About These Statements (Policies)	12 Months Ended
Dec. 31, 2025
Significant Accounting Policies [Abstract]
Statement of compliance	Statement of compliance The financial statements are general purpose financial statements, which have been prepared in accordance with the requirements of the International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board. They also include additional disclosures required for foreign registrants by the United States Securities and Exchange Commission (US SEC). The Group’s accounting policies are materially consistent with those disclosed in the Group’s 2024 Financial Statements. Adoption of new or amended standards and interpretations effective 1 January 2025 did not result in any significant changes to the Group’s accounting policies. Refer to Note E.9 for more details. Estimates have been revised, where required, to reflect current market conditions including the impact of climate change. Updated assumptions used for impairment assessments, restoration provisions and embedded commodity derivatives are disclosed in Notes B.4, D.5 and D.6 respectively; these assumptions could change in the future. New estimates and judgements relating to transactions with equity holders of the Group are disclosed in Note B.9.
Currency	Currency The accounting functional and presentation currency of Woodside and all its material subsidiaries is the US dollar. Transactions in foreign currencies are initially recorded in the functional currency of the transacting entity at the exchange rates ruling at the date of transaction. Monetary assets and liabilities denominated in foreign currencies at the reporting date are translated at the rates of exchange ruling at that date. Exchange differences in the consolidated financial statements are taken to the consolidated income statement.
Basis of preparation	Basis of preparation The financial statements have been prepared on a historical cost basis, except for derivative financial instruments and certain other financial assets and financial liabilities, which have been measured at fair value or amortised cost adjusted for changes in fair value attributable to the risks that are being hedged in effective hedge relationships. Where not carried at fair value, if the carrying value of financial assets and financial liabilities does not approximate their fair value, the fair value has been included in the notes to the financial statements. Subsidiaries are fully consolidated from the date on which control is obtained by the Group and cease to be consolidated from the date at which the Group ceases to have control. The financial statements comprise the financial position and results of the Group as at and for the year ended 31 December 2025 (refer to Note E.8). The material subsidiaries of the Group apply the same reporting period and accounting policies as the parent company in their financial statements. All intercompany balances and transactions, including unrealised profits and losses arising from intra-group transactions, have been eliminated in full. Non-controlling interests are allocated their share of the net profit after tax in the consolidated income statement and their share of other comprehensive income net of tax in the consolidated statement of comprehensive income, and are presented within equity in the consolidated statement of financial position, separately from parent shareholders’ equity. The consolidated financial statements provide comparative information in respect of the previous periods. Where required, a reclassification of items in the financial statements of the previous periods has been made in accordance with the classification of items in the financial statements of the current period.
Climate Change And Energy Transition	Climate Change And Energy Transition Climate considerations Woodside has considered the impact of climate and the energy transition across its global portfolio in assessing the carrying values of its assets and liabilities. This note describes the assumptions underpinning key areas of the financial statements and the potential short-term and long-term impacts of differing climate-related scenarios on the financial performance, position and cash flow of Woodside for the year ended 31 December 2025. Financial planning and assumptions Woodside considers a range of climate and macroeconomic scenarios to help benchmark our long-term price assumptions and inform our decision making to maintain a resilient financial position. These scenarios are informed by a wide range of externally published data and are part of a broad consideration of risks, opportunities, competitiveness and resilience. The assumptions applied in assessing amounts within the financial statements require significant judgement and are in each case calculated in accordance with the requirements of the applicable accounting standards. Our long-term price assumptions reflect management’s current “best estimate” scenario in which global governments pursue decarbonisation goals as well as other goals such as energy security and economic development. Price assumptions consider current legislation in the locations where Woodside operates and place some weight on scenarios in which the transition to a lower carbon energy system is sufficiently rapid to meet global climate goals, as well as scenarios in which the transition is not, or may not be, sufficiently rapid. They also place some weight on a range of other assumptions which can drive prices (e.g. inflation) and which are not related to the global climate goals. Woodside’s oil and gas facilities are subject to physical risks such as metocean conditions and are located in regions that experience tropical cyclones, hurricanes and high ambient temperatures. Woodside has significant experience designing and operating facilities located in harsh environments. The high degree of uncertainty around the nature, timing and magnitude of climate-related risks, and the uncertainty as to how the energy transition will evolve, makes it difficult to determine the potential impacts of the risks with precision. Woodside continues to monitor the uncertainty around climate change risks and expects to take into account ongoing developments into its assumptions, including assumptions concerning commodity and carbon pricing, as considered appropriate. Investment cases include a carbon price assumption which takes into consideration uncertainty around the impact of climate change. Commodity pricing assumptions are key value drivers with greater significance to assets and liabilities than carbon pricing.
Impairment of exploration and evaluation, property, plant and equipment and goodwill	Impairment of exploration and evaluation, property, plant and equipment and goodwill In accordance with the Group's accounting policies and applicable accounting standards, elements of Woodside’s financial statements are based on reasonable and supportable assumptions that represent management’s current best estimate of the range of economic conditions that may exist in the foreseeable future. The estimation of recoverable amounts for impairment testing includes estimating what an independent market participant would pay to acquire the asset as at the reporting date. Market participants will be guided by their own views on future economic and technical conditions and therefore Woodside considers a range of data sources in determining a future price forecast, including industry and market benchmarks along with asset sales transaction data to support the recoverable amount. The completion of the sale of the 10% and 15.1% non-operating participating interest in the Scarborough Joint Venture to LNG Japan and JERA respectively in 2024, is a clear example of an independent market valuation fully supporting the carrying value of the multi- decade asset. Price forecasts are adjusted for premiums and discounts based on the nature and quality of the product. Commodity oil price estimates consider macroeconomic factors such as population growth and have regard to potential climate pathways along with other factors such as industry investment and cost trends. There remains significant uncertainty around how society will respond to the climate challenge. The energy transition is expected to bring volatility and there is uncertainty as to how commodity prices will develop. Woodside’s assumptions for Brent and JKM sit within the range of scenarios considered by management. Refer to Note B.4Impairment Refer to Note B.4 for details on impairment, including any write‑offs. Impairment Refer to Note B.4 for details on impairment. Exploration and evaluation Impairment testing The recoverability of the carrying amount of exploration and evaluation assets is dependent on successful development and commercial exploitation, or alternatively sale of the respective AOI. Each AOI is reviewed half-yearly to determine whether economic quantities of hydrocarbons have been found, or whether further exploration and evaluation work is underway or planned to support continued carry forward of capitalised costs. Where a potential impairment is indicated for an AOI, an assessment is performed using a fair value less costs to dispose (FVLCD) method to determine its recoverable amount. Upon approval for commercial development, exploration and evaluation assets are assessed for impairment before they are transferred to property, plant and equipment. Impairment calculations If the carrying amount of an AOI exceeds its recoverable amount, the AOI is written down to its recoverable amount and an impairment loss is recognised in the consolidated income statement. Property, plant and equipment Impairment testing The carrying amounts of property, plant and equipment are assessed half-yearly to determine whether there is an indicator of impairment or impairment reversal for those assets which have previously been impaired. Indicators of impairment and impairment reversals include changes in reserves for oil and gas assets, expected future sales prices, or costs. Property, plant and equipment are assessed for impairment indicators and impairments on a cash-generating unit (CGU) basis. CGUs are determined as offshore and onshore facilities, infrastructure and associated oil and/or gas fields and new energy assets. If there is an indicator of impairment or impairment reversal for a CGU, its recoverable amount is calculated and compared with the CGU’s carrying value (refer to impairment calculations below). Goodwill For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash-generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Goodwill is tested for impairment at least annually and more frequently if events or changes in circumstances indicate that it might be impaired. Impairment of goodwill is determined by assessing the recoverable amount of each CGU to which the goodwill relates and comparing it with its carrying value, which includes deferred taxes (refer to impairment calculations below and Note B.5). When part of an operation is disposed of, any goodwill associated with the disposed operation is included in the carrying amount of the operation in determining the gain or loss on disposal. Goodwill and property, plant and equipment impairment calculations The recoverable amount of an asset or CGU is determined as the higher of its value in use (VIU) and FVLCD. VIU is determined by estimating future cash flows after taking into account the risks specific to the asset and discounting to present value using an appropriate discount rate. FVLCD is the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the effects of factors that may be specific to the Group. In determining FVLCD, recent market transactions are considered. If no such transactions can be identified, an appropriate valuation model, such as discounted cash flow techniques, is applied on a post-tax basis using an appropriate discount rate and estimates are made about the assumptions market participants would use when pricing the asset or CGU. If the carrying amount of an asset or CGU, including any allocated goodwill, exceeds its recoverable amount, the asset or CGU is written down to its recoverable amount and an impairment loss is recognised in the consolidated income statement. Any impairment losses are first allocated to reduce the carrying amount of any goodwill allocated, with the remaining impairment losses allocated to the relevant assets. If the recoverable amount of an asset or CGU exceeds its carrying amount, and that asset or CGU has previously been impaired, the impairment is reversed. The carrying amount of the asset or CGU is increased to its recoverable amount, but only to the extent that the carrying amount does not exceed the value that would have been determined, net of depreciation, if no impairment had been recognised. Impairments of goodwill are not reversed.
Impact on remaining life of assets	Impact on remaining life of assets Oil and gas properties, included within property, plant and equipment, are depreciated using the unit of production basis over either proved or proved plus probable reserves. The energy transition may result in changes to the expected useful life of oil and gas properties and economically recoverable reserves and resources thereby accelerating depreciation charges or resulting in an impairment. New energy assets under development still require significant capital spend. The Group will review depreciation methodology and useful life of new energy assets as they are brought into use. Recognition and measurement Property, plant and equipment are stated at cost less accumulated depreciation and impairment charges. Projects in development include the construction of oil and gas assets and new energy assets: •Projects in development for oil and gas assets include the costs to acquire, construct, install or complete production and infrastructure facilities such as pipelines and platforms, capitalised borrowing costs, transferred exploration and evaluation assets, development wells and the estimated cost of dismantling and restoration. •Projects in development for new energy assets include the costs to acquire, construct, install or complete infrastructure facilities, capitalised borrowing costs and the estimated cost of dismantling and restoration. Borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset are capitalised as part of the cost of that project when it is probable that they will result in future economic benefits and the costs can be measured reliably. The interest rate used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the Group’s outstanding borrowings during the period. When commercial operation commences, the accumulated costs in projects in development will be transferred to oil and gas properties or new energy assets. Subsequent capital costs, including major maintenance, are included in the asset’s carrying amount only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be reliably measured.
Carbon credits	Carbon credits Woodside utilises certified carbon credits to offset equity Scope 1 and 2 emissions that are above our targets in a given year and to meet our regulatory requirements, after design out and operate out measures have been taken. The Group’s portfolio of carbon credits enables our base business to manage the price risk associated with regulations and our corporate net equity Scope 1 and 2 emissions targets.
Restoration and other provisions	Restoration and other provisions The energy transition may result in restoration activities occurring earlier than expected. 56% (2024: 53%) of the Group’s non-current restoration liabilities are expected to be settled more than 10 years in the future. Restoration cost estimates require judgemental assumptions regarding removal date, environmental legislation and regulations and the extent of restoration activities required. These cost estimates may change in the future, as a result of increased regulatory scrutiny and the energy transition. This includes the demand and related costs for offshore services which can be influenced by renewable energy construction. Woodside continues to monitor the uncertainty around climate change risks to assess if additional changes to restoration provisions should be recognised. Refer to Note D.5 for further details. Recognition and measurement Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
Long-term contracts	Long-term contracts Climate risks may impact underlying assumptions used to assess the forecast cash flows of long-term contracts. These judgemental assumptions include pricing forecast and discount rate adjustments based on the nature of the product. Contractual arrangements, including the Corpus Christi contract, could be impacted by adverse market conditions arising from climate- related factors. Given the uncertainty in climate events, Woodside continues to review the forecast cash flows of long‑term contracts.
Deferred tax assets	Deferred tax assets The Group has determined that it is probable that sufficient future taxable income will be available to utilise the deferred tax assets relating to carry forward unused tax losses and credits recognised as at 31 December 2025. The recoverability of deferred tax assets is dependent on the Group’s future taxable income which can be impacted by the uncertainty of commodity and carbon pricing.
Commodity price risk management, Foreign exchange risk management and Capital risk management	Commodity price risk management The Group’s revenue is exposed to commodity price fluctuations through the sale of hydrocarbons. Commodity price risks are measured by monitoring and stress testing the Group’s forecast financial position to sustained periods of low commodity prices. This analysis is regularly performed on the Group’s portfolio and as required for discrete projects and transactions. The Group’s management of commodity price risk includes the use of commodity derivatives to hedge its exposure (refer to Note D.6). The hedged exposure includes oil-linked revenue related to produced volumes and revenues derived from trading operations. Commodity derivatives are used to manage the Group’s price risk within its corporate and trading portfolios. Foreign exchange risk management Foreign exchange risk arises from future commitments, financial assets and financial liabilities that are not denominated in US dollars. The majority of the Group’s revenue is denominated in US dollars. The Group is exposed to foreign currency risk arising from operating and capital expenditure incurred in currencies other than US dollars, particularly Australian dollars. The Group’s management of foreign exchange risk relating to capital expenditure includes the use of forward exchange contract derivatives to hedge its exposure (refer to Note D.6). Capital risk management Group Treasury is responsible for the Group's capital management including cash, debt and equity. Capital management is undertaken to ensure that a secure, cost-effective and flexible supply of funds is available to meet the Group’s operating and capital expenditure requirements. A stable capital base is maintained from which the Group can pursue its growth aspirations, whilst maintaining a flexible capital structure that allows access to a range of debt and equity markets to both draw upon and repay capital. The Dividend Reinvestment Plan (DRP) was approved by shareholders at the Annual General Meeting in 2003 for activation as required to fund future growth. The DRP was reactivated in 2019 and suspended by the Board of Directors on 27 February 2023. A range of financial metrics are monitored, including gearing and cash flow leverage, and Treasury policy breaches and exceptions.
Revenue from contracts with customers	Revenue from contracts with customers Revenue is recognised when or as the Group transfers control of products or provides services to a customer at the amount to which the Group expects to be entitled. If the consideration includes a variable component, the Group estimates the amount of the expected consideration receivable. Variable consideration is estimated throughout the contract and is recognised to the extent that it is highly probable a significant reversal will not occur. •Revenue from sale of hydrocarbons – Revenue from the sale of hydrocarbons is recognised at a point in time when control of the product is transferred to the customer. Revenue from take or pay contracts is recorded as unearned revenue until the product has been drawn by the customer (transfer of control), at which time it is recognised in earnings. •Other operating revenue – Revenue earned from LNG processing and other services is recognised over time as the services are rendered. (a) Revenue from contracts with customers The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices. Judgement is also used to determine if it is highly probable that a significant reversal will not occur in relation to revenue recognised during open pricing periods in LNG contracts. The Group estimates variable consideration based on available information from contract negotiations and market indicators.
