Climate-related metrics

Index: 29(a) maps to 13.1 and 17.4; 29(b)–(d) to 14.3; 29(e) to 12.1; 29(f) to 12.2; 29(g) to 16.2.1.

Emissions, MtCO2e (13.1, p.112). Scope 2 is location-based; FY26 is estimated.

FY26 Scope 3 is 8.3 (supply of electricity to customers), 5.4 (supply of natural gas to customers), 9.4 (end use of coal sold to Loy Yang B) and 0.7 other; material sources fall in GHG Protocol Category 3 and Category 11 (p.144). FY25 Scope 3 was restated to an updated calculation methodology (pp.112, 145). Scope 1 and 2 follow the NGER (Measurement) Determination for facilities under operational control; no material non-consolidated entities are excluded (pp.144–145). AGL adopted relief C4(b) for Scope 3 and C3 for comparatives, and reports selected Scope 3 and comparative data voluntarily (p.106).

Other metrics. Capital deployment: $573 million climate solutions capex (42% of total) and $156 million gas-powered generation (p.109). Carbon price: the potential future cost of carbon offsets is considered in financial planning and capital approvals, using approximately $20/tCO2e (nominal) on average over FY36–FY50 (p.110). Remuneration: 7.8% of executive remuneration linked to climate (p.138).

Greenhouse gas emissions

AMP seeks to minimise emissions from operational activities where practicable and offsets residual emissions by purchasing and retiring Australian Carbon Credit Units and Verified Carbon Standard offsets. Since 2013, we have offset our annual operational Scope 1 and 2 emissions, as well as Scope 3 emissions associated with business travel. We have measured our operational emissions (Scope 1 and Scope 2) per the Greenhouse Gas Protocol. Further information regarding our Scope 1 and Scope 2 greenhouse gas emissions methodology, assumptions and exclusions can be found in AMP's 2025 Greenhouse gas reporting criteria.

AMP has adopted the transitional relief provided under AASB S2 paragraph C4(b), which permits entities not to disclose Scope 3 greenhouse gas emissions in their first annual reporting period applying AASB S2. While this exemption applies to AMP's mandatory disclosures, AMP has voluntarily reported selected categories of Scope 3 greenhouse gas emissions in the "Managing our own operations" section of the Sustainability supplement to provide additional transparency.

AMP has adopted the transitional relief provided under AASB S2 paragraph C3, which provides an exemption from disclosing comparative information in the first annual reporting period in which it applies AASB S2.

Scope 1 and Scope 2 market‑based greenhouse gas emissions are presented post‑consideration of green energy purchased, and pre‑consideration of carbon offsets purchased and retired subsequent to the reporting period.

AMP New Zealand Wealth Management holds a contract with Ecotricity for electricity supply to its New Zealand offices where electricity consumption is matched with renewable electricity on an annualised basis. Associated emissions are measured, minimised and offset, and independently verified by Toitū Envirocare.

Physical risks

As a financial services organisation operating primarily in the capital cities of Australia and New Zealand, AMP does not have direct operations in industry, sectors or locations that are considered highly exposed to climate‑related physical or transition risks. While our Australian and New Zealand wealth management businesses manage diversified and single sector investment portfolios on behalf of members that may have exposure to such risks through underlying investments, AMP does not own these investments and hence there is no direct impact on our financial position as the underlying assets are not recognised in AMP's balance sheet in accordance with the requirements of accounting standards. Additionally, AMP Bank does not provide business financing to industries typically associated with elevated climate risk, and therefore has limited direct exposure there. To better understand our exposure to physical climate risks in respect of the residential mortgage portfolio, AMP conducted a vulnerability assessment of the portfolio using suburb‑level data to identify areas potentially exposed to climate‑related hazards. This analysis indicates less than 0.5% of AMP's residential mortgage book as at 31 December 2025 is located in the elevated climate risk zone.

Internal carbon prices

Internal carbon pricing is used within AMP's scenario analysis and in respect of our decisions on carbon offset purchases. In relation to the purchase of carbon credits to offset the unavoidable carbon emissions of AMP, the internal carbon price of $34/tCO2‑e is applied. The high emissions scenario assumes a global carbon price of $34/tCO2‑e in 2025, decreasing to $27/tCO2‑e by 2050. On the other hand, the net zero by 2050 scenario assumes a price of $34/tCO2‑e carbon price in 2025, increasing to $138/tCO2‑e by 2050.

Remuneration

AMP's executive remuneration framework does not include direct climate‑related performance metrics. There is no linkage between executive remuneration outcomes and climate‑related risks or opportunities at this time.

Greenhouse gas emissions

Methodology (4.1)

Scope 1 and 2 GHG emissions are measured in accordance with the Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (2004) except for Ampol's Australian assets and operations, which are within scope of the National Greenhouse and Energy Reporting scheme (NGERs). Ampol has applied the Australian Sustainability Reporting Standard AASB S2025-1 Amendments to Greenhouse Gas Emissions Disclosures, which allows it to align Australian emissions reporting to NGERs methodology rather than the GHG Protocol (2004). Ampol applies an operational control approach to define its organisational boundary. Ampol prioritises data reflecting actual GHG emissions from operational activities or value chain activities; where such data does not exist or is not practically available, Ampol relies on estimates using proxies such as emissions factors combined with known economic output information. Scope 3 emissions calculations combine direct measurement and estimates where necessary, prioritising inputs/assumptions based on the Scope 3 measurement framework within AASB S2; certain categories are estimated using industry assumptions rather than supplier/customer specific data. The GHG Protocol Corporate Value Chain (Scope 3) Accounting and Reporting Standard (2011) establishes 15 categories, divided into Upstream (eight categories) and Downstream (seven categories) emissions. There were no changes in the measurement approach, inputs or assumptions in the current period.

Ampol has adopted the transitional relief provided under AASB S2 paragraph C4(b) which allows it to not disclose Scope 3 GHG emissions in its first annual reporting period; Ampol has elected to voluntarily report selected Scope 3 GHG emissions to provide additional transparency.

2025 operational greenhouse gas emissions (4.2)

In the period 1 January – 31 December 2025, Ampol's total absolute gross Scope 1 and 2 GHG emissions were 887,517 tCO2e, comprising 687,328 tCO2e Scope 1 and 200,189 tCO2e Scope 2 (location-based). Market-based Scope 2 GHG emissions for Australian assets only were 208,555 tCO2e. 99.58% of the Group's Scope 1 and 2 GHG emissions are in Australia, measured in accordance with NGERs (emissions factors from NGER (Measurement) Determination compilation 18 for 1 Jan–30 June 2025 and compilation 19 for 1 July–31 Dec 2025). The remaining 0.42% (New Zealand and rest of world) are measured in accordance with the GHG Protocol (2004), applying emissions factors from the New Zealand Ministry for the Environment, the Singapore Emissions Factors Registry, and the US Environmental Protection Agency. Group operational GHG emissions rose by 1.7% in 2025 due to an increase in Scope 1 emissions from Lytton refinery, resulting from isolated cases of increased flaring and reduced energy efficiency including extension of planned turnaround/inspection activity and proactive preparations for Cyclone Alfred. Scope 2 emissions are measured using the location-based method reflecting average emissions factors of the electricity grids consumed. As part of its transition plan, Ampol entered into an electricity retail agreement with Alinta Energy (operating wind farm), matching approximately 4% of total electricity consumption; this arrangement ended in November 2025 and was replaced with a new ~100 MW Power Purchase Agreement linked to an operating wind farm in New South Wales, under which renewable energy certificates are provided for Ampol's own use.

2025 value chain greenhouse gas emissions (4.3)

Ampol's Scope 3 inventory includes 11 of the 15 categories established by the GHG Protocol Corporate Value Chain (Scope 3) Standard (2011); reviewed whenever there is a significant event/change affecting the value chain. Ampol does not have emissions associated with processing of sold products (Category 10); remaining excluded categories deemed immaterial through relevance testing. In 2025, Ampol's Scope 3 emissions were 63,273,854 tCO2e. Upstream categories represented around 18% of Scope 3 emissions, with purchasing/shipment of crude oil and finished product (Category 1) the most material, accounting for 15% of total Scope 3 emissions. Downstream categories accounted for the other 82%, principally use of sold products (Category 11), accounting for 82% of total Scope 3 emissions.

Percentage emissions share for key aspects of Ampol's oil value chain: Emissions from oil production 16.2%; Transport of crude oil and refined product 2.1%; Emissions from oil refining 1.5%; Distribution and supply of refined oil products to end-users 0.2%; Emissions from use of sold products 80.0%; Total emissions 100.0%.

(2024 calendar year operational emissions have not been subject to assurance.)

Transition risks

Vulnerability of business activities to climate-related transition risks (4.4)

Financial Statements Note B1 Revenue and other income indicates a measure of the Group's exposure to the risk of declining demand for traditional fuels, comparing gasoline sales to sales of diesel, jet fuels (expected to be more resilient) and lubricants/other products. In 2025, revenue from sale of gasoline was approximately 24.6% of the Group's total revenue, with non-fuel income representing approximately 3.3%. Ampol has several credible levers to manage its asset portfolio as volumes decline such that minimal stranded assets are anticipated as a result of transition risks, including: closing leased sites; conversion of existing retail assets to alternative formats (U-GO, EV charging hubs); sale of surplus owned assets as network is rationalised; combining supply chain infrastructure (terminals/pipelines) with other market participants in joint ventures, releasing surplus land; and Lytton refinery planned for conversion to an import terminal with optionality as a lower carbon liquid fuels manufacturing facility or other industrial applications.

Physical risks

Vulnerability of assets to climate-related physical risks (4.5)

Ampol engaged an external risk specialist to undertake climate-related physical hazard modelling across different warming scenarios. A physical risk vulnerability assessment was completed over all 1,217 of Ampol's physical assets (service stations, manufacturing facilities, terminals, pump stations, pipelines, depots, offices and data centres) for five climate indicators: extreme weather, fire, flood, heat and precipitation. Materiality was established using an overall risk rating of "Very High" or "Excessively High" under the Group Operational Risk Matrix. The vulnerability assessment showed: across all asset types, 99.9% have a "Low" vulnerability rating, while only 0.1% have a "Medium" vulnerability rating; among business units, the refinery exhibits a higher vulnerability rating to extreme weather events (floods, heavy precipitation, wildfires) compared to retail, distribution and other general assets. Given these results relative to the "Very High" materiality rating, climate-related physical risks do not currently pose a material physical risk to Ampol's assets or business activities under any of the selected scenarios or timeframes. During Cyclone Alfred in 2025, Lytton refinery was proactively placed into safe recirculation mode; extreme weather caused damage to a crude storage tank, with clean-up/repair/demurrage costs of $12.1 million net of insurance recoveries to date of $15.0 million.

Opportunities

Amount of business activities aligned to climate-related opportunities (4.6)

In 2025, revenue from sale of EV charging and lower carbon liquid fuels more than tripled, though very minor relative to overall Group revenue, representing approximately 0.04% of Group revenue.

Capital deployment

Capital deployment (4.7)

Ampol continued to invest in climate-related opportunities, including a further $42.6 million in 2025. Total capital expenditure in both 2024 and 2025 includes significant investment in the Ultra Low Sulfur Fuels project intended to enable the refinery to manufacture gasoline reducing tailpipe sulfur emissions and enable import of more fuel efficient vehicle models.

Internal carbon prices

Use of an internal (shadow) carbon price (4.8.4)

Ampol uses an internal decision-making framework for reviewing material investments/business cases considered by the Investment Committee, including alignment with the Group's strategy to address the energy transition and potential impacts on operating costs from carbon pricing regulation. Ampol assesses potential impacts through an internal shadow carbon price for Scope 1 and 2 emissions in Australia, applying costs to carbon emissions for significant capital investments where applicable. In New Zealand, the NZ ETS puts a price on carbon requiring participants to buy or earn NZUs; Z Energy's surrender obligation is applied to fuel imports and passed on to customers through the supply chain. Ampol's internal carbon price is set with reference to external benchmarks, including spot prices and forward curves for ACCUs and NZUs in the short-to-medium term, and World Bank forecasts (State and Trends of Carbon Pricing Report May 2024 for the 2°C scenario) in the long term; pricing and assumptions reviewed quarterly. As at 31 December 2025, adopted carbon prices ranged from $39 (2026) to $61 (by 2030) for ACCUs, and NZ$38 (2026) to NZ$44 (by 2030) for NZUs. In New Zealand, the carbon price is a real cost rather than a shadow impact.

