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"fact-753": {
"value": "About these statements Following the approval by shareholders at the Annual General Meeting on 19 May 2022, Woodside Petroleum Ltd has registered the change of company name to Woodside Energy Group Ltd. Woodside Energy Group Ltd and its controlled entities (Woodside or the Group) is a for-pro\ufb01t entity limited by shares, incorporated and domiciled in Australia. Its shares are publicly traded on the Australian Securities Exchange (ASX), on the Main Market for listed securities of the London Stock Exchange (LSE) (with trades settled in the form of UK Depository Interests) and on the New York Stock Exchange (NYSE) (in the form of Woodside American Depositary Shares). The nature of the operations and the principal activities of the Group are described in the Directors\u2019 Report and in the segment information in Note A.1. The \ufb01nancial statements were authorised for issue in accordance with a resolution of the Directors on 27 February 2023. ",
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"fact-751": {
"value": "About these statements Following the approval by shareholders at the Annual General Meeting on 19 May 2022, Woodside Petroleum Ltd has registered the change of company name to Woodside Energy Group Ltd. Woodside Energy Group Ltd and its controlled entities (Woodside or the Group) is a for-pro\ufb01t entity limited by shares, incorporated and domiciled in Australia. Its shares are publicly traded on the Australian Securities Exchange (ASX), on the Main Market for listed securities of the London Stock Exchange (LSE) (with trades settled in the form of UK Depository Interests) and on the New York Stock Exchange (NYSE) (in the form of Woodside American Depositary Shares). The nature of the operations and the principal activities of the Group are described in the Directors\u2019 Report and in the segment information in Note A.1. The \ufb01nancial statements were authorised for issue in accordance with a resolution of the Directors on 27 February 2023. Statement of compliance The \ufb01nancial statements are general purpose \ufb01nancial statements, which have been prepared in accordance with the requirements of the Corporations Act 2001, Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board (AASB). The \ufb01nancial statements comply with 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). Subsequent to the merger with BHPP, BHPP\u2019s accounting policies have been aligned with the Group. The Group\u2019s accounting policies are consistent with those disclosed in the Group\u2019s 2021 Financial Statements except for new policies applicable in 2022. Adoption of new or amended standards and interpretations effective 1 January 2022 did not result in any signi\ufb01cant changes to the Group\u2019s accounting policies. Estimates have been revised, where required, to re\ufb02ect current market conditions including the impact of COVID-19 and climate change. Updated assumptions used for impairment assessments and the measurement of onerous contracts are disclosed in Notes B.4 and D.5 respectively; these assumptions could change in the future. New estimates and judgements for signi\ufb01cant transactions during the period including the recognition of goodwill as a result of the business combination, the allocation of goodwill to the Group\u2019s cash generating units, and the sell-down of Train 2 are disclosed in Notes B.5, B.4 and B.7 respectively. Currency The 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 \ufb01nancial statements are taken to the income statement. Rounding of amounts The amounts contained in these \ufb01nancial statements have been rounded to the nearest million dollars under the option available to the Group under Australian Securities and Investments Commission (ASIC) Corporations (Rounding in Financial/ Directors\u2019 Reports) Instrument 2016/191 dated 24 March 2016, unless otherwise stated. Basis of preparation The \ufb01nancial statements have been prepared on a historical cost basis, except for derivative \ufb01nancial instruments and certain other \ufb01nancial assets and \ufb01nancial 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 \ufb01nancial assets and \ufb01nancial liabilities does not approximate their fair value, the fair value has been included in the notes to the \ufb01nancial statements. The \ufb01nancial statements comprise the \ufb01nancial position and results of the Group as at and for the year ended 31 December 2022 (refer to Note E.8). 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 subsidiaries of the Group apply the same reporting period and accounting policies as the parent company in their \ufb01nancial statements. All intercompany balances and transactions, including unrealised pro\ufb01ts and losses arising from intra-group transactions, have been eliminated in full. Non-controlling interests are allocated their share of the net pro\ufb01t 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 \ufb01nancial position, separately from parent shareholders\u2019 equity. The consolidated \ufb01nancial statements provide comparative information in respect of the previous periods. Where required, a reclassi\ufb01cation of items in the \ufb01nancial statements of the previous periods has been made in accordance with the classi\ufb01cation of items in the \ufb01nancial statements of the current period. Climate change and energy transition Climate considerations Woodside has considered the impact of climate and the energy transition in assessing the carrying value of its assets and liabilities. This note describes climate-related assumptions that underpin key areas of the \ufb01nancial statements and the potential short- and long-term impacts differing scenarios could have on the \ufb01nancial results and \ufb01nancial position of Woodside. Climate change and energy transition (cont.) 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 ensure we maintain a resilient \ufb01nancial position. The assumptions applied in assessing amounts within the \ufb01nancial statements are in each case calculated in accordance with the requirements of the applicable accounting standards. Our long-term price assumptions re\ufb02ect management\u2019s current \u2018best estimate\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. All price assumptions consider current legislation in the locations where Woodside operates and place some weight on scenarios in which the transition to a low carbon energy system is sufficiently rapid to meet the goals of the Paris Agreement, 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. in\ufb02ation) and which are not related to the Paris goals. Woodside\u2019s facilities are subject to physical risks such as oceanic conditions and are located in regions that experience tropical cyclones, hurricanes and high ambient temperatures. Woodside has signi\ufb01cant experience designing and operating facilities located in harsh environments. Woodside notes that 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 and disclose the risks and their potential impacts with precision. Woodside continues to monitor the uncertainty around climate change risks and will revise commodity and carbon pricing assumptions accordingly. Oil and gas 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 signi\ufb01cance to assets and liabilities than carbon pricing. Impairment of exploration and evaluation, oil and gas properties and goodwill In accordance with IFRS, elements of Woodside\u2019s \ufb01nancial statements are based on reasonable and supportable assumptions that represent management\u2019s 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. Price forecasts are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the impacts of climate policies along with other factors such as industry investment and cost trends. There remains signi\ufb01cant 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 over the medium and long term. The IEA\u2019s World Energy Outlook 2022 (WEO) explores three main climate change scenarios. The IEA scenarios are not predictions and the IEA does not have a single view on the future of the energy system. There is signi\ufb01cant uncertainty as to whether any of these scenarios will eventuate. Because Woodside considers what a market participant would pay to acquire an asset in assessing impairments, these external scenarios are not necessarily consistent with the pricing assumptions used for the Group\u2019s impairment assessment as disclosed in Table A below and Note B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill. The WEO explores three main scenarios1: \u2022 The Net Zero Emissions by 2050 Scenario (NZE) \u2022 The Announced Pledges Scenario (APS) \u2022 The Stated Policies Scenario (STEPS) Table A: Average real terms 2022 oil price (US$/bbl, Brent)2, North Asian LNG price (US$/MMbtu)2 and carbon price (US$/tCO\u2082-e)3 consistent with IEA dataset compared against Woodside\u2019s assumptions: Average Brent (RT US$/bbl) 2023-2026 2027-2031 2032-2036 2037-2040 NZE 59 38 33 31 APS 88 70 65 65 STEPS 92 85 85 88 Woodside 75 70 70 70 Average North Asian LNG (RT US$/MMbtu) 2023-2026 2027-2031 2032-2036 2037-2040 NZE 18 6 6 6 APS 20 9 9 9 STEPS 21 11 11 11 Woodside 23 9 9 9 Average Carbon (RT US$/tonne) 2023-2026 2027-2031 2032-2036 2037-2040 NZE 100 135 169 199 APS 98 130 154 172 STEPS 80 80 80 80 Woodside 80 80 80 80 1. IEA 2022. \u2018World Energy Outlook 2022\u2019. All rights reserved. 2. Based on data from IEA 2022. \u2018World Energy Outlook 2022\u2019 as modi\ufb01ed by Woodside analysis. Woodside used interpolation techniques to estimate Brent annual price points in between the years for which the IEA disclosed price points. For gas pricing assumptions all non-contracted LNG volumes were assessed at IEA\u2019s Japan import price, as a proxy for North Asian LNG spot price. Woodside used interpolation techniques to estimate annual gas price points in between the years for which the IEA disclosed prices. For oil linked LNG contracts, prices are derived from the Brent forecasts and the terms of the contracts. 3. Based on data from IEA 2022. \u2018World Energy Outlook 2022\u2019 as modi\ufb01ed by Woodside analysis. The IEA only provide carbon prices from 2030 onwards. As a result, Woodside used a starting point of US$80/tCO\u2082-e consistent with internal carbon cost pricing. Woodside used the 2022 starting price point and the IEA\u2019s published 2030 and 2040 carbon prices for each scenario to interpolate annual price points through to 2040. Climate change and energy transition (cont.) Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.) Refer to Note B.4 for the sensitivity analysis performed on Woodside\u2019s Brent oil pricing assumptions and the potential impact on the carrying value of Woodside\u2019s non-current assets. The benchmarked pricing above has limitations and is based on a wide range of assumptions. The impact of the benchmark pricing assumptions could be managed by decisions Woodside could make in response such as acquisitions, divestments or cost reductions as well as other consequential changes. The scenarios must therefore not be interpreted as Woodside\u2019s investment guidance. These are scenarios, not forecasts, and no likelihood is assigned to any of these scenarios eventuating. Impact on remaining life of assets Oil and gas properties relating to transferred exploration and evaluation and offshore 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. Restoration and other provisions The energy transition may result in restoration activities occurring earlier than expected. 54% (2021: 65%) of the Group\u2019s 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. Woodside continues to monitor the uncertainty around climate change risks to assess if additional changes to restoration provisions should be recognised. Onerous contracts Closure or early termination of activities may lead to supply contracts becoming onerous. As at 31 December 2022, the Corpus Christi contract is expected to return a positive value and on this basis the onerous contract provision has been reversed to nil (2021: $214 million). This and other contractual arrangements could be impacted by adverse market conditions arising from climate-related factors. 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 2022. The recoverability of deferred tax assets is dependent on the Group\u2019s future taxable income which can be impacted by the uncertainty of commodity and carbon pricing. Regulatory environment Regulation of climate-related emissions can change over time. Woodside is not currently aware of speci\ufb01c proposals that would materially change the assumptions underpinning the \ufb01nancial statements. Key estimates and judgements In applying the Group\u2019s accounting policies, management continually evaluates judgements, estimates and assumptions based on experience and other factors, including expectations of future events that may have an impact on the Group. All judgements, estimates and assumptions made are believed to be reasonable based on the most current set of circumstances known to management, and actual results may differ. Signi\ufb01cant judgements, estimates and assumptions made by management in the preparation of these \ufb01nancial statements are found in the following notes: Note A.1 Revenue from contracts with customers Page 110 Note A.5 Taxes Page 115 Note B.2 Exploration and evaluation Page 120 Note B.3 Oil and gas properties Page 121 Note B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill Page 123 Note B.5 Business combination Page 128 Note B.6 Signi\ufb01cant production and growth asset acquisitions Page 130 Note B.7 Disposal of assets Page 131 Note D.5 Provisions Page 138 Note D.6 Other \ufb01nancial assets and liabilities Page 140 Note D.7 Leases Page 143 Note E.6 Joint arrangements Page 149 Recognition and measurement 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 signi\ufb01cant reversal will not occur. \u2022 Revenue from sale of hydrocarbons \u2013 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. \u2022 Other operating revenue \u2013 Revenue earned from LNG processing and other services is recognised over time as the services are rendered. Expenses \u2022 Royalties, excise and levies \u2013 Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group\u2019s entitlement to physical production. \u2022 Depreciation and amortisation \u2013 Refer to Note B.3. \u2022 Impairment and impairment reversals \u2013 Refer to Note B.4. \u2022 Leases \u2013 Refer to Note D.7. \u2022 Employee bene\ufb01ts \u2013 Refer to Note E.2. Key estimates and judgements 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 signi\ufb01cant 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. Earnings/(losses) per share is calculated by dividing the pro\ufb01t/ (loss) for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares on issue during the year. The weighted average number of shares makes allowance for shares reserved for employee share plans. Diluted earnings/(losses) per share is calculated by adjusting basic earnings/(losses) per share by the number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares into ordinary shares. At 31 December 2022, 13,061,376 awards (2021: 9,023,439 awards) granted under the Woodside employee share plans are considered dilutive. Total outstanding share awards as at 31 December 2020 were 9,392,203 and considered anti-dilutive due to the loss position in 2020. There have been no signi\ufb01cant transactions involving ordinary shares between the reporting date and the date of completion of these \ufb01nancial statements. Key estimates and judgements (a) Income tax classi\ufb01cation 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 the USA Tax Consolidation Group (USA TCG) of $1,371 million (2021: nil) and $93 million (2021: nil) arising from regions 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 within those regions. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $250 million from the USA TCG, $146 million from USA entities outside of the USA TCG and $1,061 million from regions other than Australia and the USA have not been recognised as it is not currently probable that the assets will be utilised based on current planned activities in those regions (2021: $497 million unrecognised DTAs). PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. As a result of higher actual and forecast assessable revenues supporting future recoverability of unrecognised quarantined exploration and general expenditure, the Pluto PRRT DTA has increased by $1,362 million. In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable pro\ufb01ts are risk-adjusted where appropriate by a market premium risk rate to re\ufb02ect uncertainty inherent in long-term forecasts. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 pro\ufb01ts. $6,523 million (2021: $4,507 million) relates to the North West Shelf Project, $189 million (2021: $1,432 million) relates to remaining Pluto quarantined exploration expenditure and $831 million (2021: $1,071 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 bene\ufb01t 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 AASB 112/ 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 out\ufb02ows 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 re\ufb02ected as increases or decreases to tax expense in the period in which new information is available. A.5 Taxes (cont.) Tax transparency code Woodside participates in the Australian Board of Taxation\u2019s voluntary Tax Transparency Code (TTC). To increase public con\ufb01dence in the contributions and compliance of corporate taxpayers, the TTC recommends public disclosure of tax information. Part A of the recommended disclosures are addressed within this Taxes note and Part B within our Sustainable Development Report, supported by additional information on our website. 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 substantially 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 \ufb01nancial 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 pro\ufb01t nor the taxable pro\ufb01t. In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable pro\ufb01ts when assessing the extent to which a deferred tax asset can be recognised in the consolidated statement of \ufb01nancial 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. Recognition and measurement Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method. Areas of interest 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: \u2022 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 \u2022 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 oil and gas properties. In the consolidated statement of cash \ufb02ows, those cash \ufb02ows associated with capitalised exploration and evaluation expenditure, including unsuccessful wells, are classi\ufb01ed as cash \ufb02ows used in investing activities. Exploration commitments The Group has exploration expenditure obligations which are contracted for, but not provided for in the \ufb01nancial statements. These obligations may be varied from time to time and are expected to be ful\ufb01lled in the normal course of the Group\u2019s operations. Impairment Refer to Note B.4 for details on impairment, including any write-offs. Key estimates and judgements (a) Area of interest Typically, an area of interest (AOI) is de\ufb01ned 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. Key estimates and judgements (a) Reserves The estimation of reserves requires signi\ufb01cant 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\u2019s oil and gas properties. Judgement is used in determining the economic reserve base applied to each asset. Typically, late life oil assets use proved reserves. Estimates are reviewed at least annually or when there are changes in the economic circumstances impacting speci\ufb01c assets or asset groups. These changes may impact depreciation, asset carrying values, restoration provisions and deferred tax balances. If proved plus probable (2P) reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the asset\u2019s carrying value. (b) Depreciation and amortisation Judgement is required to determine when assets are available for use to commence depreciation and amortisation. Depreciation and amortisation generally commences on \ufb01rst production. B.3 Oil and gas properties (cont.) Recognition and measurement Oil and gas properties are stated at cost less accumulated depreciation and impairment charges. Oil and gas properties 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. Subsequent capital costs, including major maintenance, are included in the asset\u2019s carrying amount only when it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group and the cost of the item can be reliably measured. Depreciation and amortisation Oil and gas properties are depreciated to their estimated residual values at rates based on their expected useful lives. Transferred exploration and evaluation and offshore plant and equipment are depreciated using the unit of production basis over proved plus probable reserves or proved reserves for late life assets. The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. For certain offshore assets, methodologies using proved and probable reserves are adjusted to best re\ufb02ect the expected pattern of consumption. Onshore plant and equipment is 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 oil and gas properties are depreciated using the straight-line method over their useful life. They are depreciated as follows: \u2022 Buildings \u2013 24-50 years; \u2022 Plant and equipment \u2013 2-40 years; and \u2022 Land is not depreciated. Impairment Refer to Note B.4 for details on impairment. Capital commitments The Group has capital expenditure commitments contracted for, but not provided for in the \ufb01nancial statements, of $7,762 million as at 31 December 2022 (2021: $7,875 million). Capital expenditure commitments relate predominantly to the Scarborough and Sangomar projects. B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill 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 oil and gas properties. Impairment calculations The recoverable amounts of exploration and evaluation assets are determined using FVLCD, as there is no value in use (VIU). Costs to dispose are the incremental costs directly attributable to the disposal of an asset, excluding \ufb01nance costs and income tax expense. 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. For assets previously impaired, if the recoverable amount exceeds the carrying amount, the impairment is reversed, but only to the extent that the asset\u2019s carrying amount does not exceed the carrying amount that would have been recognised if no impairment had occurred. Oil and gas properties Impairment testing The carrying amounts of oil and gas properties 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, expected future sales prices or costs. Oil and gas properties 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 \ufb01elds. If there is an indicator of impairment or impairment reversal for a CGU, its recoverable amount is calculated and compared with the CGU\u2019s 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\u2019s cash-generating units (CGUs) that are expected to bene\ufb01t 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 oil and gas impairment calculations The recoverable amount of an asset or CGU is determined as the higher of its VIU and FVLCD. VIU is determined by estimating future cash \ufb02ows after taking into account the risks speci\ufb01c 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 re\ufb02ect the effects of factors that may be speci\ufb01c to the Group. In determining FVLCD, recent market transactions are considered. If no such transactions can be identi\ufb01ed, an appropriate valuation model, such as discounted cash \ufb02ow techniques, are 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 \ufb01rst 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 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 or amortisation, if no impairment had been recognised. Impairments of goodwill are not reversed. Key estimates and judgements CGU determination Identi\ufb01cation of a CGU requires management judgement. In determining CGUs for acquired assets during the reporting period, management has assessed based on the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or groups of assets. Allocation of goodwill Allocation of goodwill to the relevant CGUs requires management judgement. The goodwill arising from the merger has been allocated to relevant CGUs which are expected to bene\ufb01t from the expected synergies as a result of the merger. Recoverable amount calculation key assumptions In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash \ufb02ows when determining the FVLCD. These estimates require signi\ufb01cant 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 \ufb02ow estimates. The basis for each estimate used to determine recoverable amounts as at 31 December 2022 is set out below: \u2022 Resource estimates \u2013 2P and a portion of 2C reserves (where applicable) for oil and gas properties. The reserves are as disclosed in the Reserves and Resources Statement in the 31 December 2022 Annual Report. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied for US based assets and 2.5% for Australian based assets. \u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on management\u2019s view of long-term exchange rates. Key estimates and judgements (cont.) Recoverable amount calculation key assumptions (cont.) \u2022 Discount rates \u2013 a range of post-tax discount rates between 8% and 11.5% for CGUs has been applied. The discount rate re\ufb02ects an assessment of the risks speci\ufb01c to the asset. \u2022 Carbon pricing \u2013 a long-term price of US$80/tonne of emissions (real terms 2022) is based on management\u2019s assumptions on carbon cost pricing and incorporates an evaluation of climate risk. This is applicable to Australian emissions that exceed facility- speci\ufb01c baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. Refer to Climate change and energy transition section within the basis of preparation for further information. \u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. \u2022 Brent oil prices \u2013 derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is signi\ufb01cant uncertainty around how society will respond to the climate challenge; Woodside\u2019s pricing assumptions re\ufb02ect a \u2018best estimate\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in the Climate change and energy transition section within the basis of preparation. The nominal Brent oil prices (US$/bbl) used were: 2023 2024 2025 2026 2027 2028 31 December 20221 87 78 74 76 77 79 31 December 20212 71 68 69 70 72 73 1. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 2. Long-term oil prices are based on US$65/bbl (2022 real terms) from 2024 and prices are escalated at 2.0% onwards. Key estimates and judgements CGU determination Identi\ufb01cation of a CGU requires management judgement. For the year ended 31 December 2021, management has determined that the Scarborough and Pluto Train 2 development concept integrates with the existing Pluto onshore assets and is the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or group of assets. Recoverable amount calculation key assumptions In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash \ufb02ows when determining the VIU. These estimates require signi\ufb01cant 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 \ufb02ow estimates. The basis for each estimate used to determine recoverable amounts as at 31 December 2021 is set out below: \u2022 Resource estimates \u2013 2P reserves for oil and gas properties, except for NWS Oil (Okha) which is based on 1P reserves due to the reclassi\ufb01cation to a late life asset. The reserves are as disclosed in the Reserves and resources statement in the 31 December 2021 Annual Report on pages 55-59. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied. \u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on management\u2019s view of long-term exchange rates. \u2022 Discount rates \u2013 a range of pre-tax discount rates between 8.9% and 11.6% (post-tax discount rate 7.5%-8.5%) for CGUs has been applied. The discount rate re\ufb02ects an assessment of the risks speci\ufb01c to the asset. \u2022 An evaluation of climate risk is re\ufb02ected in Woodside's assumptions on carbon cost pricing, including a long-term Australian carbon price of US$80/tonne of emissions (real terms 2022). This is applicable to Australian emissions that exceed facility-speci\ufb01c baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. \u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. \u2022 Brent oil prices \u2013 derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is signi\ufb01cant uncertainty around how society will respond to the climate challenge; Woodside\u2019s pricing assumptions re\ufb02ect a \u2018most-likely\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in Woodside\u2019s Climate Report 2021. The nominal Brent oil prices (US$/bbl) used were: 2022 2023 2024 2025 2026 2027 31 December 20211 73 71 68 69 70 72 30 June 20202 57 62 67 72 73 75 1. Based on US$65/bbl (2022 real terms) from 2024 with prices escalated at 2.0% annually thereafter. 