Determination. Reporters were unable to use the auto-calculate function in the Clean Energy Regulator’s Emissions and Energy Reporting System (EERS) that is available to reporters who estimate emissions using method 1. This created additional reporting burden for reporters who elected to use method 2. This is despite method 2 for estimating emissions of CH4 and N2O from liquid fuel combustion being the same as method 1, but with different technology specific emission factors. Method 2 for estimating emissions of CH4 and N2O from liquid fuel combustion does not involve any facility specific testing, sampling or analysis, for which the uncertainty would need to be assessed on a facility basis in accordance with the Uncertainty Protocol. The 50% emission factor uncertainty in section 8.7 for method 1 default CH4 and N2O liquid fuel emission factors is also applicable for the technology specific factors used under method 2.

To reduce unnecessary reporting burden, the Update Determination allows reporters to assess uncertainty in accordance with section 8.7, aligning the approach with estimates made using method 1.

ATTACHMENT A

National Greenhouse and Energy Reporting (Measurement) Amendment (2026 Update) Determination 2026

Section 1 – Name

This section provides that the title of the instrument is the National Greenhouse and Energy Reporting (Measurement) Amendment (2026 Update) Determination 2026 (the Update Determination).

Section 2 – Commencement

This section provides that the commencement of the Update Determination would commence on 1 July 2026.

Section 3 – Authority

This section outlines that the Update Determination is made under subsection 10(3) of the Act. The power to make legislative instruments under this subsection includes the power to amend or revoke instruments that have already been made, with any doubt about this resolved by subsection 33(3) of the Acts Interpretation Act 1901.

Section 4 – Schedules

This section provides that the amendments are outlined at Schedule 1.

Schedule 1—Amendments

ATTACHMENT B

Statement of Compatibility with Human Rights

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

National Greenhouse and Energy Reporting (Measurement) Amendment (2026 Update) Determination 2026

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

Overview of the Legislative Instrument

The National Greenhouse and Energy Reporting (Measurement) Amendment (2026 Update) Determination 2026 makes amendments to the National Greenhouse and Energy Reporting (Measurement) Determination 2008 for the purpose of:

• Renewable fuels:
  • Introducing provisions for the reporting of scope 1 emissions from consumption of co-processed liquid fuels,
  • Adding bioLPG as a reportable fuel type,
  • Making a minor update to the definition of biomethane displacement ACCU in the renewable gas market-based reporting arrangements,
• Fugitive emissions from coal mines:
  • Updating the Australian Standard for gas desorption testing undertaken on or after 1 July 2027, under Method 2 for estimating emissions from the extraction of coal from open cut mines,
  • Making other minor technical updates to improve clarity,
• Fugitive emissions from oil and gas:
  • Making clear, including via a supporting interpretative Note, when flaring methods should be applied.
  • Updating Method 2A for flared emissions of methane and nitrous oxide from oil or gas exploration and development,
  • Expanding the availability of Method 2B (mass balance approach) for flared emissions from gas extraction and development sources,
  • Making minor editorial updates to Method 2B flaring note 2, available methods for flaring from natural gas production and Schedule 4 Part 2 matters to be identified (MTBI) to improve clarity,
  • Updating Method 2 for emissions from natural gas transmission to improve its usability and coverage of equipment types,
  • Adding an option to Method 3 for LNG leakage emissions that enables greater use of facility-specific measurement,
  • Updating Method 3 for emissions from natural gas distribution to account for hydrogen content,
  • Updating MTBI for Method 2 for emissions from produced water, for venting emissions from oil and gas activities, and for Method 1 for mud degassing in oil and gas exploration and development,
• Emissions of methane released from landfills:
  • Updating Method 2 to expand the range of eligible detection technologies, provide more specificity for measurement of emissions and remove the collection efficiency limit (CEL),
  • Making consequential changes to Method 1 following the changes to Method 2,
  • Updating default waste composition values in Method 1 to reflect modern disposal practices,
• Emissions from wastewater treatment:
  • Enabling reporting of zero emissions from managed aerobic ponds,
  • Updating emission factors for wastewater and sludge,
• Scope 2 emissions:
  • Updating emission factors for the 2026-27 reporting year,
  • Updating matters to be identified under Schedule 4,
• Other changes:
  • Adding new emission factors for liquid fuels combusted in Euro V and Euro VI trucks,
  • Updating the rules for assessing the uncertainty of methane and nitrous oxide emissions from combustion of liquid fuels estimated using method 2.

Human rights implications

This Legislative Instrument does not engage any of the applicable human rights or freedoms.

Conclusion

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

The Hon Chris Bowen MP

Minister for Climate Change and Energy

[1] National Greenhouse and Energy Reporting (Measurement) Amendment (2024 Update) Determination 2024 (version F2024L00823)

[2] National Greenhouse and Energy Reporting (Measurement) Amendment (2025 Update) Determination 2025 (version F2025L00671)

[3] National Greenhouse and Energy Reporting (Measurement) Amendment (2024 Update) Determination 2024 (version F2024L00823)

[4] https://www.api.org/~/media/files/ehs/climate-change/api-lng-ghg-emissions-guidelines-05-2015.pdf

[5] 2027 IPCC Methodology Report on Inventories for Short-lived Climate Forcers — IPCC