Expenses	Expenses •Royalties, excise and levies – Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group’s entitlement to physical production. •Depreciation and amortisation - Refer to Note B.3. •Impairment and impairment reversals - Refer to Note B.4. •Leases - Refer to Note D.7. •Employee benefits - Refer to Note E.2.
Taxes - Recognition and measurement	Recognition and measurement Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset is realised. The tax rates and laws used to determine the amount are based on those that have been enacted or substantively enacted by the end of the reporting period. Income taxes relating to items recognised directly in equity are recognised in equity. Current taxes Current tax expense is the expected tax payable on the taxable income for the current year and any adjustment to tax paid in respect of previous years. Deferred taxes Deferred tax expense represents movements in the temporary differences between the carrying amount of an asset or liability in the consolidated statement of financial position and its tax base. With the exception of those noted below, deferred tax liabilities are recognised for all taxable temporary differences. Deferred tax assets are recognised for deductible temporary differences, unused tax losses and tax credits only if it is probable that sufficient future taxable income will be available to utilise those temporary differences and losses. Deferred tax is not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of assets and liabilities in a transaction that affects neither accounting profit nor the taxable profit. In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable profits when assessing the extent to which a deferred tax asset can be recognised in the consolidated statement of financial position. Offsetting deferred tax balances Deferred tax assets and liabilities are offset only if there is a legally enforceable right to offset current tax assets and liabilities and when they relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities that the Group intends to settle its current tax assets and liabilities on a net basis. Refer to Notes E.8 and E.9 for detail on the tax consolidated groups. Pillar Two legislation In December 2021, the Organisation for Economic Co-operation and Development (OECD) published its Pillar Two legislation rules. The Pillar Two legislation rules aim to ensure that large multinational groups pay a minimum of 15% tax for each jurisdiction in which they operate. Pillar Two legislation has been enacted or substantively enacted in a number of jurisdictions in which the Group operates with effect from 1 January 2024. The Group applies the exception to recognising and disclosing information about deferred tax assets and liabilities related to Pillar Two income taxes. The Group has undertaken a Pillar Two analysis for the year ended 31 December 2025 and is expected to have met relevant safe harbours for all jurisdictions in which it operates except for Singapore. The amount of Singapore Pillar Two tax expense is not material. Significant estimates and judgements (a) Income tax classification Judgement is required when determining whether a particular tax is an income tax or another type of tax. PRRT is considered, for accounting purposes, to be an income tax. Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes, e.g. North West Shelf royalties, excise and levies which are recognised in cost of sales in the income statement. (b) Deferred tax asset recognition Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from USA TCG 1 of $1,227 million (2024: $1,274 million), USA TCG 2 of $200 million (2024:nil) and $396 million (2024: $410 million) arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a) for details of tax consolidated groups. Unrecognised DTAs relating to carry forward unused tax losses and credits of $320 million (2024: $366 million) from the USA TCG 1, $150 million (2024: $343 million) from USA TCG 2 and $663 million (2024: $715 million) from countries other than Australia and the USA. These DTAs have not been recognised as it is not currently probable that the losses and credits will be utilised based on current planned activities in those countries. On 29 April 2025, the Group approved an FID to develop the Louisiana LNG Project. Upon FID, the Group recognised a DTA of $182 million. In the prior year, subsequent to achieving first oil on the Sangomar project in June 2024, the Group recognised a net DTA of $342 million. PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable profits. During the year ended 31 December 2025, the Group did not recognise any additional Pluto PRRT DTA as a result of recoverability assessments performed. In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable profits are risk‑adjusted where appropriate by a market premium risk rate to reflect uncertainty inherent in long-term forecasts. A long-term bond rate of 4.3% (31 December 2024: 3.2%) was used for the purposes of augmentation. Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable profits. $7,728 million (2024: $7,490 million) relates to the North West Shelf Project, $779 million (2024: $601 million) relates to remaining Pluto deductible balances and $776 million (2024: $795 million) relates to Wheatstone. A long-term bond rate of 4.3% (31 December 2024: 3.2%) was used for the purposes of augmentation. Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the assessment, additional deferred tax assets would be recognised, with a corresponding benefit to tax expense. It was determined that the approach adopted provides the most meaningful information on the implications of the PRRT regime, whilst ensuring compliance with IAS 12 Income Taxes. (c) Uncertain tax positions The Group has tax matters, litigation and other claims, for which the timing of resolution and potential economic outflows are uncertain. Where the Group assesses an outcome for any tax matter, litigation or other claim as more likely than not to be accepted by the relevant tax authority, the position is adopted in the reported tax balances. Because of the complexity of some of these positions, the ultimate outcome may differ from the current estimate of the position. These differences will be reflected as increases or decreases to tax expense in the period in which new information is available. Tax matters without a probable economic outflow and/or presently cannot be measured reliably are contingent liabilities and disclosed in Note E.1 Contingent liabilities and assets. (a) Summary of other material accounting policies Australia tax consolidation The parent and its wholly owned Australian controlled entities have elected to enter a tax consolidation, with Woodside Energy Group Ltd as the head entity of the tax consolidated group. The members of the Australian tax consolidated group are identified in Note E.8(a). The tax expense/benefit, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax consolidated group are recognised in the separate financial statements of the members of the tax consolidated group, using the stand- alone approach. Entities within the tax consolidated group have entered into a tax funding arrangement and a tax sharing agreement with the head entity. Under the tax funding agreement, Woodside Energy Group Ltd and each of the entities in the tax consolidated group have agreed to pay or receive a tax equivalent payment to or from the head entity, based on the current tax liability or current tax asset of the entity. The tax sharing agreement entered into between members of the tax consolidated group provides for the determination of the allocation of income tax liabilities between the entities, should the head entity default on its tax payment obligations. No amounts have been recognised in the financial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is considered remote. US tax consolidation The Group has two separate USA Tax Consolidation Groups as at 31 December 2025: •Woodside Energy USA Operations Inc. and its wholly owned USA controlled entities have elected to file a consolidated tax return, with Woodside Energy USA Operations Inc. as the parent of the tax consolidated group (USA TCG 1). •Woodside Energy Holdings (USA) Inc. and its wholly owned USA controlled entities have elected to file a consolidated tax return, with Woodside Energy Holdings (USA) Inc. as the parent of the tax consolidated group. The consolidated tax return will include the subsidiaries acquired as part of the Tellurian acquisition from acquisition date. Deferred tax assets and liabilities arising from temporary differences within this consolidated group have been recognised to the extent that they do not meet the initial recognition exemption in relation to the Tellurian acquisition (USA TCG 2). The tax expense/benefit, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax consolidated group are computed on a separate company basis. Entities within the tax consolidated group have entered into a tax sharing agreement. Under the tax sharing agreement, the tax liability for the consolidated group or the utilisation of tax attributes are settled periodically between the members of the group. The tax sharing agreement between members of the tax consolidated group has no overall impact on the financial statements.
Significant estimates and judgements	Significant estimates and judgements (a) Income tax classification Judgement is required when determining whether a particular tax is an income tax or another type of tax. PRRT is considered, for accounting purposes, to be an income tax. Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes, e.g. North West Shelf royalties, excise and levies which are recognised in cost of sales in the income statement. (b) Deferred tax asset recognition Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from USA TCG 1 of $1,227 million (2024: $1,274 million), USA TCG 2 of $200 million (2024:nil) and $396 million (2024: $410 million) arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a) for details of tax consolidated groups. Unrecognised DTAs relating to carry forward unused tax losses and credits of $320 million (2024: $366 million) from the USA TCG 1, $150 million (2024: $343 million) from USA TCG 2 and $663 million (2024: $715 million) from countries other than Australia and the USA. These DTAs have not been recognised as it is not currently probable that the losses and credits will be utilised based on current planned activities in those countries. On 29 April 2025, the Group approved an FID to develop the Louisiana LNG Project. Upon FID, the Group recognised a DTA of $182 million. In the prior year, subsequent to achieving first oil on the Sangomar project in June 2024, the Group recognised a net DTA of $342 million. PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable profits. During the year ended 31 December 2025, the Group did not recognise any additional Pluto PRRT DTA as a result of recoverability assessments performed. In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable profits are risk‑adjusted where appropriate by a market premium risk rate to reflect uncertainty inherent in long-term forecasts. A long-term bond rate of 4.3% (31 December 2024: 3.2%) was used for the purposes of augmentation. Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable profits. $7,728 million (2024: $7,490 million) relates to the North West Shelf Project, $779 million (2024: $601 million) relates to remaining Pluto deductible balances and $776 million (2024: $795 million) relates to Wheatstone. A long-term bond rate of 4.3% (31 December 2024: 3.2%) was used for the purposes of augmentation. Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the assessment, additional deferred tax assets would be recognised, with a corresponding benefit to tax expense. It was determined that the approach adopted provides the most meaningful information on the implications of the PRRT regime, whilst ensuring compliance with IAS 12 Income Taxes. (c) Uncertain tax positions The Group has tax matters, litigation and other claims, for which the timing of resolution and potential economic outflows are uncertain. Where the Group assesses an outcome for any tax matter, litigation or other claim as more likely than not to be accepted by the relevant tax authority, the position is adopted in the reported tax balances. Because of the complexity of some of these positions, the ultimate outcome may differ from the current estimate of the position. These differences will be reflected as increases or decreases to tax expense in the period in which new information is available. Tax matters without a probable economic outflow and/or presently cannot be measured reliably are contingent liabilities and disclosed in Note E.1 Contingent liabilities and assets. Significant estimates and judgements (a) Area of interest Typically, an AOI is defined by the Group as an individual geographical area whereby the presence of hydrocarbons is considered favourable or proved to exist. The Group has established criteria to recognise and maintain an AOI. (b) Transfer to projects in development Development activities commence after project sanctioning by the appropriate level of management. Judgement is applied by management in determining when the project is technically feasible and economically viable to transfer to projects in development. Significant estimates and judgements (a) Reserves The estimation of reserves requires significant management judgement and interpretation of complex geological and geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs, and their anticipated recoveries. Estimates of oil and natural gas reserves are used to calculate depreciation and amortisation charges for the Group’s oil and gas properties. Judgement is used in determining the economic reserve base applied to each asset. Estimates are reviewed at least annually or when there are changes in the economic circumstances impacting specific assets or asset groups. These changes may impact depreciation, asset carrying values, restoration provisions and deferred tax balances. If reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the asset’s carrying value. (b) Depreciation Judgement is required to determine when assets are available for use to commence depreciation. Depreciation generally commences on first production. Significant estimates and judgements (a) CGU determination Identification of a CGU requires management judgement. Management has determined CGUs based on the smallest group of assets that generate significant cash inflows that are independent from other assets or groups of assets. (b) Allocation of goodwill Judgement is required in the allocation of goodwill arising from business combinations to the Group’s CGUs that are expected to benefit from the synergies of the business combination. (c) Recoverable amount calculation key assumptions In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash flows when determining the FVLCD. FVLCD methodology uses assumptions reflecting market participant's current expectations of such future cash flows (to determine a value that a willing seller and a willing buyer would accept in a market transaction). These estimates require significant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can also affect the assumptions used and the rates used to discount future cash flow estimates. Significant estimates and judgements (a) Nature of acquisition Judgement is required to determine if the acquisition is a business combination due to the stage of completion of the project and the timing of transfer of employees. The project is under construction, with agreements in place to complete construction and transfer a fully operational asset together with a workforce to the Group. The agreements were in place at acquisition date and provide Woodside with control over the future economic benefits of the project, and the necessary inputs and processes to create outputs, meeting the definition of a business combination. (b) Fair value determination for net assets acquired Judgement is required to determine the fair value of assets acquired and liabilities assumed in a business combination, which can have a material impact on resultant goodwill. This includes the use of a cash flow model to estimate the expected future cash flows and the discount rate used. On acquisition date, the reproduction cost method was used to fair value the property, plant and equipment in its construction phase. The reproduction cost method calculates the cost to construct an equivalent asset with the same specifications. (c) Contingent consideration Judgement is required to determine the fair value of the contingent consideration which includes consideration on the construction progress, estimates to complete compared to the schedule and performance guaranteesSignificant estimates and judgements (a) Goodwill allocation Judgement is required in the allocation of goodwill to the Group’s CGUs that are expected to benefit from the synergies of the business combination. Refer to Note B.4 for the details of the goodwill allocation. (b) Contract assets In determining the fair value of the contract assets as part of a business combination, estimates are made regarding the pricing assumptions and discount rate. These estimates require management judgement and changes in economic conditions can impact the fair value assessment of the contracts. Significant estimates and judgements (a) Nature of acquisition Judgement is required to determine if the transaction is the acquisition of an asset or a business combination. The Louisiana LNG Project is in its preliminary phase with significant construction milestones and costs to be incurred prior to the facility being operational and the acquired assets and liabilities did not meet the criteria for a business combination due to the absence of a substantive process and organised workforce required to convert inputs to outputs. (b) Employee compensation program As part of the acquisition, the Group has assumed the obligation of Tellurian’s compensation programs to its employees. Judgement is required to determine the measurement of the employee provision on acquisition as certain conditions in the compensation programs are linked to future milestones of the Louisiana LNG Project. This includes determining the likelihood and timing of the milestones. Significant estimates and judgements (a) Control Under IFRS 10 Consolidated Financial Statements, consolidation is required when an investor controls an investee. If a parent loses control of a subsidiary, the parent is required to derecognise the assets and liabilities of the former subsidiary at their carrying amounts at the date when control is lost. Judgement is required to determine if the Group continues to control Louisiana LNG Infrastructure LLC after the sell-down. It has been determined that the Group continues to control and consolidate Louisiana LNG Infrastructure LLC as it has the power to direct the relevant activities and decisions requiring majority approval through its roles as operator, construction manager, and majority interest holder. (b) Classification of non-controlling interest as equity or liability Judgement is required to determine if the classification of the non‑controlling interest is either equity or liability based on the Group’s contractual obligation to deliver cash or another financial asset. Louisiana LNG Infrastructure LLC and Louisiana LNG LLC are not required to distribute dividends unless Woodside Energy Group Ltd declares dividends. As the Group can indefinitely defer payment of the Louisiana LNG Infrastructure LLC dividend and Louisiana LNG LLC dividend based on the terms in the agreement, the non‑controlling interest in Louisiana LNG Infrastructure LLC and Louisiana LNG LLC is classified as equity in the Group’s consolidated financial statements. While the terms grant the Group discretion to avoid distributing dividends from Louisiana LNG Infrastructure LLC and Louisiana LNG LLC, the exercise of this discretion may increase the non-controlling interest’s entitlement to future discretionary distributions. Significant estimates and judgements (a) Restoration obligations The Group estimates the future decommissioning and remediation costs of offshore oil and gas platforms, offshore and onshore production facilities, wells and pipelines at different stages of the development and construction of assets or facilities including for