2. Based on US$65/bbl (2020 real terms) from 2025 with prices escalated at 2.0% annually thereafter. Business combination accounting The acquisition method of accounting is used to account for all business combinations, including business combinations involving entities or businesses under common control, regardless of whether equity instruments are issued or liabilities incurred or assumed at the date of exchange. Where equity instruments are issued in an acquisition, the fair value of the instruments is their published market price as at the date of exchange. Transaction costs arising on the issue of equity instruments are recognised directly in equity. Transaction costs that were not directly attributable to the issue of shares are expensed as incurred. Contractual assets and liabilities in respect of sales agreements are recognised at fair value. Restoration provisions are recognised on acquisition at fair value. Key estimates and judgements (a) 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 \ufb02ow model to estimate the expected future cash \ufb02ows of the oil and gas assets acquired, based on reserves and resources at acquisition date and the discount rate used. The expected future cash \ufb02ows are based on estimates of future production, commodity and carbon prices, operating costs, and forecast capital expenditures at acquisition date. Restoration provisions require judgemental assumptions regarding removal date, environmental legislation and regulations and the extent of restoration activities required in determining the cost estimate. Carry forward tax losses are recognised only if it is probable that sufficient future taxable income will be available to utilise the losses. (b) Goodwill allocation Judgement is required in the allocation of goodwill to the Group\u2019s CGUs that are expected to bene\ufb01t from the synergies of the business combination. Refer to Note B.4 for the details of the goodwill allocation. Key estimates and judgements Nature of acquisition Judgement was required to determine if the transaction was the acquisition of an asset or a business combination. The Sangomar project was in the early phase of development and a substantive process that had the ability to convert inputs to outputs was not present and therefore the acquisition in 2021 was treated as asset acquisitions. Key estimates and judgements Sell-down of Train 2 Given the arrangements include provisions for GIP to sell its 49% interest back to Woodside if the status of key regulatory environmental approvals materially changes and the requirement for Woodside to fund up to $822 million of GIP\u2019s share in the event of a cost overrun, judgement is required to determine if the sell- down of Train 2 constitutes a sale and if a portion of the transaction price should be considered a variable consideration. Judgement was used to determine that the sell-down of Train 2 constituted a sale given the various conditions included in the sale and purchase agreement. The Group determined that a sale occurred as control of the 49% interest was passed to GIP on completion date. Control is determined as the ability to direct the use of, and obtain substantially all of the economic bene\ufb01ts of, the associated interest. Judgement was used to determine if it is highly probable that a signi\ufb01cant reversal will not occur in relation to the consideration received. The Group estimated the variable consideration based on the construction capital expenditure cost pro\ufb01le, the development schedule, and assessing the probability and impact of any event which may result in a signi\ufb01cant reversal. The constraining estimates of variable consideration have been applied resulting in the initial pre-tax gain on sale of $427 million. The variable consideration is remeasured at each reporting period with any changes recognised through the consolidated income statement. As at 31 December 2022, the variable consideration has been remeasured with a $71 million revaluation gain recognised as other income. Recognition and measurement Cash and cash equivalents in the consolidated statement of \ufb01nancial 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 \ufb01nancial position. Cash and cash equivalents include $12 million (2021: nil) restricted by legal or contractual arrangements. 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. The changes in the fair value risks of the hedged item resulted in a gain of $7 million being recorded (2021: gain of $5 million), and a loss of $7 million recorded on the hedging instrument (2021: loss of $7 million). 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. Recognition and measurement Issued capital Ordinary shares are classi\ufb01ed 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 are the Group\u2019s own equity instruments, which are reacquired for later use in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). These shares are deducted from equity. No gain or loss is recognised in the income statement on the purchase, sale, issue or cancellation of the Group\u2019s own equity instruments. Recognition and measurement Trade receivables are initially recognised at the transaction price determined under AASB 15/ IFRS 15 Revenue from Contracts with Customers. Other receivables are initially recognised at fair value. Receivables that satisfy the contractual cash \ufb02ow 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 \ufb02ow and business model tests are subsequently measured at fair value (refer to Note D.6). The Group\u2019s customers are required to pay in accordance with agreed payment terms. Depending on the product, settlement terms are 14 to 30 days from the date of invoice or bill of lading and customers regularly pay on time. There are no signi\ufb01cant overdue trade receivables as at the end of the reporting period (2021: nil). Fair value The carrying amount of trade and other receivables approximates their fair value. Foreign exchange risk The Group held $174 million of receivables at 31 December 2022 (2021: $121 million) in currencies other than US dollars (predominantly Australian dollars). Loans receivable On 9 January 2020, Woodside Energy Finance (UK) Ltd entered into a secured loan agreement with Petrosen (the Senegal National Oil Company), to provide up to $450 million for the purpose of funding Sangomar project costs. The facility has a maximum term of 12 years and semi-annual repayments of the loan are due to commence at the earlier of 12 months after RFSU or 30 June 2025. The carrying amount of the loan receivable is $408 million at 31 December 2022 (2021: $335 million), which approximates its fair value. The remaining balance of loans receivable is due from non-controlling interests. Recognition and measurement Inventories include hydrocarbon stocks, consumable supplies and maintenance spares. 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 \ufb01xed 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. 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. Foreign exchange risk The Group held $657 million of payables at 31 December 2022 (2021: $311 million) in currencies other than US dollars (predominantly Australian dollars). Maturity pro\ufb01le of payables The Group\u2019s payables balances at 31 December 2022 and 31 December 2021 are due for payment within a year. 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 out\ufb02ow of resources embodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Restoration The restoration provision is \ufb01rst 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 oil and gas properties 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 \ufb01nance costs. The carrying amount capitalised in oil and gas properties 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 bene\ufb01t, are expensed. Key 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. In many instances, decommissioning of assets occurs many years into the future. The Group\u2019s 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. The Group maintains technical expertise to ensure that industry learnings, scienti\ufb01c research and local and international guidelines are reviewed in assessing its restoration obligations. The restoration obligation requires judgemental assumptions regarding removal date, environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating cost, technologies used in determining the decommissioning cost, and liability-speci\ufb01c discount rates to determine the present value of these cash \ufb02ows. The Group applies either the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in assessing the cost estimate, re\ufb02ecting a difference in approach to cost estimation for heritage Woodside and heritage BHPP assets. Both approaches are supported by AASB 137/ IAS 37 Provisions, Contingent Liabilities and Contingent Assets, produce reliable estimates and are widely used in practice. Heritage Woodside assets refer to assets held by the Group prior to the BHPP merger. Heritage BHPP assets refers to assets acquired from BHP but excludes the commonly held assets by both heritage entities. Expected outcome approach This approach is used for heritage Woodside assets, and those assets commonly held by both heritage entities. The following cost assumptions are applied: \u2022 for onshore assets, provision has been made for the removal of production facilities and above ground pipelines using current restoration standards and techniques and taking into account risks and uncertainties; and \u2022 for offshore assets, provision has been made for the plug and abandonment of wells and the removal of offshore platform topsides, \ufb02oating production storage offloading (FPSO) and some subsea infrastructure. It is currently the Group\u2019s assumption that in some regulatory jurisdictions and environments, certain pipelines and infrastructure, parts of offshore platform substructures, and certain subsea infrastructure 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. Expected value approach This approach is used for heritage BHPP assets (excluding those commonly held by both heritage entities). 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. Individual site provisions are an estimate of the expected value of future cash \ufb02ows 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 country speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows. 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 re\ufb02ect the Group\u2019s best estimate based on current knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be performed near the end of their operational life and/or when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash out\ufb02ows 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 2022. A range of pre-tax discount rates between 3.4% and 4.7% (2021: 0.4% to 2.4%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $316 million higher. If the cost estimates were increased by 10% then the provision would be $627 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 54% (2021: 65%). (b) Legal case outcomes Provisions for legal cases are measured at the present value of the amount expected to settle the claim. Management is required to use judgement when assessing the likely outcome of legal cases, estimating the risked amount and whether a provision or contingent liability should be recognised. Employee bene\ufb01ts Provision is made for employee bene\ufb01ts accumulated as a result of employees rendering services up to the end of the reporting period. These bene\ufb01ts include wages, salaries, annual leave and long service leave. Liabilities in respect of employees\u2019 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 bene\ufb01ts. These liabilities are measured at the present value of the estimated future cash out\ufb02ow 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 classi\ufb01ed as short- term bene\ufb01ts and are measured at the amount due to be paid. Onerous contract provision Provision is made for loss-making contracts at the present value of the lower of the net cost of ful\ufb01lling and the cost arising from failure to ful\ufb01ll each contract. (c) Onerous contracts The onerous contract provision assessment requires management to make certain estimates regarding the unavoidable costs and the expected economic bene\ufb01ts from the contract. These estimates require signi\ufb01cant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions. As at 31 December 2022, the Corpus Christi contract is expected to return a positive value and on this basis the provision has been reversed to nil (2021: $214 million). Changes in assumptions predominantly relating to the narrowing of the spread between the sales price and purchase price could result in the contract becoming onerous in the future. Assumptions used to determine the present value as at 31 December 2022 are set out below: \u2022 Remaining contract term \u2013 18 years. \u2022 Discount rate \u2013 a pre-tax, risk free US government bond rate of 4.10% (2021: 1.855%) has been applied. \u2022 LNG pricing \u2013 forecast sales and purchase prices are subject to a number of price markers. Price assumptions are based on the best information on the market available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The forecasted sales are linked to gas hub prices (Title Transfer Facility (TTF)) at which physical sales are expected to occur and incorporate known sales pricing information . The long-term gas sales price is estimated on the basis of the Group\u2019s Brent price forecast. The estimated purchase price is linked to US gas hub prices (Henry Hub (HH)) at which physical purchases are expected to occur. The nominal TTF, Brent oil prices and HH gas prices used at 31 December 2022 were: 2023 2024 2025 2026 2027 TTF (US$/MMBtu) 47.9 36.4 22.3 8.8 9.0 Brent (US$/bbl) 87 78 74 76 77\u00b2 HH (US$/MMBtu) 6.1 4.7 4.0 4.1 4.23 1. For committed volumes, contracted pricing has been applied. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 3. Long-term gas prices are based on US$3.8/MMBtu (2022 real terms) from 2025. All long-term prices are escalated at 2.0%. Recognition and measurement Other \ufb01nancial assets and liabilities Receivables subject to provisional pricing adjustments are initially recognised at the transaction price and subsequently measured at fair value with movements recognised in the consolidated income statement. Derivative \ufb01nancial instruments Derivative \ufb01nancial 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 \ufb02ow 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 reclassi\ufb01ed to the consolidated income statement in the periods when the hedged item affects pro\ufb01t or loss. Derivative \ufb01nancial instruments (cont.) 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 \ufb02ows 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 LNG revenue contracts. Fair value Except for the other \ufb01nancial assets and other \ufb01nancial liabilities set out in this note, there are no material \ufb01nancial assets or \ufb01nancial liabilities carried at fair value. The fair value of commodity derivative \ufb01nancial instruments is determined based on observable quoted forward pricing and swap models and is classi\ufb01ed 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 \ufb02ows based on the terms of maturity of each contract, using market interest rates for a similar instrument at the reporting date and is classi\ufb01ed 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 classi\ufb01ed as Level 2 on the fair value hierarchy. The fair values of other \ufb01nancial assets and other \ufb01nancial liabilities are predominantly determined based on observable quoted forward pricing and are predominantly classi\ufb01ed as Level 2 on the fair value hierarchy. Key estimates and judgements Fair value of other \ufb01nancial assets and liabilities Estimates have been applied in the measurement of other \ufb01nancial assets and liabilities and, where required, judgement is applied in the settlement of any \ufb01nancial assets or liabilities. In the current period, this included a $3 million periodic adjustment relating to timing which increased other \ufb01nancial liabilities, re\ufb02ecting the arrangements governing Wheatstone LNG sales (2021: $56 million increase). 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 identi\ufb01ed asset which is not substitutable and to obtain substantially all economic bene\ufb01ts 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\u2019s impairment policies. Lease liabilities are initially measured at the present value of future minimum lease payments, discounted using the Group\u2019s 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 \ufb01xed payments or index-based variable payments incorporating the Group\u2019s 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 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. Foreign exchange risk The Group held $441 million of lease liabilities at 31 December 2022 (2021: $476 million) in currencies other than the US dollar (predominantly Australian dollars). Key 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 identi\ufb01ed asset and obtain substantially all the economic bene\ufb01ts 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 signi\ufb01cant change in circumstances occurs. On this basis, possible additional lease payments amounting to $2,323 million (2021: $1,654 million) were not included in the measurement of lease liabilities. (c) lnterest in joint arrangements Judgement is required to determine the Group\u2019s rights and obligations for lease contracts within joint operations, to assess whether lease liabilities are recognised gross (100%) or in proportion to the Group\u2019s 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\u2019s 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\u2019s borrowing portfolio at the inception of the arrangement or the time of the modi\ufb01cation. Contingent liabilities relate predominantly to possible obligations whose existence will only be con\ufb01rmed by the occurrence or non-occurrence of uncertain future events, and therefore the Group has not provided for such amounts in these \ufb01nancial statements. Additionally, there are a number of other claims and possible claims that have arisen in the course of business against entities in the Group, the outcome of which cannot be estimated at present and for which no amounts have been included in the table above. The Group has contingent assets of $199 million as at 31 December 2022 (2021: nil). Recognition and measurement The Group\u2019s accounting policy for employee bene\ufb01ts 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 bene\ufb01ts on retirement, disability or death from the Group\u2019s retirement plans. The Group operates a number of pension schemes throughout the world. Employees entitled to de\ufb01ned contribution schemes receive \ufb01xed contributions from Group companies and the Group\u2019s legal or constructive obligation is limited to these contributions. Contributions to de\ufb01ned 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 and Executive share plans 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 ful\ufb01lled, 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 bene\ufb01t 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 bene\ufb01t provided for the RTSR PRs 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. Key estimates and judgements 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 signi\ufb01cant in\ufb02uence 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 signi\ufb01cant in\ufb02uence over the entity, which is then accounted for as an associate. 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 classi\ufb01ed 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 classi\ufb01ed as a joint operation, and as such the Group recognises its: \u2022 assets, including its share of any assets held jointly; \u2022 liabilities, including its share of any liabilities incurred jointly; \u2022 revenue from the sale of its share of the output arising from the joint operation; \u2022 share of revenue from the sale of the output by the joint operation; and \u2022 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 classi\ufb01ed 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 AASB 3/ IFRS 3 Business Combinations. Joint arrangements which are not deemed to be carrying on a business are treated as asset acquisitions.E.9 Other accounting policies (a) Summary of other signi\ufb01cant 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 identi\ufb01ed in Note E.8(a). The tax expense/bene\ufb01t, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax consolidated group are recognised in the separate \ufb01nancial 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 \ufb01nancial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is considered remote. US tax consolidation Woodside Energy USA Operations Inc and its wholly owned USA controlled entities have elected to \ufb01le a consolidated tax return, with Woodside Energy USA Operations Inc as the parent of the tax consolidated group. The tax expense/bene\ufb01t, 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. No amounts have been recognised in the \ufb01nancial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is considered remote. (b) New and amended accounting standards and interpretations issued but not yet effective A number of new standards, amendments of standards and interpretations have recently been issued but are not yet effective and have not been adopted by the Group as at the \ufb01nancial reporting date. The Group has reviewed these standards and interpretations and has determined that none of the new or amended standards will signi\ufb01cantly affect the Group\u2019s accounting policies, \ufb01nancial position or performance. (c) New and amended accounting standards and interpretations adopted As of 1 January 2022, the Group adopted AASB 2020-3 Amendments to AASs \u2013 Annual Improvements 2018-2020 and Other Amendments including: \u2022 Amendments to AASB 3 Reference to the Conceptual Framework \u2022 Amendments to AASB 9 Fees in the \u201810 per cent\u2019 Test for Derecognition of Financial Liabilities \u2022 Amendments to AASB 137 Onerous Contracts \u2013 Costs of Ful\ufb01lling a Contract These amendments did not impact the \ufb01nancial statements of the Group. A number of other new standards are also effective from 1 January 2022 but they do not have a material effect on the Group\u2019s \ufb01nancial statements. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSummaryOfSignificantAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-750": {
"value": "About these statements Following the approval by shareholders at the Annual General Meeting on 19 May 2022, Woodside Petroleum Ltd has registered the change of company name to Woodside Energy Group Ltd. Woodside Energy Group Ltd and its controlled entities (Woodside or the Group) is a for-pro\ufb01t entity limited by shares, incorporated and domiciled in Australia. Its shares are publicly traded on the Australian Securities Exchange (ASX), on the Main Market for listed securities of the London Stock Exchange (LSE) (with trades settled in the form of UK Depository Interests) and on the New York Stock Exchange (NYSE) (in the form of Woodside American Depositary Shares). The nature of the operations and the principal activities of the Group are described in the Directors\u2019 Report and in the segment information in Note A.1. The \ufb01nancial statements were authorised for issue in accordance with a resolution of the Directors on 27 February 2023. Statement of compliance The \ufb01nancial statements are general purpose \ufb01nancial statements, which have been prepared in accordance with the requirements of the Corporations Act 2001, Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board (AASB). The \ufb01nancial statements comply with 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). Subsequent to the merger with BHPP, BHPP\u2019s accounting policies have been aligned with the Group. The Group\u2019s accounting policies are consistent with those disclosed in the Group\u2019s 2021 Financial Statements except for new policies applicable in 2022. Adoption of new or amended standards and interpretations effective 1 January 2022 did not result in any signi\ufb01cant changes to the Group\u2019s accounting policies. Estimates have been revised, where required, to re\ufb02ect current market conditions including the impact of COVID-19 and climate change. Updated assumptions used for impairment assessments and the measurement of onerous contracts are disclosed in Notes B.4 and D.5 respectively; these assumptions could change in the future. New estimates and judgements for signi\ufb01cant transactions during the period including the recognition of goodwill as a result of the business combination, the allocation of goodwill to the Group\u2019s cash generating units, and the sell-down of Train 2 are disclosed in Notes B.5, B.4 and B.7 respectively. Currency The 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 \ufb01nancial statements are taken to the income statement. Rounding of amounts The amounts contained in these \ufb01nancial statements have been rounded to the nearest million dollars under the option available to the Group under Australian Securities and Investments Commission (ASIC) Corporations (Rounding in Financial/ Directors\u2019 Reports) Instrument 2016/191 dated 24 March 2016, unless otherwise stated. Basis of preparation The \ufb01nancial statements have been prepared on a historical cost basis, except for derivative \ufb01nancial instruments and certain other \ufb01nancial assets and \ufb01nancial 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 \ufb01nancial assets and \ufb01nancial liabilities does not approximate their fair value, the fair value has been included in the notes to the \ufb01nancial statements. The \ufb01nancial statements comprise the \ufb01nancial position and results of the Group as at and for the year ended 31 December 2022 (refer to Note E.8). 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 subsidiaries of the Group apply the same reporting period and accounting policies as the parent company in their \ufb01nancial statements. All intercompany balances and transactions, including unrealised pro\ufb01ts and losses arising from intra-group transactions, have been eliminated in full. Non-controlling interests are allocated their share of the net pro\ufb01t 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 \ufb01nancial position, separately from parent shareholders\u2019 equity. The consolidated \ufb01nancial statements provide comparative information in respect of the previous periods. Where required, a reclassi\ufb01cation of items in the \ufb01nancial statements of the previous periods has been made in accordance with the classi\ufb01cation of items in the \ufb01nancial statements of the current period. Climate change and energy transition Climate considerations Woodside has considered the impact of climate and the energy transition in assessing the carrying value of its assets and liabilities. This note describes climate-related assumptions that underpin key areas of the \ufb01nancial statements and the potential short- and long-term impacts differing scenarios could have on the \ufb01nancial results and \ufb01nancial position of Woodside. Notes to the \ufb01nancial statements for the year ended 31 December 2022 Climate change and energy transition (cont.) 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 ensure we maintain a resilient \ufb01nancial position. The assumptions applied in assessing amounts within the \ufb01nancial statements are in each case calculated in accordance with the requirements of the applicable accounting standards. Our long-term price assumptions re\ufb02ect management\u2019s current \u2018best estimate\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. All price assumptions consider current legislation in the locations where Woodside operates and place some weight on scenarios in which the transition to a low carbon energy system is sufficiently rapid to meet the goals of the Paris Agreement, 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. in\ufb02ation) and which are not related to the Paris goals. Woodside\u2019s facilities are subject to physical risks such as oceanic conditions and are located in regions that experience tropical cyclones, hurricanes and high ambient temperatures. Woodside has signi\ufb01cant experience designing and operating facilities located in harsh environments. Woodside notes that 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 and disclose the risks and their potential impacts with precision. Woodside continues to monitor the uncertainty around climate change risks and will revise commodity and carbon pricing assumptions accordingly. Oil and gas 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 signi\ufb01cance to assets and liabilities than carbon pricing. Impairment of exploration and evaluation, oil and gas properties and goodwill In accordance with IFRS, elements of Woodside\u2019s \ufb01nancial statements are based on reasonable and supportable assumptions that represent management\u2019s 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. Price forecasts are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the impacts of climate policies along with other factors such as industry investment and cost trends. There remains signi\ufb01cant 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 over the medium and long term. The IEA\u2019s World Energy Outlook 2022 (WEO) explores three main climate change scenarios. The IEA scenarios are not predictions and the IEA does not have a single view on the future of the energy system. There is signi\ufb01cant uncertainty as to whether any of these scenarios will eventuate. Because Woodside considers what a market participant would pay to acquire an asset in assessing impairments, these external scenarios are not necessarily consistent with the pricing assumptions used for the Group\u2019s impairment assessment as disclosed in Table A below and Note B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill. The WEO explores three main scenarios1: \u2022 The Net Zero Emissions by 2050 Scenario (NZE) \u2022 The Announced Pledges Scenario (APS) \u2022 The Stated Policies Scenario (STEPS) Table A: Average real terms 2022 oil price (US$/bbl, Brent)2, North Asian LNG price (US$/MMbtu)2 and carbon price (US$/tCO\u2082-e)3 consistent with IEA dataset compared against Woodside\u2019s assumptions: Average Brent (RT US$/bbl) 2023-2026 2027-2031 2032-2036 2037-2040 NZE 59 38 33 31 APS 88 70 65 65 STEPS 92 85 85 88 Woodside 75 70 70 70 Average North Asian LNG (RT US$/MMbtu) 2023-2026 2027-2031 2032-2036 2037-2040 NZE 18 6 6 6 APS 20 9 9 9 STEPS 21 11 11 11 Woodside 23 9 9 9 Average Carbon (RT US$/tonne) 2023-2026 2027-2031 2032-2036 2037-2040 NZE 100 135 169 199 APS 98 130 154 172 STEPS 80 80 80 80 Woodside 80 80 80 80 1. IEA 2022. \u2018World Energy Outlook 2022\u2019. All rights reserved. 2. Based on data from IEA 2022. \u2018World Energy Outlook 2022\u2019 as modi\ufb01ed by Woodside analysis. Woodside used interpolation techniques to estimate Brent annual price points in between the years for which the IEA disclosed price points. For gas pricing assumptions all non-contracted LNG volumes were assessed at IEA\u2019s Japan import price, as a proxy for North Asian LNG spot price. Woodside used interpolation techniques to estimate annual gas price points in between the years for which the IEA disclosed prices. For oil linked LNG contracts, prices are derived from the Brent forecasts and the terms of the contracts. 3. Based on data from IEA 2022. \u2018World Energy Outlook 2022\u2019 as modi\ufb01ed by Woodside analysis. The IEA only provide carbon prices from 2030 onwards. As a result, Woodside used a starting point of US$80/tCO\u2082-e consistent with internal carbon cost pricing. Woodside used the 2022 starting price point and the IEA\u2019s published 2030 and 2040 carbon prices for each scenario to interpolate annual price points through to 2040. Notes to the \ufb01nancial statements for the year ended 31 December 2022 107Woodside Energy Group Ltd |
Climate change and energy transition (cont.)
