2025 Basis of Reporting

A fatality is a death of a worker⁴  resulting from an injury as a result of a work-related incident or an occupational disease.

Fatalities as a result of occupational injuries and diseases are differentiated in our HSEC&HR database.

A lost time injury (LTI) is an occupational injury that is recorded when a worker is unable to work following a work-related incident.

We record lost days as beginning on the first rostered day that the worker is absent after the day of the work-related injury. The day of the work-related injury is not included. LTIs do not include restricted work injuries (RWIs) and fatalities.

The lost time injury frequency rate (LTIFR) is the total number of LTIs recorded in the reporting period compared to the total hours worked: 

LTIFR = LTIs/hours worked* 1,000,000

The LTIFR is calculated by the Glencore HSEC&HR Database based on the reported number of LTIs and the hours worked.

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

A medical treatment injury (MTI) is an occupational injury not classified as an LTI or RWI, which requires treatment beyond first aid. 

Medical treatment is defined as occurring when a work-related injury of a worker requires a higher degree of patient management to ensure a full recovery.

The total recordable injury frequency rate (TRIFR) is the total number of TRIs recorded in the reporting period compared to the total hours worked:

TRIFR = TRIs/hours worked* 1,000,000

The TRIFR is calculated by the Glencore HSEC&HR Database based on the reported number of TRIs and the hours worked.

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

An actual environmental incident is any event that causes damage or loss to the environment, including spills containing contaminants or non-compliant disposal of waste, discharges and abstractions, gaseous or particulate emissions to the atmosphere, subsidence or sink holes, harm to biodiversity and rehabilitation/land, as well as harm as a result of noise, odour, blast or vibration.
We classify the severity of environmental incidents on a five-point scale:

• category 1: negligible;
• category 2: minor;
• category 3: moderate;
• category 4: major; and
• category 5: catastrophic.

We consider incidents occurring on or off-site, with widespread, but reversible, environmental impact to ecosystems, habitats, or species (2 to 10 years to remediate) as major environmental incidents, and unconfined and widespread incidents, with widespread environmental impact to ecosystems, habitats, or species (irreversible, or >10 years to remediate) as catastrophic environmental incidents.

Direct energy consumption
Primary energy used by our industrial assets including energy generated by combustion in our boilers, furnaces and vehicles. Sources include coal, coke, diesel, gasoline, biomass, biodiesel, fuel oil, jet fuel, kerosene, LPG, naphtha, natural gas, propane and electricity generated from renewable sources and coal seam emissions or electricity recovered on-site or off-site and supplied via an exclusive, direct physical link.

Indirect energy consumption
Secondary energy used by our industrial assets which are generated and supplied by third parties. This includes electricity, steam and heat/cooling. Where our industrial assets are supplied with energy from another of our industrial sites (within our organisational boundary of operational control) via a wider grid rather than an exclusive, direct physical link, we account for this as indirect energy.

Energy-related data is entered by our industrial assets based on the Glencore Emissions and Energy Reporting Procedure (EERP).

This requires the reporting of the activity data (i.e., quantity consumed) while the energy related to the consumed fuels is automatically calculated by the HSEC&HR database based on the net calorific values provided by the IPCC.⁵

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

Our CO₂e emission reporting of our industrial assets generally follows the GHG Protocol’s Corporate Accounting and Reporting Standard, the Scope 2 Guidance, the Corporate Value Chain (Scope 3) Accounting & Reporting Standard and Technical Guidance for Calculating Scope 3 Emissions, and the ICMM Scope 3 Emissions Accounting and Reporting Guidance. Our approach is set out in our EERP.

Our CO₂e emissions include CO₂, CH₄ and N₂O. Other GHGs are not included, pursuant to our most recent materiality assessment, which concluded that their contribution to the overall CO₂e emissions of our industrial assets is sufficiently small so as to be immaterial in the context of our industrial CO₂e emissions profile.⁶ 

Our CO₂e emissions are converted based on the IPCC’s Sixth Assessment Report, 2021 (AR6), GWP values for 100-year time horizon, where the granularity of the published emission factors allows such a conversion. 
 