new energy assets. In many instances, decommissioning of assets occurs many years into the future. The Group’s restoration obligations are based on compliance with the requirements of relevant regulations which vary for different jurisdictions. For example Australian regulations require full removal for offshore assets unless regulator approval is received to decommission in-situ. It is currently the Group’s assumption that in some regulatory jurisdictions and environments, certain infrastructures are decommissioned in-situ where it can be demonstrated that this will deliver equal or better environmental outcomes than full removal and that regulatory approval is obtained where arrangements are satisfactory to the regulator. The Group maintains technical expertise to ensure that industry learnings, scientific research and local and international guidelines are reviewed in assessing its restoration obligations. The restoration obligation requires judgemental assumptions regarding removal timing, applicable environmental legislation and regulations, the extent of restoration activities required, the engineering methodology and the technologies used for estimating costs. These assumptions inform the estimated future cash flows, which are then discounted using the risk-free discount rates aligned to the expected timing of the cash outflows. Expected value approach For both onshore and offshore assets, provision has been made taking into consideration a risked range of possible removal outcomes, including full removal of certain assets or project-specific risks (where applicable). Individual site provisions are an estimate of the expected value of future cash flows required to rehabilitate the relevant site using current restoration standards and techniques and taking into account risks and uncertainties. Individual site provisions are discounted to their present value using risk-free country-specific discount rates aligned to the estimated timing of cash outflows. This approach also takes into consideration the possibility that full removal of all assets may be required. Inherent uncertainties The basis of the restoration obligation provision for assets with approved decommissioning plans or general directions issued by the regulator can differ from the assumptions disclosed above. Whilst the provisions reflect the Group’s best estimate based on current knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be ongoing to ensure that the most accurate information is available when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash outflows can materially differ from the current estimate as a result of changes in regulations and their application, prices, analysis of site conditions, further studies, timing of restoration and changes in removal technology. These uncertainties may result in actual expenditure differing from amounts included in the provision recognised as at 31 December 2025. Significant estimates and judgements (a) Change in embedded derivative valuation inputs The Group has reassessed the valuation inputs of the Perdaman embedded derivative factoring current market conditions and as a result revised pricing inputs that reflect the long-term nature of the contract and external market data. The change has been applied from 1 January 2025, resulting in an increase in fair value gains of $151 million for the year ended 31 December 2025. The effect of future periods is not disclosed because estimating it is impracticable. (b) Embedded derivative The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast cash flows, discount rate, credit risk and volatility. These assumptions require significant judgement and are subject to risk and uncertainty. The present value of the embedded derivative was estimated using the assumptions set out below. •Inflation rate – 2.5% (2024: 2.5%) has been applied. •Discount rate – a pre-tax interest rate curve with a range of 4.69% to 7.53% (2024: range of 5.80% to 6.95%). •Domestic gas pricing – forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (TTF) prices available in the market. The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses recognised in other income/expenses. Significant estimates and judgements (a) Control Judgement is required to assess whether a contract is or contains a lease at inception by assessing whether the Group has the right to direct the use of the identified asset and obtain substantially all the economic benefits from the use of that asset. (b) Lease term Judgement is required when assessing the term of the lease and whether to include optional extension and termination periods. Option periods are only included in determining the lease term at inception when they are reasonably certain to be exercised. Lease terms are reassessed when a significant change in circumstances occurs. On this basis, possible additional lease payments amounting to $2,342 million (2024: $2,113 million) were not included in the measurement of lease liabilities. (c) Interest in joint arrangements Judgement is required to determine the Group’s rights and obligations for lease contracts within joint operations, to assess whether lease liabilities are recognised gross (100%) or in proportion to the Group’s participating interest in the joint operation. This includes an evaluation of whether the lease arrangement contains a sublease with the joint operation. (d) Discount rates Judgement is required to determine the discount rate, where the discount rate is the Group’s incremental borrowing rate if the rate implicit in the lease cannot be readily determined. The incremental borrowing rate is determined with reference to the Group’s borrowing portfolio at the inception of the arrangement or the time of the modification. Significant estimates and judgements (a) Accounting for interests in other entities Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity. Depending upon the facts and circumstances in each case, Woodside may obtain control, joint control or significant influence over the entity or arrangement. Judgement is applied when determining the relevant activities of a project and if joint control is held over it. Relevant activities include, but are not limited to, work program and budget approval, investment decision approval, voting rights in joint operating committees, amendments to permits and changes to joint arrangement participant holdings. Transactions which give Woodside control of a business are business combinations. If Woodside obtains joint control of an arrangement, judgement is also required to assess whether the arrangement is a joint operation or a joint venture. If Woodside has neither control nor joint control, it may be in a position to exercise significant influence over the entity, which is then accounted for as an associate.
Exploration and evaluation - Recognition and measurement and Exploration commitments	Recognition and measurement Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method. Areas of interest (AOI) are based on a geographical area for which the rights of tenure are current. All exploration and evaluation expenditure, including general permit activity, geological and geophysical costs and new venture activity costs, is expensed as incurred except for the following: •where the expenditure relates to an exploration discovery for which the assessment of the existence or otherwise of economically recoverable hydrocarbons is not yet complete; or •where the expenditure is expected to be recouped through successful exploitation of the area of interest, or alternatively, by its sale. The costs of acquiring interests in new exploration and evaluation licences are capitalised. The costs of drilling exploration wells are initially capitalised pending the results of the well. Costs are expensed where the well does not result in the successful discovery of economically recoverable hydrocarbons and the recognition of an area of interest. Subsequent to the recognition of an area of interest, all further evaluation costs relating to that area of interest are capitalised. Upon approval for the commercial development of an area of interest, accumulated expenditure for the area of interest is transferred to projects in development within property, plant and equipment. In the consolidated statement of cash flows, those cash flows associated with capitalised exploration and evaluation expenditure, including unsuccessful wells, are classified as cash flows used in investing activities. Exploration commitments The Group has exploration expenditure obligations which are contracted for, but not provided for in the financial statements. These obligations may be varied from time to time and are expected to be fulfilled in the normal course of the Group’s operations.
Property, plant and equipment - Recognition and measurement	Impact on remaining life of assets Oil and gas properties, included within property, plant and equipment, are depreciated using the unit of production basis over either proved or proved plus probable reserves. The energy transition may result in changes to the expected useful life of oil and gas properties and economically recoverable reserves and resources thereby accelerating depreciation charges or resulting in an impairment. New energy assets under development still require significant capital spend. The Group will review depreciation methodology and useful life of new energy assets as they are brought into use. Recognition and measurement Property, plant and equipment are stated at cost less accumulated depreciation and impairment charges. Projects in development include the construction of oil and gas assets and new energy assets: •Projects in development for oil and gas assets include the costs to acquire, construct, install or complete production and infrastructure facilities such as pipelines and platforms, capitalised borrowing costs, transferred exploration and evaluation assets, development wells and the estimated cost of dismantling and restoration. •Projects in development for new energy assets include the costs to acquire, construct, install or complete infrastructure facilities, capitalised borrowing costs and the estimated cost of dismantling and restoration. Borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset are capitalised as part of the cost of that project when it is probable that they will result in future economic benefits and the costs can be measured reliably. The interest rate used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the Group’s outstanding borrowings during the period. When commercial operation commences, the accumulated costs in projects in development will be transferred to oil and gas properties or new energy assets. Subsequent capital costs, including major maintenance, are included in the asset’s carrying amount only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be reliably measured.
Property, plant and equipment - Depreciation and amortisation	Depreciation and amortisation Property, plant and equipment are depreciated to their estimated residual values at rates based on their expected useful lives. Upstream oil and conventional gas assets are depreciated using the unit of production basis over proved reserves. Upstream LNG assets are depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life. The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. Downstream assets (primarily onshore plant and equipment) are depreciated using a straight-line basis over the lesser of useful life and the life of proved plus probable reserves. On a straight-line basis the assets have an estimated useful life of 5-50 years. All other items of property, plant and equipment are depreciated using the straight-line method over their useful life. They are depreciated as follows: •Buildings – 24–40 years; •Other plant and equipment – 5–40 years; and •Land is not depreciated.
Intangible assets - Recognition and measurement	Recognition and measurement Goodwill is initially measured at cost and is subsequently measured at cost less any accumulated impairment losses. For the purposes of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s CGUs or groups of CGUs no larger than an operating segment that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Where goodwill has been allocated to a CGU and part of the operation within that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill is not amortised but will be assessed at least annually for impairment and more frequently if events or changes in circumstances indicate that it might be impaired. The contract assets were acquired as part of a business combination and represent the difference in contract pricing and market prices, adjusted for time value of money. The contracts are recognised at fair value at the acquisition date and are subsequently amortised over 30 years (2024: 6 months to 17 years). Software is recognised at historical cost less accumulated amortisation and impairment. All software costs are amortised over the useful life of 5–15 years on a straight-line basis.
Asset acquisition accounting	Asset acquisition accounting Purchase consideration, including capitalised transaction cost, has been allocated against identifiable assets and liabilities acquired on the following basis: •Assets and liabilities initially measured at an amount other than cost, are measured by the Group at the amounts specified in the applicable accounting standards. Assets and liabilities in this category include financial assets and financial liabilities recognised initially at fair value, lease assets and liabilities measured in accordance with the accounting standard for leases, and employee benefit liabilities measured in accordance with the accounting standard for employee benefits. •The residual transaction price is allocated to the remaining identifiable assets and liabilities based on their relative fair values at the date of the acquisition.
Liquidity risk management	Liquidity risk management Liquidity risk arises from the financial liabilities of the Group and the Group’s subsequent ability to meet its obligations to repay financial liabilities as and when they fall due. The liquidity position of the Group is managed to ensure sufficient liquid funds are available to meet its financial commitments in a timely and cost-effective manner. The Group’s liquidity is continually reviewed, including cash flow forecasts to determine the forecast liquidity position and maintain appropriate liquidity levels. The Group’s primary sources of liquidity are cash and cash equivalents, net cash from operating activities, unused borrowing capacity under its bilateral facilities and syndicated facilities, issuances of debt or equity securities and other potential sources of liquidity, such as sales of assets or equity interests in assets. At 31 December 2025, the Group had a total of $9,262 million (2024: $6,723 million) of available undrawn facilities and cash at its disposal. The maturity profile of interest-bearing liabilities is disclosed in Note C.2, trade and other payables are disclosed in Note D.4 and lease liabilities are disclosed in Note D.7. Financing facilities available to the Group are disclosed in Note C.2. Capital commitments contracted for, but not provided for in the financial statements, are disclosed in Note B.3.
Interest rate risk management	Interest rate risk management Interest rate risk is the risk that the Group’s financial position will fluctuate due to changes in market interest rates. The Group’s exposure to the risk of changes in market interest rates relates primarily to financial instruments with floating interest rates including long-term debt obligations, cash and short-term deposits. The Group manages its interest rate risk by maintaining an appropriate mix of fixed and floating rate debt. To manage the ratio of fixed rate debt to floating rate debt, the Group may enter into interest rate swaps. The Group holds interest rate swaps to hedge the interest rate risk associated with the $600 million syndicated facility. Refer to Notes C.2 and D.6 for further details. At the reporting date, the Group was exposed to various benchmark interest rates that were not designated in cash flow hedges, primarily through $5,712 million (2024: $3,923 million) on cash and cash equivalents and $2,650 million (2024: $3,150 million) on interest- bearing liabilities (excluding transaction costs). A reasonably possible change in the Secured Overnight Financing Rate (SOFR) (+2.0%/-2.0% (2024: +2.0%/-2.0%)), with all variables held constant, would not have a material impact (2024: no material impact) on the Group’s equity or the income statement in the current period.
Cash and cash equivalents - recognition and measurement	Recognition and measurement Cash and cash equivalents in the consolidated statement of financial position comprise cash at bank and short-term deposits with an original maturity of three months or less. Cash and cash equivalents are stated at face value in the consolidated statement of financial position. There are no cash and cash equivalents (2024: nil) restricted by legal or contractual arrangements.
Interest-bearing liabilities and financing facilities - Recognition and measurement	Recognition and measurement All borrowings are initially recognised at fair value less transaction costs. Borrowings are subsequently carried at amortised cost. Any difference between the proceeds received and the redemption amount is recognised in the income statement over the period of the borrowings using the effective interest method. Borrowings designated as a hedged item are measured at amortised cost adjusted to record changes in the fair value of risks that are being hedged in fair value hedges. All bonds, notes and facilities are subject to various covenants and negative pledges restricting future secured borrowings, subject to a number of permitted lien exceptions. Neither the covenants nor the negative pledges have been breached at any time during the reporting period.
Issued capital	Issued capital Ordinary shares are classified as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds.
Reserved shares	Reserved shares Reserved shares are the Group’s own equity instruments, which are used in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity. No gain or loss is recognised in the consolidated income statement on the purchase, sale, issue or cancellation of the Group’s own equity instruments.
Other reserves - Nature and purpose	Nature and purpose Employee benefits reserve Used to record share-based payments associated with the employee share plans. Foreign currency translation reserve Used to record foreign exchange differences arising from the translation of the financial statements of foreign entities from their functional currency to the Group’s presentation currency. Hedging reserve Used to record gains and losses on effective portion of hedges designated as cash flow hedges, and foreign currency basis spread arising from the designation of a financial instrument as a hedging instrument. Gains and losses accumulated in the cash flow hedge reserve for qualifying assets are capitalised against the carrying amount of that asset and recognised in the income statement as the asset is depreciated. Distributable profits reserve Used to record distributable profits generated by the parent entity, Woodside Energy Group Ltd. Other reserves Used to record gains and losses on financial instruments at fair value through other comprehensive income. Non-controlling interest contribution reserve Transactions that do not result in a loss of control are accounted for as equity transactions. When ownership interests change, the carrying amounts of both controlling and non‑controlling interests are adjusted to reflect the revised ownership proportions, with any difference between the adjustment and the consideration received recognised in the non-controlling interest contribution reserve within other reserves.