Impairment of exploration and evaluation, oil and gas
properties and goodwill (cont.)
Refer to Note B.4 for the sensitivity analysis performed on
Woodside\u2019s Brent oil pricing assumptions and the potential
impact on the carrying value of Woodside\u2019s non-current assets.
The benchmarked pricing above has limitations and is based
on a wide range of assumptions. The impact of the benchmark
pricing assumptions could be managed by decisions Woodside
could make in response such as acquisitions, divestments or cost
reductions as well as other consequential changes. The scenarios
must therefore not be interpreted as Woodside\u2019s investment
guidance. These are scenarios, not forecasts, and no likelihood is
assigned to any of these scenarios eventuating.
Impact on remaining life of assets
Oil and gas properties relating to transferred exploration and
evaluation and offshore 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.
Restoration and other provisions
The energy transition may result in restoration activities
occurring earlier than expected. 54% (2021: 65%) of the Group\u2019s
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.
Woodside continues to monitor the uncertainty around climate
change risks to assess if additional changes to restoration
provisions should be recognised.
Onerous contracts
Closure or early termination of activities may lead to supply
contracts becoming onerous. As at 31 December 2022, the
Corpus Christi contract is expected to return a positive value
and on this basis the onerous contract provision has been
reversed to nil (2021: $214 million). This and other contractual
arrangements could be impacted by adverse market conditions
arising from climate-related factors.
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 2022. The recoverability of
deferred tax assets is dependent on the Group\u2019s future taxable
income which can be impacted by the uncertainty of commodity
and carbon pricing.
Regulatory environment
Regulation of climate-related emissions can change over time.
Woodside is not currently aware of speci\ufb01c proposals that
would materially change the assumptions underpinning the
\ufb01nancial statements.
Notes to the \ufb01nancial statements
for the year ended 31 December 2022
108 | Annual Report 2022
Notes to the \ufb01nancial statements
for the year ended 31 December 2022
Financial and capital risk management
The Board of Directors has overall responsibility for the
establishment and oversight of the Group\u2019s risk management
framework, including review and approval of the Group\u2019s risk
management strategy, policy and key risk parameters. The Board
of Directors and the Audit and Risk Committee have oversight of
the Group\u2019s internal control system and risk management process,
including oversight of the internal audit function.
The Group\u2019s management of \ufb01nancial and capital risks is aimed
at ensuring that available capital, funding and cash \ufb02ows are
sufficient to:
\u2022 meet the Group\u2019s \ufb01nancial commitments as and when they fall
due;
\u2022 maintain the capacity to fund its committed project developments;
\u2022 pay a reasonable dividend; and
\u2022 maintain a long-term credit rating of not less than \u2018investment
grade\u2019.
The Group monitors and tests its forecast \ufb01nancial position against
these criteria and, in general, will undertake hedging activity when
necessary to ensure that these objectives are achieved.
Other circumstances that may lead to hedging include the
management of exposures relating to trading activities. It is, and
has been throughout the period, the Group Treasury policy that
no speculative trading in \ufb01nancial instruments shall be undertaken.
Refer to Section 3.8 Risk Factors for more information on the Group\u2019s
objectives, policies and processes for managing \ufb01nancial risk.
The below risks arise in the normal course of the Group\u2019s business.
Risk information can be found in the following sections:
Section A Commodity price risk management Page 109
Section A Foreign exchange risk management Page 109
Section C Capital risk management Page 132
Section C Liquidity risk management Page 132
Section C Interest rate risk management Page 132
Section D Credit risk management Page 136
Key estimates and judgements
In applying the Group\u2019s accounting policies, management
continually evaluates judgements, estimates and assumptions
based on experience and other factors, including expectations
of future events that may have an impact on the Group. All
judgements, estimates and assumptions made are believed to
be reasonable based on the most current set of circumstances
known to management, and actual results may differ. Signi\ufb01cant
judgements, estimates and assumptions made by management
in the preparation of these \ufb01nancial statements are found in the
following notes:
Note A.1 Revenue from contracts with customers Page 110
Note A.5 Taxes Page 115
Note B.2 Exploration and evaluation Page 120
Note B.3 Oil and gas properties Page 121
Note B.4 Impairment of exploration and evaluation,
oil and gas properties and goodwill
Page 123
Note B.5 Business combination Page 128
Note B.6 Signi\ufb01cant production and growth asset
acquisitions
Page 130
Note B.7 Disposal of assets Page 131
Note D.5 Provisions Page 138
Note D.6 Other \ufb01nancial assets and liabilities Page 140
Note D.7 Leases Page 143
Note E.6 Joint arrangements Page 149
109Woodside Energy Group Ltd |
In this section
This section addresses \ufb01nancial performance of the Group for the reporting period including, where applicable, the accounting policies
applied and the key estimates and judgements made. This section also includes the tax position of the Group for and at the end of the
reporting period.
A. Earnings for the year
A.1 Segment revenue and expenses Page 110
A.2 Finance costs Page 114
A.3 Dividends paid and proposed Page 114
A.4 Earnings/(losses) per share Page 114
A.5 Taxes Page 115
Key \ufb01nancial and capital risks in this section
Commodity price risk management
The Group\u2019s revenue is exposed to commodity price \ufb02uctuations through the sale of hydrocarbons. Commodity price risks are
measured by monitoring and stress testing the Group\u2019s forecast \ufb01nancial position to sustained periods of low oil and gas prices.
This analysis is regularly performed on the Group\u2019s portfolio and as required for discrete projects and transactions.
The Group\u2019s 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 protect the Group against downside price risk within its strategic and trading portfolio.
As at the reporting date, the Group held hedging \ufb01nancial instruments with a net liability carrying value of $557 million (2021:
$431 million) exposed to commodity price risk. An increase in relevant commodity prices of 10% would increase the instruments\u2019 net
liability by $219 million, the effect of which would be recognised within reserves and/or the income statement in accordance with
hedge accounting application. A 10% decrease would have the same but opposite effect. This analysis assumes that all other variables
remain constant (including the price on underlying physical exposures).
Foreign exchange risk management
Foreign exchange risk arises from future commitments, \ufb01nancial assets and \ufb01nancial liabilities that are not denominated in US dollars.
The majority of the Group\u2019s 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\u2019s 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).
As at the reporting date, the Group held hedging \ufb01nancial instruments with a net liability carrying value of $17 million (2021: net asset
carrying value of $10 million) exposed to foreign exchange risk.
Measuring the exposure to foreign exchange risk is achieved by regularly monitoring and performing sensitivity analysis on the
Group\u2019s \ufb01nancial position.
A reasonably possible change in the exchange rate of the US dollar to the Australian dollar (+12%/-12% (2021: +12%/-12%)), with all
other variables held constant, would not have a material impact on the Group\u2019s equity or the income statement. Refer to Notes C1,
C2, D2, D4 and D7 for details of the denominations of cash and cash equivalents, interest-bearing liabilities, receivables, payables and
lease liabilities held at 31 December 2022.
The Group entered into foreign exchange forward contracts to \ufb01x the Australian dollar to US dollar exchange rate in relation to
a portion of the Australian dollar denominated capital expenditure incurred or expected to be incurred under the Scarborough
development from 2022 to 2025 (refer to Note D.6). In order to hedge the foreign exchange risk and interest rate risk (refer to Section
C) of a Swiss Franc (CHF) denominated medium term note, Woodside holds a number of cross-currency interest rate swaps (refer to
Notes C.2 and D.6). The aim of these investments is to convert the \ufb01xed interest CHF bond into variable interest US dollar debt.
Notes to the \ufb01nancial statements A. Earnings for the year
for the year ended 31 December 2022
110 | Annual Report 2022
A.1 Segment revenue and expenses
Operating segment information
The Group has identi\ufb01ed its operating segments based on
the internal reports that are reviewed and used by the Chief
Executive Officer (Chief Operating Decision Maker) in assessing
performance and determining the allocation of resources.
As a result of the merger with BHPP on 1 June 2022, the Group
has transformed into a global energy company which has led to
a change in how \ufb01nancial information is reported in the Group.
The disclosed operating segments have been updated to re\ufb02ect
this change and the 2021 and 2020 amounts have been restated
to be presented on the same basis.
Operating segments outlined below are identi\ufb01ed by
management based on the nature and geographical location
of the business and venture.
Australia:
Exploration, evaluation, development, production and sale of
liqui\ufb01ed natural gas, pipeline gas, crude oil and condensate
and natural gas liquids in Australia.
International:
Exploration, evaluation, development, production and sale of
pipeline gas, crude oil and condensate and natural gas liquids
in international jurisdictions outside of Australia.
Marketing:
Marketing, Shipping and Trading of Woodside\u2019s oil and gas
portfolio (including non-produced volumes) and optimisation
activities attributed to Marketing which have generated
incremental value.
Corporate/Other items:
Corporate/Other items comprise primarily corporate non-
segmental items of revenue and expenses and associated
assets and liabilities not allocated to operating segments as
they are not considered part of the core operations of any
segment.
In addition to the updated segments, the Group has reassessed
the reporting of revenue from the sale of liqui\ufb01ed natural gas
on a portfolio basis. With the Marketing segment separately
reported for the year ended 31 December 2022, the Group will
no longer report revenue from the sale of liqui\ufb01ed natural gas on
a portfolio basis to better represent the revenues and margins
generated by each segment. 2021 and 2020 amounts have been
restated to be presented on the same basis.
Major customer information
The Group has two major customers which respectively account
for 12% and 9% of the Group\u2019s external revenue. The sales are
generated by the Australia and Marketing operating segments
(2021: two major customers; 8% and 6% generated by the
Australia operating segment and 2020: two major customers;
15% and 13% generated by the Australia operating segment).
Geographical
information
Revenue from external
customers
1
Non-current
assets
2
2022 2021 2020 2022 2021
US$m US$m US$m US$m US$m
Asia Paci\ufb01c 12,521 6,342 3,362 36,966 18,386
Americas 1,545 - - 7,057 1
Africa - - - 4,049 2,802
Europe 2,751 620 238 - -
Consolidated 16,817 6,962 3,600 48,072 21,189
1. Revenue is attributable to geographic location based on the location of the
customers.
2. Non-current assets exclude deferred tax of $1,959 million (2021:
$1,007 million).
Recognition and measurement
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 signi\ufb01cant reversal will
not occur.
\u2022 Revenue from sale of hydrocarbons \u2013 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.
\u2022 Other operating revenue \u2013 Revenue earned from LNG
processing and other services is recognised over time as
the services are rendered.
Expenses
\u2022 Royalties, excise and levies \u2013 Royalties, excise and levies are
considered to be production-based taxes and are therefore
accrued on the basis of the Group\u2019s entitlement to physical
production.
\u2022 Depreciation and amortisation \u2013 Refer to Note B.3.
\u2022 Impairment and impairment reversals \u2013 Refer to Note B.4.
\u2022 Leases \u2013 Refer to Note D.7.
\u2022 Employee bene\ufb01ts \u2013 Refer to Note E.2.
Key estimates and judgements
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
signi\ufb01cant 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.
Notes to the \ufb01nancial statements A. Earnings for the year
for the year ended 31 December 2022
111Woodside Energy Group Ltd |
A.1 Segment revenue and expenses (cont.)
Australia International Marketing
Corporate/
Other
Consolidated
2022 2022 2022 2022 2022
US$m US$m US$m US$m US$m
Lique\ufb01ed natural gas 8,855 - 2,434 - 11,289
Pipeline gas 1,086 276 - - 1,362
Crude oil and condensate 2,467 1,273 18 - 3,758
Natural gas liquids 171 26 9 - 206
Revenue from sale of hydrocarbons 12,579 1,575 2,461 - 16,615
Intersegment revenue1 (455) (5) 460 - -
Processing and services revenue 175 - - - 175
Shipping and other revenue - - 27 - 27
Other revenue (280) (5) 487 - 202
Operating revenue
2
12,299 1,570 2,948 - 16,817
Production costs (975) (313) - 7 (1,281 )
Royalties, excise and levies (540) (39) - (17) (596)
Insurance (35) (7) - (1) (43)
Inventory movement 44 (3) - - 41
Costs of production (1,506) (362) - (11) (1,879)
Land and buildings (51) (3) - - (54)
Transferred exploration and evaluation (107) - - - (107 )
Plant and equipment (2,168) (436) - (33) (2,637)
Oil and gas properties depreciation and amortisation (2,326) (439) - (33) (2,798 )
Shipping and direct sales costs (312) (36) (73) 142 (279 )
Trading costs (14) - (1,763) - (1,777 )
Other hydrocarbon costs (19) - - - (19)
Other cost of sales (4) - - - (4)
Movement in onerous contract provision3 - - 216 - 216
Other cost of sales (349) (36) (1,620) 142 (1,863)
Cost of sales (4,181) (837) (1,620) 98 (6,540)
Gross pro\ufb01t 8,118 733 1,328 98 10,277
Other income
4
722 4 5 4 735
Exploration and evaluation expenditure5 (20) (277) - 1 (296)
Amortisation of permit acquisition (1) (9) - - (10)
Write-offs6 - (164) - - (164)
Exploration and evaluation (21) (450) - 1 (470)
General, administrative and other costs7 (13) (21) (10) (747) (791)
Depreciation of other plant and equipment - - - - -
Depreciation of lease assets (49) (11) - (80) (140)
Restoration movement (234) (46) - 8 (272 )
Other8 (8) (84) (475) (486) (1,053)
Other costs (304) (162) (485) (1,305) (2,256)
Other expenses (325) (612) (485) (1,304) (2,726)
Impairment losses - - - - -
Impairment reversals
9
900 - - - 900
Pro\ufb01t/(loss) before tax and net \ufb01nance costs 9,415 125 848 (1,202) 9,186
1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio.
The value is incremental income net of incremental costs.
2. Operating revenue includes revenue from contracts with customers of $16,790 million and sub-lease income of $27 million disclosed within shipping and other revenue.
3. Comprises changes in estimates of $245 million offset by provisions used of $29 million. Refer to Note D.5 for further details.
4. Includes initial gain on Train 2 sell-down of $427 million, revaluation gain on the remeasurement of the Train 2 sell-down variable consideration of $71 million, fees and
recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business.
5. Includes $142 million for various costs relating to the Group\u2019s exit from the Orphan Basin exploration licences in Canada.
6. $125 million relates to costs of unsuccessful wells that have been written off. Refer to Note B.2.
7. Transaction costs of $419 million incurred as a result of the BHPP merger on 1 June 2022 are included in the Corporate/Other segment. Refer to Note B.5 for details.
8. Includes losses on hedging activities and changes in fair value of derivative \ufb01nancial instruments of $960 million in the Marketing and Corporate/Other segments and
other expenses not associated with the ongoing operations of the business.
9. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details.
Notes to the \ufb01nancial statements A. Earnings for the year
for the year ended 31 December 2022
112 | Annual Report 2022
A.1 Segment revenue and expenses (cont.)
Australia International Marketing
Corporate/
Other
Consolidated
20218 20218 20218 20218 2021
US$m US$m US$m US$m US$m
Lique\ufb01ed natural gas 3,910 - 1,449 - 5,359
Pipeline gas 43 - - - 43
Crude oil and condensate 1,316 - - - 1,316
Natural gas liquids 60 - - - 60
Revenue from sale of hydrocarbons 5,329 - 1,449 - 6,778
Intersegment revenue1 (236) - 236 - -
Processing and services revenue 143 - - - 143
Shipping and other revenue 4 - 37 - 41
Other revenue (89) - 273 - 184
Operating revenue
2
5,240 - 1,722 - 6,962
Production costs (489) - - 8 (481 )
Royalties, excise and levies (218) - - - (218 )
Insurance (32) - - 1 (31 )
Inventory movement 17 - - - 17
Costs of production (722) - - 9 (713 )
Land and buildings (51) - - - (51)
Transferred exploration and evaluation (79) - - - (79 )
Plant and equipment (1,419) - - - (1,419 )
Oil and gas properties depreciation and amortisation (1,549) - - - (1,549 )
Shipping and direct sales costs (197) - (45) 32 (210)
Trading costs (3) - (1,492) - (1,495 )
Other hydrocarbon costs (6) - - - (6)
Other cost of sales (11) - - (1) (12 )
Movement in onerous contract provision3 - - 140 - 140
Other cost of sales (217) - (1,397) 31 (1,583)
Cost of sales (2,488) - (1,397) 40 (3,845 )
Gross pro\ufb01t/(loss) 2,752 - 325 40 3,117
Other income
4
97 (2) 1 43 139
Exploration and evaluation expenditure (16) (27) - (11) (54 )
Amortisation of permit acquisition - (2) - (1) (3 )
Write-offs5 - (265) - - (265 )
Exploration and evaluation (16) (294) - (12) (322 )
General, administrative and other costs (5) (1) - (152) (158)
Depreciation of other plant and equipment - - - (30) (30 )
Depreciation of lease assets (28) - - (80) (108 )
Restoration movement (80) 12 - - (68 )
Other6 (57) (32) 28 (64) (125 )
Other costs (170) (21) 28 (326) (489 )
Other expenses (186) (315) 28 (338) (811)
Impairment losses (10) - - - (10)
Impairment reversals
7
1,058 - - - 1,058
Pro\ufb01t/(loss) before tax and net \ufb01nance costs 3,711 (317) 354 (255) 3,493
1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio.
The value is incremental income net of incremental costs.
2. Operating revenue includes revenue from contracts with customers of $6,923 million and sub-lease income of $39 million disclosed within shipping and other revenue.
3. Comprises provisions used of $45 million and changes in estimates of $95 million. Refer to Note D.5 for further details.
4. Includes other income of $67 million relating to Pluto volumes delivered into Wheatstone\u2019s sales commitments and net foreign exchange gains of $44 million.
5. $56 million relates to costs of unsuccessful wells. $209 million relates to capitalised costs written off due to the Group\u2019s decision to withdraw from its interests in
Myanmar. Refer to Note B.2.