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

CO₂e emissions generated by the industrial assets (i.e., direct CO₂e emissions) under our operational control, including those stemming from the following activities:

• stationary combustion (such as boilers and generation plants, and including flaring if relevant);
• mobile combustion (such as vehicles, drilling and hauling plant and equipment);
• process emissions (such as vented CO₂ or methane, emissions from roasting of calcium carbonate, or use of reductants); and
• fugitive emissions (uncontrolled emissions such as coal seam emissions).

By source, our scope 1 emissions include the following at our industrial assets: 

• CO₂e emissions from consumption of fossil fuels, including coal and coke as solid fossil fuels, diesel and other oil products as liquid fossil fuels, as well as natural gas, refinery gas and other gas-based fossil fuels as gaseous fossil fuels;
• CO₂e emissions from consumption of reductants, i.e., carbon-based materials, for the chemical reduction of metal oxides;
• CO₂e emissions from fossil fuel extraction, i.e., coal seam emissions from the production of coal, which primarily represent a mix of methane and CO₂: 
  • coal seam emissions from our underground coal industrial assets, primarily involving methane; 
  • CO₂e emissions from open pit mining as well as from stockpiling coal prior to its sale; and
  • CO₂e emissions from decommissioned/closed coal mines; and
• other direct CO₂e emissions include those not covered in the above, directly caused by process activities (e.g., CO₂e from the use of recyclable materials or carbonates). 

Our scope 1 emissions-related data is entered into our HSEC&HR database by our industrial assets based on the EERP. Depending on the indicator, the scope 1 emissions are either entered as activity data (i.e., quantity of consumed fuels) and automatically converted by means of material-specific emission factors into scope 1 emissions by the HSEC&HR database, or directly entered as scope 1 emissions by the relevant industrial assets (e.g., coal seam emissions, CO2e emissions related to processes that are not covered elsewhere).

The applied emission factors are primarily based on the IPCC and the related GHG Protocol as shown in Additional information, Appendix 1.

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

Scope 2 emissions are indirect CO₂e emissions associated with the generation of purchased electricity, steam, and heat/cooling (purchased power) which is consumed by the industrial assets under our operational control. These CO₂e emissions are considered indirect as they are a consequence of our industrial assets’ activities but are emitted at sources outside our organisational boundary, i.e., third-party electricity generators or utilities.

Scope 2 emissions cover the CO₂e emissions from the generation of purchased power which is consumed by our industrial assets. Other upstream CO₂e emissions associated with the third-party production and processing of upstream fuels, and the transmission and distribution of energy within a grid, are considered scope 3, category 3 emissions. CO₂e emissions from energy generation at our industrial assets with an exclusive, direct physical link to our industrial assets are accounted for in our scope 1 emissions. Where our industrial assets are supplied with electricity from energy generation at another of our industrial sites (within our organisational boundary of operational control) via a wider grid, we account for them as purchased power. 

Calculating scope 2 emissions requires a method of allocating the CO₂e emissions created by the generation of the purchased power to the end consumers of a given grid. Two methods are used as further explained below:

• location-based method; and
• market-based method.

While the emission source underlying each scope 2 method is the same, the differential between location-based and market-based accounting is the emission factor used to quantify emissions from the generation of purchased power consumed.

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

The location-based method applies the average CO₂e emissions intensity of grids on which the consumption of purchased power physically occurs, regardless of specific qualifying market-based contractual instruments purchased.

This method emphasises the connection between collective consumer demand for electricity and the CO2e emissions resulting from local electricity generation

Scope 2 emissions-related data is entered into our HSEC&HR database by our industrial assets based on the EERP which requires the reporting of the relevant activity data (i.e., quantity of purchased power consumed).

The scope 2 emissions are automatically calculated by our HSEC&HR database, applying the GHG Protocol’s location-based approach. For this, the reported purchased power data is multiplied by the applicable country-specific grid-emission factors.