Credit risk management	Credit risk management Credit risk is the risk that a counterparty will not meet its payment obligation under a financial instrument or customer contract, leading to a financial loss to the Group. Credit risk arises from the financial instruments of the Group, which include trade and other receivables, loans receivables and deposits with banks and financial institutions. The Group manages its credit risk on trade receivables and financial instruments by predominantly dealing with counterparties with an investment grade credit rating. Sufficient financial security is obtained to mitigate the risk of financial loss when transacting with counterparties with below investment grade credit ratings. Customers who wish to trade on unsecured credit terms are subject to credit assessment procedures. Receivable balances are monitored on an ongoing basis. As a result, the Group’s exposure to credit loss is not significant. The Group’s maximum credit exposure is limited to the carrying amount of its financial assets. Customer credit risk is managed by the Treasury function subject to the Group’s established policy, procedures and controls relating to customer credit risk management. The credit quality of a customer is assessed based on various credit metrics, including its credit rating, and individual credit limits and requirements are defined in accordance with this assessment. Outstanding customer receivables are regularly monitored. At 31 December 2025, the Group had 20 customers (2024: 23 customers) that owed the Group more than $10 million each and accounted for approximately 90% (2024: 88%) of product-related trade receivables. Depending on the product, standard settlement terms are 7 to 30 days from the date of invoice or bill of lading. The Group considers the probability of default upon initial recognition of the asset and whether there has been a significant depreciation in credit quality on an ongoing basis. A significant decrease in credit quality is defined as a debtor being greater than 30 days past due in making a contractual payment. Credit losses for trade receivables (including lease receivables) and contract assets are determined by applying the simplified approach and are measured at an amount equal to lifetime expected loss. Under the simplified approach, determination of the loss allowance provision and expected loss rate incorporates past experience and forward-looking information, including the outlook for market demand and forward-looking interest rates. A default on other financial assets is considered to be when the counterparty fails to make contractual payments within 60 days of when they fall due. At 31 December 2025, the Group had a provision for credit losses of nil (2024: nil). Subsequent to 31 December 2025, 99%(2024: 96%) of product-related trade receivables balance of $948 million (2024: $972 million) has been received. Credit risk from balances with banks is managed by the Treasury function in accordance with the Group’s policy. The Group places funds from time to time as short-term deposits with reputable financial institutions with investment grade credit ratings. At 31 December 2025 and 31 December 2024, there were no significant concentrations of credit risk within the Group and financial instruments are spread amongst a number of financial institutions to minimise the risk of counterparty default. The maximum exposure to financial institution credit risk is represented by the sum of all cash deposits plus accrued interest, bank account balances and fair value of derivative assets. The Group’s counterparty credit policy limits this exposure to commercial and investment banks, according to approved credit limits based on the counterparty’s credit rating.
Receivables - Recognition and measurements and Fair value	Recognition and measurement Trade receivables are initially recognised at the transaction price determined under IFRS 15 Revenue from Contracts with Customers. Other receivables are initially recognised at fair value. Receivables that satisfy the contractual cash flow and business model tests are subsequently measured at amortised cost less an allowance for uncollectable amounts. Uncollectable amounts are determined using the expected loss impairment model. Collectability and impairment are assessed on a regular basis. Subsequent recoveries of amounts previously written off are credited against other expenses in the consolidated income statement. Certain receivables that do not satisfy the contractual cash flow and business model tests are subsequently measured at fair value (refer to Note D.6). The Group’s customers are required to pay in accordance with agreed payment terms. Depending on the product, settlement terms are 7 to 30 days from the date of invoice or bill of lading and customers regularly pay on time. There are no significant overdue product- related trade receivables as at the end of the reporting period (2024: nil). Fair value The carrying amount of trade and other receivables approximates their fair value.
Inventories - Recognition and measurement	Recognition and measurement Inventories include hydrocarbon stocks, consumable supplies, maintenance spares and carbon credits expected to be utilised to offset future emissions. Inventories are valued at the lower of cost and net realisable value. Cost is determined on a weighted average basis and includes direct costs and an appropriate portion of fixed and variable production overheads where applicable. Inventories determined to be obsolete or damaged are written down to net realisable value, being the estimated selling price less selling costs.
Payables - Recognition and measurement and Fair value	Recognition and measurement Trade and other payables are carried at amortised cost and are recognised when goods and services are received, whether or not billed to the Group, prior to the end of the reporting period. Fair value The carrying amount of payables approximates their fair value.
Restoration	Restoration The restoration provision is first recognised in the period in which the obligation arises. The nature of restoration activities includes the removal of facilities, abandonment of wells and restoration of affected areas. Restoration provisions are updated annually, with the corresponding movement recognised against the related exploration and evaluation assets or property, plant and equipment or expensed for late life projects with no corresponding asset. Over time, the liability is increased for the change in the present value based on a pre-tax discount rate appropriate to the risks inherent in the liability. The unwinding of the discount is recorded as an accretion charge within finance costs. The carrying amount capitalised in property, plant and equipment is depreciated over the useful life of the related asset (refer to Note B.3). Costs incurred that relate to an existing condition caused by past operations, and which do not have a future economic benefit, are expensed.
Employee benefits	Employee benefits Provision is made for employee benefits accumulated as a result of employees rendering services up to the end of the reporting period. These benefits include wages, salaries, annual leave and long service leave. Liabilities in respect of employees’ services rendered that are not expected to be wholly settled within one year after the end of the period in which the employees render the related services are recognised as long-term employee benefits. These liabilities are measured at the present value of the estimated future cash outflow to the employees using the projected unit credit method. Liabilities expected to be wholly settled within one year after the end of the period in which the employees render the related services are classified as short-term benefits and are measured at the amount due to be paid.
Onerous contract provision	Onerous contract provision Provision is made for loss-making contracts at the present value of the lower of the net cost of fulfilling and the cost arising from failure to fulfil each contract. The Group had no onerous contract provision as at 31 December 2025.
Other financial assets and liabilities - Recognition and measurement	Recognition and measurement Derivative financial instruments Derivative financial instruments that are designated within qualifying hedge relationships are initially recognised at fair value on the date the contract is entered into. For relationships designated as fair value hedges, subsequent fair value movements of the derivative are recognised in the consolidated income statement. For relationships designated as cash flow hedges, subsequent fair value movements of the derivative for the effective portion of the hedge are recognised in other comprehensive income and accumulated in reserves in equity; fair value movements for the ineffective portion are recognised immediately in the consolidated income statement. Costs of hedging have been separated from the hedging arrangements and deferred to other comprehensive income and accumulated in reserves in equity. Amounts accumulated in equity are reclassified to the consolidated income statement in the periods when the hedged item affects profit or loss. Hedge effectiveness is determined at the inception of the hedge relationship, and through periodic prospective effectiveness assessments to ensure that an economic relationship exists between the hedged exposure and the hedging instrument. The Group assesses whether the derivative designated in each hedging relationship has been, and is expected to be, effective in offsetting changes in cash flows of the hedged exposure using the hypothetical derivative method. Ineffectiveness is recognised where the cumulative change in the designated component value of the hedging instrument on an absolute basis exceeds the change in value of the hedged exposure attributable to the hedged risk. Ineffectiveness may arise where the timing of the transaction changes from what was originally estimated such as delayed shipments or changes in timing of forecast sales. This may also arise where the commodity swap pricing terms do not perfectly match the pricing terms of the revenue contracts. Fair value Except for the other financial assets and other financial liabilities set out in this note, there are no material financial assets or financial liabilities carried at fair value. The fair value of commodity derivative financial instruments is determined based on observable quoted forward pricing and swap models and is classified as Level 2 on the fair value hierarchy. The most frequently applied valuation techniques include forward pricing and swap models that use present value calculations. The models incorporate various inputs including the credit quality of counterparties and forward rate curves of the underlying commodity. The fair value of interest rate swaps is calculated by discounting estimated future cash flows based on the terms of maturity of each contract, using market interest rates for a similar instrument at the reporting date, and is classified as Level 2 on the fair value hierarchy. The fair value of foreign exchange forward contracts is determined using quoted forward exchange rates at the reporting date and present value calculations based on high credit quality yield curves in the respective currencies and is classified as Level 2 on the fair value hierarchy. The fair values of other financial assets and other financial liabilities are predominantly determined based on observable quoted forward pricing and are predominantly classified as Level 2 on the fair value hierarchy. Embedded commodity derivatives are classified as Level 3 on the fair value hierarchy with no market observable inputs. Except for the revised valuation inputs for the embedded commodity derivative, there were no changes to the Group’s valuation processes, valuation techniques and types of inputs used in the fair value measurements during the period. Foreign exchange The derivative financial instruments include foreign exchange forward contracts that are denominated in Australian dollars. The Group had no material other financial assets and liabilities denominated in currencies other than US dollars.
Leases - Recognition and measurement	Recognition and measurement When a contract is entered into, the Group assesses whether the contract contains a lease. A lease arises when the Group has the right to direct the use of an identified asset which is not substitutable and to obtain substantially all economic benefits from the use of the asset throughout the period of use. The leases recognised by the Group predominantly relate to LNG vessels, property and drilling rigs. The Group separates the lease and non-lease components of the contract and accounts for these separately. The Group allocates the consideration in the contract to each component on the basis of their relative stand-alone prices. Leases as a lessee Lease assets and lease liabilities are recognised at the lease commencement date, which is when the assets are available for use. The assets are initially measured at cost, which is the present value of future lease payments adjusted for any lease payments made at or before the commencement date, plus any make-good obligations and initial direct costs incurred. Lease assets are depreciated using the straight-line method over the shorter of their useful life and the lease term. Refer to Note B.3 for the useful lives of assets. Periodic adjustments are made for any re-measurements of the lease assets and for impairment losses, assessed in accordance with the Group’s impairment policies. Lease liabilities are initially measured at the present value of future minimum lease payments, discounted using the Group’s incremental borrowing rate if the rate implicit in the lease cannot be readily determined, and are subsequently measured at amortised cost using the effective interest rate. Minimum lease payments are fixed payments or index-based variable payments incorporating the Group’s expectations of extension options and do not include non-lease components of a contract. A portfolio approach was taken when determining the implicit discount rate for LNG vessels with similar terms and conditions on transition. The lease liability is remeasured when there are changes in future lease payments arising from a change in rates, index or lease terms from exercising an extension or termination option. A corresponding adjustment is made to the carrying amount of the lease assets, with any excess recognised in the consolidated income statement. There are no restrictions placed upon the lessee by entering into these leases. Short-term leases and leases of low value assets Short-term leases (lease term of 12 months or less) and leases of low value assets are recognised as incurred as an expense in the consolidated income statement. Low value assets comprise plant and equipment.
Employee benefits - Recognition and measurement	Recognition and measurement The Group’s accounting policy for employee benefits other than superannuation is set out in Note D.5. The policy relating to share-based payments is set out in Note E.2(c). All employees of the Group are entitled to benefits on retirement, disability or death. The Group operates a number of pension schemes throughout the world. Employees entitled to defined contribution schemes receive fixed contributions from Group companies and the Group’s legal or constructive obligation is limited to these contributions. Contributions to defined contribution funds are recognised as an expense as they become payable. Prepaid contributions are recognised as an asset to the extent that a cash refund or a reduction in the future payment is available. Recognition and measurement All compensation under WEP, SWEP, PBP Plus and EIS Restricted Shares and Performance Rights is accounted for as share-based payments to employees for services provided. The cost of equity-settled transactions with employees is measured by reference to the fair values of the equity instruments at the date at which they are granted. The fair value of share-based payments is recognised, together with the corresponding increase in equity, over the period in which the vesting conditions are fulfilled, ending on the date on which the relevant employee becomes fully entitled to the shares. At each balance sheet date, the Group reassesses the number of awards that are expected to vest based on service conditions. The expense recognised each year takes into account the most recent estimate. The fair value of the benefit provided for the WEP and SWEP is estimated using the Black-Scholes option pricing technique. The fair value of the Restricted Shares is estimated as the closing share price at grant date. The fair value of the benefit provided for the relative total shareholder return Performance Rights is calculated using the Binomial or Black-Scholes option pricing technique combined with a Monte Carlo simulation methodology, where relevant, using historical volatility to estimate the volatility of the share price in the future.
Joint arrangements - Recognition and measurement	Recognition and measurement Joint arrangements are arrangements in which two or more parties have joint control. Joint control is the contractual agreed sharing of control of the arrangement which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control. Joint arrangements are classified as either a joint operation or joint venture, based on the rights and obligations arising from the contractual obligations between the parties to the arrangement. To the extent the joint arrangement provides the Group with rights to the individual assets and obligations arising from the joint arrangement, the arrangement is classified as a joint operation, and as such the Group recognises its: •assets, including its share of any assets held jointly; •liabilities, including its share of any liabilities incurred jointly; •revenue from the sale of its share of the output arising from the joint operation; •share of revenue from the sale of the output by the joint operation; and •expenses, including its share of any expenses incurred jointly. To the extent the joint arrangement provides the Group with rights to the net assets of the arrangement, the investment is classified as a joint venture and accounted for using the equity method. Joint arrangements acquired which are deemed to be carrying on a business are accounted for applying the principles of IFRS 3 Business Combinations. Joint arrangements which are not deemed to be carrying on a business are treated as asset acquisitions.
Subsidiaries - Classification	Classification Subsidiaries are all the entities over which the Group has the power over the investee such that the Group is able to direct the relevant activities; has exposure, or rights, to variable returns from its involvement with the investee; and has the ability to use its power over the investee to affect the amount of the investor’s returns.
New and amended accounting standards adopted	(b) New standards and interpretations New and amended accounting standards adopted A number of amended standards became applicable for the current reporting period. The Group did not make any significant changes to its accounting policies and did not make retrospective adjustments as a result of adopting these amended standards. These amendments did not materially impact the accounting policies or amounts disclosed in the year end financial statements of the Group.
New standards and interpretations not yet adopted	New standards and interpretations not yet adopted Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for the 31 December 2025 reporting period and have not been early adopted by the Group: •IFRS 18 Presentation and Disclosure in Financial Statements will replace IAS 101 Presentation of financial statements, introducing new requirements that will help to achieve comparability of the financial performance of similar entities and provide more relevant information and transparency to users. Even though IFRS 18 will not impact the recognition or measurement of items in the financial statements, its impacts on presentation and disclosure are expected to be pervasive, particularly those related to the consolidated income statement and providing management-defined performance measures within the financial statements. Management is currently assessing the detailed implications of applying the new standard on the Group’s financial statements. The Group will apply the new standard from its mandatory effective date of 1 January 2027. Retrospective application is required. •Amendments to IFRS 7 & IFRS 9 Classification and Measurement of Financial Instruments introducing an option to derecognise financial liabilities that are settled via electronic transfer before the settlement date. The amendments also provide additional guidance on the assessment of whether contractual cash flows of certain financial assets meet the “solely payments of principal and interest” (SPPI) criterion, including assets with terms that may alter the timing or amount of cash flows, assets with non‑recourse features, and contractually linked instruments. In addition, the amendments introduce new disclosure requirements for financial instruments with contractual terms that allow cash flows to change in response to events not directly related to basic lending risks. Management is currently assessing the detailed implications of applying the new standard on the Group’s financial statements. The Group will apply the new standard from its mandatory effective date of 1 January 2026.