Remuneration

Remuneration and climate performance (4.8.5)

In 2022 the Board strengthened the link between employee remuneration and delivery of climate-related initiatives. The short-term incentive scorecard includes a climate component of 10% and applies to all Ampol employees eligible to receive a short-term incentive, representing 100% of above-(non) store employees and over 25% of Ampol's total employee base. In 2025, four measures were assessed under the climate component, including rollout of EV charging bays in Australia and New Zealand, and progress against three key operational emissions and emissions intensity reduction targets. The percentage of Senior Executives' remuneration recognised in 2025 that is linked to the climate-related performance measure can be found in the Remuneration Report (not reproduced in this Sustainability Report).

Emissions, equity share (Table 5, page 56). Operated-asset data are in Table 6.

Scope 3 is disclosed voluntarily for limited categories (Table 7): upstream (categories 1-8) 561 ktCO2e, downstream (9, 10, 15) 245 ktCO2e, use of sold products (11) 5,850 ktCO2e, total 6,656 ktCO2e.

Vulnerability (pages 45–52). As a percentage of total assets: physical risk $3,892 million or 72%; transition risk $3,892 million or 72% (Risks 1 to 3), $394 million or 7% (Risk 4) and $4,286 million or 79% (Risk 5). CCS opportunity: current asset alignment is considered to be zero (page 53).

Carbon prices used in FY26 (page 58). Australia A$38/tCO2e for FY27 rising to A$77/tCO2e by FY32 and A$109/tCO2e post 2040; New Zealand NZ$42/tCO2e from FY27 rising to NZ$95/tCO2e by FY32 and NZ$127/tCO2e post 2040.

Remuneration (page 58). 2.5% of the FY26 company scorecard relates to climate performance. Therefore up to 3.25% of the MD & CEO's STI and up to 1.2% of the Executive team's STI is directly related to climate objectives.

Emissions (Table 6, p. 77): unadjusted, operational control boundary, MtCO2-e. BMA is included at 100% (p. 87); Scope 3 is estimated, not directly measured (p. 90).

FY2026 Scope 1 splits into 6.2 (consolidated accounting group) and 1.4 (other investees); location-based Scope 2 into 3.0 and 0.3 (p. 77). Scope 2 contractual instruments: Table 7 (pp. 89–90).

Other metrics (p. 76). Transition risk, physical risk and opportunity metrics are in Table 1 and Figure 4, and capital metrics in Table 1 current financial effects (pp. 66–71). Internal carbon prices: US$0 to US$100 per tCO2-e in FY2026, US$0 to US$250 by FY2050 (p. 64). Remuneration weighted toward decarbonization: 5.1% of total target remuneration for the CEO, on average 5.4% for other Executive KMP (p. 86).

Reliefs (pp. 87–88). Transition relief for comparatives (some voluntarily disclosed); jurisdictional relief, by early adoption of AASB S2025-1, on Global Warming Potential values for Scope 1 under direct measurement.

Scope 1 and 2 GHG emissions (p. 192), absolute gross, without offsets:

Numbers are rounded to the nearest 10 ktCO2-e. Measurement follows the Greenhouse Gas Protocol (2004), except for Australian operations within the NGER scheme, where jurisdictional relief has been adopted (early adoption of AASB S2025-1, p. 175); boundaries use the equity share approach unless superseded by that relief (p. 192).

Other metrics (p. 193). About $1,522M of FY2026 revenue (nine percent of Group consolidated revenue) is associated with activities vulnerable to transition risks and about $15,466M (93 percent) with activities aligned with opportunities. About $8,060M of PPE (over 99 percent of Group total assets, based on the assets included in the assessment) was assessed as vulnerable to physical risks. FY2026 investment under the decarbonization program was $139M, net of grants received for New Zealand's EAF. Carbon prices are applied in investment cases and forecasting; at 30 June 2026 the ACCU price used was $38t/tCO2-e and the NZU price NZ$54.8t/tCO2-e (as printed). Executive remuneration: p. 178.

Greenhouse gas emissions (Table 5, p. 61). Operational control approach; GHG Protocol Corporate Standard (2004); Scope 1 and 2 use NGER methods (pp. 61, 69).

Other metrics (p. 62). High hazard exposure (elevated flood risk): supermarkets 5% (40), liquor stores 5% (47), large facilities 0% (0). Supermarkets with natural refrigerants in use: 16% (141). Capital deployed: $112 million. Shadow carbon price on Scope 1 and 2 in capital projects, per tonne: $56 (FY26–FY28), $78 (FY29–FY32), $100 (FY33–FY35), $140 (FY36–FY40), $170 (FY41 onwards). Remuneration: 10% target weighting for the sustainability measure in the MD & CEO's FY26 short-term incentive (p. 60).

Emissions (p.136); FY25 Scope 1 and Scope 3 are restated.

Reliefs were applied for comparatives and Scope 3, which are given voluntarily (p.91). Emissions follow the GHG Protocol with an operational control boundary (p.357) and cover the consolidated accounting group; other investees were assessed as not material (p.380). Market-based Scope 2 is zero through renewable electricity certificates (p.116).

Vulnerability (pp.120–121). Physical: 2.3% of Group total committed exposures (TCE) ($37.3bn of Australian home loans), covering 47.9% of TCE; corporate physical risk is not quantified. Transition: 4.8% of TCE, covering 92.1%; home loans $24.9bn (1.5%), corporate $52.8bn (3.3%).

Other (pp.132, 141, 376, 380). No amount aligned with opportunities, as none is expected to be material. Capital deployment is represented by sustainability funding ($8.3 billion in FY26; $72.7 billion cumulative); only funding identified as climate-related should be read as such. No internal carbon price. No executive remuneration amount attributable to climate.

Scope 1 and 2 (p. 152).

Calculated in accordance with the Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (2004), using an operational control approach; no changes in measurement calculations or assumptions for Scope 1 and 2 (p. 155).

Other metrics (pp. 152–153). Physical: 41% of modeled sites (7 of 17) exposed, 0% (0 of 17) vulnerable. Transition: projected carbon cost 2030/business unit revenue ($ today) of $22 million for CSL Behring, $3 million for CSL Seqirus, negligible for CSL Vifor. Opportunities: 100% of assets and business activities aligned to the near-term science-based target. Capital: spending on key transition plan initiatives immaterial; renewable energy procurement below $1 million. Carbon price: no shadow internal carbon price in decision making. Remuneration: 5% of the GLT's total short-term incentive (STI) metric linked to sustainability, with the two emissions target objectives comprising 1.65% of total remuneration (p. 144).

Company index: 29(a)(i)–(v), pp. 151–154; 29(b)–(e), pp. 152–153; 29(f), p. 153; 29(g), p. 144.

FY26 GHG emissions (p. 87). The Group's total absolute gross GHG emissions, measured in tonnes of carbon dioxide equivalent (tCO2-e):

Method (pp. 77, 87–88). Measured under the GHG Protocol Corporate Accounting and Reporting Standard, using the operational control approach for the organizational boundary. Scope 2 uses the location-based method. Global Warming Potential (GWP) values are from IPCC's Sixth Assessment Report (AR6), and four gases are considered relevant: CO2, CH4, N2O and HFCs. Scope 1 uses actual refrigerant top-up data where available for a proportion of the portfolio, otherwise area-based estimates. Scope 2 uses utility invoices, with proxy data or area-based estimates where data is missing. The report notes inherent uncertainty from reliance on third party activity data and emission factors (p. 78).

Greenhouse gas emissions, FY26 (p. 75)

Measurement follows the NGER Scheme and the Operational Control approach (pp. 56, 77). Scope 1 is 167,380 consolidated accounting group, 53,538 subcontractor-operated assets and 88 joint arrangements (p. 75). Scope 3 is not disclosed (relief C4(b), pp. 56, 73) and no comparatives are given (relief C3, p. 74).

Other categories (p. 74)

Capital deployment: no material capital expenditures towards climate-related risks and opportunities in FY26. Internal emissions price: none set. Remuneration: a decarbonization element is 10% of the total Short-Term Incentive (STI) scorecard; climate-linked remuneration ranged from 2% to 4% of total Executive Management remuneration.

Scope 1 and 2 GHG emissions (p. 46). Total absolute gross GHG emissions in F26 were 331,989 tonnes of carbon dioxide equivalent (tCO2e):

Figures are for Endeavour Group and its consolidated subsidiaries; the Group does not have joint ventures. Scope 3 is not disclosed: the Group elected the transition relief in AASB S2 Appendix C4(b) for F26 (p. 46).

Measurement (pp. 46–47). Under the National Greenhouse and Energy Reporting Act 2007 (NGER Act) and the GHG Protocol: A Corporate Accounting and Reporting Standard (2004), using the operational control approach. Where primary activity data is unavailable, proxy data per brand and per State is used. Scope 2 follows NGER (Measurement) Determination Method 1A (Location Based Method). No material changes to methodologies; no material contractual instruments affect Scope 2 (p. 47).

Other metrics (pp. 48–49). No sites, operations or activities were identified as materially more vulnerable to physical or transition risks (p. 48). No internal carbon price is applied. Climate-related metrics are not incorporated into ELT or senior leadership remuneration (p. 49).

Greenhouse gas emissions, 2026 (p. 92)

Metrics are rounded. Scope 1 and 2 follow NGER requirements on an operational control basis; other Scope 3 categories and methods are in Note 5 (pp. 99 to 102). No comparatives are given, under the transition relief, and Scope 3 is given voluntarily (pp. 98, 99). No quantitative figure is reported for Scope 1 biogenic emissions (p. 99).

Other metrics. Vulnerability: US$16.7bn of operating sales revenue (98%) for physical risk and market exposure (pp. 76, 78); US$610m of cost of sales, administration and research expenditure attributable to fossil fuels (5%) for policy and regulatory uncertainty (p. 77). Alignment: US$1,945m of property, plant and equipment and intangible assets (9%) (p. 79) and US$360m of non-current assets (2%) (p. 80). Capital deployment: p. 84. Internal carbon price: A$97.92 per tCO2-e (p. 84). Remuneration: cross-referenced (p. 72).

Greenhouse gas emissions

Year in Review Emissions Summary

(Measured against 2019 which provides a benchmark to pre-COVID operating conditions, data as of 31 December 2025. Scope 1 increase attributed to increased refrigerant consumption due to maintenance activities during 2025.)

Appendix B: Environmental performance metrics – Emissions

Measurement approach

GPT's reporting of sustainability data is in accordance with our Basis of Preparation and aligned to the relevant sustainability reporting frameworks of the Global Reporting Initiative (GRI) and the Greenhouse Gas (GHG) Protocol (2004). Annual assurance of any data and metrics is conducted in accordance with relevant assurance standards for non-financial reporting. GPT has obtained limited assurance of the emissions, energy, water and waste metrics as at 31 December 2025.

Scope 1 emissions include base building natural gas and stationary diesel consumption onsite as well as emissions from refrigerant loss. Scope 2 (location-based) reflects the emissions of the electricity grid each asset operates in and is calculated using grid-average emission factors for the locations where energy is used; it does not include offsite renewable energy. Scope 2 (market-based) reflects the emissions of electricity procurement decisions, including the purchase of offsite renewable energy; under the market-based method, renewable electricity is recognised where Large-scale Generation Certificates (LGCs) or GreenPower units from offsite or onsite renewable energy sources are voluntarily retired. The Net Scope 1 & 2 (market-based) figure is the total Scope 1 and 2 (market-based) emissions, less any relevant carbon offsets.

Reporting scope

Environmental data is reported for assets in which GPT has an ownership interest and that were under GPT's property management or co-owner property management for the full year ended 31 December 2025 (the reporting period). The scope excludes assets recently acquired, intended for sale, under development, tenant-controlled, or deemed peripheral/non-core, and also excludes assets acquired or divested during the reporting period.

Scope 3

This Statement focuses on material emissions within our operational control, primarily Scope 1 and 2 emissions. While we acknowledge that future reporting may expand on Scope 3 emissions, that is not the focus of this Statement.

Transition risks

No amount or percentage of assets/business activities vulnerable to transition risk is quantified in this Statement.

Physical risks

Less than 3.5% of portfolio value identified as moderate Value-At-Risk (VAR); no assets assessed as high VAR (under the high-emissions RCP 8.5 scenario).

Opportunities

No amount or percentage of assets/business activities aligned with climate-related opportunities is quantified in this Statement.

Capital deployment

$1.3b of combined debt issued by GPT and GWOF under our Sustainable Debt Framework at the end 2025. 15.5MW of installed solar PV capacity on GPT-owned assets.