For most countries, national grid-emission factors are sourced from the annual ‘IEA Emission Factors’ publications produced by the International Energy Agency (IEA). For the following countries, regional emission factors are applied as follows:

We apply the latest versions of the applicable emission factor sources as available at the end of a given reporting year.

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

The market-based method reflects the CO₂e emissions from the generators from which the industrial assets under our operational control contractually obtain purchased power bundled with Energy Attribute Certificates (EACs),⁷  or unbundled purchased power with EACs on their own, and for which specific emissions factors are known.⁸
 

Unlike the location-based method, the market-based approach allows for differentiation in scope 2 emissions calculations if emissions data can be sourced from qualifying contractual instruments. Our EERP and the GHG Protocol specify that to qualify, renewable power claims must:

• be based on contractual arrangements between supplier and consumer;
• be limited to the environmental attributes that have been contractually conveyed;
• have a direct causal relationship between the purchase of electricity and the claimed environmental attributes;
• be legally enforceable;
• be exclusive to the purchasing entity; and
• have a specified start and end date in which renewable energy attributes are valid.

We consider the following qualifying contractual instruments and emissions factors:

• EACs (such as Guarantees of Origin, Renewable Energy Certificates (RECs), or International Renewable Energy Certificate (I-RECs)⁹);
• direct contracts such as power purchase agreements with a specific energy generating unit (PPAs) and contracts from specified sources, where other instruments or EACs do not exist;
• government-approved green power procurement schemes; In some regions, governments or regulatory bodies establish approved renewable power procurement schemes;¹⁰ 
• supplier-specific emission factors; and
• publicly available, official residual emissions factor i.e., representing the mix of energy generation resources within a defined geographic boundary left after all contractual instruments that are tracked have been claimed/retired/cancelled.

Where contractual instruments do not meet the market-based quality criteria, or where our industrial assets operate in markets where qualifying contractual instruments are not available,⁸  we use the location-based emission factors to represent their emissions. For these industrial assets, the calculated market-based scope 2 emissions are identical to the location-based scope 2 emissions.

Scope 2-related data is entered into our HSEC&HR database by our industrial assets based on the EERP, which requires the reporting of the relevant activity data (i.e., quantity of purchased power consumed).

With regards to the applicable emission factors, our process for the calculation and reporting of market-based scope 2 emissions follows various steps:¹¹ 

1. Collect all activity data and emission factor data from contractual instruments meeting the market-based quality criteria. Our industrial assets are required to ensure that they use the most appropriate, accurate, precise and highest quality instruments available in their respective energy markets.^{8, 12}    
2. Assign renewable EAC or equivalent activity data to individual electricity consuming industrial assets and multiply by associated emission factor.
3. If the renewable EACs or equivalents do not account for the entire industrial asset’s activity data, the remaining portion must be accounted for by considering other contractual instruments that meet the quality criteria from the market-based emissions hierarchy.
4. Multiply the remaining portion of activity data by supplier specific or utility provided emission factors.
5. If supplier specific or utility emission factors are not available, multiply the remaining portion of the activity data by the country or regional residual emission factor.
6. If a residual emission factor is not available for a given country or region, multiply the remaining activity data by country or regional average emission factor (i.e., grid emission factors; refer to the Scope 2 emissions – location-based section above).

Residual emission factors are currently applied for the following regions:
 

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics. 

The scope 3 emissions we report on reflect the sum of the value-chain emissions of our industrial assets that are extracting, producing, or processing minerals, metals, steelmaking coal and energy products for sale or further processing reported within the following scope 3 categories: 

• Category 1. Purchased goods and services
• Category 2. Capital goods
• Category 3. Fuel- and energy-related activities
• Category 4. Upstream transportation and distribution
• Category 9. Downstream transportation and distribution
• Category 10. Processing of sold products
• Category 11. Use of sold products  Our assured scope 3 emissions metrics comprise our category 11 emissions, as further set out below. 
• Category 15. Investments

The definitions, method, activity and emissions data sources we use to calculate the scope 3 emissions categories that are not assured metrics are set out in Additional information, Appendix 2 – Non-assured scope 3 emissions categories. 