About These Statements (Policies)

12 Months Ended

Dec. 31, 2025

Significant Accounting Policies [Abstract]

The financial statements are general purpose financial statements, which have been prepared in accordance with the requirements of the

International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board. They also include

additional disclosures required for foreign registrants by the United States Securities and Exchange Commission (US SEC).

The Group’s accounting policies are materially consistent with those disclosed in the Group’s 2024 Financial Statements. Adoption of

new or amended standards and interpretations effective 1 January 2025 did not result in any significant changes to the Group’s

accounting policies. Refer to Note E.9 for more details.

Estimates have been revised, where required, to reflect current market conditions including the impact of climate change. Updated

assumptions used for impairment assessments, restoration provisions and embedded commodity derivatives are disclosed in Notes B.4,

D.5 and D.6 respectively; these assumptions could change in the future. New estimates and judgements relating to transactions with

equity holders of the Group are disclosed in Note B.9.

Currency

The accounting functional and presentation currency of Woodside and all its material subsidiaries is the US dollar.

Transactions in foreign currencies are initially recorded in the functional currency of the transacting entity at the exchange rates ruling at

the date of transaction. Monetary assets and liabilities denominated in foreign currencies at the reporting date are translated at the rates of

exchange ruling at that date. Exchange differences in the consolidated financial statements are taken to the consolidated income

statement.