6. Includes net loss on hedging activities of $91 million, various costs relating to Woodside\u2019s exit from the Kitimat LNG development of $33 million and other expenses not
associated with the ongoing operations of the business.
7. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details.
8. The 2021 amounts have been restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue.
Notes to the \ufb01nancial statements A. Earnings for the year
for the year ended 31 December 2022
113Woodside Energy Group Ltd |
A.1 Segment revenue and expenses (cont.)
Australia International Marketing
Corporate/
Other
Consolidated
20206 20206 20206 20206 2020
US$m US$m US$m US$m US$m
Lique\ufb01ed natural gas1 2,390 - 129 - 2,519
Pipeline gas 73 - - - 73
Crude oil and condensate 843 - - - 843
Natural gas liquids 16 - - - 16
Revenue from sale of hydrocarbons 3,322 - 129 - 3,451
Intersegment revenue2 (47) - 47 - -
Processing and services revenue 142 - - - 142
Shipping and other revenue 4 - 3 - 7
Other revenue 99 - 50 - 149
Operating revenue 3,421 - 179 - 3,600
Production costs (486) - - 8 (478)
Royalties, excise and levies (82) - - - (82)
Insurance (32) - - 1 (31)
Inventory movement (32) - - - (32)
Costs of production (632) - - 9 (623)
Land and buildings (55) - - - (55)
Transferred exploration and evaluation (99) - - - (99)
Plant and equipment (1,535) - - - (1,535)
Oil and gas properties depreciation and amortisation (1,689) - - - (1,689)
Shipping and direct sales costs (146) - (3) 38 (111)
Trading costs (4) - (207) - (211)
Other hydrocarbon costs (4) - - - (4)
Other cost of sales - - - - -
Movement in onerous contract provision3 - - (347) - (347)
Other cost of sales (154) - (557) 38 (673)
Cost of sales (2,475) - (557) 47 (2,985)
Gross pro\ufb01t/(loss) 946 - (378) 47 615
Other income
4
3 (1) 1 (39) (36)
Exploration and evaluation expenditure (26) (32) - (9) (67)
Amortisation of permit acquisition (6) (5) - (1) (12)
Write-offs - (2) - - (2)
Exploration and evaluation (32) (39) - (10) (81)
General, administrative and other costs (7) (14) - (169) (190)
Depreciation of other plant and equipment - - - (29) (29)
Depreciation of lease assets (26) - - (68) (94)
Restoration movement (65) 37 - - (28)
Other4 (8) - - (51) (59)
Other costs (106) 23 - (317) (400)
Other expenses (138) (16) - (327) (481)
Impairment losses
5
(3,971) (1,298) - - (5,269)
Impairment reversals - - - - -
Loss before tax and net \ufb01nance costs (3,160) (1,315) (377) (319) (5,171)
1. Includes an adjustment of $113 million related to price reviews under negotiation for multiple contracts in the Australia segment, reducing revenue recognised in the
current and prior periods and increasing other liabilities.
2. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio.
The value is incremental income net of incremental costs.
3. Comprised of the recognition of an onerous contract provision $447 million, offset by changes in estimates of $54 million, provisions used of $41 million and a revision of
discount rates of $5 million.
4. Includes foreign exchange gains and losses, gains and losses on hedging activities, cancellation costs and other expenses not associated with the ongoing operations of
the business.
5. The impairment losses represent charges on exploration and evaluation of $1,557 million and oil and gas properties of $3,712 million.
6. The 2020 amounts have been restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue.
Notes to the \ufb01nancial statements A. Earnings for the year
for the year ended 31 December 2022
114 | Annual Report 2022
A.2 Finance costs
2022 2021 2020
US$m US$m US$m
Interest on interest-bearing liabilities 212 201 237
Interest on lease liabilities 103 97 86
Accretion charge 110 29 32
Other \ufb01nance costs 36 26 29
Less: Finance costs capitalised
against qualifying assets (294) (123) (57)
167 230 327
A.3 Dividends paid and proposed
Woodside Energy Group Ltd, the parent entity, paid and
proposed dividends set out below:
2022 2021 2020
US$m US$m US$m
(a) Dividends paid during the \ufb01nancial
year
Prior year fully franked \ufb01nal
dividend1 1,018 115 518
Current year fully franked interim
dividend2 2,070 289 248
3,088 404 766
(b) Dividend declared subsequent to
the reporting period (not recorded as
a liability)
Final dividend3 2,734 1,018 115
(c) Other information
Franking credits available for
subsequent periods 1,406 1,744 1,823
Current year dividends per share (US
cents) 253 135 38
1. 2022: US$1.05, paid on 23 March 2022
2021: US$0.12, paid on 24 March 2021
2020: US$0.55, paid on 20 March 2020
2. 2022: US$1.09, paid on 6 October 2022
2021: US$0.30, paid on 24 September 2021
2020: US$0.26, paid on 18 September 2020
3. 2022: US$1.44, to be paid on 5 April 2023
2021: US$1.05, paid on 23 March 2022
2020: US$0.12, paid on 24 March 2021
The Dividend Reinvestment Plan (DRP) was approved by
the shareholders at the Annual General Meeting in 2003 for
activation as required to fund future growth. The DRP was
reactivated in 2019 and suspended by the Board of Directors
on 27 February 2023.
A.4 Earnings/(losses) per share
2022 2021 2020
Pro\ufb01t/(loss) attributable to
equity holders of the parent
(US$m) 6,498 1,983 (4,028)
Weighted average number
of shares on issue for basic
earnings/(loss) per share 1,511,257,404 962,604,811 951,113,086
Effect of dilution from
contingently issuable shares 13,061,376 9,023,439 -
Weighted average number of
shares on issue adjusted for
the effect of dilution1 1,524,318,780 971,628,250 951,113,086
Basic earnings/(losses) per
share (US cents) 430.0 206.0 (423.5)
Diluted earnings/(losses)
per share (US cents) 426.3 204.1 (423.5)
1. The contingently issuable shares in 2020 have an anti-dilutive impact.
Earnings/(losses) per share is calculated by dividing the pro\ufb01t/
(loss) for the year attributable to ordinary equity holders of the
parent by the weighted average number of ordinary shares on
issue during the year. The weighted average number of shares
makes allowance for shares reserved for employee share plans.
Diluted earnings/(losses) per share is calculated by adjusting
basic earnings/(losses) per share by the number of ordinary
shares that would be issued on conversion of all the dilutive
potential ordinary shares into ordinary shares. At 31 December
2022, 13,061,376 awards (2021: 9,023,439 awards) granted under
the Woodside employee share plans are considered dilutive.
Total outstanding share awards as at 31 December 2020 were
9,392,203 and considered anti-dilutive due to the loss position
in 2020.
There have been no signi\ufb01cant transactions involving ordinary
shares between the reporting date and the date of completion
of these \ufb01nancial statements.
Notes to the \ufb01nancial statements A. Earnings for the year
for the year ended 31 December 2022
115Woodside Energy Group Ltd |
2022 2021 2020
US$m US$m US$m
(a) Tax expense comprises
Petroleum resource rent tax (PRRT)
Current tax expense 501 - -
Deferred tax (bene\ufb01t)/expense (814) 297 (439)
PRRT (bene\ufb01t)/expense (313) 297 (439)
Income tax
Current year
Current tax expense 2,256 658 275
Deferred tax expense/(bene\ufb01t) 701 301 (1,308)
Adjustment to prior years
Current tax (bene\ufb01t)/expense (276) (20) 16
Deferred tax expense/(bene\ufb01t) 231 18 (9)
Income tax expense/(bene\ufb01t) 2,912 957 (1,026)
Tax expense/(bene\ufb01t) 2,599 1,254 (1,465)
(b) Reconciliation of income tax expense
Pro\ufb01t/(loss) before tax 9,174 3,290 (5,440)
PRRT bene\ufb01t/(expense) 313 (297) 439
Pro\ufb01t/(loss) before income tax 9,487 2,993 (5,001)
Income tax expense/(bene\ufb01t) calculated at 30% 2,847 898 (1,500)
Effect of tax rate differentials (141) (42) 192
Effect of deferred tax assets not recognised 150 114 270
Foreign exchange impact on tax (bene\ufb01t)/
expense (44) (18) 3
Adjustment to prior years (45) (2) 7
Integration and transaction costs non-
deductible 142 - -
Other 3 7 2
Income tax expense/(bene\ufb01t) 2,912 957 (1,026)
(c) Reconciliation of PRRT bene\ufb01t
Pro\ufb01t/(loss) before tax 9,174 3,290 (5,440)
Non-PRRT assessable (pro\ufb01t)/loss (6,197) (2,134) 3,080
PRRT projects pro\ufb01t/(loss) before tax 2,977 1,156 (2,360)
PRRT expense/(bene\ufb01t) calculated at 40% 1,191 462 (944)
(Recognition)/derecognition of Pluto general
expenditure1 (1,362) - 627
Augmentation (175) (166) (138)
Other 33 1 16
PRRT (bene\ufb01t)/expense (313) 297 (439)
(d) Deferred tax income statement
reconciliation
PRRT
Production and growth assets (710) 455 (242)
Augmentation for current year (175) (166) (138)
Provisions (12) (29) (32)
Other 83 37 (27)
PRRT (bene\ufb01t)/expense (814) 297 (439)
Income tax
Oil and gas properties 292 674 (981)
Exploration and evaluation assets 14 (204) (210)
Lease assets and liabilities 25 1 (16)
Provisions 151 (10) (106)
PRRT assets and liabilities 236 (88) 134
Unused tax losses and tax credits 19 149 (149)
Assets held for sale 205 (205) -
Derivatives 21 (11) 16
Other (31) 13 (5)
Income tax deferred tax expense/(bene\ufb01t) 932 319 (1,317)
Deferred tax expense/(bene\ufb01t) 118 616 (1,756)
(e) Deferred tax other comprehensive income
reconciliation
Income tax
Derivatives (64) 5 (25)
Other (2) 5 6
Deferred income tax (bene\ufb01t)/expense via
other comprehensive income (66) 10 (19)
A.5 Taxes
Notes to the \ufb01nancial statements A. Earnings for the year
for the year ended 31 December 2022
2022 2021 2020
% % %
(f) Effective income tax rate: Australian and
global operations
Effective income tax rate2
Australia 30.0% 30.6% 29.6%
Global 30.7% 32.0% 20.5%
1. The $1,362 million increase of the Pluto PRRT deferred tax asset is due to the
recognition of previously unrecognised deductible expenditure that is now
expected to be utilised to offset future taxable pro\ufb01ts.
2. The global operations effective income tax rate (ETR) is calculated as the
Group\u2019s income tax expense divided by pro\ufb01t before income tax. The Australian
operations ETR is calculated with reference to all Australian companies and
excludes foreign exchange on settlement and revaluation of income tax
liabilities.
2022 2021
US$m US$m
(g) Deferred tax balance sheet reconciliation
Deferred tax assets
PRRT
Production and growth assets 1,460 767
Augmentation for current year 113 166
Provisions 271 75
Other (23) (1)
PRRT deferred tax assets 1,821 1,007
Income tax3
Oil and gas properties (1,496) -
Exploration and evaluation assets 30 -
Lease assets and liabilities 23 -
Unused tax losses and tax credits 1,464 -
Derivatives 23 -
Provisions 60 -
Other 34 -
Income tax deferred tax assets 138 -
Deferred tax assets 1,959 1,007
Deferred tax liabilities
PRRT4
Production and growth assets 1,281 -
Augmentation for current year (62) -
Provisions (743) -
Other 137 -
PRRT deferred tax liabilities 613 -
Income tax
Oil and gas properties 2,857 1,520
Exploration and evaluation assets 67 51
Lease assets and liabilities (22) (38)
Provisions (1,280) (706)
PRRT assets and liabilities 347 303
Assets held for sale - (205)
Derivatives (36) (15)
Other (89) (32)
Income tax deferred tax liabilities 1,844 878
Deferred tax liabilities 2,457 878
3. The Group was in a net income tax deferred tax liability position in
2021.
4. The Group was in a net PRRT deferred tax asset position in 2021.
116 | Annual Report 2022
Key estimates and judgements
(a) Income tax classi\ufb01cation
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 the USA
Tax Consolidation Group (USA TCG) of $1,371 million (2021: nil) and
$93 million (2021: nil) arising from regions 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 within those regions. Refer to Note E.9(a) for
details of tax consolidated groups.
DTAs relating to carry forward unused tax losses and credits of
$250 million from the USA TCG, $146 million from USA entities
outside of the USA TCG and $1,061 million from regions other than
Australia and the USA have not been recognised as it is not currently
probable that the assets will be utilised based on current planned
activities in those regions (2021: $497 million unrecognised DTAs).
PRRT: The recoverability of PRRT deferred tax assets is primarily
assessed with regard to future oil price assumptions impacting
forecast future taxable pro\ufb01ts. As a result of higher actual and
forecast assessable revenues supporting future recoverability of
unrecognised quarantined exploration and general expenditure,
the Pluto PRRT DTA has increased by $1,362 million. In determining
the amount of DTA that is considered probable and eligible for
recognition, forecast future taxable pro\ufb01ts are risk-adjusted where
appropriate by a market premium risk rate to re\ufb02ect uncertainty
inherent in long-term forecasts. A long-term bond rate of 3.2%
(31 December 2021: 1.5%) 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 pro\ufb01ts. $6,523 million (2021:
$4,507 million) relates to the North West Shelf Project, $189 million
(2021: $1,432 million) relates to remaining Pluto quarantined
exploration expenditure and $831 million (2021: $1,071 million) relates
to Wheatstone. A long-term bond rate of 3.2% (31 December 2021:
1.5%) 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 bene\ufb01t 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 AASB 112/ 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 out\ufb02ows 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 re\ufb02ected as increases or decreases to tax expense
in the period in which new information is available.
A.5 Taxes (cont.)
Tax transparency code
Woodside participates in the Australian Board of Taxation\u2019s
voluntary Tax Transparency Code (TTC). To increase public
con\ufb01dence in the contributions and compliance of corporate
taxpayers, the TTC recommends public disclosure of tax
information. Part A of the recommended disclosures are
addressed within this Taxes note and Part B within our
Sustainable Development Report, supported by additional
information on our website.
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 substantially 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 \ufb01nancial 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 pro\ufb01t nor the taxable pro\ufb01t.
In relation to PRRT, the impact of future augmentation on
expenditure is included in the determination of future taxable
pro\ufb01ts when assessing the extent to which a deferred tax asset
can be recognised in the consolidated statement of \ufb01nancial
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.
Notes to the \ufb01nancial statements A. Earnings for the year
for the year ended 31 December 2022
117Woodside Energy Group Ltd |
In this section
This section addresses the strategic growth (exploration and evaluation), core producing and development (oil and gas properties)
assets position of the Group at the end of the reporting period including, where applicable, the accounting policies and key estimates
and judgements applied. This section also includes the impairment position of the Group at the end of the reporting period.
B. Production and growth assets
B.1 Segment production and growth assets Page 118
B.2 Exploration and evaluation Page 120
B.3 Oil and gas properties Page 121
B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill Page 123
B.5 Business combination Page 128
B.6 Signi\ufb01cant production and growth asset acquisitions Page 130
B.7 Disposal of assets Page 131
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
118 | Annual Report 2022
Refer to Note A.1 for descriptions of the Group\u2019s segments and geographical regions.
Australia International Marketing
Corporate/
Other Consolidated
2022 2022 2022 2022 2022
US$m US$m US$m US$m US$m
Balance as at 31 December
Asia Paci\ufb01c 529 - - - 529
Americas - 240 - - 240
Africa - 38 - - 38
Total exploration and evaluation 529 278 - - 807
Balance as at 31 December
Land and buildings 802 37 - 1 840
Transferred exploration and evaluation 481 - - - 481
Plant and equipment 18,249 4,647 - 161 23,057
Projects in development1 5,623 9,795 - 123 15,541
Total oil and gas properties 25,155 14,479 - 285 39,919
Balance as at 31 December
Land and buildings 93 107 - 264 464
Plant and equipment 214 131 - 455 800
Total lease assets 307 238 - 719 1,264
Additions to exploration and evaluation
2
:
Exploration 1 121 - - 122
Evaluation 19 100 - - 119
Restoration3 (1) - - - (1 )
19 221 - - 240
Additions to oil and gas properties
2
:
Oil and gas properties 2,252 1,560 - 92 3,904
Capitalised borrowings costs4 115 179 - - 294
Restoration3 (346) (28) - - (374)
2,021 1,711 - 92 3,824
Additions to lease assets
2
:
Land and buildings 4 - - - 4
Plant and equipment 139 90 - 9 238
143 90 - 9 242
1. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.
2. Additions exclude acquisitions through business combinations.
3. Relates to changes in restoration provision assumptions.
4. Borrowing costs capitalised were at a weighted average interest rate of 3.8%.
B.1 Segment production and growth assets
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
119Woodside Energy Group Ltd |
B.1 Segment production and growth assets (cont.)
Australia International Marketing
Corporate/
Other Consolidated
20212 20212 20212 20212 2021
US$m US$m US$m US$m US$m
Balance as at 31 December
Asia Paci\ufb01c 546 - - - 546
Americas - - - - -
Africa - 68 - - 68
Total exploration and evaluation 546 68 - - 614
Balance as at 31 December
Land and buildings 738 - - 1 739
Transferred exploration and evaluation 526 - - - 526
Plant and equipment 12,316 3 - 146 12,465
Projects in development 2,646 2,195 - 78 4,919
Total oil and gas properties 16,226 2,198 - 225 18,649
Balance as at 31 December
Land and buildings 76 11 1 289 377
Plant and equipment 133 176 - 394 703
Total lease assets 209 187 1 683 1,080
Additions to exploration and evaluation:
Exploration 1 41 - - 42
Evaluation 451 2 - - 453
Restoration 6 - - - 6
458 43 - - 501
Additions to oil and gas properties:
Oil and gas properties 1,071 1,051 - 57 2,179
Capitalised borrowings costs1 46 77 - - 123
Restoration 18 14 - - 32
1,135 1,142 - 57 2,334
Additions to lease assets:
Land and buildings - 14 - - 14
Plant and equipment - 214 - - 214
- 228 - - 228
1. Borrowing costs capitalised were at a weighted average interest rate of 3.6%.
2. The 2021 amounts have been restated to re\ufb02ect the changes in operating segments. Refer to \u2018Operating segment information\u2019 in Note A.1 for details. In addition, oil and
gas properties includes other plant and equipment which is no longer separately presented in the consolidated statement of \ufb01nancial position. The 2021 amounts have
been reclassi\ufb01ed to be presented on the same basis.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
120 | Annual Report 2022
B.2 Exploration and evaluation
Asia Paci\ufb01c Americas Africa Total
US$m US$m US$m US$m
Year ended 31 December 2022
Carrying amount at 1 January 2022 546 - 68 614
Acquisitions through business combination1 - 180 - 180
Additions 19 204 17 240
Disposals - (10) - (10)
Amortisation of licence acquisition costs - (8) (2) (10)
Expensed2 - (126) (45) (171)
Transferred exploration and evaluation (36) - - (36)
Carrying amount at 31 December 2022 529 240 38 807
Year ended 31 December 20213
Carrying amount at 1 January 2021 1,981 - 64 2,045
Additions 494 - 7 501
Amortisation of licence acquisition costs - - (3) (3)
Expensed2 (265) - - (265)
Transferred exploration and evaluation (1,664) - - (1,664)
Carrying amount at 31 December 2021 546 - 68 614
Exploration commitments
Year ended 31 December 2022 1 1 27 29
Year ended 31 December 20213 16 1 77 94
1. Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is
obtained within 12 months from the acquisition date. Refer to Note B.5 for details.
2. $125 million (2021: $56 million) relates to costs of unsuccessful wells. For the year ended 31 December 2021, $209 million relates to capitalised costs written off due to the
Group\u2019s decision to withdraw its interests in Myanmar.
3. Oceania and Asia have been presented within Asia Paci\ufb01c for the year ended 31 December 2022. The 2021 amounts have been reclassi\ufb01ed to be presented on the same
basis.
Recognition and measurement
Expenditure on exploration and evaluation is accounted for in
accordance with the area of interest method.
Areas of interest 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:
\u2022 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
\u2022 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 oil and gas properties.
In the consolidated statement of cash \ufb02ows, those cash
\ufb02ows associated with capitalised exploration and evaluation
expenditure, including unsuccessful wells, are classi\ufb01ed as cash
\ufb02ows used in investing activities.
Exploration commitments
The Group has exploration expenditure obligations which
are contracted for, but not provided for in the \ufb01nancial
statements. These obligations may be varied from time to time
and are expected to be ful\ufb01lled in the normal course of the
Group\u2019s operations.
Impairment
Refer to Note B.4 for details on impairment, including any
write-offs.