Internal carbon prices

Offsets have been purchased at an effective carbon price of approximately $30 per tonne through to 2027, with the associated costs budgeted as a recurring property operating expense for properties under management.

Remuneration

Accountability for sustainability and climate performance forms part of executive remuneration. As outlined in GPT's 2025 Remuneration Report, within GPT's 2025 Annual Report, Key Management Personnel (KMP), including the CEO and CIO, have a specific sustainability-related key performance indicator (KPI) in the FY25 Group scorecard.

Greenhouse gas emissions (pp. 72–73). Scope 1 and 2 emissions were calculated in accordance with the Greenhouse Gas (GHG) Protocol: Corporate Standard Reporting Standard (2004), using the operational control approach. Table 4, TOTAL EMISSIONS TCO2E FY26:

Emissions from franchisee businesses in Australia are excluded and "form part of the Scope 3 emissions". Part of the electricity consumption in the Republic of Ireland and Northern Ireland is sourced from renewable energy products under a supplier-specific renewable electricity contract; its effect is not reflected in the location-based Scope 2 figure. 88% of refrigerant consumption (11.6% of Scope 1 emissions) and <0.1% of purchased electricity were estimated (Table 5).

Scope 3 (p. 73). Not disclosed. The entity applied the transitional relief in AASB S2 paragraph C4(b).

Other categories (pp. 64–68, 73–74). The amount and percentage of assets or business activities exposed to risks or aligned with opportunities is stated as not currently available or not yet separately identifiable for six of the seven items. Capital deployed towards climate-related initiatives includes solar photovoltaic systems and lighting upgrades. No internal carbon price is applied. "Climate-related performance metrics are not incorporated into executive remuneration frameworks".

Greenhouse gas emissions

Under the GHG Protocol: A Corporate Accounting and Reporting Standard (2004), Iluka applies the operational control approach to define its organisational boundary for GHG emissions, enabling the Group to distinguish between emissions from activities it controls (through the authority to introduce and implement operating policies) and emissions from activities in the broader value chain which it does not directly control but may be able to influence. Under this approach, Iluka accounts for 100% of GHG emissions from operations over which it has the authority to introduce and implement operating policies, including health, safety, environmental, and production policies. The approach is applied to capture GHG (Scope 1 and Scope 2) emissions for all of Iluka's controlled Australian operations and for its international rehabilitation and exploration operations in the United States. Iluka's equity accounted investment in Deterra Royalties Limited is excluded from the Scope 1 and Scope 2 reporting.

For Australian operations registered under the NGER scheme, Iluka measures and reports Scope 1 and Scope 2 GHG emissions in accordance with the NGER Act, ensuring consistency with Iluka's mandatory annual reporting to the Clean Energy Regulator. For operations outside Australia, Iluka applies the Greenhouse Gas Protocol; for rehabilitation activities in the United States, emissions are calculated using Greenhouse Gas Protocol methodologies with emissions factors sourced from the United States Environmental Protection Agency (US EPA) 2025 GHG Factors Hub. Emissions arising from operations in Europe and China are quantitatively and qualitatively immaterial, both individually and in aggregate, and have not been separately measured or disclosed for the reporting period. The measurement and reporting methodologies applied are consistent with those used in prior period voluntary reporting; Iluka has not changed its measurement approach for Scope 1 and 2 GHG emissions collation and reporting from prior years.

Emissions are based on Iluka's corporate reporting year (1 January to 31 December) and reported for Iluka's Group-wide businesses, including all exploration, construction, operations, rehabilitation and corporate activities. Location-based calculation methodologies are applied to derive Scope 1 and 2 GHG. Iluka has PPAs in place in relation to its Cataby solar farm and its hybrid diesel and solar farm at Jacinth-Ambrosia. In 2025, Iluka finalised the PPA for its Balranald site, securing a hybrid diesel/solar/BESS power station; construction commenced in 2025 with completion of the diesel power station anticipated in March 2026 and an anticipated operational date of July 2026.

2025 Total Scope 1 and 2 GHG emissions (applying operational control approach):

Some total figures may vary due to rounding.

Scope 1 and 2 GHG calculation methodologies: Emissions are quantified using direct measurement, invoice data, and metered or equipment activity records, converted to GHG emissions by applying applicable emission factors under the NGER reporting framework (Australian activities registered under NGER) and the United States EPA 2025 GHG Factors Hub (for US activities). For Scope 1 GHG emissions originated by coal, Iluka applies a mass balance methodology, consistent with a methodology accepted under NGER legislation: emissions are calculated based on the carbon content of coal inputs, adjusted for carbon retained in products, by-products, and residues, with the balance assumed emitted as carbon dioxide through combustion or processing activities, used where it provides a more accurate representation than default combustion factors. Scope 1 GHG emissions are calculated at each controlled facility level using direct measurement, invoices and consumption data, multiplied by applicable emission factors for the reporting period. Scope 2 GHG emissions are calculated based on electricity consumption at each controlled facility using metered data and electricity invoices; Iluka applies the location-based method, multiplying consumption data by relevant location-based emission factors published annually in the applicable reporting framework, reflecting emissions intensity of the electricity grids where Iluka's facilities operate. All of Iluka's PPAs operate as behind-the-meter arrangements, meaning electricity is generated on-site and consumed directly by Iluka's operations, reducing reliance on grid-supplied electricity. Large Scale Generation Certificates (LGCs) from all of Iluka's solar solutions are retained by the third-party PPA operator.

(Note: as first-year transition relief, Iluka has not disclosed Scope 3 GHG emissions for this reporting period.)

Transition risks

Assets vulnerable to transition risks (out of Iluka's five sites):

• Increased energy costs: All assets, 100%
• Increase in safeguard compliance costs: 1 out of 5, 20%
• Decarbonisation technology not commercially feasible: 1 out of 5, 20%

Physical risks

Assets vulnerable to physical risks:

• Increased severity and frequency of extreme rainfall and storm events: All assets, 100%
• Increase in frequency of extreme temperature days: 2 out of 5, 40%

Opportunities

Assets aligned with opportunities:

• Increased demand for rare earth oxides: 1 out of 5, 20%
• Increased deployment of renewable energy generation: All assets, 100%

Capital deployment

Not separately disclosed as a distinct cross-industry metric in this report.

Internal carbon prices

Iluka uses an internal shadow carbon price. Within Iluka, the main uses of shadow carbon price forecasts are: (i) to run shadow carbon price sensitivities on feasibility study stage projects; (ii) to assess the relative economics of self-generating ACCUs versus buying on-market; and (iii) to anticipate safeguard compliance costs associated at its safeguard facility in North Capel to inform its strategy and planning.

The 2025 internal shadow carbon price approved by Iluka's Board reflects the Reputex Slow Decarbonisation Scenario ('Reputex High Scenario'), characterised by high offset demand coupled with slow industrial decarbonisation. Adopting this scenario enables Iluka to prepare for safeguard facility compliance costs in its corporate plan that might be higher than what may eventuate. RepuTex also maintains other scenarios, including a central scenario characterised by incremental industrial decarbonisation in Australia and a low scenario characterised by low offset demand and accelerated industrial decarbonisation in Australia. In the short-term (to 2030), the price pursuant to the Reputex High Scenario is below the Government Cost Containment price of $75/tCO2e and increases to $175/tCO2e by the end of 2035.

Remuneration

The outcomes of the Climate Change Work Program are part of the Group's overall Short-term Incentive Plan (STIP) that applies to all Iluka employees and the Executive, assessed using Iluka's scorecard measures (ranging from below threshold to stretch outcomes, with threshold, target and stretch outcomes defined at each annual review). These targets are set internally and are not subject to review by a third-party. For 2025, the Climate Change Work Program contributed 6% to Iluka's Group scorecard, with overall outcomes achieved being at threshold.

Emissions, FY26 (p. 47; Group). Measured using the financial control approach; methodology developed in accordance with the Greenhouse Gas Protocol – A Corporate Accounting and Reporting Standard Revised Edition; all seven gases of the GHG Protocol included (p. 49).

Scope 3 is disclosed on a voluntary basis. Category 15 (investment emissions) and supply chain and general procurement emissions within Category 1 are material but not reported, under transitionary relief (p. 50). Scope 2 market based is measured after accounting for contractual arrangements for renewable electricity; 3,530 Large-scale Generation Certificates (Australia) and 900 New Zealand Energy Certificates were purchased and retired in FY26 (p. 47).

Other metrics (p. 47). Business activities vulnerable to climate-related physical risk: GWP $m 16,201 (88%). Capital deployed towards climate-related risks and opportunities: $m 254 (green bonds). No internal carbon price. Executive remuneration linked to climate-related considerations: 1.7%.

Scope 1 and 2 emissions, FY2026 (p. 71), t-CO2-e

Base year emissions are unaudited. Australian operations (about 99% of FY2026 scope 1 and 2 emissions) use National Greenhouse and Energy Reporting (NGER) Scheme methods and New Zealand operations (about 1%) use GHG Protocol methods, with an operational control boundary; 8% of electricity consumption was estimated (pp. 70–71). Market-based scope 2, reported voluntarily (pp. 75–76), recognizes Large-scale Generation Certificates (LGCs) and New Zealand Energy Certificates (NZECs) procured through contractual agreements with energy providers (p. 70). The Group applied the transitional relief for Scope 3 emissions and comparative figures (p. 53).

Other categories. Physical risk: 38 locations, 5.4% of total assets (p. 61). Opportunity amounts and percentages are withheld as commercially sensitive (pp. 64, 66). Capital deployment: no financially material expenditure planned (p. 69). Internal carbon pricing: not used (p. 69). Remuneration: one measure in the 25% non-financial part of the executive scorecard covers sustainability initiatives (p. 55).

Total gross emissions includes gross Scope 1 emissions and gross Scope 2 emissions (market-based). The operational control approach is used, per the Greenhouse Gas Protocol (p. 85). At publication an estimated 35 percent of the Renewable Energy Certificates (RECs) in the dataset had not yet been purchased, and the Group commits to purchase and retire them after the year-end assurance of the associated emissions (p. 86).

Internal carbon price (p. 85). Carbon offset price per tCO2-eq, in Australian dollars rounded to the nearest 10 dollars: FY26 $50, FY27 $50, FY28 $60, FY29 $60, FY30 $70. Carbon price considerations are built into project emissions forecasting and budgeting at the investment decision-making stage.

Other metrics. 39 percent of commercial assets are currently fossil fuel free (p. 80). 100 percent of assets in development are targeting a top-tier rating (p. 84). A carbon emissions target is not a remuneration-linked measure in FY26 (p. 73).

Greenhouse gas emissions, FY26 (p. 70)

The table prints no unit. Operational control boundary (p. 68). Under the January 2025 amendments (AASB S2025-1), Metcash uses the NGER Determination 2008 for Australian operations subject to NGER and the GHG Protocol for the rest (p. 57). 36,500 LGCs for 1 November 2025 – 30 April 2026, representing 36,500 MWh of renewable electricity (p. 71). Scope 3 is not disclosed (transition relief, p. 57).

Other categories. Physical risk: 5 Food and Liquor Mega DCs and 3 Hardware Mega DCs are most vulnerable; in addition 31 stores and satellite distribution centers are in more vulnerable locations, which represents 11% of total operationally controlled sites (p. 62). Transition risk: 5 Mega DCs and 27 Satellite DCs, 11% of sites (p. 64). Opportunity: associated activities would encompass 100% of operations (p. 65). Capital deployment: no material climate-specific capital expenditure, financing or investment for physical risks (p. 62) and no additional financing or investment for energy and fuel costs (p. 64). No internal carbon price (p. 68). Remuneration: no standalone climate or ESG KPIs (p. 60).

Emissions (p. 90). Measured under the Greenhouse Gas Protocol (2004) on a financial control boundary covering all entities in the consolidated Group, with Scope 2 location-based; approach, inputs and assumptions are on pp. 92–93. FY26 (tCO2-e):

Scope 3 is not disclosed (relief C4(b)) and there are no comparatives (relief C3) (pp. 70, 90); Scope 3 reporting is planned from FY27 (p. 71). Prior years used an operational control basis, still shown in the Planet section (p. 33). Renewable electricity is procured through GreenPower purchases and Large-scale Generation Certificates (LGCs). A formal internal carbon price is not applied (p. 74). Mirvac's share of office electrification capital deployed in FY26 was $4m (p. 89).

Scope 1 and 2 only; no comparatives and no Scope 3, under the transitional relief the Group elected (pages 98, 124).