Basis of preparation

The financial statements have been prepared on a historical cost basis, except for derivative financial instruments and certain other

financial assets and financial liabilities, which have been measured at fair value or amortised cost adjusted for changes in fair value

attributable to the risks that are being hedged in effective hedge relationships. Where not carried at fair value, if the carrying value of

financial assets and financial liabilities does not approximate their fair value, the fair value has been included in the notes to the financial

statements.

Subsidiaries are fully consolidated from the date on which control is obtained by the Group and cease to be consolidated from the date at

which the Group ceases to have control.

The financial statements comprise the financial position and results of the Group as at and for the year ended 31 December 2025 (refer to

Note E.8).

The material subsidiaries of the Group apply the same reporting period and accounting policies as the parent company in their financial

statements. All intercompany balances and transactions, including unrealised profits and losses arising from intra-group transactions,

have been eliminated in full.

Non-controlling interests are allocated their share of the net profit after tax in the consolidated income statement and their share of other

comprehensive income net of tax in the consolidated statement of comprehensive income, and are presented within equity in the

consolidated statement of financial position, separately from parent shareholders’ equity.

The consolidated financial statements provide comparative information in respect of the previous periods. Where required,

a reclassification of items in the financial statements of the previous periods has been made in accordance with the classification of items

in the financial statements of the current period.

Climate Change And Energy Transition

Climate considerations

Woodside has considered the impact of climate and the energy transition across its global portfolio in assessing the carrying values of its

assets and liabilities. This note describes the assumptions underpinning key areas of the financial statements and the potential short-term

and long-term impacts of differing climate-related scenarios on the financial performance, position and cash flow of Woodside for the

year ended 31 December 2025.

Financial planning and assumptions

Woodside considers a range of climate and macroeconomic scenarios to help benchmark our long-term price assumptions and inform our

decision making to maintain a resilient financial position. These scenarios are informed by a wide range of externally published data and

are part of a broad consideration of risks, opportunities, competitiveness and resilience. The assumptions applied in assessing amounts

within the financial statements require significant judgement and are in each case calculated in accordance with the requirements of

the applicable accounting standards.

Our long-term price assumptions reflect management’s current “best estimate” scenario in which global governments pursue

decarbonisation goals as well as other goals such as energy security and economic development. Price assumptions consider current

legislation in the locations where Woodside operates and place some weight on scenarios in which the transition to a lower carbon

energy system is sufficiently rapid to meet global climate goals, as well as scenarios in which the transition is not, or may not be,

sufficiently rapid. They also place some weight on a range of other assumptions which can drive prices (e.g. inflation) and which are not

related to the global climate goals.

Woodside’s oil and gas facilities are subject to physical risks such as metocean conditions and are located in regions that experience

tropical cyclones, hurricanes and high ambient temperatures. Woodside has significant experience designing and operating facilities

located in harsh environments.

The high degree of uncertainty around the nature, timing and magnitude of climate-related risks, and the uncertainty as to how the energy

transition will evolve, makes it difficult to determine the potential impacts of the risks with precision.

Woodside continues to monitor the uncertainty around climate change risks and expects to take into account ongoing developments into

its assumptions, including assumptions concerning commodity and carbon pricing, as considered appropriate. Investment cases include a

carbon price assumption which takes into consideration uncertainty around the impact of climate change. Commodity pricing

assumptions are key value drivers with greater significance to assets and liabilities than carbon pricing.

Impairment of exploration and evaluation, property, plant and equipment and goodwill

In accordance with the Group's accounting policies and applicable accounting standards, elements of Woodside’s financial statements are

based on reasonable and supportable assumptions that represent management’s current best estimate of the range of economic conditions

that may exist in the foreseeable future.

The estimation of recoverable amounts for impairment testing includes estimating what an independent market participant would pay to

acquire the asset as at the reporting date. Market participants will be guided by their own views on future economic and technical

conditions and therefore Woodside considers a range of data sources in determining a future price forecast, including industry and

market benchmarks along with asset sales transaction data to support the recoverable amount.

The completion of the sale of the 10% and 15.1% non-operating participating interest in the Scarborough Joint Venture to LNG Japan

and JERA respectively in 2024, is a clear example of an independent market valuation fully supporting the carrying value of the multi-

decade asset.

Price forecasts are adjusted for premiums and discounts based on the nature and quality of the product. Commodity oil price estimates

consider macroeconomic factors such as population growth and have regard to potential climate pathways along with other factors such

as industry investment and cost trends. There remains significant uncertainty around how society will respond to the climate challenge.

The energy transition is expected to bring volatility and there is uncertainty as to how commodity prices will develop.

Woodside’s assumptions for Brent and JKM sit within the range of scenarios considered by management. Refer to Note B.4Impairment

Refer to Note B.4 for details on impairment, including any write‑offs.

Impairment

Refer to Note B.4 for details on impairment.

Exploration and evaluation

Impairment testing

The recoverability of the carrying amount of exploration and evaluation assets is dependent on successful development and commercial

exploitation, or alternatively sale of the respective AOI.

Each AOI is reviewed half-yearly to determine whether economic quantities of hydrocarbons have been found, or whether further

exploration and evaluation work is underway or planned to support continued carry forward of capitalised costs. Where a potential

impairment is indicated for an AOI, an assessment is performed using a fair value less costs to dispose (FVLCD) method to determine its

recoverable amount. Upon approval for commercial development, exploration and evaluation assets are assessed for impairment before

they are transferred to property, plant and equipment.

Impairment calculations

If the carrying amount of an AOI exceeds its recoverable amount, the AOI is written down to its recoverable amount and an impairment

loss is recognised in the consolidated income statement.

Property, plant and equipment

Impairment testing

The carrying amounts of property, plant and equipment are assessed half-yearly to determine whether there is an indicator of impairment

or impairment reversal for those assets which have previously been impaired. Indicators of impairment and impairment reversals include

changes in reserves for oil and gas assets, expected future sales prices, or costs.

Property, plant and equipment are assessed for impairment indicators and impairments on a cash-generating unit (CGU) basis. CGUs are

determined as offshore and onshore facilities, infrastructure and associated oil and/or gas fields and new energy assets.

If there is an indicator of impairment or impairment reversal for a CGU, its recoverable amount is calculated and compared with the

CGU’s carrying value (refer to impairment calculations below).

Goodwill

For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the

Group’s cash-generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or

liabilities of the acquiree are assigned to those units. Goodwill is tested for impairment at least annually and more frequently if events or

changes in circumstances indicate that it might be impaired. Impairment of goodwill is determined by assessing the recoverable amount

of each CGU to which the goodwill relates and comparing it with its carrying value, which includes deferred taxes (refer to impairment

calculations below and Note B.5).

When part of an operation is disposed of, any goodwill associated with the disposed operation is included in the carrying amount of the

operation in determining the gain or loss on disposal.

Goodwill and property, plant and equipment impairment calculations

The recoverable amount of an asset or CGU is determined as the higher of its value in use (VIU) and FVLCD.

VIU is determined by estimating future cash flows after taking into account the risks specific to the asset and discounting to present

value using an appropriate discount rate.

FVLCD is the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the

effects of factors that may be specific to the Group. In determining FVLCD, recent market transactions are considered. If no such

transactions can be identified, an appropriate valuation model, such as discounted cash flow techniques, is applied on a post-tax basis

using an appropriate discount rate and estimates are made about the assumptions market participants would use when pricing the asset or

CGU.

If the carrying amount of an asset or CGU, including any allocated goodwill, exceeds its recoverable amount, the asset or CGU is written

down to its recoverable amount and an impairment loss is recognised in the consolidated income statement. Any impairment losses are

first allocated to reduce the carrying amount of any goodwill allocated, with the remaining impairment losses allocated to the relevant

assets.

If the recoverable amount of an asset or CGU exceeds its carrying amount, and that asset or CGU has previously been impaired, the

impairment is reversed. The carrying amount of the asset or CGU is increased to its recoverable amount, but only to the extent that the

carrying amount does not exceed the value that would have been determined, net of depreciation, if no impairment had been recognised.

Impairments of goodwill are not reversed.

Impact on remaining life of assets

Oil and gas properties, included within property, plant and equipment, are depreciated using the unit of production basis over either

proved or proved plus probable reserves. The energy transition may result in changes to the expected useful life of oil and gas properties

and economically recoverable reserves and resources thereby accelerating depreciation charges or resulting in an impairment. New

energy assets under development still require significant capital spend. The Group will review depreciation methodology and useful life

of new energy assets as they are brought into use.

Recognition and measurement

Property, plant and equipment are stated at cost less accumulated depreciation and impairment charges.

Projects in development include the construction of oil and gas assets and new energy assets:

•Projects in development for oil and gas assets include the costs to acquire, construct, install or complete production and infrastructure

facilities such as pipelines and platforms, capitalised borrowing costs, transferred exploration and evaluation assets, development

wells and the estimated cost of dismantling and restoration.

•Projects in development for new energy assets include the costs to acquire, construct, install or complete infrastructure facilities,

capitalised borrowing costs and the estimated cost of dismantling and restoration.

Borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset are capitalised as part of

the cost of that project when it is probable that they will result in future economic benefits and the costs can be measured reliably. The

interest rate used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the

Group’s outstanding borrowings during the period.

When commercial operation commences, the accumulated costs in projects in development will be transferred to oil and gas properties

or new energy assets.

Subsequent capital costs, including major maintenance, are included in the asset’s carrying amount only when it is probable that future

economic benefits associated with the item will flow to the Group and the cost of the item can be reliably measured.

Carbon credits

Woodside utilises certified carbon credits to offset equity Scope 1 and 2 emissions that are above our targets in a given year and to meet

our regulatory requirements, after design out and operate out measures have been taken. The Group’s portfolio of carbon credits enables

our base business to manage the price risk associated with regulations and our corporate net equity Scope 1 and 2 emissions targets.

Restoration and other provisions

The energy transition may result in restoration activities occurring earlier than expected. 56% (2024: 53%) of the Group’s non-current

restoration liabilities are expected to be settled more than 10 years in the future.

Restoration cost estimates require judgemental assumptions regarding removal date, environmental legislation and regulations and the

extent of restoration activities required. These cost estimates may change in the future, as a result of increased regulatory scrutiny and the

energy transition. This includes the demand and related costs for offshore services which can be influenced by renewable energy

construction. Woodside continues to monitor the uncertainty around climate change risks to assess if additional changes to restoration

provisions should be recognised. Refer to Note D.5 for further details.

Recognition and measurement

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an

outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the

amount of the obligation.

Long-term contracts

Climate risks may impact underlying assumptions used to assess the forecast cash flows of long-term contracts. These judgemental

assumptions include pricing forecast and discount rate adjustments based on the nature of the product.

Contractual arrangements, including the Corpus Christi contract, could be impacted by adverse market conditions arising from climate-

related factors. Given the uncertainty in climate events, Woodside continues to review the forecast cash flows of long‑term contracts.

Deferred tax assets

The Group has determined that it is probable that sufficient future taxable income will be available to utilise the deferred tax assets

relating to carry forward unused tax losses and credits recognised as at 31 December 2025. The recoverability of deferred tax assets is

dependent on the Group’s future taxable income which can be impacted by the uncertainty of commodity and carbon pricing.

Commodity price risk management, Foreign exchange risk management and Capital risk management

Commodity price risk management

The Group’s revenue is exposed to commodity price fluctuations through the sale of hydrocarbons. Commodity price risks are measured

by monitoring and stress testing the Group’s forecast financial position to sustained periods of low commodity prices. This analysis is

regularly performed on the Group’s portfolio and as required for discrete projects and transactions.

The Group’s management of commodity price risk includes the use of commodity derivatives to hedge its exposure (refer to Note D.6).

The hedged exposure includes oil-linked revenue related to produced volumes and revenues derived from trading operations. Commodity

derivatives are used to manage the Group’s price risk within its corporate and trading portfolios.

Foreign exchange risk management

Foreign exchange risk arises from future commitments, financial assets and financial liabilities that are not denominated in US dollars.