Key estimates and judgements
(a) Area of interest
Typically, an area of interest (AOI) is de\ufb01ned 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.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
121Woodside Energy Group Ltd |
Land and
buildings
Transferred
exploration and
evaluation
Plant and
equipment
Projects in
development Total
US$m US$m US$m US$m US$m
Year ended 31 December 2022
Carrying amount at 1 January 2022 739 526 12,465 4,919 18,649
Acquisitions through business combinations1 64 - 11,952 7,337 19,353
Additions2 - - (508) 4,332 3,824
Disposals at written down value (3) (10) (32) - (45)
Depreciation and amortisation (54) (107) (2,637) - (2,798)
Impairment reversal3 87 30 783 - 900
Completions and transfers 7 42 1,034 (1,047) 36
Carrying amount at 31 December 2022 840 481 23,057 15,541 39,919
At 31 December 2022
Historical cost 1,765 1,538 45,273 15,937 64,513
Accumulated depreciation and impairment (925) (1,057) (22,216) (396) (24,594)
Net carrying amount 840 481 23,057 15,541 39,919
Year ended 31 December 20214
Carrying amount at 1 January 2021 749 431 12,091 2,195 15,466
Additions - - 13 2,321 2,334
Disposals at written down value (2) - (6) (22) (30)
Depreciation and amortisation (51) (79) (1,449) - (1,579)
Impairment losses3 (10) - - - (10)
Impairment reversal3 44 66 911 37 1,058
Completions and transfers 11 108 905 640 1,664
Transfer to assets held for sale5 (2) - - (252) (254)
Carrying amount at 31 December 2021 739 526 12,465 4,919 18,649
At 31 December 20214
Historical cost 1,701 1,495 32,796 5,321 41,313
Accumulated depreciation and impairment (962) (969) (20,331) (402) (22,664)
Net carrying amount 739 526 12,465 4,919 18,649
1. Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is
obtained within 12 months from the acquisition date. Refer to Note B.5 for details. Projects in development include the fair value ascribed to future phases of certain
projects acquired through business combinations.
2. Includes $3,904 million of capital additions and $294 million of capitalised borrowing costs offset by $374 million following changes in restoration provision assumptions.
3. Refer to Note B.4 for details on impairment losses and impairment reversals.
4. Oil and gas properties includes other plant and equipment which is no longer separately presented in the consolidated statement of \ufb01nancial position. The 2021 amounts
have been reclassi\ufb01ed to be presented on the same basis.
5. Refer to Note B.7 for details on assets held for sale.
B.3 Oil and gas properties
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
122 | Annual Report 2022
Key estimates and judgements
(a) Reserves
The estimation of reserves requires signi\ufb01cant 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\u2019s oil and gas
properties. Judgement is used in determining the economic reserve
base applied to each asset. Typically, late life oil assets use proved
reserves.
Estimates are reviewed at least annually or when there are changes
in the economic circumstances impacting speci\ufb01c assets or asset
groups. These changes may impact depreciation, asset carrying
values, restoration provisions and deferred tax balances. If proved
plus probable (2P) reserves estimates are revised downwards,
earnings could be affected by higher depreciation expense or an
immediate write-down of the asset\u2019s carrying value.
(b) Depreciation and amortisation
Judgement is required to determine when assets are available for
use to commence depreciation and amortisation. Depreciation and
amortisation generally commences on \ufb01rst production.
B.3 Oil and gas properties (cont.)
Recognition and measurement
Oil and gas properties are stated at cost less accumulated
depreciation and impairment charges. Oil and gas properties
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.
Subsequent capital costs, including major maintenance, are
included in the asset\u2019s carrying amount only when it is probable
that future economic bene\ufb01ts associated with the item will \ufb02ow
to the Group and the cost of the item can be reliably measured.
Depreciation and amortisation
Oil and gas properties are depreciated to their estimated
residual values at rates based on their expected useful lives.
Transferred exploration and evaluation and offshore plant and
equipment are depreciated using the unit of production basis
over proved plus probable reserves or proved reserves for late
life assets. The depreciable amount for the unit of production
basis excludes future development costs necessary to bring
probable reserves into production. For certain offshore assets,
methodologies using proved and probable reserves are adjusted
to best re\ufb02ect the expected pattern of consumption. Onshore
plant and equipment is 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 oil and gas properties are depreciated
using the straight-line method over their useful life. They are
depreciated as follows:
\u2022 Buildings \u2013 24-50 years;
\u2022 Plant and equipment \u2013 2-40 years; and
\u2022 Land is not depreciated.
Impairment
Refer to Note B.4 for details on impairment.
Capital commitments
The Group has capital expenditure commitments contracted
for, but not provided for in the \ufb01nancial statements, of
$7,762 million as at 31 December 2022 (2021: $7,875 million).
Capital expenditure commitments relate predominantly to the
Scarborough and Sangomar projects.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
123Woodside Energy Group Ltd |
B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill
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 oil and gas properties.
Impairment calculations
The recoverable amounts of exploration and evaluation assets
are determined using FVLCD, as there is no value in use (VIU).
Costs to dispose are the incremental costs directly attributable
to the disposal of an asset, excluding \ufb01nance costs and income
tax expense.
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.
For assets previously impaired, if the recoverable amount
exceeds the carrying amount, the impairment is reversed, but
only to the extent that the asset\u2019s carrying amount does not
exceed the carrying amount that would have been recognised
if no impairment had occurred.
Oil and gas properties
Impairment testing
The carrying amounts of oil and gas properties 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, expected
future sales prices or costs.
Oil and gas properties 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 \ufb01elds.
If there is an indicator of impairment or impairment reversal
for a CGU, its recoverable amount is calculated and compared
with the CGU\u2019s 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\u2019s cash-generating units (CGUs) that are
expected to bene\ufb01t 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 oil and gas impairment calculations
The recoverable amount of an asset or CGU is determined as the
higher of its VIU and FVLCD.
VIU is determined by estimating future cash \ufb02ows after taking
into account the risks speci\ufb01c 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
re\ufb02ect the effects of factors that may be speci\ufb01c to the Group. In
determining FVLCD, recent market transactions are considered.
If no such transactions can be identi\ufb01ed, an appropriate
valuation model, such as discounted cash \ufb02ow techniques,
are 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 \ufb01rst 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 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
or amortisation, if no impairment had been recognised.
Impairments of goodwill are not reversed.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
124 | Annual Report 2022
B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.)
For the year ended 31 December 2022
Goodwill allocation
The Group performed its annual goodwill impairment test as at 31 December 2022.
The carrying amount of goodwill allocated to each CGU, or groups of CGUs and excess recoverable amounts are as follows:
Segment CGU Goodwill carrying amount1
Excess of recoverable amount over CGU
carrying amount2
US$m US$m
Australia Pluto-Scarborough 2,955 7,656
Australia NWS Gas 394 1,399
International Shenzi 469 401
International Atlantis 513 189
International Other goodwill 283 107
Total 4,614
1. Carrying amount of goodwill as at 31 December 2021 was nil.
2. Amounts are with reference to the total CGU value including goodwill.
Other goodwill of $283 million (2021: nil) has been allocated across a number of CGUs within the International segment.
This represents less than one percent of net assets as at 31 December 2022.
Recognised impairment and impairment reversals
As at 31 December 2022, the Group assessed each AOI and CGU to determine whether an indicator of impairment or impairment
reversal existed. The Group identi\ufb01ed the following indicators of impairment reversals:
\u2022 Wheatstone CGU \u2013 revision in short- and long-term LNG price assumptions and updated cost and production pro\ufb01les.
For CGUs where goodwill has been allocated, no impairment was recognised as the recoverable amount exceeds the carrying amount
of the CGU.
An impairment reversal was recognised for Wheatstone (refer to Note A.1), with results as follows:
Impairment reversal
Oil and gas properties
Recoverable amount Land and buildings
Transferred
exploration and
evaluation Plant and equipment Total
Segment CGU US$m US$m US$m US$m US$m
Australia Wheatstone 3,456 87 30 783 900
Recoverable amounts have been determined using the FVLCD method using discounted cash \ufb02ow projections, classi\ufb01ed as Level 3 on
the fair value hierarchy. The carrying amount of each CGU includes all assets allocated to the respective CGU. Refer to key estimates
and judgements for further details.
Sensitivity analysis
Recoverable amount valuations are sensitive to changes in certain key accounting estimates and judgements (refer to key estimates
and judgements for further details). Reasonable possible changes to these key assumptions are set out below:
\u2022 Post tax discount rate \u2013 plus or minus 1.5% (representing a change of 150 basis points)
\u2022 Commodity pricing \u2013 plus or minus 10%
\u2022 Foreign exchange (FX) rate \u2013 plus or minus 12%
\u2022 Production volumes \u2013 plus or minus 4%
Management\u2019s analysis on the impact of reasonable possible changes to these assumptions on recoverable amounts is detailed below.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
125Woodside Energy Group Ltd |
B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.)
For the year ended 31 December 2022 (cont.)
Sensitivity analysis (cont.)
CGUs with impairment or impairment reversals
Changes in the following key assumptions have been estimated to result in a higher or lower carrying amount1 than what was
determined as at 31 December 2022:
Sensitivity (US$m)2
CGU
Discount rate
increase\u00b3
Discount rate
decrease\u00b3
Brent price
increase
Brent price
decrease FX increase FX increase
Production
increase\u2074
Production
decrease\u2074
Wheatstone (117) 127 294 (294) (79) 79 116 (43)
1. Increases to carrying amounts are limited to historical impairment losses recognised, net of depreciation and amortisation, that would have been recognised had no
impairment taken place.
2. The sensitivities represent the reasonable possible changes to discount rate, oil price, FX and production volumes assumptions.
3. The relationship between the discount rate and the carrying amount is non-linear and as such, sensitivities are unlikely to result in a symmetrical impact. Due to the non-
linear relationship, the impact of changing the discount rate is likely to be greater at a lower discount rate than at a higher discount rate.
4. The relationship between production and the carrying amount is non-linear due to the proportion of \ufb01xed costs. Sensitivities are therefore unlikely to result in a
symmetrical impact. A signi\ufb01cant change in production volumes would typically require a reassessment of the asset concept and should not be interpreted in isolation.
A change in any of the above assumptions would likely have an impact on other assumptions which, when considered together, may
offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions.
CGUs with goodwill
The valuation of CGUs with goodwill are most sensitive to changes in commodity prices and discount rates. Reasonably possible
changes in these estimates which could result in the estimated recoverable amount being equal to the carrying amount, assuming all
other variables are held constant, are as follows:
CGU
Commodity price1 Nominal discount rate
% change (absolute terms)
Oil and gas properties Pluto-Scarborough N/A\u00b2 N/A\u00b2
Oil and gas properties NWS Gas N/A\u00b2 N/A\u00b2
Oil and gas properties Shenzi (7%) N/A \u00b2
Oil and gas properties Atlantis (2%) 10%
1. Brent price applies to Pluto-Scarborough and NWS Gas. WTI price (Brent - $3/bbl) applies to Shenzi and Atlantis.
2. Management considers there to be no reasonably possible change in the respective estimate which, in isolation, would result in the estimated recoverable amount being
equal to the carrying amount.
A change in any of the above assumptions would have an impact on other assumptions which when considered together may offset.
This does not incorporate decisions management may take in order to mitigate the change in assumptions. Management considers
there to be no reasonably possible changes in production volumes, carbon prices or foreign exchange rates that would, in isolation
result in the estimated recoverable amount being equal to the carrying amount. Analysis of key assumptions which could result in
the carrying value to equal the recoverable value provides a basis to assess the magnitude of a reasonable possible change to the
carrying amounts of respective CGUs.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
Key estimates and judgements
CGU determination
Identi\ufb01cation of a CGU requires management judgement. In
determining CGUs for acquired assets during the reporting period,
management has assessed based on the smallest group of assets that
generate signi\ufb01cant cash in\ufb02ows that are independent from other
assets or groups of assets.
Allocation of goodwill
Allocation of goodwill to the relevant CGUs requires management
judgement. The goodwill arising from the merger has been allocated
to relevant CGUs which are expected to bene\ufb01t from the expected
synergies as a result of the merger.
Recoverable amount calculation key assumptions
In determining the recoverable amount of CGUs, estimates are made
regarding the present value of future cash \ufb02ows when determining the
FVLCD. These estimates require signi\ufb01cant 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 \ufb02ow estimates.
The basis for each estimate used to determine recoverable amounts as
at 31 December 2022 is set out below:
\u2022 Resource estimates \u2013 2P and a portion of 2C reserves (where
applicable) for oil and gas properties. The reserves are as disclosed
in the Reserves and Resources Statement in the 31 December 2022
Annual Report.
\u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied for US
based assets and 2.5% for Australian based assets.
\u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on
management\u2019s view of long-term exchange rates.
126 | Annual Report 2022
For the year ended 31 December 2021
Recognised impairment and impairment reversals
As at 31 December 2021, the Group identi\ufb01ed the following indicators for impairment and impairment reversals:
\u2022 Pluto-Scarborough and Wheatstone CGU \u2013 a reduction of 2P total reserves within the Greater Pluto and Wheatstone reserves and
resources estimates.
\u2022 Pluto-Scarborough CGU \u2013 additional value generated by Scarborough and Pluto Train 2, which have been combined with Pluto into
a new Pluto-Scarborough CGU following the \ufb01nal investment decision for Scarborough and Pluto Train 2 in November 2021.
\u2022 North West Shelf CGU \u2013 updated cost and production pro\ufb01les, including the impact of third-party processing agreements, and
short-term pricing assumptions.
\u2022 NWS Oil (Okha) CGU \u2013 the reclassi\ufb01cation to a late life oil asset due to natural reservoir decline and short-term pricing assumptions.
No impairment was recognised for Wheatstone and NWS Oil (Okha) as the recoverable amount exceeds the carrying amount
of the CGU.
Impairment reversals were recognised for Pluto-Scarborough and NWS Gas (refer to Note A.1). The results were as follows:
Impairment reversal
Oil and gas properties
Recoverable
amount
Land and
buildings
Transferred
exploration and
evaluation
Plant and
equipment
Projects in
development Total
Segment CGU US$m US$m US$m US$m US$m US$m
Producing and
Development Pluto-Scarborough 17,474 42 53 563 24 682
Producing North West Shelf 2,425 2 13 348 13 376
Total 19,899 44 66 911 37 1,058
The recoverable amounts were determined using the VIU method. The carrying amounts of the CGUs include all assets allocated to
the CGU. Refer to key estimates and judgements for further details.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
Key estimates and judgements (cont.)
Recoverable amount calculation key assumptions (cont.)
\u2022 Discount rates \u2013 a range of post-tax discount rates between 8%
and 11.5% for CGUs has been applied. The discount rate re\ufb02ects an
assessment of the risks speci\ufb01c to the asset.
\u2022 Carbon pricing \u2013 a long-term price of US$80/tonne of emissions
(real terms 2022) is based on management\u2019s assumptions on
carbon cost pricing and incorporates an evaluation of climate risk.
This is applicable to Australian emissions that exceed facility-
speci\ufb01c baselines in accordance with Australian regulations, as well
as global emissions that exceed voluntary corporate net emissions
targets. Woodside continues to monitor the uncertainty around
climate change risks and will revise carbon pricing assumptions
accordingly. Refer to Climate change and energy transition section
within the basis of preparation for further information.
\u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil
price marker; accordingly the LNG prices used are consistent with
oil price assumptions.
\u2022 Brent oil prices \u2013 derived from long-term views of global supply
and demand, building upon past experience of the industry and
consistent with external sources. Prices are adjusted for premiums
and discounts based on the nature and quality of the product. Brent
oil price estimates have considered the risk of climate policies along
with other factors such as industry investment and cost trends.
There is signi\ufb01cant uncertainty around how society will respond
to the climate challenge; Woodside\u2019s pricing assumptions re\ufb02ect
a \u2018best estimate\u2019 scenario in which global governments pursue
decarbonisation as well as other goals such as energy security
and economic development. As with carbon pricing, Woodside
continues to monitor this uncertainty and will revise its oil pricing
assumptions accordingly in its transition to a lower carbon
economy. Further information on climate change risk is provided
in the Climate change and energy transition section within the basis
of preparation. The nominal Brent oil prices (US$/bbl) used were:
2023 2024 2025 2026 2027 2028
31 December 20221 87 78 74 76 77 79
31 December 20212 71 68 69 70 72 73
1. Long-term oil prices are based on US$70/bbl (2022 real terms) from
2025 and prices are escalated at 2.0% onwards.
2. Long-term oil prices are based on US$65/bbl (2022 real terms) from
2024 and prices are escalated at 2.0% onwards.
B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.)
For the year ended 31 December 2022 (cont.)
127Woodside Energy Group Ltd |
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.)
For the year ended 31 December 2021 (cont.)
Sensitivity analysis
Changes in the following key assumptions were estimated to result in a higher or lower carrying amounts1 than what was
determined as at 31 December 2021:
Sensitivity (US$m)2
Discount rate:
increase of 1%
3,4
Discount rate:
decrease of 1%
Brent price:
increase of 10%
Brent price:
decrease of 10%
FX:
increase of 12%5
FX:
decrease of 12%
Oil and gas
properties
Producing and
Development
Pluto-
Scarborough - - - - - -
Producing North West Shelf - - - (13) - -
Wheatstone (159) 178 438 (438) (122) 122
NWS Oil (Okha) (4) 4 39 (39) (28) 28
1. Increases to carrying amounts are limited to historical impairment losses recognised, net of depreciation and amortisation that would have been incurred had no
impairment taken place.
2. The sensitivities represent reasonable possible changes to the discount rate, oil price and FX assumptions.
3. A change of 1% represents 100 basis points.
4. The relationship between the discount rate and carrying amount is non-linear and as such, the sensitivities are unlikely to result in a symmetrical impact. Due to the
non-linear relationship, the impact of changing the discount rate is likely to be greater at a lower discount rate than at a higher discount rate.
5. FX sensitivity of +12%/-12% was determined based on historical 5-year standard deviation of AU$/US$.
Impairment on non-current assets held for sale
The sale of a portion of the Wheatstone Construction Village resulted in an impairment loss of $10 million as the asset\u2019s carrying value
exceeded its FVLCD, which was determined based on the underlying sale agreements, classi\ufb01ed as Level 3 on the fair value hierarchy.
For the year ended 31 December 2021, an impairment loss of $10 million was recognised in the Australia operating segment of
Note A.1.
Key estimates and judgements
CGU determination
Identi\ufb01cation of a CGU requires management judgement. For the
year ended 31 December 2021, management has determined that the
Scarborough and Pluto Train 2 development concept integrates with
the existing Pluto onshore assets and is the smallest group of assets
that generate signi\ufb01cant cash in\ufb02ows that are independent from other
assets or group of assets.
Recoverable amount calculation key assumptions
In determining the recoverable amount of CGUs, estimates are made
regarding the present value of future cash \ufb02ows when determining
the VIU. These estimates require signi\ufb01cant 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 \ufb02ow estimates.
The basis for each estimate used to determine recoverable amounts
as at 31 December 2021 is set out below:
\u2022 Resource estimates \u2013 2P reserves for oil and gas properties, except
for NWS Oil (Okha) which is based on 1P reserves due to the
reclassi\ufb01cation to a late life asset. The reserves are as disclosed in
the Reserves and resources statement in the 31 December 2021
Annual Report on pages 55-59.
\u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied.
\u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on
management\u2019s view of long-term exchange rates.
\u2022 Discount rates \u2013 a range of pre-tax discount rates between 8.9%
and 11.6% (post-tax discount rate 7.5%-8.5%) for CGUs has been
applied. The discount rate re\ufb02ects an assessment of the risks
speci\ufb01c to the asset.
\u2022 An evaluation of climate risk is re\ufb02ected in Woodside's assumptions
on carbon cost pricing, including a long-term Australian carbon
price of US$80/tonne of emissions (real terms 2022). This is
applicable to Australian emissions that exceed facility-speci\ufb01c
baselines in accordance with Australian regulations, as well as
global emissions that exceed voluntary corporate net emissions
targets. Woodside continues to monitor the uncertainty around
climate change risks and will revise carbon pricing assumptions
accordingly.
\u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil
price marker; accordingly the LNG prices used are consistent with
oil price assumptions.
\u2022 Brent oil prices \u2013 derived from long-term views of global supply
and demand, building upon past experience of the industry and
consistent with external sources. Prices are adjusted for premiums
and discounts based on the nature and quality of the product.
Brent oil price estimates have considered the risk of climate policies
along with other factors such as industry investment and cost
trends. There is signi\ufb01cant uncertainty around how society will
respond to the climate challenge; Woodside\u2019s pricing assumptions
re\ufb02ect a \u2018most-likely\u2019 scenario in which global governments pursue
decarbonisation as well as other goals such as energy security
and economic development. As with carbon pricing, Woodside
continues to monitor this uncertainty and will revise its oil pricing
assumptions accordingly in its transition to a lower carbon
economy. Further information on climate change risk is provided
in Woodside\u2019s Climate Report 2021. The nominal Brent oil prices
(US$/bbl) used were:
2022 2023 2024 2025 2026 2027
31 December 20211 73 71 68 69 70 72
30 June 20202 57 62 67 72 73 75
1. Based on US$65/bbl (2022 real terms) from 2024 with prices escalated
at 2.0% annually thereafter.
2. Based on US$65/bbl (2020 real terms) from 2025 with prices escalated
at 2.0% annually thereafter.
128 | Annual Report 2022
B.5 Business combination
BHP Petroleum merger
On 17 August 2021, Woodside and BHP Group (BHP) entered
into a merger commitment deed to combine their respective
oil and gas portfolios by an all-stock merger. The Share Sale
Agreement (SSA) and the integration and transition services
agreement were executed on 22 November 2021. Under the
SSA, the merger took economic effect from 1 July 2021 and
Woodside became entitled to the economic bene\ufb01ts and risks
of the assets and liabilities that were the subject of the merger
from that date.