Method (pages 124–126). Operational control approach covering the Company and its controlled entities. Scope 2 is location-based; the Group has no contractual instruments that would give a materially different market-based outcome. Sources accounting for 99% of Scope 1 and 2 emissions are measured under the NGER Determination, applying the jurisdiction relief under paragraph 29(a)(ii) of AASB S2; other sources follow the GHG Protocol. Final-month data is estimated.

Other categories. Revenue from assets and activities exposed to transition risks and to physical risks: 100%, $1,767,000,000 (page 118). No capital expenditure, financing or investment was deployed directly toward the management of climate-related risks (page 126). Internal carbon price: ACCU price forecasts with a ceiling price equivalent to the Clean Energy Regulator's cost containment measure unit price; the fixed price for an ACCU was $82.88 for the 2025-26 NGER reporting year (page 126). A climate-related compliance measure carries a 3 percent weighting in the executive short-term incentive; there are no other climate-related incentives (page 126).

Greenhouse gas emissions, FY26 (p. 82)

Emissions are measured under the GHG Protocol Corporate Standard with an operational-control approach and relate to the consolidated accounting group (pp. 66–67). Scope 1 arises principally from diesel combustion for backup power, corporate fleet fuel and refrigerant losses. Scope 2 includes electricity used by cooling, ventilation and other shared facility infrastructure; electricity attributable to customer IT equipment is treated as supplied to end users and excluded. No contractual instruments were used, so no market-based adjustment was applied (p. 82). Figures may differ from those reported under the NGER framework (p. 67).

Other cross-industry metrics (pp. 70, 83). 18 of 18 operating data center sites (100%) are within the scope of CRR3 and CRR4. 11 of 18 sites (61%) have medium or high modeled baseline exposure to water stress and eight of 18 (44%) to river flooding. 18 of 18 sites (100%) are aligned with CRO1. Capital deployed towards climate-related risks and opportunities is not separately tracked. No internal carbon price is applied. In FY26, 0% of executive remuneration was specifically linked to net zero or greenhouse gas emissions reduction targets (p. 70).

Greenhouse gas emissions

For the reporting period, which represents Nickel Industries' first year of mandatory climate-related reporting, GHG emissions are measured and compiled using energy and fuel consumption data at the operational level. The Group has applied the transition relief available under AASB S2 paragraph C4(b); accordingly, Scope 3 greenhouse gas emissions are not disclosed in this AASB S2 Sustainability Report.

The GHG inventory comprises emissions from mining and processing operations operated by Nickel Industries, for which fuel and electricity consumption data are collected at the site level. Nickel Industries has elected to apply the equity share approach as its primary organisational boundary for all GHG emissions. Under this approach, the Group accounts for GHG emissions from operations according to its share of equity in the operation; equity share emissions are calculated by multiplying gross emissions by the percentage equity share in the joint venture or underlying ownership percentage.

The emissions inventory includes operated mining assets and RKEF processing lines, and HPAL across operating entities via the equity-based approach. Assets and activities that are not in the operational phase are not included in the reported Scope 1 and Scope 2 emissions. Scope 1 and Scope 2 GHG emissions arise primarily from mining and processing operations in Indonesia, associated with fuel combustion and electricity consumption at operated mining sites and RKEF processing facilities, with a smaller proportion from HPAL, Huayue Nickel Cobalt. Reported Scope 1 and Scope 2 emissions do not include emissions from Europe, the Americas or other regions as the Group does not operate mining or processing assets in those jurisdictions.

*Scope 2 are location-based.

Methodology for the calculation of GHG emissions Emission factors have been sourced from the 2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2019).

Calculation standard: Nickel Industries applies the Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (2004). Scope 1 emissions reflect direct emissions from operated activities, while Scope 2 emissions reflect indirect emissions associated with generation of purchased electricity consumed by the Group's operations and are reported on a location-based basis.

Challenges for measurement: Data availability and consistency across multiple operating sites present challenges. Accuracy is dependent on the quality of underlying fuel and electricity consumption data, and completeness of operational records. Variations in operational practices and energy use across sites may affect comparability. The GHG inventory focuses on material Scope 1 and Scope 2 emission sources associated with core mining and processing activities; no new Scope 1 or Scope 2 emission sources were identified or added during the reporting period, and immaterial sources are not included.

Transition risks

The amount of assets vulnerable table presents a combined category, 'Climate related physical and transition risks', not disaggregated between transition and physical risk types:

Physical risks

The same combined 'Climate related physical and transition risks' table applies (see above); the report does not separately disaggregate assets vulnerable to physical risk alone.

Opportunities

The transition presents several strategic opportunities (e.g. Net Zero Roadmap implementation, green financing, market positioning from lower-emissions nickel production) however these are described as 'not considered material at this point' and no amount or percentage of assets or business activities aligned to opportunities is quantified.

Capital deployment

At 31 December 2025 the Group had acquired a 44% interest in ENC for $1,012.0 million, part of the transition into HPAL projects producing MHP for the electric vehicle supply chain. The Group is a participant in a solar project in the IMIP (262MWp photovoltaic and 80MWh BESS) which achieved financial close on 23 January 2026, with a 25-year fixed rate power purchase agreement. No consolidated capital deployment figure specifically labelled as a 'capital deployment' metric is presented.

Internal carbon prices

No internal carbon price is disclosed in the report.

Remuneration

In 2025 the Remuneration Committee oversaw the introduction of a performance rights incentive program under which both STI and LTI components included specific sustainability related performance conditions: establishment of a charitable foundation, transitioning to electric vehicle hauling trucks, safety based on actual LTIR performance, ESG based on the Group's MSCI rating, society based on any industrial strike action, and corporate governance breaches. The number of performance rights to vest will be determined by the level of achievement of the specific performance conditions. No percentage of remuneration recognised in the current period linked to climate considerations is disclosed.

Emissions, equity share basis, kt CO2-e (p.183).

Scope 1 and 2 follow the NGER Measurement Determination under jurisdictional relief. Transition relief applies to comparatives and Scope 3, both disclosed voluntarily (p.158).

Other metrics. Assets or activities exposed (pp.161–169; bases differ): Transition Risk 1 ~$1 billion (5%); Risk 2 ~$12.5 billion (82%); Risk 3 ~$1 billion owned and ~$2 billion equity accounted (14%); Risk 4/Opportunity 1 ~$8.5 billion (54%); Risk 5/Opportunity 2 100%; Opportunity 3 ~$11 billion owned and ~$7 billion equity accounted (73%). Capital deployed in FY26: $742 million (p.178). Carbon price: real $36 to $89 per tonne in sensitivity analysis (p.159). Remuneration: see Remuneration Report, p.78.

Greenhouse gas emissions

Pepper Money has calculated its Scope 1 and 2 emissions in accordance with the GHG Protocol – A Corporate Accounting and Reporting Standard (2004).

Setting the organisational boundary: Pepper Money has selected the Operational Control approach to determine its organisational boundary for the calculation of Scope 1 and 2 emissions. The Group applies the operational control approach when defining its GHG emissions boundary, which requires entities to report emissions from facilities where they have the authority to implement operating, health and safety, or environmental policies. As a non-bank lender, the Group does not exercise day to day operational authority over financed or secured assets, and therefore reports only those emissions it can directly influence – such as those arising from offices, data centres and corporate activities.

Scope 1 emissions

Approach, inputs and assumptions:

• Generation of electricity, heat or steam: Pepper Money has determined that there is no material emissions generated in this category. Pepper Money does not own any assets that directly produce emissions through generation of electricity, heat or steam. Pepper Money has engaged each office location to confirm that all energy is purchased from assets not owned by the Group. Purchased energy has been included in Scope 2 emissions.
• Fugitive Emissions: Pepper Money has collected registers of all refrigerants containing air-conditioning units and refrigerators that are owned or operationally controlled by the Group. Refrigerant capacity and types were obtained from air-conditioning unit and refrigerator model specifications to support calculation of emissions (if any). Pepper Money has relied on the actual top-up approach to calculate the amount of refrigerants that were released during 2025. Pepper Money obtained confirmations from office or building managers that no refrigerant top ups occurred in 2025 for any identified air-conditioning units or refrigerators.
• Transportation of materials, products, waste, and employees: Pepper Money has determined that there is no material emissions assigned with this category. Pepper Money does not own or control any company vehicles. Emissions from employee commuting are indirect and categorised as Scope 3.

As this is Pepper Money's first reporting period aligned to AASB S2, there have been no changes in methodological approach.

Pepper Money reports zero Scope 1 emissions for the consolidated Group:

Scope 2 emissions

Approach: The Group has collated electricity invoice information from each office to determine the amount of kilowatt ("kW") usage occurred across the reporting period. Where offices did not have specific electricity invoices, building management was contacted to provide the Group with metered electricity usage. Calculations were conducted using the location-based approach which multiplies the kWh of electricity by the emissions factor for the geographic location. The following emissions factors were used: For office locations in Australia, emissions factors were obtained from the National Greenhouse Gas Accounts Factors 2025 released by the Department of Climate Change, Environment, Energy and Water ("DCCEEW"). For the New Zealand office, the emissions factor was obtained from the New Zealand Ministry of the Environment. For the Manila office in the Philippines, Pepper Money has estimated an emissions factor by taking an average of emissions factors released by Governments of 3 comparable countries (Vietnam, Malaysia and Thailand). This approach was undertaken as the Philippines Government does not release endorsed emissions factors.

Inputs: Electricity usage (kWh) for each office; Emissions factors from the National Greenhouse Account Factors 2025 (Australia); the Measuring Emissions Guide 2025 (New Zealand); the Department of Climate Change, Ministry of Natural Resources and Environment (Vietnam); the Energy Commission (Malaysia) and the Thailand Greenhouse Gas Management Organization (Thailand).

Assumption: The Group has applied electricity usage on a pro-rata day-count convention for invoices with periods that included both December 2024 and January 2025. The estimated portion for December 2024 was excluded. Not all monthly electricity usage invoices for 2025 were available at the time of reporting. In these instances, the Group calculated an average daily rate for each location based on available data and aggregated across a 12-month basis. As the Philippines does not have a government endorsed emissions factor for the local grid, Pepper Money has estimated the emissions factor based on comparable countries.

Justification: Pepper Money believes that the approach, inputs, and assumptions are reasonable given: they reflect the best estimate of indirect electricity-related emissions given the information available; and the Group did not purchase or engage in specific contractual instruments for the purpose of acquiring energy in the reporting period.

Pepper has calculated its Scope 2 emissions as follows:

Scope 3

The Group has applied transition relief from disclosing Scope 3 greenhouse gas emissions, which includes, if the entity participates in asset management, commercial banking or insurance activities, the additional information about its financed emissions.

Transition risks

As at 31 December 2025, the proportion of borrower's employment industry deemed vulnerable to transition risk:

(ANZSIC codes are not known for 53% of Mortgage borrowers and 47% of Asset Finance borrowers. Borrowers with unknown ANZSIC codes are included in calculations to determine the exposures to industries vulnerable to transition risk.)

Physical risks

Australian Residential Mortgages loan exposure to physical risk as at 31 December 2025 ($ million):

Proportion of Australian Residential Mortgages AUM as at 31 December 2025 (%):

Asset Finance bushfire exposure as at 31 December 2025 (assets with highest 5% of bushfire risk score):

Asset Finance flood exposure as at 31 December 2025 (highest 5% of flood risk scores):

Asset Finance cyclone exposure as at 31 December 2025 (highest 5% of cyclone risk scores):

Asset Finance storm exposure as at 31 December 2025 (highest 5% of storm risk scores):

Opportunities

At this time, no climate-related opportunities were assessed as material in CY2025.

Capital deployment

Not separately quantified in the report beyond narrative descriptions of investment in climate-related data acquisition and learning and development initiatives (see Strategy 22 for related narrative).

Internal carbon prices

Pepper Money has not set an internal carbon price in the reporting period.

Remuneration

Executive remuneration policies do not directly reflect climate-related risks or opportunities. For the Chief Financial Officer, 15% of STVR outcomes is allocated to the delivery of ESG AASB S2 reporting.

Emissions (ktCO2-e; operational control; pp. 27–28).

Under transition relief no comparatives are given, other than voluntary ones for Scope 1, 2 (location-based) and 3 (p. 5). Domestic emissions follow the NGER Scheme methodology, using the local jurisdictional method relief (p. 40).