The majority of the Group’s revenue is denominated in US dollars. The Group is exposed to foreign currency risk arising from operating

and capital expenditure incurred in currencies other than US dollars, particularly Australian dollars.

The Group’s management of foreign exchange risk relating to capital expenditure includes the use of forward exchange contract

derivatives to hedge its exposure (refer to Note D.6).

Capital risk management

Group Treasury is responsible for the Group's capital management including cash, debt and equity. Capital management is undertaken to

ensure that a secure, cost-effective and flexible supply of funds is available to meet the Group’s operating and capital expenditure

requirements. A stable capital base is maintained from which the Group can pursue its growth aspirations, whilst maintaining a flexible

capital structure that allows access to a range of debt and equity markets to both draw upon and repay capital.

The Dividend Reinvestment Plan (DRP) was approved by shareholders at the Annual General Meeting in 2003 for activation as required

to fund future growth. The DRP was reactivated in 2019 and suspended by the Board of Directors on 27 February 2023.

A range of financial metrics are monitored, including gearing and cash flow leverage, and Treasury policy breaches and exceptions.

Revenue from contracts with customers

Revenue is recognised when or as the Group transfers control of products or provides services to a customer at the amount to which the

Group expects to be entitled. If the consideration includes a variable component, the Group estimates the amount of the expected

consideration receivable. Variable consideration is estimated throughout the contract and is recognised to the extent that it is highly

probable a significant reversal will not occur.

•Revenue from sale of hydrocarbons – Revenue from the sale of hydrocarbons is recognised at a point in time when control of the

product is transferred to the customer. Revenue from take or pay contracts is recorded as unearned revenue until the product has been

drawn by the customer (transfer of control), at which time it is recognised in earnings.

•Other operating revenue – Revenue earned from LNG processing and other services is recognised over time as the services are rendered.

(a) Revenue from contracts with customers

The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is

determined with reference to quoted commodity prices.

Judgement is also used to determine if it is highly probable that a significant reversal will not occur in relation to revenue recognised

during open pricing periods in LNG contracts. The Group estimates variable consideration based on available information from contract

negotiations and market indicators.

Expenses

•Royalties, excise and levies – Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on

the basis of the Group’s entitlement to physical production.

•Depreciation and amortisation - Refer to Note B.3.

•Impairment and impairment reversals - Refer to Note B.4.

•Leases - Refer to Note D.7.

•Employee benefits - Refer to Note E.2.

Taxes - Recognition and measurement

Recognition and measurement

Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. Deferred

tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset is

realised. The tax rates and laws used to determine the amount are based on those that have been enacted or substantively enacted by the

end of the reporting period. Income taxes relating to items recognised directly in equity are recognised in equity.

Current taxes

Current tax expense is the expected tax payable on the taxable income for the current year and any adjustment to tax paid in respect of

previous years.

Deferred taxes

Deferred tax expense represents movements in the temporary differences between the carrying amount of an asset or liability in the

consolidated statement of financial position and its tax base.

With the exception of those noted below, deferred tax liabilities are recognised for all taxable temporary differences.

Deferred tax assets are recognised for deductible temporary differences, unused tax losses and tax credits only if it is probable that

sufficient future taxable income will be available to utilise those temporary differences and losses.

Deferred tax is not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business

combination) of assets and liabilities in a transaction that affects neither accounting profit nor the taxable profit.

In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable profits when

assessing the extent to which a deferred tax asset can be recognised in the consolidated statement of financial position.

Offsetting deferred tax balances

Deferred tax assets and liabilities are offset only if there is a legally enforceable right to offset current tax assets and liabilities and when

they relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities that the

Group intends to settle its current tax assets and liabilities on a net basis. Refer to Notes E.8 and E.9 for detail on the tax consolidated

groups.

Pillar Two legislation

In December 2021, the Organisation for Economic Co-operation and Development (OECD) published its Pillar Two legislation rules.

The Pillar Two legislation rules aim to ensure that large multinational groups pay a minimum of 15% tax for each jurisdiction in which

they operate. Pillar Two legislation has been enacted or substantively enacted in a number of jurisdictions in which the Group operates

with effect from 1 January 2024. The Group applies the exception to recognising and disclosing information about deferred tax assets

and liabilities related to Pillar Two income taxes.

The Group has undertaken a Pillar Two analysis for the year ended 31 December 2025 and is expected to have met relevant safe

harbours for all jurisdictions in which it operates except for Singapore. The amount of Singapore Pillar Two tax expense is not material.

Significant estimates and judgements

(a) Income tax classification

Judgement is required when determining whether a particular tax is an income tax or another type of tax. PRRT is considered,

for accounting purposes, to be an income tax. Accounting for deferred tax is applied to income taxes as described above, but is not

applied to other types of taxes, e.g. North West Shelf royalties, excise and levies which are recognised in cost of sales in the

income statement.

(b) Deferred tax asset recognition

Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from USA

TCG 1 of $1,227 million (2024: $1,274 million), USA TCG 2 of $200 million (2024:nil) and $396 million (2024: $410 million)

arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable

that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a)

for details of tax consolidated groups.

Unrecognised DTAs relating to carry forward unused tax losses and credits of $320 million (2024: $366 million) from the USA TCG 1,

$150 million (2024: $343 million) from USA TCG 2 and $663 million (2024: $715 million) from countries other than Australia and the

USA. These DTAs have not been recognised as it is not currently probable that the losses and credits will be utilised based on

current planned activities in those countries.

On 29 April 2025, the Group approved an FID to develop the Louisiana LNG Project. Upon FID, the Group recognised a DTA of

$182 million. In the prior year, subsequent to achieving first oil on the Sangomar project in June 2024, the Group recognised a net DTA

of $342 million.

PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting

forecast future taxable profits. During the year ended 31 December 2025, the Group did not recognise any additional Pluto PRRT DTA

as a result of recoverability assessments performed.

In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable profits are

risk‑adjusted where appropriate by a market premium risk rate to reflect uncertainty inherent in long-term forecasts. A long-term bond

rate of 4.3% (31 December 2024: 3.2%) was used for the purposes of augmentation.

Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future

augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable profits. $7,728 million (2024:

$7,490 million) relates to the North West Shelf Project, $779 million (2024: $601 million) relates to remaining Pluto deductible balances

and $776 million (2024: $795 million) relates to Wheatstone. A long-term bond rate of 4.3% (31 December 2024: 3.2%) was used for the

purposes of augmentation.

Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the

assessment, additional deferred tax assets would be recognised, with a corresponding benefit to tax expense. It was determined that the

approach adopted provides the most meaningful information on the implications of the PRRT regime, whilst ensuring compliance with

IAS 12 Income Taxes.

The Group has tax matters, litigation and other claims, for which the timing of resolution and potential economic outflows are uncertain.

Where the Group assesses an outcome for any tax matter, litigation or other claim as more likely than not to be accepted by the relevant

tax authority, the position is adopted in the reported tax balances.

Because of the complexity of some of these positions, the ultimate outcome may differ from the current estimate of the position.

These differences will be reflected as increases or decreases to tax expense in the period in which new information is available. Tax

matters without a probable economic outflow and/or presently cannot be measured reliably are contingent liabilities and disclosed in

Note E.1 Contingent liabilities and assets.

(a) Summary of other material accounting policies

Australia tax consolidation

The parent and its wholly owned Australian controlled entities have elected to enter a tax consolidation, with Woodside Energy Group

Ltd as the head entity of the tax consolidated group. The members of the Australian tax consolidated group are identified in Note E.8(a).

The tax expense/benefit, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax

consolidated group are recognised in the separate financial statements of the members of the tax consolidated group, using the stand-

alone approach.

Entities within the tax consolidated group have entered into a tax funding arrangement and a tax sharing agreement with the head entity.

Under the tax funding agreement, Woodside Energy Group Ltd and each of the entities in the tax consolidated group have agreed to pay

or receive a tax equivalent payment to or from the head entity, based on the current tax liability or current tax asset of the entity.

The tax sharing agreement entered into between members of the tax consolidated group provides for the determination of the allocation

of income tax liabilities between the entities, should the head entity default on its tax payment obligations. No amounts have been

recognised in the financial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is

considered remote.

US tax consolidation

The Group has two separate USA Tax Consolidation Groups as at 31 December 2025:

•Woodside Energy USA Operations Inc. and its wholly owned USA controlled entities have elected to file a consolidated tax return,

with Woodside Energy USA Operations Inc. as the parent of the tax consolidated group (USA TCG 1).

•Woodside Energy Holdings (USA) Inc. and its wholly owned USA controlled entities have elected to file a consolidated tax return,

with Woodside Energy Holdings (USA) Inc. as the parent of the tax consolidated group. The consolidated tax return will include the

subsidiaries acquired as part of the Tellurian acquisition from acquisition date. Deferred tax assets and liabilities arising from

temporary differences within this consolidated group have been recognised to the extent that they do not meet the initial recognition

exemption in relation to the Tellurian acquisition (USA TCG 2).

The tax expense/benefit, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax

consolidated group are computed on a separate company basis.

Entities within the tax consolidated group have entered into a tax sharing agreement. Under the tax sharing agreement, the tax liability

for the consolidated group or the utilisation of tax attributes are settled periodically between the members of the group. The tax sharing

agreement between members of the tax consolidated group has no overall impact on the financial statements.

Significant estimates and judgements

(a) Income tax classification

Judgement is required when determining whether a particular tax is an income tax or another type of tax. PRRT is considered,

for accounting purposes, to be an income tax. Accounting for deferred tax is applied to income taxes as described above, but is not

applied to other types of taxes, e.g. North West Shelf royalties, excise and levies which are recognised in cost of sales in the

income statement.

(b) Deferred tax asset recognition

Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from USA

TCG 1 of $1,227 million (2024: $1,274 million), USA TCG 2 of $200 million (2024:nil) and $396 million (2024: $410 million)

arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable

that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a)

for details of tax consolidated groups.

Unrecognised DTAs relating to carry forward unused tax losses and credits of $320 million (2024: $366 million) from the USA TCG 1,

$150 million (2024: $343 million) from USA TCG 2 and $663 million (2024: $715 million) from countries other than Australia and the

USA. These DTAs have not been recognised as it is not currently probable that the losses and credits will be utilised based on

current planned activities in those countries.

On 29 April 2025, the Group approved an FID to develop the Louisiana LNG Project. Upon FID, the Group recognised a DTA of

$182 million. In the prior year, subsequent to achieving first oil on the Sangomar project in June 2024, the Group recognised a net DTA

of $342 million.

PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting

forecast future taxable profits. During the year ended 31 December 2025, the Group did not recognise any additional Pluto PRRT DTA

as a result of recoverability assessments performed.

In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable profits are

risk‑adjusted where appropriate by a market premium risk rate to reflect uncertainty inherent in long-term forecasts. A long-term bond

rate of 4.3% (31 December 2024: 3.2%) was used for the purposes of augmentation.

Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future

augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable profits. $7,728 million (2024:

$7,490 million) relates to the North West Shelf Project, $779 million (2024: $601 million) relates to remaining Pluto deductible balances

and $776 million (2024: $795 million) relates to Wheatstone. A long-term bond rate of 4.3% (31 December 2024: 3.2%) was used for the

purposes of augmentation.

Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the

assessment, additional deferred tax assets would be recognised, with a corresponding benefit to tax expense. It was determined that the

approach adopted provides the most meaningful information on the implications of the PRRT regime, whilst ensuring compliance with

IAS 12 Income Taxes.

The Group has tax matters, litigation and other claims, for which the timing of resolution and potential economic outflows are uncertain.

Where the Group assesses an outcome for any tax matter, litigation or other claim as more likely than not to be accepted by the relevant

tax authority, the position is adopted in the reported tax balances.

Because of the complexity of some of these positions, the ultimate outcome may differ from the current estimate of the position.

These differences will be reflected as increases or decreases to tax expense in the period in which new information is available. Tax

matters without a probable economic outflow and/or presently cannot be measured reliably are contingent liabilities and disclosed in

Note E.1 Contingent liabilities and assets.

Significant estimates and judgements

(a) Area of interest

Typically, an AOI is defined by the Group as an individual geographical area whereby the presence of hydrocarbons is considered

favourable or proved to exist. The Group has established criteria to recognise and maintain an AOI.