On 19 May 2022, 98.66% of Woodside shareholders voted in
favour of the merger at Woodside\u2019s Annual General Meeting.
On 1 June 2022, the transaction was completed with the Group
acquiring 100% of the issued share capital of BHP Petroleum
International Pty Ltd (subsequently renamed Woodside Energy
Global Holdings Pty Ltd), which held BHP\u2019s oil and gas business.
In exchange, the Group issued 914,768,948 new Woodside
shares to BHP as part of the merger consideration. The
transaction has been accounted for as a business combination
with an acquisition date of 1 June 2022. The Group\u2019s net pro\ufb01t
after tax for the year ended 31 December 2022 incorporates
BHPP results from acquisition date. The merger is expected to
create opportunities to realise ongoing synergies.
Due to the size, complexity and timing of the transaction, the
assets acquired and liabilities assumed are measured on a
provisional basis. As at 31 December 2022, the Allocable Cost
Amount (ACA) tax valuation process has been substantially
completed with potential adjustments if new information is
obtained within 12 months from the acquisition date about
facts and circumstances that existed at the acquisition
date. Adjustments will be made to the provisional amounts
recognised including the value of goodwill.
The merged Group\u2019s \ufb01nancial results could be adversely affected
by impairments of goodwill or other intangible assets, the
application of future accounting policies or interpretations of
existing accounting policies including by regulatory direction,
and changes in estimates of decommissioning costs. Details
and risks have been included in the Merger Explanatory
Memorandum released on 8 April 2022.
Given the purchase consideration was agreed on 22 November
2021 based on a \ufb01xed number of shares, the \ufb01nal value of
consideration paid was subject to \ufb02uctuations in share price
until completion on 1 June 2022. This has resulted in a material
goodwill number which will be subject to impairment in future,
for example should commodity prices decrease.
Details of the purchase consideration and the provisional fair
value of goodwill, identi\ufb01able assets and liabilities of BHPP
acquired are as follows:
Provisional fair value of net identi\ufb01able assets and goodwill
arising on acquisition date US$m
Cash and cash equivalents 399
Receivables 1,164
Inventories 295
Investments accounted for using the equity method 267
Other \ufb01nancial assets 59
Other assets 114
Exploration and evaluation assets 180
Oil and gas properties 19,353
Lease assets 142
Payables (910)
Provisions (4,804)
Tax payable (365)
Deferred tax liabilities (576)
Lease liabilities (268)
Other liabilities (1,054)
Net identi\ufb01able assets acquired 13,996
Goodwill arising on acquisition 4,614
Purchase consideration 18,610
Purchase consideration US$m
Shares issued, at fair value 19,265
Other reserves (share replacement awards) 18
Provisional locked box payment received1 (683)
Adjustments to locked box payment 10
Total purchase consideration 18,610
1. Represents the positive net cash \ufb02ow of $1,513 million generated by BHPP assets
from the effective date of the business combination offset by the notional
dividend distribution of $830 million paid to BHP.
Analysis of cash \ufb02ows on acquisition US$m
Cash acquired on acquisition 399
Provisional locked box payment received 683
Net cash \ufb02ow on acquisition (included in the consolidated
statement of cash \ufb02ows as investing activities) 1,082
Acquisition-related costs of $419 million that were not directly
attributable to the issue of shares are included as an expense
in general, administration and other costs in the consolidated
income statement. $357 million has been paid and included in
the consolidated statement of cash \ufb02ows as operating activities.
Acquisition-related costs of $5 million directly attributable to the
issue of shares are included in contributed equity and included in
the consolidated statement of cash \ufb02ows as \ufb01nancing activities.
Shares issued, at fair value
The fair value of 914,768,948 shares issued as part of the
consideration paid to BHP was $19,265 million. This was based
on the published share price on 1 June 2022 of US$21.06
per share.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
129Woodside Energy Group Ltd |
B.5 Business comination (cont.)
Provisional locked box payment received
The Group received $683 million as part of the merger
consideration which includes the locked box payment of
$1,513 million representing the positive net cash \ufb02ow generated
by BHPP assets from the effective date of the transaction to
completion date offset by the notional dividend distribution
of $830 million paid to BHP.
The $683 million of provisional locked box payment received
and the $399 million of cash and cash equivalents acquired as
part of the merger have been included within investing activities
in the consolidated statement of cash \ufb02ows.
Revenue and contribution to the Group
The acquired business contributed operating revenue of
$4,653 million and pro\ufb01t before tax of $2,042 million to the
Group from the acquisition date to 31 December 2022. If the
acquisition had occurred on 1 January 2022, consolidated
operating revenue and pro\ufb01t before tax would have been higher
by $3,115 million and $1,265 million respectively.
Acquired receivables
The fair value of receivables approximates the gross amount of
trade receivables. None of the receivables have been impaired
and the full contractual amounts are expected to be collected.
Other liabilities
The Group recognised contingent liabilities of $79 million within
other liabilities. This is based on the Group\u2019s assessment of the
fair value of contingent liabilities acquired on acquisition, taking
into account a range of possible outcomes.
As at 31 December 2022, there have been no changes to the
amount recognised on acquisition date.
Goodwill
Goodwill arising from the acquisition has been recognised as
the excess of consideration paid above the fair value of the
assets acquired and liabilities assumed as part of the business
combination. $1,958 million of the goodwill arises from the
deferred tax liability recognised on acquisition as a consequence
of asset tax bases received in the merger being lower than
the fair value of the assets acquired. The remaining goodwill
of $2,656 million re\ufb02ects the value expected to be generated
from the Pluto-Scarborough CGU as a result of the merger. The
goodwill is not deductible for tax purposes.
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\u2019s CGUs or groups of CGUs no larger than
an operating segment that are expected to bene\ufb01t 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.
Share replacement awards
In accordance with the terms of the SSA, the Group exchanged
equity-settled share-based payment awards held by employees
of BHPP for equity-settled share-based payment awards of
Woodside. The replacement awards are based on service
conditions with a vesting date of 31 August 2023 and 31 August
2024. The fair value of the replacement awards on acquisition
is $49 million based on a forfeiture rate of 3%. $18 million
has been included as part of the purchase consideration and
the remaining amount will be recognised as post-acquisition
compensation cost.
Business combination accounting
The acquisition method of accounting is used to account for
all business combinations, including business combinations
involving entities or businesses under common control,
regardless of whether equity instruments are issued or liabilities
incurred or assumed at the date of exchange. Where equity
instruments are issued in an acquisition, the fair value of the
instruments is their published market price as at the date of
exchange.
Transaction costs arising on the issue of equity instruments
are recognised directly in equity. Transaction costs that were
not directly attributable to the issue of shares are expensed as
incurred.
Contractual assets and liabilities in respect of sales agreements
are recognised at fair value.
Restoration provisions are recognised on acquisition at fair value.
Key estimates and judgements
(a) 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 \ufb02ow model to estimate the expected future
cash \ufb02ows of the oil and gas assets acquired, based on reserves
and resources at acquisition date and the discount rate used.
The expected future cash \ufb02ows are based on estimates of future
production, commodity and carbon prices, operating costs, and
forecast capital expenditures at acquisition date.
Restoration provisions require judgemental assumptions regarding
removal date, environmental legislation and regulations and the
extent of restoration activities required in determining the cost
estimate.
Carry forward tax losses are recognised only if it is probable that
sufficient future taxable income will be available to utilise the losses.
(b) Goodwill allocation
Judgement is required in the allocation of goodwill to the Group\u2019s
CGUs that are expected to bene\ufb01t from the synergies of the
business combination. Refer to Note B.4 for the details of the
goodwill allocation.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
130 | Annual Report 2022
B.6 Signi\ufb01cant production and growth asset acquisitions
(a) Sangomar \u2013 Acquisition from FAR Senegal
RSSD SA
On 7 July 2021, Woodside completed the acquisition of FAR
Senegal RSSD SA\u2019s interest in the RSSD Joint Venture (13.67%
interest in the Sangomar exploitation area and 15% interest in
the remaining RSSD evaluation area), for an aggregate purchase
price of $212 million. The transaction was accounted for as an
asset acquisition.
Additional payments of up to $55 million are contingent on
future commodity prices and timing of \ufb01rst oil. The contingent
payments terminate on the earliest of 31 December 2027, three
years from \ufb01rst oil being sold, and a total contingent payment
of $55 million being reached. The contingent payments are
accounted for as contingent liabilities in accordance with the
Group\u2019s accounting policies.
As at 31 December 2021, Woodside held an 82% interest in the
Sangomar exploitation area (2020: 68.33%) and a 90% interest
in the remaining RSSD evaluation area (2020: 75%).
Assets acquired and liabilities assumed
The identi\ufb01able assets and liabilities acquired as at the date of
the acquisition inclusive of transaction costs are:
US$m
Oil and gas properties 205
Exploration and evaluation 7
Cash acquired 3
Payables (13)
Net other assets and liabilities assumed 10
Total identi\ufb01able net assets at acquisition 212
Cash \ufb02ows on acquisition
US$m
Purchase cash consideration 212
Transaction costs -
Total purchase consideration 212
Net cash out\ufb02ows on acquisition 212
Key estimates and judgements
Nature of acquisition
Judgement was required to determine if the transaction was the
acquisition of an asset or a business combination. The Sangomar
project was in the early phase of development and a substantive
process that had the ability to convert inputs to outputs was not
present and therefore the acquisition in 2021 was treated as asset
acquisitions.
(b) Sangomar \u2013 Acquisition from Capricorn
Senegal Limited
On 22 December 2020, Woodside completed the acquisition of
Capricorn Senegal Limited\u2019s (Cairn\u2019s) interest in the RSSD Joint
Venture (36.44% interest in the Sangomar exploitation area
and 40% interest in the remaining RSSD evaluation area) for an
aggregate purchase price of $527 million. The transaction was
accounted for as an asset acquisition.
Additional payments of up to $100 million are contingent on
future commodity prices and the occurrence of \ufb01rst oil prior to
2025. The contingent payments are accounted for as contingent
liabilities in accordance with the Group\u2019s accounting policies.
Assets acquired and liabilities assumed
The identi\ufb01able assets and liabilities acquired as at the date of
the acquisition inclusive of transaction costs were:
US$m
Oil and gas properties 540
Exploration and evaluation 26
Cash acquired 5
Payables (51)
Net other assets and liabilities assumed 7
Total identi\ufb01able net assets at acquisition 527
Cash \ufb02ows on acquisition
US$m
Purchase cash consideration 525
Transaction costs 2
Total purchase consideration 527
Net cash out\ufb02ows on acquisition 527
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
131Woodside Energy Group Ltd |
B.7 Disposal of assets
Sell-down of Train 2
On 15 November 2021 the Group entered into a sale and
purchase agreement with Global Infrastructure Partners (GIP)
for the sale of a 49% non-operating participating interest in the
Pluto Train 2 Joint Venture.
As at 31 December 2021, the Group reclassi\ufb01ed the carrying
value of the 49% interest in the Pluto Train 2 assets to assets
held for sale. There were no recognised liabilities associated
with the assets held for sale.
The transaction completed on 18 January 2022, reducing the
Group\u2019s participating interest from 100% to 51%. The Group
recognised an initial pre-tax gain on sale of $427 million.
The arrangements require GIP to fund its 49% share of capital
expenditure from 1 October 2021 and an additional amount of
construction capital expenditure of $822 million on behalf of
the Group. If the total capital expenditure incurred is less than
$5,800 million, GIP will pay Woodside an additional amount
equal to 49% of the under-spend. In the event of a cost overrun,
Woodside will fund up to $822 million of GIP\u2019s share of the
overrun. Delays to the expected start-up of production will result
in payments by Woodside to GIP in certain circumstances. The
arrangements include provisions for GIP to be compensated for
exposure to additional Scope 1 emissions liabilities above agreed
baselines, and to sell its 49% interest back to Woodside if the
status of key regulatory approvals materially changes.
Given judgement was used to determine the consideration
received, the Group is required to remeasure the variable
consideration at each reporting period. As at 31 December
2022, the variable consideration has been remeasured with a
$71 million revaluation gain recognised as other income, with a
corresponding reduction to other liabilities. The fair value of the
remaining unpaid funding from GIP has been netted against the
other liabilities and will be recognised as oil and gas properties in
the future.
Key estimates and judgements
Sell-down of Train 2
Given the arrangements include provisions for GIP to sell its
49% interest back to Woodside if the status of key regulatory
environmental approvals materially changes and the requirement
for Woodside to fund up to $822 million of GIP\u2019s share in the event
of a cost overrun, judgement is required to determine if the sell-
down of Train 2 constitutes a sale and if a portion of the transaction
price should be considered a variable consideration.
Judgement was used to determine that the sell-down of
Train 2 constituted a sale given the various conditions included in
the sale and purchase agreement. The Group determined that a
sale occurred as control of the 49% interest was passed to GIP on
completion date. Control is determined as the ability to direct the
use of, and obtain substantially all of the economic bene\ufb01ts of, the
associated interest.
Judgement was used to determine if it is highly probable that a
signi\ufb01cant reversal will not occur in relation to the consideration
received. The Group estimated the variable consideration based on
the construction capital expenditure cost pro\ufb01le, the development
schedule, and assessing the probability and impact of any event
which may result in a signi\ufb01cant reversal. The constraining
estimates of variable consideration have been applied resulting
in the initial pre-tax gain on sale of $427 million.
The variable consideration is remeasured at each reporting period
with any changes recognised through the consolidated income
statement. As at 31 December 2022, the variable consideration has
been remeasured with a $71 million revaluation gain recognised as
other income.
Notes to the \ufb01nancial statements B. Production and growth assets
for the year ended 31 December 2022
132 | Annual Report 2022
Notes to the \ufb01nancial statements C. Debt and capital
for the year ended 31 December 2022
In this section
This section addresses cash, debt and the capital position of the Group at the end of the reporting period including, where applicable,
the accounting policies applied and the key estimates and judgements made.
C. Debt and capital
C.1 Cash and cash equivalents Page 133
C.2 Interest-bearing liabilities and \ufb01nancing facilities Page 133
C.3 Contributed equity Page 135
C.4 Other reserves Page 135
Key \ufb01nancial and capital risks in this section
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 \ufb02exible supply of funds is available to meet the Group\u2019s operating and capital expenditure
requirements. A stable capital base is maintained from which the Group can pursue its growth aspirations, whilst maintaining a \ufb02exible
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 \ufb01nancial metrics are monitored, including gearing and cash \ufb02ow leverage, and Treasury policy breaches and exceptions.
Liquidity risk management
Liquidity risk arises from the \ufb01nancial liabilities of the Group and the Group\u2019s subsequent ability to meet its obligations to repay
\ufb01nancial 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 \ufb01nancial commitments in a timely and cost-effective manner.
The Group\u2019s liquidity is continually reviewed, including cash \ufb02ow forecasts to determine the forecast liquidity position and maintain
appropriate liquidity levels. At 31 December 2022, the Group had a total of $10,239 million (2021: $6,125 million) of available undrawn
facilities and cash at its disposal. The maturity pro\ufb01le 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.
Interest rate risk management
Interest rate risk is the risk that the Group\u2019s \ufb01nancial position will \ufb02uctuate due to changes in market interest rates.
The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to \ufb01nancial instruments with \ufb02oating 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 \ufb01xed and \ufb02oating rate debt. To manage the ratio of \ufb01xed rate debt to \ufb02oating rate debt, the Group may enter into
interest rate swaps. The Group holds cross-currency interest rate swaps to hedge the foreign exchange risk (refer to Section A) and
interest rate risk of the CHF denominated medium term note. The Group also 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 \ufb02ow hedges,
primarily through $6,143 million (2021: $2,962 million) on cash and cash equivalents, $83 million (2021: $367 million) on interest-
bearing liabilities (excluding transaction costs), $167 million of other \ufb01nancial assets (2021: nil) and $5 million (2021: $9 million) on
cross-currency interest rate swaps.
A reasonably possible change in the USD London Interbank Offered Rate (USD LIBOR) (+1.5%/-1.5% (2021: +1.0%/-1.0%)), with all
variables held constant, would not have a material impact on the Group\u2019s equity or the income statement in the current period.
The transition of a number of the Group\u2019s \ufb01nancial liabilities from USD LIBOR to SOFR during the year ended 31 December 2022
did not result in a material impact to the Group. The Group\u2019s Treasury function continues to execute the transition of the remaining
\ufb01nancial instruments from current benchmark rates to alternative benchmark rates.
133Woodside Energy Group Ltd |
C.1 Cash and cash equivalents
2022 2021
US$m US$m
Cash and cash equivalents
Cash at bank 1,222 300
Term deposits 4,967 2,725
Restricted cash 12 -
Total cash and cash equivalents 6,201 3,025
Recognition and measurement
Cash and cash equivalents in the consolidated statement of
\ufb01nancial 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 \ufb01nancial position. Cash and cash equivalents
include $12 million (2021: nil) restricted by legal or contractual
arrangements.
Foreign exchange risk
The following table summarises the Group's cash and cash
equivalents by currency.
2022 2021
US$m US$m
US dollar 5,886 2,917
Australian dollar 182 63
Other 133 45
Total cash and cash equivalents 6,201 3,025
C.2 Interest-bearing liabilities and \ufb01nancing facilities
Bilateral
Facilities
Syndicated
Facilities JBIC Facility US Bonds
Medium Term
Notes Total
US$m US$m US$m US$m US$m US$m
Year ended 31 December 2022
At 1 January 2022 (4) 595 166 4,081 592 5,430
Repayments1 - - (83) - (200) (283)
Fair value adjustment and foreign exchange movement - - - - (7) (7 )
Transaction costs capitalised and amortised (1) (4) - 3 - (2 )
Carrying amount at 31 December 2022 (5) 591 83 4,084 385 5,138
Current (2) (3) 83 (3) 185 260
Non-current (3) 594 - 4,087 200 4,878
Carrying amount at 31 December 2022 (5) 591 83 4,084 385 5,138
Undrawn balance at 31 December 2022 2,050 2,000 - - - 4,050
Year ended 31 December 2021
At 1 January 2021 (4) 593 250 4,778 597 6,214
Repayments1 - - (84) (700) - (784 )
Fair value adjustment and foreign exchange movement - - - - (5) (5 )
Capitalised borrowing costs - 2 - 3 - 5
Carrying amount at 31 December 2021 (4) 595 166 4,081 592 5,430
Current (2) (2) 83 (2) 200 277
Non-current (2) 597 83 4,083 392 5,153
Carrying amount at 31 December 2021 (4) 595 166 4,081 592 5,430
Undrawn balance at 31 December 2021 1,900 1,200 - - - 3,100
1. Included in cash \ufb02ows classi\ufb01ed within \ufb01nancing activities in the consolidated statement of cash \ufb02ows.
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. The changes in
the fair value risks of the hedged item resulted in a gain of
$7 million being recorded (2021: gain of $5 million), and a loss
of $7 million recorded on the hedging instrument (2021: loss of
$7 million).
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.
Notes to the \ufb01nancial statements C. Debt and capital
for the year ended 31 December 2022
134 | Annual Report 2022
C.2 Interest-bearing liabilities and \ufb01nancing facilities (cont.)
Fair value
The carrying amount of interest-bearing liabilities approximates
their fair value, with the exception of the Group\u2019s unsecured
bonds and the medium term notes. The unsecured bonds have
a carrying amount of $4,084 million (2021: $4,081 million) and a
fair value of $3,852 million (2021: $4,443 million). The medium
term notes have a carrying amount of $385 million (2021:
$592 million) and a fair value of $372 million (2021:
$604 million). Fair value is calculated based on the present value
of future principal and interest cash \ufb02ows, discounted at the
market rate of interest at the reporting date and classi\ufb01ed as
Level 1 on the fair value hierarchy. Where these cash \ufb02ows are in
a foreign currency, the present value is converted to US dollars
at the foreign exchange spot rate prevailing at the reporting
date. The Group\u2019s repayment obligations remain unchanged.
Foreign exchange risk
All interest-bearing liabilities are denominated in US dollars,
excluding the CHF175 million medium term note.
Maturity pro\ufb01le of interest-bearing liabilities
The table below presents the contractual undiscounted
cash \ufb02ows associated with the Group\u2019s interest-bearing
liabilities, representing principal and interest. The \ufb01gures will
not necessarily reconcile with the amounts disclosed in the
consolidated statement of \ufb01nancial position.
2022 2021
US$m US$m
Due for payment in:
1 year or less 483 470
1-2 years 206 462
2-3 years 1,181 188
3-4 years 962 1,169
4-5 years 908 951
More than 5 years 2,416 3,320
6,156 6,560
Amounts exclude transaction costs.
Bilateral facilities
The Group has 14 bilateral loan facilities totalling $2,050 million
(2021: 14 bilateral loan facilities totalling $1,900 million). Details
of bilateral loan facilities at the reporting date are as follows:
Number of
facilities Term (years) Currency Extension option
1 5 - 6 US$ Evergreen
5 4 - 5 US$ Evergreen
4 3 - 4 US$ Evergreen
4 3 years or less US$ Evergreen
Interest rates are based on USD LIBOR or Secured Overnight
Financing Rate (SOFR) and margins are \ufb01xed at the
commencement of the drawdown period. Interest is paid at
the end of the drawdown period. Evergreen facilities may be
extended continually by a year subject to the bank\u2019s agreement.