Other metrics. Transition risk: 75 to 85% of business activities vulnerable (p. 14). Physical risk: 60% of net book value of total assets (p. 11). Opportunity: 75 to 85% of business activities aligned (p. 21). Dollar amounts are cross-referenced to the 2025/26 Financial Report. Capital deployed: $36 million via the Climate Fund (p. 19). Internal carbon price: gross AUD $60 to $70 per tCO2-e (p. 22). Remuneration: 5% Group Scorecard weighting (p. 36).

Greenhouse gas emissions

Operations and supply chain measures table (2025)

Absolute GHG emissions - defined inventory (2025 tCO2e)

Measurement methodology

QBE measures its GHG emissions in accordance with the Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (2004) as required by AASB S2. The operational control approach has been adopted to define the organisational boundary; QBE reports 100% of emissions from operations over which it has the authority to introduce and implement operating policies, including all entities in the consolidated accounting group with the exception of Challenger Private Debt Q Fund over which QBE does not have operational control. Associates and unconsolidated investees are also excluded from the Group's Scope 1 and 2 emissions boundary on this basis.

Scope 1 and 2: Measured using the indirect method, applying relevant emission factors to activity data. Emission factors are sourced from national and international authorities including NGER (Australia), DEFRA (UK), EPA (US), the Ministry for the Environment (New Zealand), and the IEA. In countries where high-quality, locally published emission factors are not available, proxy factors from DEFRA or other internationally recognised sources have been applied. Primary sources such as utility invoices and fuel card records are prioritised where available. Reported Scope 1 includes mobile combustion (fuel used in owned/controlled vehicles, excluding novated leases), stationary combustion (natural gas for heating in owned/leased buildings), and fugitive emissions (refrigerant leakage from HVAC systems). Reported Scope 2 (location-based) includes purchased electricity, purchased heating (gas), and purchased heating and cooling (electricity) centrally provided by landlords. Reported Scope 2 (market-based) emissions have been measured after accounting for electricity consumed under green electricity contracts and unbundled energy attribute certificates surrendered by QBE.

Scope 3: Measured using an indirect estimation approach, applying relevant emission factors to activity data. Primary data used where reliable internal records available (supplier invoices, travel management systems, asset registers); secondary data and extrapolations applied where unavailable. Emission factors sourced from third-party data providers, with DEFRA factors applied as proxy where jurisdiction-specific factors unavailable. Categories included in the defined inventory: Category 1 (Purchased goods and services – limited to office paper and electricity usage from externally hosted data centres), Category 2 (Capital goods – purchased IT equipment), Category 3 (Fuel- and energy-related activities), Category 5 (Waste generated in operations), Category 6 (Business travel), Category 7 (Employee commuting), Category 11 (Use of sold products – policyholder travel for claims), Category 13 (Downstream leased assets). In line with the transitional provisions in AASB S2 which permit the deferral of full Scope 3 disclosures until the second year of application, QBE will expand its Scope 3 disclosures from full year 2026 to include all sources within its value chain that are material and relevant to the Group's operations.

Additional reported emissions in 2025 include fugitive emissions within Scope 1 and emissions from centrally provided electricity in landlord-managed buildings within Scope 2. Baseline emissions used to measure reduction targets have not been restated to reflect these inclusions.

Investment measures table (2025)

Transition risks

The Group's Marine, Energy & Aviation product class accounts for $1,758 million or 7% of the Group's gross written premium in the current year, being the exposure most significantly exposed to sectors considered at high risk from the transition to a lower-carbon economy. In investments, infrastructure assets comprising $1,426 million or 4% of total investments at 31 December 2025 and developed/emerging market equity investments amounting to $856 million or less than 3% of total investments are considered the classes with the highest relative exposure to transition-sensitive sectors.

Physical risks

The modelled aggregate net annual average loss (AAL) for climate-related perils for 2026 is $654 million and represents approximately 5% of the Group's 2026 plan net claims.

Opportunities

The carrying value of the Group's investments at 31 December 2025 included $2,359 million of climate solutions investments, representing 7% of QBE's total assets under management.

Capital deployment

Climate-related risks and opportunities are managed as part of business-as-usual activities and are resourced through existing budgets across the Group. Other than investments in climate solutions, the Group did not identify material direct expenditure attributable solely to the delivery of climate-related initiatives during the reporting period.

Internal carbon prices

To support the achievement of QBE's operational emissions targets, an internal carbon price of $65 per metric tonne of carbon dioxide equivalent has been applied to GHG emissions within the scope of QBE's net-zero target and carbon neutrality commitment. This price reflects the estimated cost of emissions management, including investment in emissions reduction initiatives, procurement of renewable electricity, and the future purchase of carbon removal certificates. The internal carbon price is applied to divisions based on actual operational GHG emissions and is intended to incentivise decarbonisation while funding Group-wide environmental initiatives. The pricing mechanism is reviewed periodically and is informed by projected costs associated with maintaining carbon neutrality and achieving net-zero commitments.

Remuneration

Conditional rights granted under the 2024 and 2025 LTI plans are subject to financial and non-financial performance targets, including 10% that are subject to a sustainability performance measure. Sustainability performance within the LTI plans is measured based on progress against the initiatives and targets in the Sustainability Scorecard, which comprise metrics attributable to climate as well as other areas of sustainability. This component represents 2.0% of total executive key management personnel remuneration recognised in the current year, of which 1.1% is estimated to be attributable to climate-related initiatives based on the proportion of metrics in the 2023–2025 Sustainability Scorecard that are attributable to climate.

Greenhouse gas emissions

2025 gross Scope 1 and 2 GHG emissions (adjusted equity basis): 31.5 Mt CO2e (2024: 31.7 Mt CO2e). Scope 3 GHG emissions: 575.7 Mt CO2e (2024: 569.8 Mt CO2e).

Emissions are reported using the equity share approach. Emissions reporting complies with the WRI/WBCSD GHG Protocol: A Corporate Accounting and Reporting Standard (Revised Edition) (2015), GHG Protocol Corporate Value Chain (Scope 3) Accounting and Reporting Standard (2013) and the Technical Guidance for Calculating Scope 3 Emissions (version 1.0).

Scope 1 emissions are direct GHG emissions from facilities we own or control, including fuel use, onsite electricity generation, anode and reductant use, process emissions, land management and livestock. Scope 2 emissions arise from purchased electricity, heat or steam. From 2023, we report Scope 2 using both the location-based method and the market-based method, which accounts for contractual instruments such as renewable energy certificates and exclusive energy attribute contracts.

Disaggregation of Scope 1 and 2 (location-based) (equity basis)

Scope 3 sources (equity basis, Mt CO2e)

Categories excluded: Category 11 (Use of sold products) - not applicable; Category 8, 12, 13, 14 - not applicable; Category 15 (Investments) - Rio Tinto reports using equity share approach, so Scope 1/2 emissions of investments are included in Scope 1/2 and Scope 3 within other applicable categories.

Energy - equity basis

Total energy consumed 2025: 516.8 PJ. Electricity from renewable sources: 77% (2024: 78%).

Carbon credits retired

We retired approximately 1.01 million Australian Carbon Credit Units (ACCUs) to meet our 2024 Safeguard Mechanism compliance obligations. For 2025, we expect to retire approximately 1.17 million ACCUs. Total credits counted towards net emissions for 2025: 1,169,079.

Transition risks

82% of our global Scope 1 GHG emissions (19.6 Mt CO2e) are covered by emissions-limiting frameworks (total gross global Scope 1 GHG: 24.0 Mt CO2e). 59% of our Scope 1 and 2 emissions (18.5 Mt CO2e) are classified as hard-to-abate. 7% of our operating costs ($3.1 billion) are attributable to fossil fuels.

Physical risks

All of our inventory and PPE ($91.6 billion), which together account for 72% of our total assets, are exposed to some degree of unmitigated physical climate-related risk, supplemented by annualised damage risk scoring by region and hazard (Low <0.2%, Medium 0.2-1%, High >1%).

Opportunities

Transition materials metrics (KTM/OTM production, capital expenditure, revenue): Of consolidated sales revenue, KTMs accounted for US$7,608 million (13%) in 2025 and US$4,728 million (9%) in 2024. Lithium, copper (KTM); silver, molybdenum, aluminium, alumina, bauxite, minerals (OTM); gold, iron ore (TNM) production, capex, operating assets and 2026 guidance disclosed in the transition materials metrics table.

Capital deployment

Total decarbonisation spend for 2025 was $612 million (2024: $589 million), comprising capital expenditure, investments and carbon credits of $182 million (2024: $283 million), and operational expenditure of $430 million (2024: $306 million). Updated capital expenditure forecast for decarbonisation is $1-2 billion to 2030. In the medium term, we will invest up to $10 billion (in real terms) annually in sustaining, replacement and growth capital.

Internal carbon prices

Dependent on location and time horizon, our internally applied carbon prices range from $0/t CO2e to $250/t CO₂e.

Remuneration

In 2025, 10% of the short-term incentive plan (STIP) and 20% of the long-term incentive plan (LTIP) were weighted towards decarbonisation, including the progress of our carbon abatement projects.

Greenhouse gas emissions

Emissions methodology

Santos has elected to apply the equity share approach as its primary organisational boundary for all greenhouse gas (GHG) emissions. Under the equity share approach, a company accounts for GHG emissions from operations according to its share of equity in the operation. Santos’ operated Australian Scope 1 and 2 greenhouse gas emissions are independently audited each year prior to submission of the annual NGER Report. Santos primarily adopts the prescribed emissions factors under Method 1 (default method) in the NGER Determination. Emissions for Santos’ Alaskan operations are reported to the United States Environmental Protection Agency (“US EPA”) pursuant to Title 40 (40 CFR 98) of the Code of Federal Regulations Part 98 (“US EPA Code”). Emissions calculated in accordance with the NGER Determination and US EPA Code for the 2025 year use global warming potential (GWP) values from the IPCC Fifth Assessment Report (AR5). GWP values from the IPCC Sixth Assessment Report (AR6) are used in the calculation of emissions in other areas. There were no changes in measurement approach in the current period.

Santos’ Scope 3 emissions have been calculated in accordance with the Scope 3 measurement framework within AASB S2. Santos has considered all of the 15 categories in the GHG Protocol and determined which of the Scope 3 categories are relevant to the business model. The material Scope 3 categories comprise approximately 96% of Santos equity share Scope 3 emissions and include Category 1 (purchased goods and services), Category 10 (processing of sold products) and Category 11 (use of sold products). Other non-material Scope 3 categories are aggregated and reported as Other Upstream or Other Downstream.

Emissions data

Santos’ equity share gross emissions were 3.81 million tonnes of carbon dioxide equivalent (MtCO2e). This included 3.55 MtCO2e Scope 1 and 0.26 MtCO2e Scope 2 (location-based). 67% of Scope 1 and 2 GHG emissions are in Australia (NGER), 1.8% from Alaska (US EPA Code), and the remainder calculated under the GHG Protocol, primarily PNG (30%). Santos’ equity share gross emissions reflect emissions after CO2e has been captured and stored by Moomba CCS operations.

Santos’ Scope 3 equity share gross emissions were 28.4 MtCO2e.

Scope 1 equity share greenhouse gas emissions

Scope 2 equity share greenhouse gas emissions

Scope 1 and 2 equity share greenhouse gas emissions

Scope 3 equity share greenhouse emissions

Supplementary data (not part of mandatory AASB S2 reporting, provided for comparison):

Scope 1 total operated greenhouse gas emissions

Methane emissions (OGCI, total operated)

Scope 2 total operated greenhouse gas emissions

Scope 3 greenhouse emissions

Methane emissions contributed to approximately 12 per cent of total operated Scope 1 emissions in 2025. 2025 methane emissions breakdown: Fugitives 43%, Flare 29%, Vent 24%, CO2 removal 5%, Fuel 0%. In 2025, across operated sites, methane intensity was 0.16 per cent, compared to 0.19 per cent in 2023 and 0.16 per cent in 2024.

Capital deployment

Annual investment in Climate Transition Action Plan projects: $136m in 2025 (Enabling projects $98m, Operational efficiencies $16m, Carbon capture and storage $20m, Other $2m); $290m in 2024; $265m in 2023. Our current carbon planning price assumption projects a carbon price of $63 per tonne of carbon dioxide equivalent (real 2025) in 2030. Over the next five years, potentially up to $500 million to $1 billion could be invested in operational efficiency projects, other CCS and low carbon fuels hubs and nature-based projects.