(b) Transfer to projects in development

Development activities commence after project sanctioning by the appropriate level of management. Judgement is applied by

management in determining when the project is technically feasible and economically viable to transfer to projects in development.

Significant estimates and judgements

(a) Reserves

The estimation of reserves requires significant management judgement and interpretation of complex geological and geophysical models

in order to make an assessment of the size, shape, depth and quality of reservoirs, and their anticipated recoveries. Estimates of oil and

natural gas reserves are used to calculate depreciation and amortisation charges for the Group’s oil and gas properties. Judgement is used

in determining the economic reserve base applied to each asset. Estimates are reviewed at least annually or when there are changes in the

economic circumstances impacting specific assets or asset groups. These changes may impact depreciation, asset carrying values,

restoration provisions and deferred tax balances. If reserves estimates are revised downwards, earnings could be affected by higher

depreciation expense or an immediate write-down of the asset’s carrying value.

(b) Depreciation

Judgement is required to determine when assets are available for use to commence depreciation. Depreciation generally commences on

first production.

Significant estimates and judgements

(a) CGU determination

Identification of a CGU requires management judgement. Management has determined CGUs based on the smallest group of assets that

generate significant cash inflows that are independent from other assets or groups of assets.

(b) Allocation of goodwill

Judgement is required in the allocation of goodwill arising from business combinations to the Group’s CGUs that are expected to benefit

from the synergies of the business combination.

In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash flows when determining

the FVLCD. FVLCD methodology uses assumptions reflecting market participant's current expectations of such future cash flows (to

determine a value that a willing seller and a willing buyer would accept in a market transaction). These estimates require significant

management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can also affect the

assumptions used and the rates used to discount future cash flow estimates.

Significant estimates and judgements

(a) Nature of acquisition

Judgement is required to determine if the acquisition is a business combination due to the stage of completion of the project and the

timing of transfer of employees.

The project is under construction, with agreements in place to complete construction and transfer a fully operational asset together with a

workforce to the Group. The agreements were in place at acquisition date and provide Woodside with control over the future economic

benefits of the project, and the necessary inputs and processes to create outputs, meeting the definition of a business combination.

(b) Fair value determination for net assets acquired

Judgement is required to determine the fair value of assets acquired and liabilities assumed in a business combination, which can have a

material impact on resultant goodwill. This includes the use of a cash flow model to estimate the expected future cash flows and the

discount rate used.

On acquisition date, the reproduction cost method was used to fair value the property, plant and equipment in its construction phase. The

reproduction cost method calculates the cost to construct an equivalent asset with the same specifications.

Judgement is required to determine the fair value of the contingent consideration which includes consideration on the construction

progress, estimates to complete compared to the schedule and performance guaranteesSignificant estimates and judgements

(a) Goodwill allocation

Judgement is required in the allocation of goodwill to the Group’s CGUs that are expected to benefit from the synergies of the business

combination. Refer to Note B.4 for the details of the goodwill allocation.

(b) Contract assets

In determining the fair value of the contract assets as part of a business combination, estimates are made regarding the pricing

assumptions and discount rate. These estimates require management judgement and changes in economic conditions can impact the fair

value assessment of the contracts.

Significant estimates and judgements

(a) Nature of acquisition

Judgement is required to determine if the transaction is the acquisition of an asset or a business combination.

The Louisiana LNG Project is in its preliminary phase with significant construction milestones and costs to be incurred prior to the

facility being operational and the acquired assets and liabilities did not meet the criteria for a business combination due to the absence of

a substantive process and organised workforce required to convert inputs to outputs.

(b) Employee compensation program

As part of the acquisition, the Group has assumed the obligation of Tellurian’s compensation programs to its employees. Judgement is

required to determine the measurement of the employee provision on acquisition as certain conditions in the compensation programs are

linked to future milestones of the Louisiana LNG Project. This includes determining the likelihood and timing of the milestones.

Significant estimates and judgements

(a) Control

Under IFRS 10 Consolidated Financial Statements, consolidation is required when an investor controls an investee. If a parent loses

control of a subsidiary, the parent is required to derecognise the assets and liabilities of the former subsidiary at their carrying amounts at

the date when control is lost. Judgement is required to determine if the Group continues to control Louisiana LNG Infrastructure LLC

after the sell-down.

It has been determined that the Group continues to control and consolidate Louisiana LNG Infrastructure LLC as it has the power

to direct the relevant activities and decisions requiring majority approval through its roles as operator, construction manager,

and majority interest holder.

(b) Classification of non-controlling interest as equity or liability

Judgement is required to determine if the classification of the non‑controlling interest is either equity or liability based on the Group’s

contractual obligation to deliver cash or another financial asset. Louisiana LNG Infrastructure LLC and Louisiana LNG LLC are not

required to distribute dividends unless Woodside Energy Group Ltd declares dividends. As the Group can indefinitely defer payment of

the Louisiana LNG Infrastructure LLC dividend and Louisiana LNG LLC dividend based on the terms in the agreement, the

non‑controlling interest in Louisiana LNG Infrastructure LLC and Louisiana LNG LLC is classified as equity in the Group’s

consolidated financial statements. While the terms grant the Group discretion to avoid distributing dividends from Louisiana LNG

Infrastructure LLC and Louisiana LNG LLC, the exercise of this discretion may increase the non-controlling interest’s entitlement to

future discretionary distributions.

Significant estimates and judgements

(a) Restoration obligations

The Group estimates the future decommissioning and remediation costs of offshore oil and gas platforms, offshore and onshore

production facilities, wells and pipelines at different stages of the development and construction of assets or facilities including for new

energy assets. In many instances, decommissioning of assets occurs many years into the future.

The Group’s restoration obligations are based on compliance with the requirements of relevant regulations which vary for different

jurisdictions. For example Australian regulations require full removal for offshore assets unless regulator approval is received to

decommission in-situ. It is currently the Group’s assumption that in some regulatory jurisdictions and environments, certain

infrastructures are decommissioned in-situ where it can be demonstrated that this will deliver equal or better environmental outcomes

than full removal and that regulatory approval is obtained where arrangements are satisfactory to the regulator. The Group maintains

technical expertise to ensure that industry learnings, scientific research and local and international guidelines are reviewed in assessing

its restoration obligations.

The restoration obligation requires judgemental assumptions regarding removal timing, applicable environmental legislation

and regulations, the extent of restoration activities required, the engineering methodology and the technologies used for estimating costs.

These assumptions inform the estimated future cash flows, which are then discounted using the risk-free discount rates aligned to the

expected timing of the cash outflows.

Expected value approach

For both onshore and offshore assets, provision has been made taking into consideration a risked range of possible removal outcomes,

including full removal of certain assets or project-specific risks (where applicable). Individual site provisions are an estimate of the

expected value of future cash flows required to rehabilitate the relevant site using current restoration standards and techniques and taking

into account risks and uncertainties. Individual site provisions are discounted to their present value using risk-free country-specific

discount rates aligned to the estimated timing of cash outflows. This approach also takes into consideration the possibility that full

removal of all assets may be required.

Inherent uncertainties

The basis of the restoration obligation provision for assets with approved decommissioning plans or general directions issued by the

regulator can differ from the assumptions disclosed above. Whilst the provisions reflect the Group’s best estimate based on current

knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be ongoing to

ensure that the most accurate information is available when detailed decommissioning plans are required to be submitted to the relevant

regulatory authorities. Actual costs and cash outflows can materially differ from the current estimate as a result of changes in regulations

and their application, prices, analysis of site conditions, further studies, timing of restoration and changes in removal technology. These

uncertainties may result in actual expenditure differing from amounts included in the provision recognised as at 31 December 2025.

Significant estimates and judgements

(a) Change in embedded derivative valuation inputs

The Group has reassessed the valuation inputs of the Perdaman embedded derivative factoring current market conditions and as a result

revised pricing inputs that reflect the long-term nature of the contract and external market data. The change has been applied from 1

January 2025, resulting in an increase in fair value gains of $151 million for the year ended 31 December 2025. The effect of future

periods is not disclosed because estimating it is impracticable.

(b) Embedded derivative

The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires

management to make certain assumptions about the model inputs, including forecast cash flows, discount rate, credit risk and volatility.

These assumptions require significant judgement and are subject to risk and uncertainty. The present value of the embedded derivative

was estimated using the assumptions set out below.

•Inflation rate – 2.5% (2024: 2.5%) has been applied.

•Discount rate – a pre-tax interest rate curve with a range of 4.69% to 7.53% (2024: range of 5.80% to 6.95%).

•Domestic gas pricing – forecast sales are subject to urea pricing. Price assumptions are based on the best market information

available at measurement date and derived from short- and long-term views of global supply and demand, building upon past

experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the

prevailing gas hub (TTF) prices available in the market.

The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses

recognised in other income/expenses.

Significant estimates and judgements

(a) Control

Judgement is required to assess whether a contract is or contains a lease at inception by assessing whether the Group has the right to

direct the use of the identified asset and obtain substantially all the economic benefits from the use of that asset.

(b) Lease term

Judgement is required when assessing the term of the lease and whether to include optional extension and termination periods. Option

periods are only included in determining the lease term at inception when they are reasonably certain to be exercised. Lease terms are

reassessed when a significant change in circumstances occurs. On this basis, possible additional lease payments amounting to $2,342

million (2024: $2,113 million) were not included in the measurement of lease liabilities.

Judgement is required to determine the Group’s rights and obligations for lease contracts within joint operations, to assess whether lease

liabilities are recognised gross (100%) or in proportion to the Group’s participating interest in the joint operation. This includes an

evaluation of whether the lease arrangement contains a sublease with the joint operation.

(d) Discount rates

Judgement is required to determine the discount rate, where the discount rate is the Group’s incremental borrowing rate if the rate

implicit in the lease cannot be readily determined. The incremental borrowing rate is determined with reference to the Group’s

borrowing portfolio at the inception of the arrangement or the time of the modification.

Significant estimates and judgements

(a) Accounting for interests in other entities

Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity. Depending upon

the facts and circumstances in each case, Woodside may obtain control, joint control or significant influence over the entity or

arrangement. Judgement is applied when determining the relevant activities of a project and if joint control is held over it.

Relevant activities include, but are not limited to, work program and budget approval, investment decision approval, voting rights in joint

operating committees, amendments to permits and changes to joint arrangement participant holdings. Transactions which give Woodside

control of a business are business combinations. If Woodside obtains joint control of an arrangement, judgement is also required to

assess whether the arrangement is a joint operation or a joint venture. If Woodside has neither control nor joint control, it may be in a

position to exercise significant influence over the entity, which is then accounted for as an associate.

Exploration and evaluation - Recognition and measurement and Exploration commitments

Recognition and measurement

Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method.

Areas of interest (AOI) are based on a geographical area for which the rights of tenure are current. All exploration and evaluation

expenditure, including general permit activity, geological and geophysical costs and new venture activity costs, is expensed as incurred

except for the following:

•where the expenditure relates to an exploration discovery for which the assessment of the existence or otherwise of economically

recoverable hydrocarbons is not yet complete; or

•where the expenditure is expected to be recouped through successful exploitation of the area of interest, or alternatively, by its sale.

The costs of acquiring interests in new exploration and evaluation licences are capitalised. The costs of drilling exploration wells are

initially capitalised pending the results of the well.

Costs are expensed where the well does not result in the successful discovery of economically recoverable hydrocarbons and the

recognition of an area of interest.

Subsequent to the recognition of an area of interest, all further evaluation costs relating to that area of interest are capitalised. Upon

approval for the commercial development of an area of interest, accumulated expenditure for the area of interest is transferred to projects

in development within property, plant and equipment.

In the consolidated statement of cash flows, those cash flows associated with capitalised exploration and evaluation expenditure,

including unsuccessful wells, are classified as cash flows used in investing activities.

Exploration commitments

The Group has exploration expenditure obligations which are contracted for, but not provided for in the financial statements. These

obligations may be varied from time to time and are expected to be fulfilled in the normal course of the Group’s operations.

Property, plant and equipment - Recognition and measurement