Syndicated facility
During the period, Woodside re\ufb01nanced and increased the
existing facilities to $2,000 million, with $800 million expiring
on 11 October 2024, $600 million expiring on 12 July 2025 and
$600 million expiring on 12 July 2027. Interest rates are based
on SOFR and margins are \ufb01xed at the commencement of the
drawdown period.
On 17 January 2020, the Group completed a $600 million
syndicated facility with a term of seven years. Interest is based
on the USD LIBOR plus 1.2%. Interest is paid on a quarterly basis.
Japan Bank for International Cooperation (JBIC)
facility
On 24 June 2008, the Group entered into a two tranche
committed loan facility of $1,000 million and $500 million
respectively. The $500 million tranche was repaid in 2013. There
is a prepayment option for the remaining balance. Interest rates
are based on USD LIBOR. Interest is payable semi-annually in
arrears and the principal amortises on a straight-line basis, with
equal instalments of principal due on each interest payment date
(every six months).
Under this facility, 90% of the receivables from designated Pluto
LNG sale and purchase agreements are secured in favour of
the lenders through a trust structure, with a required reserve
amount of $30 million.
To the extent that this reserve amount remains fully funded
and no default notice or acceleration notice has been given, the
revenue from Pluto LNG continues to \ufb02ow directly to the Group
from the trust account.
Medium term notes
On 28 August 2015, the Group established a $3,000 million
Global Medium Term Notes Programme listed on the Singapore
Stock Exchange. Two notes have been issued under this
programme as set out below:
Maturity date Currency
Carrying amount
(million)
Nominal interest
rate
11 December 2023 CHF 185 1.00%
29 January 2027 US$ 200 3.07%
The unutilised program is not considered to be an unused facility.
US bonds
The Group has four unsecured bonds issued in the United States
of America as de\ufb01ned in Rule 144A of the US Securities Act of
1933 as set out below:
Maturity date
Carrying amount
US$m
Nominal interest
rate
5 March 2025 1,000 3.65%
15 September 2026 800 3.70%
15 March 2028 800 3.70%
4 March 2029 1,500 4.50%
Interest on the bonds is payable semi-annually in arrears.
During the period, the Group repaid $200 million of the Yucho
2022 Medium Term Note and $83 million on the JBIC facility.
Notes to the \ufb01nancial statements C. Debt and capital
for the year ended 31 December 2022
135Woodside Energy Group Ltd | C.3 Contributed equity Recognition and measurement Issued capital Ordinary shares are classi\ufb01ed as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds. Reserved shares Reserved shares are the Group\u2019s own equity instruments, which are reacquired for later use in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). These shares are deducted from equity. No gain or loss is recognised in the income statement on the purchase, sale, issue or cancellation of the Group\u2019s own equity instruments. (a) Issued and fully paid shares Number of shares US$m Year ended 31 December 2022 Opening balance 969,631,826 9,409 DRP \u2013 ordinary shares issued at US$23.14 (2021 \ufb01nal dividend)1 14,348,997 332 Ordinary shares issued at US$21.06 for the acquisition of BHPP2 914,768,948 19,265 Transaction costs associated to the issue of shares - (5) Amounts as at 31 December 2022 1,898,749,771 29,001 Year ended 31 December 2021 Opening balance 962,225,814 9,297 DRP \u2013 ordinary shares issued at US$19.03 (2020 \ufb01nal dividend) 1,354,072 26 DRP \u2013 ordinary shares issued at US$14.21 (2021 interim dividend) 6,051,940 86 Amounts as at 31 December 2021 969,631,826 9,409 Year ended 31 December 2020 Opening balance 942,286,900 9,010 DRP \u2013 ordinary shares issued at A$25.61 (2019 \ufb01nal dividend) 12,072,034 181 DRP \u2013 ordinary shares issued at A$18.79 (2020 interim dividend) 6,091,035 83 Employee share plan \u2013 ordinary shares issued at A$18.27 (2017 Woodside equity plan) 1,775,845 23 Amounts as at 31 December 2020 962,225,814 9,297 1. Relates to ordinary shares issued for the DRP as part of the 2021 \ufb01nal dividend. The Group purchased on-market shares for the issuance of DRP as part of the 2022 interim dividend. Refer to Note C.3(b) for details of the on-market purchases and allocation. 2. 914,768,948 new Woodside shares were issued as consideration for the BHPP merger. Refer to Note B.5 for details. All shares are a single class with equal rights to dividends, capital, distributions and voting. The Company does not have authorised capital nor par value in relation to its issued shares. (b) Reserved shares Employee share plans Dividend reinvestment plan Number of shares US$m Number of shares US$m Year ended 31 December 2022 Opening balance 1,819,744 (30) - - Purchases during the year 2,232,589 (45) 6,823,092 (144) Vested/allocated during the year (2,178,556) 37 (6,823,092) 144 Amounts at 31 December 2022 1,873,777 (38) - - Year ended 31 December 2021 Opening balance 1,766,099 (23) - - Purchases during the year 2,683,469 (47) - - Vested during the year (2,629,824) 40 - - Amounts at 31 December 2021 1,819,744 (30) - - Year ended 31 December 2020 Opening balance 1,985,306 (39) - - Purchases during the year 2,242,345 (32) - - Vested during the year (2,461,552) 48 - - Amounts at 31 December 2020 1,766,099 (23) - - C.4 Other reserves 2022 2021 2020 US$m US$m US$m Other reserves Employee bene\ufb01ts reserve 278 232 219 Foreign currency translation reserve 796 793 793 Hedging reserve1 (586) (400) (71) Distributable pro\ufb01ts reserve2 3,541 58 462 Other reserves 2 - - 4,031 683 1,403 1. The portion of the hedging reserve relating to settled hedges is $226 million. 2. For the year ended 31 December 2022, the Group transferred $5,553 million of retained earnings to the distributable pro\ufb01ts reserve. The increase was offset by the 2022 interim dividend of $2,070 million which was paid on 6 October 2022. Nature and purpose Employee bene\ufb01ts 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 \ufb01nancial statements of foreign entities from their functional currency to the Group\u2019s presentation currency. Hedging reserve Used to record gains and losses on hedges designated as cash \ufb02ow hedges, and foreign currency basis spread arising from the designation of a \ufb01nancial instrument as a hedging instrument. Gains and losses accumulated in the cash \ufb02ow hedge reserve for qualifying assets are capitalised against the carrying amount of that asset and taken to the income statement as the asset is depreciated. Distributable pro\ufb01ts reserve Used to record distributable pro\ufb01ts generated by the Parent entity, Woodside Energy Group Ltd. Other reserves Used to record gains and losses on \ufb01nancial instruments at fair value through other comprehensive income. Notes to the \ufb01nancial statements C. Debt and capital for the year ended 31 December 2022 136 | Annual Report 2022
In this section
This section addresses the other assets and liabilities position at the end of the reporting period including, where applicable, the
accounting policies applied and the key estimates and judgements made.
D. Other assets and liabilities
D.1 Segment assets and liabilities Page 137
D.2 Receivables Page 137
D.3 Inventories Page 137
D.4 Payables Page 138
D.5 Provisions Page 138
D.6 Other \ufb01nancial assets and liabilities Page 140
D.7 Leases Page 143
Key \ufb01nancial and capital risks in this section
Credit risk management
Credit risk is the risk that a counterparty will not meet its obligation under a \ufb01nancial instrument or customer contract, leading to a
\ufb01nancial loss to the Group. Credit risk arises from the \ufb01nancial assets of the Group, which comprise trade and other receivables, loans
receivables and deposits with banks and \ufb01nancial institutions.
The Group manages its credit risk on trade receivables and \ufb01nancial instruments by predominantly dealing with counterparties
with an investment grade credit rating. Sufficient collateral is obtained to mitigate the risk of \ufb01nancial loss when transacting with
counterparties with below investment grade credit ratings. Customers who wish to trade on unsecured credit terms are subject to
credit veri\ufb01cation procedures. Receivable balances are monitored on an ongoing basis. As a result, the Group\u2019s exposure to bad debts
is not signi\ufb01cant. The Group\u2019s maximum credit risk is limited to the carrying amount of its \ufb01nancial assets.
Customer credit risk is managed by the Treasury function subject to the Group\u2019s established policy, procedures and controls relating
to customer credit risk management. Credit quality of a customer is assessed based on an extensive credit rating scorecard and
individual credit limits are de\ufb01ned in accordance with this assessment. Outstanding customer receivables are regularly monitored.
At 31 December 2022, the Group had nineteen customers (2021: four customers) that owed the Group more than $10 million each and
accounted for approximately 79% (2021: 88%) of all trade receivables. Depending on the product, settlement terms are 8 to 30 days
from the date of invoice or bill of lading unless otherwise stated in the agreed payment terms.
The Group considers the probability of default upon initial recognition of the asset and whether there has been a signi\ufb01cant
depreciation in credit quality on an ongoing basis. A signi\ufb01cant decrease in credit quality is de\ufb01ned 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 simpli\ufb01ed approach and are measured at an amount equal to lifetime expected loss. Under the
simpli\ufb01ed 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 \ufb01nancial assets is
considered to be when the counterparty fails to make contractual payments within 60 days of when they fall due.
At 31 December 2022, the Group had a provision for credit losses of nil (2021: nil). Subsequent to 31 December 2022, 99% (2021: 100%)
of the trade receivables balance of $1,067 million (2021: $152 million) has been received.
Credit risk from balances with banks is managed by the Treasury function in accordance with the Group\u2019s policy. The Group\u2019s
main funds are placed as short-term deposits with reputable \ufb01nancial institutions with strong investment grade credit ratings. At
31 December 2022 and 31 December 2021, there were no signi\ufb01cant concentrations of credit risk within the Group and \ufb01nancial
instruments are spread amongst a number of \ufb01nancial institutions to minimise the risk of counterparty default. The maximum
exposure to \ufb01nancial institution credit risk is represented by the sum of all cash deposits plus accrued interest, bank account balances
and fair value of derivative assets. The Group\u2019s counterparty credit policy limits this exposure to commercial and investment banks,
according to approved credit limits based on the counterparty\u2019s credit rating.
Notes to the \ufb01nancial statements D. Other assets and liabilities
for the year ended 31 December 2022
137Woodside Energy Group Ltd |
D.1 Segment assets and liabilities
2022 20212
US$m US$m
(a) Segment assets
1
Australia 31,240 18,163
International 18,084 2,877
Marketing 182 217
Corporate/Other 9,815 5,217
59,321 26,474
2022 20212
US$m US$m
(b) Segment liabilities
1
Australia 8,104 2,889
International 2,677 435
Marketing 561 639
Corporate/Other 10,852 8,282
22,194 12,245
1. Acquisitions through business combination have been recognised on a
provisional basis. Adjustments will be made to the provisional amounts if new
information is obtained within 12 months from the acquisition date. Refer to
Note B.5 for details.
2. The 2021 amounts have been restated to re\ufb02ect the changes in operating
segments. Refer to \u2018Operating segment information\u2019 in Note A.1 for details.
Refer to Note A.1 for descriptions of the Group\u2019s segments.
Corporate/other assets mainly comprise cash and cash
equivalents, deferred tax assets and lease assets. Corporate/
other liabilities mainly comprise interest-bearing liabilities,
deferred tax liabilities and lease liabilities.
D.2 Receivables
2022 2021
US$m US$m
(a) Receivables (current)
Trade receivables1 1,067 152
Other receivables1 381 123
Loans receivable 76 75
Lease receivables 35 18
Interest receivable 19 -
1,578 368
(b) Receivables (non-current)
Other receivables 75 -
Loans receivable 724 627
Lease receivables 46 26
De\ufb01ned bene\ufb01t plan asset - 33
845 686
1. Interest-free and settlement terms are usually between 14 and 30 days.
Recognition and measurement
Trade receivables are initially recognised at the transaction price
determined under AASB 15/ IFRS 15 Revenue from Contracts with
Customers. Other receivables are initially recognised at fair value.
Receivables that satisfy the contractual cash \ufb02ow 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 \ufb02ow and business model tests are subsequently measured
at fair value (refer to Note D.6).
The Group\u2019s customers are required to pay in accordance with
agreed payment terms. Depending on the product, settlement
terms are 14 to 30 days from the date of invoice or bill of lading
and customers regularly pay on time. There are no signi\ufb01cant
overdue trade receivables as at the end of the reporting period
(2021: nil).
Fair value
The carrying amount of trade and other receivables
approximates their fair value.
Foreign exchange risk
The Group held $174 million of receivables at 31 December
2022 (2021: $121 million) in currencies other than US dollars
(predominantly Australian dollars).
Loans receivable
On 9 January 2020, Woodside Energy Finance (UK) Ltd entered
into a secured loan agreement with Petrosen (the Senegal
National Oil Company), to provide up to $450 million for the
purpose of funding Sangomar project costs. The facility has a
maximum term of 12 years and semi-annual repayments of the
loan are due to commence at the earlier of 12 months after RFSU
or 30 June 2025. The carrying amount of the loan receivable is
$408 million at 31 December 2022 (2021: $335 million), which
approximates its fair value. The remaining balance of loans
receivable is due from non-controlling interests.
D.3 Inventories
2022 2021
US$m US$m
(a) Inventories (current)
Petroleum products
Goods in transit 95 35
Finished stocks 103 34
Warehouse stores and materials 480 133
678 202
(b) Inventories (non-current)
Warehouse stores and materials 11 19
11 19
Recognition and measurement
Inventories include hydrocarbon stocks, consumable supplies
and maintenance spares. Inventories are valued at the lower of
cost and net realisable value. Cost is determined on a weighted
average basis and includes direct costs and an appropriate
portion of \ufb01xed and variable production overheads where
applicable. Inventories determined to be obsolete or damaged
are written down to net realisable value, being the estimated
selling price less selling costs.
Notes to the \ufb01nancial statements D. Other assets and liabilities
for the year ended 31 December 2022
138 | Annual Report 2022
D.4 Payables
The following table shows the Group\u2019s payables balances.
2022 2021
US$m US$m
Trade payables1 759 191
Other payables1 1,270 390
Interest payable2 65 58
Total payables 2,094 639
1. Interest-free and normally settled on 30 day terms.
2. Details regarding interest-bearing liabilities are contained in Note C.2.
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.
Foreign exchange risk
The Group held $657 million of payables at 31 December 2022
(2021: $311 million) in currencies other than US dollars
(predominantly Australian dollars).
Maturity pro\ufb01le of payables
The Group\u2019s payables balances at 31 December 2022 and 31
December 2021 are due for payment within a year.
D.5 Provisions
Restoration
1
Employee bene\ufb01ts
Onerous
contracts
2
Other Total
US$m US$m US$m US$m US$m
Year ended 31 December 2022
At 1 January 2022 2,218 286 214 106 2,824
Acquisitions through business combination3 4,310 329 - 165 4,804
Change in provision (382) (98) (216) 137 (559)
Unwinding of present value discount 107 - 2 1 110
Carrying amount at 31 December 2022 6,253 517 - 409 7,179
Current 575 331 - 313 1,219
Non-current 5,678 186 - 96 5,960
Net carrying amount 6,253 517 - 409 7,179
Year ended 31 December 2021
At 1 January 2021 2,134 295 349 129 2,907
Change in provision 60 (9) (140) (23) (112)
Unwinding of present value discount 24 - 5 - 29
Carrying amount at 31 December 2021 2,218 286 214 106 2,824
Current 235 269 - 101 605
Non-current 1,983 17 214 5 2,219
Net carrying amount 2,218 286 214 106 2,824
1. 2022 change in provision is due to a revision of discount rates of $978 million (primarily due to an increase in risk free rates) and provisions used of $262 million, offset by
changes in estimates of $858 million. Changes in estimates are due to new activities, increase in scope of removal and cost and rate escalations supported by the most
recent estimates and benchmarks.
2. 2022 change in provision is due to changes in estimates of $245 million offset by provisions used of $29 million.
3. Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is
obtained within 12 months from the acquisition date. Refer to Note B.5 for 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 out\ufb02ow of resources embodying economic
bene\ufb01ts will be required to settle the obligation and a reliable
estimate can be made of the amount of the obligation.
Restoration
The restoration provision is \ufb01rst 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 oil
and gas properties 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 \ufb01nance costs.
The carrying amount capitalised in oil and gas properties 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
bene\ufb01t, are expensed.
Notes to the \ufb01nancial statements D. Other assets and liabilities
for the year ended 31 December 2022
139Woodside Energy Group Ltd |
Key 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. In many instances,
decommissioning of assets occurs many years into the future.
The Group\u2019s 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. The Group maintains technical expertise to ensure that industry
learnings, scienti\ufb01c research and local and international guidelines are
reviewed in assessing its restoration obligations.
The restoration obligation requires judgemental assumptions regarding
removal date, environmental legislation and regulations, the extent
of restoration activities required, the engineering methodology for
estimating cost, technologies used in determining the decommissioning
cost, and liability-speci\ufb01c discount rates to determine the present value
of these cash \ufb02ows.
The Group applies either the \u2018expected outcome\u2019 approach or \u2018expected
value\u2019 approach in assessing the cost estimate, re\ufb02ecting a difference in
approach to cost estimation for heritage Woodside and heritage BHPP
assets. Both approaches are supported by AASB 137/ IAS 37 Provisions,
Contingent Liabilities and Contingent Assets, produce reliable estimates
and are widely used in practice. Heritage Woodside assets refer to
assets held by the Group prior to the BHPP merger. Heritage BHPP
assets refers to assets acquired from BHP but excludes the commonly
held assets by both heritage entities.
Expected outcome approach
This approach is used for heritage Woodside assets, and those
assets commonly held by both heritage entities. The following cost
assumptions are applied:
\u2022 for onshore assets, provision has been made for the removal of
production facilities and above ground pipelines using current
restoration standards and techniques and taking into account risks
and uncertainties; and
\u2022 for offshore assets, provision has been made for the plug and
abandonment of wells and the removal of offshore platform topsides,
\ufb02oating production storage offloading (FPSO) and some subsea
infrastructure. It is currently the Group\u2019s assumption that in some
regulatory jurisdictions and environments, certain pipelines and
infrastructure, parts of offshore platform substructures, and certain
subsea infrastructure 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.
Expected value approach
This approach is used for heritage BHPP assets (excluding those
commonly held by both heritage entities).
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. Individual site provisions are
an estimate of the expected value of future cash \ufb02ows 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 country
speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows.
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 re\ufb02ect the Group\u2019s best estimate based on current
knowledge and information, further studies and detailed analysis of the
restoration activities for individual assets will be performed near the end
of their operational life and/or when detailed decommissioning plans
are required to be submitted to the relevant regulatory authorities.
Actual costs and cash out\ufb02ows 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 2022.
A range of pre-tax discount rates between 3.4% and 4.7% (2021: 0.4%
to 2.4%) has been applied. If the discount rates were decreased by 0.5%
then the provision would be $316 million higher. If the cost estimates
were increased by 10% then the provision would be $627 million higher.
The proportion of the non-current balance not expected to be settled
within 10 years is 54% (2021: 65%).
(b) Legal case outcomes
Provisions for legal cases are measured at the present value of the
amount expected to settle the claim. Management is required to use
judgement when assessing the likely outcome of legal cases, estimating
the risked amount and whether a provision or contingent liability should
be recognised.
D.5 Provisions (cont.)
Employee bene\ufb01ts
Provision is made for employee bene\ufb01ts accumulated as a result
of employees rendering services up to the end of the reporting
period. These bene\ufb01ts include wages, salaries, annual leave and
long service leave.
Liabilities in respect of employees\u2019 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 bene\ufb01ts.
These liabilities are measured at the present value of the
estimated future cash out\ufb02ow 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 classi\ufb01ed as short-
term bene\ufb01ts and are measured at the amount due to be paid.
Onerous contract provision
Provision is made for loss-making contracts at the present value
of the lower of the net cost of ful\ufb01lling and the cost arising from
failure to ful\ufb01ll each contract.
Notes to the \ufb01nancial statements D. Other assets and liabilities
for the year ended 31 December 2022
140 | Annual Report 2022
(c) Onerous contracts
The onerous contract provision assessment requires management
to make certain estimates regarding the unavoidable costs and the
expected economic bene\ufb01ts from the contract. These estimates
require signi\ufb01cant management judgement and are subject to risk and
uncertainty, and hence changes in economic conditions can affect the
assumptions.
As at 31 December 2022, the Corpus Christi contract is expected
to return a positive value and on this basis the provision has
been reversed to nil (2021: $214 million). Changes in assumptions
predominantly relating to the narrowing of the spread between the
sales price and purchase price could result in the contract becoming
onerous in the future.
Assumptions used to determine the present value as at 31 December
2022 are set out below:
\u2022 Remaining contract term \u2013 18 years.
\u2022 Discount rate \u2013 a pre-tax, risk free US government bond rate
of 4.10% (2021: 1.855%) has been applied.