Transition risks

Each transition risk in the risk tables includes a 'Vulnerability metric' showing amount and percentage of assets vulnerable, e.g.:

• Climate policy: $2,539 million Exploration and evaluation assets (11 per cent)
• Climate-related litigation: $2,539 million Exploration and evaluation assets (11 per cent)
• Environmental/shareholder activism: $2,539 million Exploration and evaluation assets (11 per cent)
• Human capital: Nil
• Carbon emissions expectations: $136 million CTAP (4 per cent)
• Access to capital markets: $382 million expense (10 per cent)
• Reduced demand for products: 6 mmboe of sales volume (7 per cent)
• Transition technologies not scalable: $4,833 million assets (22 per cent)
• Failure to achieve emissions reduction targets: $4,833 million assets (22 per cent)

Physical risks

Physical risk 1 (Flooding in the Cooper Basin) Vulnerability metric: $2,034 million assets (9 per cent), calculated as the portion of Cooper Basin’s oil and gas assets and decarbonisation assets as a percentage of total oil and gas assets and decarbonisation assets.

Opportunities

Transition opportunity 1 (Transition technologies) Alignment metric: $254 million assets (1 per cent), being the portion of Santos’ technology-based decarbonisation assets as a portion of total decarbonisation assets and total oil and gas assets. Transition opportunity 2 (Low carbon fuels) Alignment metric: $4,483 million of revenue (88 per cent), being the portion of Santos’ gas derived revenue, including LNG, as a percentage of total product revenue in the reporting period.

Internal carbon prices

Our economic analysis processes consider the greenhouse gas emissions from all projects and the impact that a carbon price would have on our business. Where applicable, a carbon price is included in Santos’ economic modelling of projects, along with sensitivity testing to assess the impact of carbon pricing on all emissions. Santos applies the same stringent economic criteria to CTAP projects at FID, including internal rate of return and payback period, as we do to traditional gas and liquids projects. Our current carbon planning price assumption projects a carbon price of $63 per tonne of carbon dioxide equivalent (real 2025) in 2030.

Remuneration

Since 2019, the Short-Term Incentive has included performance metrics that reward Key Management Personnel (KMP) for achieving sustainability and climate outcomes. In 2025, the Company Scorecard weighting for climate-related targets remained at 17.5 per cent (consistent with 2024) and included metrics relating to emissions intensity reduction and key decarbonisation projects. This further strengthens the link between climate considerations, and the outcomes of performance pay.

Greenhouse gas emissions

The Group defines the greenhouse gas (GHG) emissions boundary using the operational control approach, which is consistent with the National Greenhouse and Energy Reporting (NGER) Scheme in Australia. Under this approach, 100% of emissions from operations over which the Group has operational control regardless of ownership interest is accounted for.

The Group's scope 1 and 2 emissions in the year were 181,173 tCO2e, comprising 10,074 tCO2e scope 1 and 171,099 tCO2e scope 2. Emissions reduced by 2% compared to the prior period.

Total portfolio emissions

Scope 2 emissions are disclosed using a location-based approach.

Consolidated accounting breakdown

The Group has adopted the transitional relief provided under AASB S2 paragraph C4(b), which permits it not to disclose Scope 3 greenhouse gas emissions in its first annual reporting period applying AASB S2. The Group has also adopted the transitional relief under AASB S2 paragraph C3, exempting it from disclosing information for any period before the date of initial application, including comparative information.

Measurement approach: Scope 1 and 2 emissions are reported using both location-based and market-based methodologies. Scope 1 emissions are direct emissions from sources under the Group's operational control, primarily from consumption of gas for heating, fuels for emergency power generation and refrigerants in air conditioning units. Scope 2 emissions are indirect emissions from generation of purchased electricity consumed in common areas, predominantly for air conditioning, lighting and vertical transport. Emissions are measured in accordance with the Greenhouse Gas (GHG) Protocol: A Corporate Accounting and Reporting Standard, with reference to the GHG Protocol Scope 2 Guidance, the NGER Measurement Determination for Australia, the New Zealand Ministry for the Environment's Measuring emissions: A guide for organisations 2025, and Climate Active Electricity Accounting.

Emission factors: Scope 1 – National Greenhouse Accounts Factors: 2025 (Australia) and New Zealand Ministry for the Environment guidance (New Zealand). Scope 2 (location-based) – state-based emission factors from the same sources. Scope 2 (market-based) – the Renewable Power Percentage published by the Clean Energy Regulator, the Jurisdictional Renewable Power Percentage and Residual Mix Factor from National Greenhouse Accounts Factors: 2025, and surrender of energy attribute certificates such as Large-scale Generation Certificates and New Zealand Energy Certificates. The latest available global warming potential (GWP) values reflected are contained in the IPCC Sixth Assessment Report (AR6).

Transition risks

Qualitative descriptions of vulnerability to policy and regulatory change and stakeholder expectations have been provided; quantitative amount and percentage of assets or business activities vulnerable to transition risks have not been separately disclosed.

Physical risks

The assessment of vulnerability has taken into account the Group's mitigation activities and is representative of how much of the portfolio is exposed to the risk, not the probable impact to the portfolio.

• As at 31 December 2025, 2.1% or $698 million of the Group's portfolio by book value (across 42 destinations) may be exposed to flooding, and 12.8% or $4,298 million to hailstorms. The vulnerability to rainfall has been considered as an impact to flooding.
• As at 31 December 2025, 4.5% or $1,525 million of the Group's portfolio by book value (across 42 destinations) may be exposed to bushfire.

Opportunities

Quantitative amount and percentage of assets or business activities aligned with the identified opportunities (enhance engagement with customers and communities; support business partner transition to a low-carbon economy) have not been disclosed as they are commercially sensitive and/or subject to a high degree of measurement uncertainty.

Capital deployment

In the current 2025 reporting period, the Group deployed $0.7 million of capital for the direct management of the climate-related risks, and $0.2 million of capital towards the implementation of the climate-related opportunities.

Internal carbon prices

The Group is currently exploring the implementation of environmental feasibilities which are presently considered more relevant to the business than the adoption of a carbon price, however this approach will continue to be assessed. No internal carbon price is currently applied.

Remuneration

Executive KMPs that have more direct accountability for climate-related deliverables have a greater percentage of their individual scorecard weighted towards climate-related KPIs, noting that any KPIs set extend beyond business as usual responsibilities. In aggregate, 1.02% of executive KMP remuneration is linked to climate-related KPIs. This represents the portion of maximum short-term variable remuneration opportunity linked to climate-related measures, expressed as a percentage of total statutory remuneration. For the CEO, 100% of short-term variable remuneration (STVR) is weighted to Group performance. For other executive KMP, 70% of their STVR is weighted to Group performance and 30% is weighted to individual performance.

FY2026 Scope 1 and 2 emissions (p. 182). Absolute (gross); no offsets were used.

Method (pp. 181–182). Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (2004), operational control approach, all seven major GHGs. Scope 2 market-based is reported voluntarily. 67,081 MWh of RECs were acquired and retired in FY2026. Methods were enhanced in FY2026 (IPCC AR6 GWP values, updated refrigerant charge and leakage assumptions, expanded screening approaches).

Other metrics (pp. 183–184). Transition: approximately 44% of operating expenditure is potentially subject to carbon cost pass-through. Physical: $2,193 million, 15.5% of total non-current assets of $14,179 million (freehold land and buildings and right-of-use assets for leased premises). Capital deployed: not separately identified. Internal carbon price: none introduced.

Greenhouse gas emissions

The Group's absolute gross greenhouse gas emissions (GHG) generated during the reporting period are outlined below:

Each of the Group's facilities is covered by the National Greenhouse and Energy Reporting (NGER) Act 2007, within Australia. As such we are applying jurisdictional relief for all emissions in line with the NGER requirements.

The Group prepares its GHG inventory using the operational control consolidation approach. This is done in line with the GHG Protocol, where a company accounts for 100 percent of the GHG emissions from operations over which it has operational control.

In 2025 the Group has reported on direct Scope 1 along with indirect Scope 2 emissions from facilities under its operational control. The Group has measured and calculated GHG emissions using the methods outlined in the NGER Measurement Determination. This approach is consistent with the Group's existing requirements to report emissions to the Australian Government under the NGER legislation. The Group has not identified any other material emissions sources under the GHG Protocol.

Scope 3 Greenhouse Gas Emissions Methodology & Approach

The Group is well advanced with data collection processes in preparation for future mandatory Scope 3 reporting and will disclose additional information relating to its Scope 3 emissions in future reports in line with the requirements of the AASB S2. [Transition relief applied: the Group has applied transition relief for the first annual reporting period not to disclose Scope 3 emissions.]

Transition risks / Physical risks / Opportunities

The Group's assets and business activities were not deemed vulnerable to climate-related risks and opportunities in the short term. However, climate-related risks may impact the Group's assets and business activities in the medium and long terms, per the following table. Asset and business activity vulnerability to climate-related risks and opportunities will continue to be assessed throughout each year and reported annually.

Capital deployment

In the period, no material capital expenditure was allocated to climate-related risks and opportunities. However, climate-related adaptation and mitigation measures have been implemented through operational expenditure.

Internal carbon prices

The Group has opted to account for an internal carbon price using the current and forecast ACCU prices as a base. The Group carbon price is used across project feasibility studies and to determine the financial impact to existing operations should the emissions baseline be exceeded.

Remuneration

As of 31 December 2025, there were no climate related KPIs in relation to the material climate-related risks and opportunities contained within this report.

Emissions, year ended 30 June 2026 (p. 195). Measured under the GHG Protocol, Corporate Standard, 2004, on an operational control boundary (pp. 181, 195); Scope 2 location-based:

Scope 1 by source (p. 196): refrigerants 813, stationary energy (natural gas) 1,312, stationary energy (fuel) 221 and transport energy (fuel) 180. During the year Scope 1 rose 17%, Scope 2 rose 1% and total gross Scope 1 and 2 rose 2%.

Market-based (p. 196). Gross Scope 1 and 2 of 34,834 tCO2-e; net 0 after retiring ACCUs for Scope 1 (2,526 tCO2-e) and surrendering LGCs (49,574 MWh) and voluntary green power (5,385 MWh) for Scope 2. No direct internal carbon price or shadow price is applied (p. 197). Scope 3 is not disclosed (relief C4(b)) and there are no comparatives (relief C3) (pp. 180, 198).

Emissions (p. 41). Operational control approach, in accordance with the Greenhouse Gas Protocol; measurement approach on pp. 45–47. FY25 comparatives are voluntary; FY25 Scope 2 figures were restated (footnote 2).

Suncorp elected the transitional relief to defer mandatory Scope 3 emissions to the second year of reporting, and says the Australian Accounting Standards Board has determined that Scope 3 insurance-associated emissions from underwriting are not required (p. 41). The subsidiary AA Insurance New Zealand and joint venture entities are outside the Scope 1 and 2 boundary (p. 45).

Other metrics. No carbon price is used to inform emission reduction decisions (p. 39). Executive remuneration has no standalone climate measures and no separate weighting (p. 44). $1,188 million was invested in lower-carbon impact investments in FY26 (p. 32). Electricity purchased and self-generated was 8,213 MWh (FY25: 11,612), reported as additional information not required under AASB S2 (p. 41).

Index (p. 215): Climate-related metrics – Greenhouse Gas emissions, p. 203.

FY26 emissions (p. 203), Telstra Group including Digicel Pacific

Australian scope 1+2 use the NGER determination, with scope 2 location-based; scope 3 and international scope 1 and 2 use the GHG Protocol; operational control is the consolidation approach.

Other metrics. Physical risk: 21–27 percent (5,036–6,511) of Australian above ground assets exposed to physical hazards (excluding storms) to 2030 (p. 190). Two transition risks and three opportunities are each said to affect or apply to 100 percent of business activities (pp. 191–195). Nearly $22 million invested in energy efficiency and decommissioning (p. 200). Modeling does not include an internal carbon price; a $40–$50 per tCO2e shadow price was piloted in FY22-FY23 (p. 199). In FY26 and FY27, 5 percent of the Telstra Group short term incentive (STI) scorecard is linked to the emissions targets (p. 203).

Greenhouse gas emissions

The Group has measured its GHG emissions in accordance with Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (2004) applying relevant methodologies under the Australian National Greenhouse and Energy Reporting (NGER) scheme and the New Zealand Measuring Emissions: A Guide for Organisations 2024 scheme (with updated emission factors for 2025) as appropriate.

The Group applies the GHG Protocol Corporate Accounting and Reporting Standard and uses the operational control approach to define organisational boundary. Emissions from businesses acquired are included from the respective acquisition dates. Emissions are disclosed on a gross basis, excluding offsets, in metric tonnes of carbon dioxide equivalent (CO2-e).