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

These CO₂e emissions relate to the combustion by our customers of sold coal and refined oil products that our industrial assets produced or processed. We assume that 100% of our sold coal and refined oil products are combusted once received by our customers. 

We account for our equity share of emissions related to the use of saleable coal and oil produced by independently managed joint ventures in scope 3, category 15 (Investments).

We apply the direct use-phase method to calculate emissions related to the use of sold products. This involves multiplying the sold volumes of thermal coal, metallurgical coal, and refined oil products we produced or processed by the fuel-specific combustion emissions factors provided by the IPCC.¹³ 

Most of the coal produced by our industrial assets is sold by our marketing business, which also trades coal produced by third parties. Associated data is stored in our commodity trading management systems. Due to the blending and inventory management activities of both our industrial asset and marketing teams, the volumes of coal produced and procured each year do not typically match the volumes of coal sold. To calculate the quantities of our marketing sales of coal produced by our industrial assets, for each reporting year we remove the quantities of third-party procured coal volumes from our total coal sales data (assuming that quantities of third-party coal we procured equal the quantities of third-party coal we sold in a given year). To this calculated total we add any volumes of coal that were sold directly by our industrial assets during the reporting year. For 2025, this amounted to total sales of 115 million tonnes of thermal and metallurgical coal that were produced by our industrial assets. We compare the resulting total to the total coal production by the industrial assets under our operational control (on a 100% saleable basis), with minimal deviations accepted when they fall within the limits of expected inventory changes. 

For oil volumes processed in our Astron Energy Refinery, we use refined product sales during the reporting period as the basis of our calculations for category 11. Total sales data derived from the Astron Energy Refinery’s trading system is analysed to exclude products that were procured from third-party producers. We compare the resulting sold volumes to the volume of total oil refined by Astron, with minimal deviations accepted when they fall within the limits of expected inventory changes. For 2025, sales of oil products that were processed by our Astron Energy Refinery amounted to 32.3 million bbls. 

Water input includes water that is withdrawn from the environment (surface water, groundwater, seawater, precipitation, or water that is entrained in ore extracted from the ground) or provided by third parties (this covers supplied potable water and water of lower quality, e.g., treated wastewater that can be used for production purposes). 

This category excludes diverted water, which is actively managed (e.g., physically pumped, actively treated, or has material consumptive losses) by our industrial assets but does not enter the operational water system used to supply the operational water demand (i.e., other managed water that is not used by our industrial assets in an operational task or activity).

Water-related data needs to be reported by our industrial assets in our HSEC&HR database, in accordance with the Glencore Environment Standard and Water Reporting Guideline which is aligned with ICMM Guidance.¹⁴  Generally, water input is reported using invoices or meters. Where neither water meters nor invoices for water use are available, water-input may be reported based on water models or other calculations based on assumptions.

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

Water output includes water that our industrial assets release back to the water environment (surface water, groundwater or seawater) or to a third party. 

Water output excludes diverted water that is actively managed (e.g., physically pumped, actively treated, or has material consumptive losses) by our industrial assets but does not enter the operational water system used to supply the operational water demand (i.e., other managed water  that is not used by our industrial assets in an operational task or activity).

Water-related data needs to be reported by our industrial assets in our HSEC&HR database, in accordance with the Glencore Environment Standard and Water Reporting Guideline which is aligned with ICMM Guidance.¹⁵  Generally, water output is reported using meters. Where water meters are not available, water-output may be reported based on water models or other calculations based on assumptions.

Refer to the Data processing and reporting methodology in general regarding the overall data processing and reporting methodology applied to the metrics.

All relevant tax, royalty and levy payments made to the governments, as well as relevant refunds received from the governments of the countries in which we operate based on the boundaries and scope defined in the Organisational boundaries and Operational boundaries subsections, as required by local and national regulation.

This includes local, national, sales and employment taxes, government royalties and licence and permitting fees, as well as diesel rebates, government subsidies and various refunds or credits from business tax incentives programs reported on a cash-paid basis during the reporting period.