The Group discloses location-based Scope 2 emissions as required by AASB S2, and voluntarily discloses market-based Scope 2 emissions, Scope 3 emissions and Scope 1 and 2 intensity.

Statutory disclosure

Of Scope 1, 24,237 tonnes CO2-e (66%) is calculated under the NGER scheme for Australia and 12,385 tonnes CO2-e (34%) under Measuring Emissions: A Guide for Organisations for New Zealand generated GHG emissions. Of location-based Scope 2, 3,966 tonnes CO2-e (96%) is calculated under NGER for Australia and 176 tonnes CO2-e (4%) under the New Zealand guide.

Voluntary disclosure

Of market-based Scope 2, 2,405 tonnes CO2-e (92%) is calculated under NGER for Australia and 198 tonnes CO2-e (8%) under the New Zealand guide.

Scope 1 and 2 measurement: Scope 1 emissions represent direct emissions from fuel and energy sources used in vehicles, assets and facilities owned or controlled by the Group, calculated monthly using activity data multiplied by applicable NGER emissions factors (Australia) or Measuring Emissions: A Guide for Organisations 2024 with the 2025 Emissions Factors Workbook (New Zealand). Scope 2 emissions cover indirect emissions from purchased electricity, calculated using supplier invoices multiplied by relevant emissions factors, using both location-based (state-based NGA factors for Australia, updated annually; NZ Government's Measuring Emissions guide for NZ) and market-based (adjusted for contracted renewable energy purchases – Accredited Greenpower and Large-scale Renewable Energy Target for Australia; Bravetrace Residual Supply Factor for New Zealand) approaches. The Group used 2,481MWh of renewable electricity in FY25, representing 31.2% of total electricity use, of which 2,250MWh was procured through accredited Greenpower and large-scale generation certificates (LGCs).

Scope 1 and 2 intensity (market-based): calculated as tonnes of CO2-equivalent for the reporting period within the Group's operational control divided by the Group's revenue for the reporting period. Used in support of the Scope 1 and 2 emissions reduction target and included in the Group's STI for Key Management Personnel.

Scope 3 measurement: Scope 3 emissions are indirect emissions from the Group's value chain, broken down into 15 categories per the GHG Protocol Corporate Value Chain (Scope 3) Accounting and Reporting Standard (2011); the Group has determined only 8 categories (1-8) are relevant, estimated by multiplying spend or activity by emissions factors from an independent third party (FootprintLab, a research body at the University of Sydney), with some category-specific approaches (e.g. Category 6 business travel using UK Department for Environment, Food and Rural Affairs conversion factors; Category 7 employee commuting using Australian Bureau of Statistics census data; Category 8 upstream leased assets using National Australian Built Environment Rating System). Categories 9-15 are considered non-relevant through relevancy testing.

Scope 3 intensity (GEVA): GEVA = Proportion of PG&S Emissions/Value Added. "Proportion of PG&S Emissions" is the Group's annual spend in a specified proportion of Category 1 Purchased Goods and Services multiplied by relevant emissions factors, determined in accordance with the Science-Based Target Initiative target-setting methodology; at the 2021 baseline these sub-categories represented 85% of Category 1, or 67% of total Scope 3 emissions during 2021. "Value Added" is the Group's Underlying EBITDA plus the Group's labour costs in the relevant financial year.

Measurement assumptions and limitations: The Group's Scope 1 and 2 inventory includes estimates accounting for 1.0% of the Group's reported 2025 emissions (where actuals were unavailable, based on previous months' actuals). GHG quantification is subject to inherent uncertainty due to evolving knowledge and information used to estimate emission factors and combine emissions of different gases. No new Scope 1 or 2 emissions sources were included in the FY25 inventory. Scope 3 emissions involve greater uncertainties due to reliance on spend proxies, third-party information, industry averages and activity data; data availability and quality vary across the value chain.

Transition risks

Approximately 5% of the Group's activities were assessed to be vulnerable to transitional climate risk, representing revenue contribution from fossil fuel-related services within the Infrastructure Services operating segment.

Physical risks

The Group has assessed assets that may be vulnerable to climate-related hazards, where vulnerable means a rating of Very High or High exposure to hazards such as flood, flash flood, bushfire, storm and cyclone (each hazard includes relevant definitions, e.g. Flood represents a 1 in 20-year and 1 in 50-year flood for Very High and High respectively). As at 31 December 2025, assets of total carrying amount of approximately $70 million were identified as vulnerable to physical climate risks, representing around 2% of the Group's total assets, comprising property, plant and equipment and right-of-use assets located in regions exposed to climate hazards. The Group engaged one of its insurers to assist with the climate hazard assessment.

Opportunities

Approximately 6% of the Group's activities were assessed to be aligned with identified climate-related opportunities, representing revenue contribution from energy and renewables services within the Infrastructure Services operating segment.

Capital deployment

In 2025, the total amount of capital expenditure, financing, or investment deployed towards climate-related risks and opportunities was $18.8 million, representing the consideration paid to acquire PowerNet.

Internal carbon prices

The Group does not have an internal carbon price. A trial began in 2024 and continued throughout 2025, in which some capital funding decisions were assessed against an emissions threshold to identify potential emissions-intensive outcomes and assess risk to the Group's emissions goals.

Remuneration

All STI participants are required to meet objectives in a scorecard, including the achievement of greenhouse gas emissions reduction targets (measured in Scope 1 and 2 emissions intensity), which carries a 5% weighting. The SASC oversees the setting and monitoring of climate-related targets. In 2025, 1.9% of the Group's Key Management Personnel's total maximum remuneration opportunity was dependent on achieving climate-related objectives.

Greenhouse gas emissions

The Group applies the operational control approach to establish its organisational boundary for the reporting of Scope 1 and 2 GHG emissions, in line with obligations under the National Greenhouse and Energy Reporting Scheme (NGERS). Viva Energy Group Limited maintains operational control over its controlled entities.

Direct GHG emissions from sources that are owned or controlled by businesses and operations within the Group's organisational boundary are reported as the Group's Scope 1 GHG emissions. GHG emissions from the generation of purchased electricity consumed by these businesses and operations are reported as the Group's location-based Scope 2 GHG emissions. Scope 3 emissions are the indirect GHG emissions that occur across the value chain and arise from activities not directly controlled by the Company; these are voluntarily reported.

Breakdown of Total Scope 1, 2 & 3 GHG emissions (1 January 2025 to 31 December 2025)

Upstream activities represent 14% and Viva Energy (Scope 1 and 2) represent 3% of the diagram breakdown; downstream activities represent 83% of total Greenhouse Gas emissions.

These emissions represent the Group's gross GHG emissions. The Group's climate targets are based on net GHG emissions and incorporate the use of ACCUs and LGCs.

Scope 1 – method and measurement

The Group's Scope 1 GHG emissions have been prepared in accordance with obligations under NGERS, ensuring methodologies, emissions factors and operational control reporting boundaries are applied in a way that is consistent with legislative requirements and aligns with recognised Australian emission measurement and reporting standards. The Geelong Refinery is the Group's largest source of GHG emissions, accounting for 98% of the Group's Scope 1 emissions in 2025. The refinery's Scope 1 GHG emissions are calculated based on: direct measurement of energy consumption (pressure and flow indicators into furnaces, calibrated to industry standards); calculations of refinery coke combusted using calibrated flow and pressure instrumentation; and quantities from invoices for natural gas import and crude oil/feedstock. A combination of Method 1 (default method, based on national average estimates) and Method 2 (facility specific method using industry sampling practices and Australian or equivalent standards) emissions factors are used to convert energy quantities to reportable GHG emissions. Method 2 emission factors are used for the site's largest fuel gas consuming furnaces; Method 1 emission factors are employed for minor fuel gas streams and non-gas energy.

2025 performance: During 1H2025, energy efficiency and emissions intensity at the refinery was broadly consistent with 2024. The largest event impacting emissions intensity during this period was the month-long maintenance event of CDU3, which reduced site feedstock consumption by 24% without a corresponding decrease in site emissions (4%). Energy and emissions performance in 2H2025 was impacted by the RCCU Turnaround (late July to mid-October 2025); as the RCCU is the site's most emission-intensive unit, its shutdown resulted in a significant reduction in the refinery's emissions intensity. Cracker coke yield, and therefore emissions from coke combustion, were lower in 2025 compared with 2024 due to a lighter (lower-carbon) average feed quality to the unit, estimated to have resulted in an emissions decrease of approximately 25,000 tCO2-e in 2025 compared with 2024. In October, the new ULSG plant was brought online; emissions associated with this new unit are expected to be largely offset by energy efficiency initiatives delivered on the RCCU during the 2025 Turnaround. The ULSG plant, together with the site's newly electrified catalyst cooler air blower, is expected to increase the site's ongoing electrical load by approximately 12%.

Scope 2 – method and measurement

The Group's Scope 2 GHG emissions have also been prepared in accordance with NGERS obligations. In addition to mandatory location-based Scope 2 emissions reporting, in 2025 the Group also commenced reporting market-based Scope 2 emissions on a voluntary basis. The majority of Scope 2 emissions were reported using metered electricity consumption data based on invoices received from utility providers. For some smaller facilities, Scope 2 emissions were estimated using a cost-allocation methodology based on tenancy space, representing 0.1% of total reported Scope 2 emissions. Emissions factors were sourced from the Department of Environment, Climate Change and Water's Australian National Greenhouse Accounts Factors, with 2024-25 data applied for 1H2025 and 2025-26 data applied to 2H2025.

2025 performance: The Group's Scope 2 emissions (calculated by location-based reporting) increased by 0.4% during 2025. Market-based emissions of 390,684 tCO2-e are reported for the first time in 2025, utilising a specific residual mix emission factor of 0.81 regardless of location, with any renewable component based on actual procurement of renewable energy through the surrender of Large Generation Certificates (LGCs). This methodology was adopted to ensure that Viva Energy Hub and EV electricity use is correctly offset with renewable energy certificates, to support Net Zero climate claims under the Clean Energy Regulator's legislative framework.

Scope 3

The Group's Scope 3 emissions arise from activities across the value chain, representing GHG emissions that occur outside the Company's ownership and direct control. The Group has elected to voluntarily disclose its Scope 3 emissions and has applied the transitional relief available under AASB S2 for this reporting period.

In 2025, the Group recorded a 6.2% increase in total Scope 3 emissions compared with 2024, with a total reported footprint of 49,025,408 tCO2-e. The most significant contributing category was Category 11 (use of sold products), representing approximately 85% of total Scope 3 emissions, equivalent to 41,970,442 tCO2-e.

Transition risks

Our risk assessment indicates that 100% of the Group's assets and business activities are vulnerable to climate-related risks in some way, with climate-related impacts applying across the entirety of the business rather than being confined to a discrete subset of activities or assets.

Physical risks

Our risk assessment indicates that 100% of the Group's assets and business activities are vulnerable to climate-related risks in some way; climate-related impacts apply across the entirety of the business rather than being confined to a discrete subset of activities or assets. For example, the Group has identified a material climate-related risk associated with a reduction in demand for hydrocarbon fuel products, which is expected to impact all business lines over the medium to long term.

Opportunities

Our risk assessment indicates that the Group's assets and business activities are aligned with climate-related opportunities in some way, with increasing demand for LCLFs and other new energies solutions providing opportunities across the Group's entire business model and value chain, from LCLF manufacturing at the Geelong Refinery, to the supply of LCLFs and other new energies to both commercial and retail customers.

Capital deployment

In 2025, the amount of capital expenditure, financing or investment deployed towards climate-related risks and opportunities by the Group was $32.4 million (exclusive of Government Grants). This 2025 investment relates to emissions reductions initiatives, new energies infrastructure, repurposing assets for the storage and supply of LCLFs, and co-processing opportunities. For example, in 2025 we received Government funding to repurpose an existing tank at our Pinkenba terminal for the storage and handling of neat SAF. We invested $85.5 million in 2025 (excluding Government contributions) to increase sulphur recovery and improve air quality emissions from fuel use through our ULSG plant at the Geelong Refinery.

Internal carbon prices

When developing new business cases for infrastructure projects that may directly or indirectly impact the Group's GHG emissions, we assess projected changes in energy consumption across electricity, natural gas, and fuel use, converted into metric tonnes of GHG emissions. To quantify the associated carbon cost, the Group applies published ACCU and renewable certificate prices:

• For natural gas and liquid fuel consumption, the midpoint between Reputex and Government Guaranteed price of ACCUs is applied. In 2025 ACCU prices ranged from $33 to $35.50 per ACCU, with an average price of $34.25 per ACCU.
• For electricity consumption, internal carbon pricing uses the midpoint of Reputex's published high and low case predictions. In 2025 the predicted LGC price ranged from $6.25/MWh to $10/MWh with an average price of $8.13/MWh.

This approach enables a consistent and transparent valuation of emissions impacts within project evaluations and supports capital allocation decisions aligned with the Group's decarbonisation strategy.

Remuneration

Certain 'strategic' and 'safety & ESG' measures within the STI program are linked to the Company's climate-related risks and opportunities. On average, 9% of the total short-term incentives accrued in 2025 for the Executive Leadership Team were linked to climate-related considerations. The 2025-2027 LTI strategic component (15% of the scorecard) also includes objectives relating to climate-related risks and opportunities, including delivering projects to achieve the Company's emission reduction targets and progress on new energies and lower carbon agenda.

Scope 1 and Scope 2 emissions, 2026 (p. 82), ktCO2e

About 98.3% of Scope 1 and 2 emissions were measured under the National Greenhouse and Energy Reporting (NGER) methodology, which the report says AASB S2 permits as a jurisdiction-specific relief (p. 82). Operational control approach; market-based Scope 2 reflects power purchase agreements, GreenPower contracts and renewable energy certificates (p. 81). Scope 1 and 2 (market-based) fell 21.9% on the prior year (p. 57).

Scope 3 (voluntary, pp. 82–83). 32,385 ktCO2e across all 15 categories: purchased goods and services (Category 1) 55%, use of sold products (Category 11) 36%, upstream transportation and distribution (Category 4) 3%, end of life treatment of sold products (Category 12) 2%. The report says the inventory is not prepared in alignment or compliance with AASB S2 (p. 90).

Other metrics. Sites exposed under Delayed Transition: heat about 200 (11%) rising to about 435 (24%) in the long term (p. 65); flooding about 375 (21%) falling to about 120 (6%) by 2050 (p. 67). Storm surge: up to about 5% of relevant logistics and transport infrastructure, about 40% by 2050 (p. 69). Internal carbon price $48.10 per metric tonne of CO2e (p. 75). Earnings contribution from WesCEF lithium operations $40 million (p. 73).

Scope 1 and 2 only, and FY26 only: the report applies transition reliefs and does not disclose comparative information or Scope 3 emissions (pages 56, 86).

Method (pages 85, 87–89). Operational control approach, including joint ventures, irrespective of equity interest; all emissions are in Australia and measured under the National Greenhouse and Energy Reporting Scheme (NGER); no change in measurement approach in FY26. Primary Scope 1 sources: diesel consumption (49.6% of Scope 1) and fugitive emissions (50.2%). New South Wales Scope 2 is covered by Climate Active-certified carbon-neutral electricity, and GreenPower from January 2026, giving net Scope 2 emissions of zero there.

Other metrics (pages 68, 90, 91). FY26 revenue from contracts with customers: $2,990m metallurgical coal and $2,411m thermal coal. Coal assets are 46% (metallurgical) and 37% (thermal) of total assets, the same figures for transition and physical risk. No FY26 revenue from climate-related opportunities. Capital invested: $47m toward opportunities (climate-related share cannot be separately identified) and $21m toward mitigation of risks. Carbon planning price: $40 per tonne of carbon dioxide equivalent, 2027 to 2031.

Greenhouse gas emissions (pp. 218–219)

FY25 comparatives are voluntary, exclude e2open and were updated for revised HVAC electricity estimates (+667 tonnes Scope 2 location-based, +768 market-based, +350 Scope 3 Category 3). Measured under the Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (2004) with an operational control boundary; methodology on pp. 220–223. Scope 3 covers Categories 1, 2, 3, 5, 6, 7, 8 and 11; Categories 4, 9, 10 and 12–15 are deemed not relevant (p. 219).

Other categories. No internal carbon price is applied (p. 211). Executive remuneration is not explicitly linked to climate performance (p. 212). Capital expenditure toward climate-related risks is not material (p. 216). Exposure is given only as percentages: 100% of data center IT assets may be exposed to the physical risk (p. 214), and approximately 30–50% of Group revenue is cited both as transaction-related revenue exposed to grid instability and as volume-based customer activity (p. 215). Investment aligned to the opportunity of climate-related regulation is approximately $3.5–19.5m, 1–5% of R&D investment (p. 216).

Greenhouse gas emissions

Gross equity Scope 1 and 2 GHG emissions were 6,616 kt CO2-e, 2.5% fewer than in 2024 despite higher production. Gross equity Scope 1 and 2 emissions do not include the use of carbon credits as offsets.

Woodside measures and discloses its GHG emissions in accordance with the GHG Protocol and AASB S2. Woodside uses the equity share approach to define its organisational boundary; GHG emissions are accounted for in line with Woodside's economic interest.

Woodside estimates Scope 1 GHG emissions using the emissions factors and methodologies that best represent our activities in accordance with the relevant reporting regulations in the jurisdiction where the GHG emissions occur, including use of the NGER Measurement Determination in Australia and the EPA Greenhouse Gas Reporting Program (GHGRP) in the US. No material changes were made to Woodside's Scope 1 GHG emissions measurement approach, inputs and assumptions during the reporting period.

Woodside estimates Scope 2 GHG emissions using the location-based approach and utilising data on electrical consumption documented in utility bills and representative grid emissions factors including those specified within the NGER Measurement Determination for Australian electricity use. Woodside reports Scope 2 GHG emissions on an equity share basis from our facilities and office locations including Australian offices and our Houston corporate office. No material changes were made to Woodside's Scope 2 GHG emissions measurement approach, inputs and assumptions during the reporting period.

Consistent with AASB S2 (29(a)(iv)) Woodside has considered disclosing relevant information on its Scope 1 and 2 GHG emissions disaggregated between the consolidated accounting group and other investees. Entities within the consolidated accounting group include those with ownership of all of Woodside's producing assets, projects and developments, such that they represent all of Woodside's Scope 1 and Scope 2 GHG emissions. There are no material Scope 1 or Scope 2 GHG emissions associated with other investees excluded from the consolidated accounting group.

Woodside is reporting under AASB S2 for the first time in the annual reporting period ended 31 December 2025 and has exercised the relief available with respect to the provision of comparative information and the disclosure of Scope 3 GHG emissions. Woodside voluntarily discloses its 2025 Scope 3 emissions under its existing GHG Protocol aligned methodology in the data table on its website.

Transition risks

See CRRO quantification for "Higher than expected cost to reduce emissions at operations" and "Lower than expected product demand", each assessed within Low (US$0–US$195m) / Moderate (US$195m–US$1b) / High (more than US$1b) categories over short/medium/long term.

Physical risks

See CRRO quantification for "Extreme weather intensification": assessed in the "Moderate" category over the long-term based on impact on financial performance of an increase in extreme heat days upon Australian operations in the Pilbara region of WA.

Opportunities

See CRRO quantification for "Increased demand for LNG" (moderate to high, medium to long-term), "Increased demand for new energy products and lower-carbon services" (moderate, long-term), and "Lower than expected decarbonisation costs" (potentially high, long-term).

Capital deployment

Cumulative expenditure against the Scope 3 investment target reached $2.6 billion at the end of 2025, up from $2.46 billion at the end of 2024, due to expenditure on Neosmelt, Beaumont New Ammonia Phase 2 assessment, and select CCS opportunities in Asia Pacific.

Internal carbon prices

Woodside's assumption on carbon cost pricing includes a long-term carbon price of US$80/t CO2-e of emissions (real terms 2024), reviewed annually. When assessing methane emissions reduction opportunities, Woodside multiplies its internal cost of carbon of US$80/t CO2-e (real terms 2024) by 84, representing the higher global warming potential of methane in the near-term, resulting in an effective price for methane of US$6,720/t emitted.

Remuneration

In 2025, safety and climate metrics were each a distinct component of the Company Scorecard impacting Variable Annual Reward. Climate metrics make up 15% of the total scorecard, and are based on gross Scope 1 and 2 GHG emissions performance and on new energy project progress. Gross equity emissions are calculated prior to retirement of carbon credits as offsets, focusing organisational priorities on avoiding and reducing emissions.

Emissions (pp. 77–78). Absolute gross emissions, calculated under the Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (2004) with an operational control approach. The boundary aligns with the consolidated reporting entity and excludes associates and joint ventures.

Other metrics. $111 million invested in F26 on initiatives driving the overall strategy and Scope 1 and 2 progress; no internal shadow carbon price adopted (p. 74). No specific percentage of executive remuneration directly linked to climate-related metrics (p. 55).

Greenhouse gas emissions, FY2026 (p. 52). Reported gross, excluding carbon credits.

Methods (pp. 55–56): Greenhouse Gas Protocol, operational control basis; about 89% of Scope 1 and 87% of Scope 2 (location-based) emissions were calculated from actual data.

Other metrics (pp. 40, 42–45, 52). Revenue aligned with CRRO 1 is $8,316m (69%); revenue vulnerable to CRROs 2, 3 and 4 is $4,657m (39%), $5,422m (45%) and $4,926m (41%). No capital was directly deployed against any CRRO in FY2026. Indicative carbon price ranges support decarbonization activities, referencing external prices of $0-200 per tCO2e; no single, consistent internal carbon price is applied to decisions such as capital allocation, transfer pricing or scenario analysis. Remuneration is described under Governance (p. 40).

Greenhouse gas emissions

Yancoal reports its greenhouse gas (GHG) emissions and energy consumption in accordance with the Australian Government's National Greenhouse and Energy Reporting Act 2007 (Cth) (NGER Act). Yancoal submitted its annual emissions and energy report under Section 19 of the NGER Act (s19 report) for the reporting period of 1 July 2024 - 30 June 2025 (FY25). The s19 report sets out our total Scope 1 and Scope 2 emissions, which are reported by 'facility' having regard to those facilities that Yancoal has operational control of.

• Scope 1 emissions arise directly from operational activities, including fugitive emissions from coal extraction and emissions from fuel combustion.
• Scope 2 emissions represent indirect emissions associated with purchased electricity.

Total Scope 1 and Scope 2 emissions for the 12-month period ending 30 June 2025 totalled 2,763,249 tonnes of carbon dioxide equivalent (tCO2-e), representing a 21% increase compared with the previous year (FY24). Of this, total Scope 1 emissions accounted for 90% at 2,476,890 tCO2-e, with the remaining 10% resulting from our Scope 2 emissions of 286,360 tCO2-e. Over the same period, total run of mine (ROM) coal production increased by 1%, resulting in an emissions intensity of 0.054 tCO2-e/ROM tonne, a 20% increase from FY24.

The Safeguard Mechanism applies to facilities whose covered Scope 1 emissions exceed the Safeguard default threshold of 100,000 tCO2-e per year, with any emissions that exceed the facility's baseline to be offset by surrendering either Australian Carbon Credit Units (ACCUs) or Safeguard Mechanism Credits (SMCs). In FY25, with the exception of Moolarben, all Yancoal-managed Safeguard facilities exceeded their baselines. This resulted in total exceedances of: Ashton: 488,761 tCO2-e; Premier: 6,030 tCO2-e; Warkworth: 301,673 tCO2-e; Yarrabee: 40,317 tCO2-e. Yancoal has surrendered sufficient ACCUs to meet its compliance obligations under the Safeguard Mechanism for FY25. Moolarben generated 39,794 SMCs, which may be used to offset future emissions obligations or sold to other Safeguard entities.

We are working to map and define our Scope 3 emissions profile. (Note: per Appendix A, Yancoal has claimed transitional relief from disclosing Scope 3 emissions and comparative information in the first annual reporting period under AASB S2, per ASIC Regulatory Guide RG 280.107, and will report Scope 3 GHG emissions in the next annual reporting year.)

Energy consumption: Total energy consumption in FY25 increased in line with a rise in ROM production, driven predominantly by diesel fuel used in mining operations. Direct and indirect energy consumption across all sites totalled 3,976,601 MWh, a 2% increase compared with FY24 (3,881,913 MWh). Energy intensity for the reporting period was 0.08 MWh/ROMt, remaining consistent with the previous year.

Internal carbon prices

During 2025, we enhanced [capital prioritisation] through the use of a carbon-pricing analytics platform, which provides market data and forward-looking insights to support Life of Mine planning and internal project evaluation. This information is considered alongside scenario-based price projections, including those that incorporate a carbon price. In 2025, Yancoal's adopted carbon price prediction was informed by data from a leading carbon pricing platform and considered within Life-of-Mine Planning models, including current ACCU market prices, forward curves, and high/mid/low pricing scenarios.