\u2022 LNG pricing \u2013 forecast sales and purchase prices are subject to
a number of price markers. Price assumptions are based on the
best information on the market available at measurement date
and derived from short- and long-term views of global supply
and demand, building upon past experience of the industry and
consistent with external sources. The forecasted sales are linked
to gas hub prices (Title Transfer Facility (TTF)) at which physical
sales are expected to occur and incorporate known sales pricing
information . The long-term gas sales price is estimated on the basis
of the Group\u2019s Brent price forecast. The estimated purchase price
is linked to US gas hub prices (Henry Hub (HH)) at which physical
purchases are expected to occur. The nominal TTF, Brent oil prices
and HH gas prices used at 31 December 2022 were:
2023 2024 2025 2026 2027
TTF (US$/MMBtu) 47.9 36.4 22.3 8.8 9.0
Brent (US$/bbl) 87 78 74 76 77\u00b2
HH (US$/MMBtu) 6.1 4.7 4.0 4.1 4.23
1. For committed volumes, contracted pricing has been applied.
2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025
and prices are escalated at 2.0% onwards.
3. Long-term gas prices are based on US$3.8/MMBtu (2022 real terms) from
2025. All long-term prices are escalated at 2.0%.
D.6 Other \ufb01nancial assets and liabilities
2022 2021
US$m US$m
Other \ufb01nancial assets
Financial instruments at fair value through
pro\ufb01t and loss
Derivative \ufb01nancial instruments designated
as hedges 207 134
Other \ufb01nancial assets 22 293
Financial instruments at amortised cost
Hedge collateral (including interest) 509 -
Other \ufb01nancial assets 30 -
Financial instruments at fair value through
other comprehensive income
Other \ufb01nancial assets 29 -
Total other \ufb01nancial assets 797 427
Current 677 320
Non-current 120 107
Net carrying amount 797 427
Other \ufb01nancial liabilities
Financial instruments at fair value through
pro\ufb01t and loss
Derivative \ufb01nancial instruments designated
as hedges 721 563
Other \ufb01nancial liabilities - 9
Total other \ufb01nancial liabilities 721 572
Current 654 411
Non-current 67 161
Net carrying amount 721 572
Recognition and measurement
Other \ufb01nancial assets and liabilities
Receivables subject to provisional pricing adjustments are
initially recognised at the transaction price and subsequently
measured at fair value with movements recognised in the
consolidated income statement.
Derivative \ufb01nancial instruments
Derivative \ufb01nancial 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 \ufb02ow 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 reclassi\ufb01ed to the
consolidated income statement in the periods when the hedged
item affects pro\ufb01t or loss.
D.5 Provisions (cont.)
Notes to the \ufb01nancial statements D. Other assets and liabilities
for the year ended 31 December 2022
141Woodside Energy Group Ltd |
D.6 Other \ufb01nancial assets and liabilities (cont.)
Derivative \ufb01nancial instruments (cont.)
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 \ufb02ows 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 LNG revenue contracts.
Fair value
Except for the other \ufb01nancial assets and other \ufb01nancial liabilities
set out in this note, there are no material \ufb01nancial assets or
\ufb01nancial liabilities carried at fair value.
The fair value of commodity derivative \ufb01nancial instruments
is determined based on observable quoted forward pricing
and swap models and is classi\ufb01ed 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 \ufb02ows based on the terms of maturity
of each contract, using market interest rates for a similar
instrument at the reporting date and is classi\ufb01ed 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
classi\ufb01ed as Level 2 on the fair value hierarchy.
The fair values of other \ufb01nancial assets and other \ufb01nancial
liabilities are predominantly determined based on observable
quoted forward pricing and are predominantly classi\ufb01ed as
Level 2 on the fair value hierarchy.
Foreign exchange
The derivative \ufb01nancial instruments include foreign exchange
forward contracts that are denominated in Australian dollars.
The Group had no material other \ufb01nancial assets and liabilities
denominated in currencies other than US dollars.
Hedging activities
During the period, the following hedging activities were
undertaken:
\u2022 The Group hedged a percentage of its oil-linked exposure,
entering into oil swap derivatives settling in 2023 in order to
achieve a minimum average sales price of $75 per barrel.
\u2022 The Group entered into additional separate HH commodity
swaps to hedge the purchase leg of the Corpus Christi
volumes and separate TTF commodity swaps to hedge the
sales leg of Corpus Christi volumes to mitigate pricing risk for
2023 to 2024.
\u2022 As a result of hedging activities, approximately 49% of
Corpus Christi volumes included in stock in transit for 2022,
approximately 82% of 2023 volumes and approximately 29%
of 2024 volumes have hedged pricing risk.
\u2022 The Group restruck $150 million of the TTF hedges to reduce
the derivative \ufb01nancial liability.
\u2022 The Group restruck $92 million of the oil swap hedges to
reduce the derivative \ufb01nancial liability. Further, the Group also
voluntarily placed $506 million as collateral against the oil
hedge positions to reduce counterparty credit risk exposure.
The collateral will mature in line with hedge settlements
in 2023.
\u2022 Through the use of foreign exchange forward contracts, the
Group hedged its Australian dollar to US dollar exchange rate
in relation to a portion of the Australian dollar denominated
capital expenditure expected to be incurred under the
Scarborough development .
Notes to the \ufb01nancial statements D. Other assets and liabilities
for the year ended 31 December 2022
142 | Annual Report 2022
D.6 Other \ufb01nancial assets and liabilities (cont.)
Hedging activities (cont.)
2022 2021
Oil swaps (cash \ufb02ow hedges)
Carrying amount (US$m) (114) (1)
Notional amount (MMbbl) 18 30
Maturity date 2023 2022-2023
Hedge ratio 1:1 1:1
Weighted average hedged rate (US$/MMbbl) 79 74
HH Corpus Christi commodity swaps (cash
\ufb02ow hedges)
Carrying amount (US$m) 26 31
Notional amount (TBtu) 58 65
Maturity date 2023-2024 2022-2023
Hedge ratio 1:1 1:1
Weighted average hedged rate (US$/MMBtu) 4 3
TTF Corpus Christi commodity swaps (cash
\ufb02ow hedges)
Carrying amount (US$m) (469) (465)
Notional amount (TBtu) 50 49
Maturity date 2023-2024 2022-2023
Hedge ratio 1:1 1:1
Weighted average hedged rate (US$/MMBtu) 16 9
TTF commodity swaps (cash \ufb02ow hedges)
Carrying amount (US$m) - 4
Notional amount (TBtu) - 3
Maturity date - 2022
Hedge ratio - 1:1
Weighted average hedged rate (US$/MMBtu) - 26
Interest rate swap (cash \ufb02ow hedges)
Carrying amount (US$m) 55 (17)
Notional amount (US$m) 600 600
Maturity date 2027 2027
Hedge ratio 1:1 1:1
Weighted average hedged rate 1.7% 1.7%
Cross currency interest rate swap (cash \ufb02ow
and fair value hedges)
Carrying amount (US$m) 5 9
Notional amount (Swiss Franc) 175 175
Maturity date 2023 2023
Hedge ratio 1:1 1:1
Weighted average hedged rate
Three
month USD
LIBOR
+2.8%
Three month
USD LIBOR
+2.8%
FX forwards (cash \ufb02ow hedges)
Carrying amount (US$m) (17) 10
Notional amount (AUD$m) 1,037 934
Maturity date 2023-2025 2022-2025
Hedge Ratio 1:1 1:1
Weighted average hedged rate (AUD:USD) 0.68 0.71
Hedge ineffectiveness loss of $72 million (2021: $38 million loss)
has been recognised in the pro\ufb01t and loss.
Other \ufb01nancial assets
Other \ufb01nancial assets measured at fair value include receivables
subject to provisional pricing adjustments of nil (2021:
$163 million) and repurchase agreements entered into for
the purposes of net settlement rather than for physical delivery
of nil (2021: $69 million).
Interest Rate Benchmark Reform
A fundamental reform of major interest rate benchmarks is
being undertaken globally, including the replacement of some
interbank offered rates (IBORs) with alternative nearly risk-free
rates (referred to as \u2018IBOR reform\u2019). The Group has exposures
to IBORs on its \ufb01nancial instruments that will be impacted as
part of these market-wide initiatives. The Group's main IBOR
exposure at the reporting date is USD LIBOR. In 2020, the
Federal Reserve announced that the three-month and six-month
LIBOR will be phased out and eventually replaced by June 2023.
During the period, the Group has transitioned a number of
\ufb01nancial liabilities from USD LIBOR to SOFR and is in the process
of transitioning the remaining \ufb01nancial instruments to alternative
benchmark rates. The Group has \ufb01nancial liabilities and \ufb01nancial
assets with a total carrying value of $670 million (2021:
$957 million) and $393 million (2021: $367 million) respectively,
which reference USD LIBOR.
The Group has the following hedging relationships which are
exposed to interest rate benchmarks impacted by IBOR Reform:
\u2022 Interest rate swaps to hedge the LIBOR interest rate risk
associated with the $600 million syndicated facility (refer to
Note C.2). The interest rate swaps are designated as cash \ufb02ow
hedges, converting the variable interest into \ufb01xed interest US
dollar debt, and mature in 2027.
\u2022 A \ufb01xed rate 175 million Swiss Franc (CHF) denominated
medium term note, which it hedges with cross-currency
interest rate swaps designated in both fair value and cash \ufb02ow
hedge relationships. The cross-currency interest rate swaps
are referenced to LIBOR (refer to Note C.2).
The transition of a number of the Group\u2019s \ufb01nancial liabilities from
USD LIBOR to SOFR during the year ended 31 December 2022
did not result in a material impact to the Group. The Group\u2019s
Treasury function continues to execute the transition of the
remaining \ufb01nancial instruments from current benchmark rates
to alternative benchmark rates.
Key estimates and judgements
Fair value of other \ufb01nancial assets and liabilities
Estimates have been applied in the measurement of other \ufb01nancial
assets and liabilities and, where required, judgement is applied in
the settlement of any \ufb01nancial assets or liabilities. In the current
period, this included a $3 million periodic adjustment relating to
timing which increased other \ufb01nancial liabilities, re\ufb02ecting the
arrangements governing Wheatstone LNG sales (2021: $56 million
increase).
Notes to the \ufb01nancial statements D. Other assets and liabilities
for the year ended 31 December 2022
143Woodside Energy Group Ltd |
D.7 Leases
Land and
buildings
Plant and
equipment
2
Total
US$m US$m US$m
Lease assets
Year ended 31 December 2022
Carrying amount at 1 January 2022 377 703 1,080
Acquisitions through business
combination1 120 22 142
Additions 4 238 242
Lease remeasurements 5 103 108
Depreciation (42) (266) (308)
Carrying amount at 31 December 2022 464 800 1,264
At 31 December 2022
Historical cost and remeasurements 591 1,311 1,902
Accumulated depreciation, impairment
and disposals (127) (511) (638)
Net carrying amount 464 800 1,264
Lease liabilities
Year ended 31 December 2022
At 1 January 2022 437 930 1,367
Acquisitions through business
combination1 245 23 268
Additions 1 189 190
Repayments (principal and interest) (60) (305) (365)
Accretion of interest 25 78 103
Lease remeasurements (25) 96 71
Carrying amount at 31 December 2022 623 1,011 1,634
Current 48 276 324
Non-current 575 735 1,310
Carrying amount at 31 December 2022 623 1,011 1,634
Lease assets
Year ended 31 December 2021
Carrying amount at 1 January 2021 392 592 984
Additions 14 214 228
Lease remeasurements 15 16 31
Disposals at written down value (12) - (12)
Depreciation (32) (119) (151)
Carrying amount at 31 December 2021 377 703 1,080
At 31 December 2021
Historical cost 462 948 1,410
Accumulated depreciation and
impairment (85) (245) (330)
Net carrying amount 377 703 1,080
Lease liabilities
Year ended 31 December 2021
At 1 January 2021 484 794 1,278
Additions 7 244 251
Repayments (principal and interest) (70) (192) (262)
Accretion of interest 25 72 97
Lease remeasurements (9) 12 3
Carrying amount at 31 December 2021 437 930 1,367
Current 19 172 191
Non-current 418 758 1,176
Carrying amount at 31 December 2021 437 930 1,367
1. Acquisitions through business combination have been recognised on a
provisional basis. Adjustments will be made to the provisional amounts if new
information is obtained within 12 months from the acquisition date. Refer to
Note B.5 for details.
2. Marine, vessels and carriers have been included within plant and equipment for
the year ended 31 December 2022. The 2021 amounts have been reclassi\ufb01ed to
be presented on the same basis.
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 identi\ufb01ed asset which is not
substitutable and to obtain substantially all economic bene\ufb01ts
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\u2019s impairment
policies.
Lease liabilities are initially measured at the present value of
future minimum lease payments, discounted using the Group\u2019s
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 \ufb01xed payments or index-based variable payments
incorporating the Group\u2019s 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
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.
Foreign exchange risk
The Group held $441 million of lease liabilities at 31 December
2022 (2021: $476 million) in currencies other than the US dollar
(predominantly Australian dollars).
Notes to the \ufb01nancial statements D. Other assets and liabilities
for the year ended 31 December 2022
144 | Annual Report 2022
D.7 Leases (cont.)
Maturity pro\ufb01le of lease liabilities
The table below presents the contractual undiscounted cash
\ufb02ows associated with the Group\u2019s lease liabilities, representing
principal and interest. The \ufb01gures will not necessarily reconcile
with the amounts disclosed in the consolidated statement of
\ufb01nancial position.
2022 2021
US$m US$m
Due for payment in:
1 year or less 433 283
1-2 years 272 283
2-3 years 199 191
3-4 years 186 171
4-5 years 176 161
More than 5 years 966 789
2,232 1,878
Lease commitments
The table below presents the contractual undiscounted cash
\ufb02ows associated with the Group's future lease commitments
for non-cancellable leases not yet commenced, representing
principal and interest.
2022 2021
US$m US$m
Due for payment:
Within one year 67 80
After one year but not more than \ufb01ve years 263 159
Later than \ufb01ve years 1,288 49
1,618 288
Payments of $162 million (2021: $68 million) for short-term
leases (lease term of 12 months or less) and payments of
$12 million (2021: $18 million) for leases of low value assets were
expensed in the consolidated income statement. Total payments
for leases in the consolidated statement of cash \ufb02ows are $525
million (2021: $330 million), with $258 million (2021:
$244 million) included in \ufb01nancing activities.
The Group has short-term and/or low value lease commitments
for marine vessels and carriers, property, drill rigs and plant and
equipment contracted for, but not provided for in the \ufb01nancial
statements, of $60 million (2021: $53 million).
Key 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 identi\ufb01ed asset and obtain substantially all the
economic bene\ufb01ts 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 signi\ufb01cant change in
circumstances occurs. On this basis, possible additional lease
payments amounting to $2,323 million (2021: $1,654 million)
were not included in the measurement of lease liabilities.
(c) lnterest in joint arrangements
Judgement is required to determine the Group\u2019s rights and
obligations for lease contracts within joint operations, to assess
whether lease liabilities are recognised gross (100%) or in proportion
to the Group\u2019s participating interest in the joint operation. This
includes an evaluation of whether the lease arrangement contains
a sublease with the joint operation.
(d) Discount rates
Judgement is required to determine the discount rate, where the
discount rate is the Group\u2019s incremental borrowing rate if the rate
implicit in the lease cannot be readily determined. The incremental
borrowing rate is determined with reference to the Group\u2019s
borrowing portfolio at the inception of the arrangement or
the time of the modi\ufb01cation.
Notes to the \ufb01nancial statements D. Other assets and liabilities
for the year ended 31 December 2022
145Woodside Energy Group Ltd |
In this section
This section addresses information on items which require disclosure to comply with Australian Accounting Standards and the
Corporations Act 2001, however are not considered critical in understanding the \ufb01nancial performance or position of the Group.
This section includes Group structure information and other disclosures.
E. Other items
E.1 Contingent liabilities and assets Page 146
E.2 Employee bene\ufb01ts Page 146
E.3 Related party transactions Page 149
E.4 Auditor remuneration Page 149
E.5 Events after the end of the reporting period Page 149
E.6 Joint arrangements Page 149
E.7 Parent entity information Page 151
E.8 Subsidiaries Page 151
E.9 Other accounting policies Page 154
Notes to the \ufb01nancial statements E. Other items
for the year ended 31 December 2022
146 | Annual Report 2022
Notes to the \ufb01nancial statements E. Other items
for the year ended 31 December 2022
E.1 Contingent liabilities and assets
2022 2021
US$m US$m
Contingent liabilities at reporting date
Contingent liabilities 161 195
Guarantees 2 7
163 202
Contingent liabilities relate predominantly to possible
obligations whose existence will only be con\ufb01rmed by the
occurrence or non-occurrence of uncertain future events, and
therefore the Group has not provided for such amounts in these
\ufb01nancial statements. Additionally, there are a number of other
claims and possible claims that have arisen in the course of
business against entities in the Group, the outcome of which
cannot be estimated at present and for which no amounts have
been included in the table above.
The Group has contingent assets of $199 million as at 31
December 2022 (2021: nil).
E.2 Employee bene\ufb01ts
2022 2021 2020
US$m US$m US$m
Employee bene\ufb01ts 415 217 252
Share-based payments 26 12 19
De\ufb01ned contribution plan costs 41 26 27
De\ufb01ned bene\ufb01t plan expense 9 1 2
491 256 300
(a) Employee bene\ufb01ts
Employee bene\ufb01ts for the reporting period are as follows:
Recognition and measurement
The Group\u2019s accounting policy for employee bene\ufb01ts 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 bene\ufb01ts on
retirement, disability or death from the Group\u2019s retirement plans.
The Group operates a number of pension schemes throughout
the world. Employees entitled to de\ufb01ned contribution schemes
receive \ufb01xed contributions from Group companies and the
Group\u2019s legal or constructive obligation is limited to these
contributions. Contributions to de\ufb01ned 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.
(b) Compensation of key management
personnel
Key management personnel (KMP) compensation for the
\ufb01nancial year was as follows:
2022 2021 2020
US$ US$ US$
Short-term employee bene\ufb01ts1 5,730,340 6,626,354 5,868,476
Post-employment bene\ufb01ts1 155,086 88,396 63,805
Share-based payments2 3,114,043 5,697,529 7,201,653
Long-term employee bene\ufb01ts 4,300 717,223 515,585
Termination bene\ufb01ts 152,531 2,447,525 390,087
9,156,300 15,577,027 14,039,606
1. The 2021 comparatives for short-term employee bene\ufb01ts and post-employment
bene\ufb01ts have been restated to include the superannuation component of the
2021 EIS cash and other cash bonuses for three key management personnel,
increasing the short-term employee bene\ufb01ts expense by $26,676 to $6,626,354
and the post-employee bene\ufb01ts expense by $10,881 to $88,396.
2. The 2021 comparative for share-based payments has been restated to
include amortisation of the fair value of 2021 performance rights for two key
management personnel, increasing the expense by $88,507 to $5,697,529.
(c) Share plans
The Group provides bene\ufb01ts to its employees (including KMP) in
the form of share-based payments whereby employees render
services for shares (equity-settled transactions).
Woodside equity plan (WEP) and
supplementary Woodside equity plan (SWEP)
The WEP is available to all permanent employees, but since 1
January 2018 has excluded Executive Incentive Scheme (EIS)
participants. The number of Equity Rights (ERs) offered to
each eligible employee is determined by the Board, and based
on individual performance as assessed under the performance
review process. The linking of performance to an allocation
allows the Group to recognise and reward eligible employees
for high performance. The ERs have no further ongoing
performance conditions after allocation, and do not require
participants to make any payment in respect of the ERs at grant
or at vesting. Each ER entitles the participant to receive
a Woodside share on the vesting date three years after the
grant date.
For awards made in 2022, the Board amended the terms of the
plan to entitle participants to receive a Woodside share on the
vesting date, three years after the grant date. Awards made in
2020 and 2021 will vest under the terms of the plan at that time,
which provided for 75% vesting of the ERs three years after the
grant date and the remaining 25% of the ERs \ufb01ve years after the
grant date.
In October 2011, the Board approved the establishment of the
SWEP to enable the offering of targeting retention awards
of ERs for key capability. The SWEP was updated in 2022 to
broaden eligibility to all employees of a subsidiary of Woodside
Energy Group Ltd and ensure compliance in all jurisdictions
in which Woodside operates. This facilitated the offer of
replacement unvested incentives, as required under transitional
arrangements for eligible heritage BHP employees transitioning
from BHP Group Long-Term Incentive (LTI) plans to VAR
offered under Woodside\u2019s VAR arrangements.
147Woodside Energy Group Ltd |
Notes to the \ufb01nancial statements E. Other items
for the year ended 31 December 2022
E.2 Employee bene\ufb01ts (cont.)
Woodside equity plan (WEP) and
supplementary Woodside equity plan (SWEP)
(cont.)
Each ER entitles the participant to receive a Woodside share or
an American Depositary share on the vesting date either one,
two, three or four years after the effective grant date, depending
on the individual details of each SWEP offered. Participants do
not make any payment in respect of the ERs at grant or
at vesting.
Executive Incentive Plans (EIP)
The EIP operated as Woodside\u2019s Executive incentive framework
until the end of 2017, after which the Board introduced the EIS.
The EIP was used to deliver Short-Term Awards (STAs) and
Long-Term Awards (LTAs) to Senior Executives.
Short-Term Awards (STAs)
STAs were delivered in the form of restricted shares to
Executives, including all Executive KMP. There are no further
performance conditions for vesting of deferred STAs.
Participants are not required to make any payments in respect
of STA awards at grant or at vesting. Restricted shares entitle
their holders to receive dividends.
Long-Term Awards (LTAs)
LTAs were granted in the form of Performance Rights (PRs)
to Executives, including all Executive KMP. Vesting of LTAs
is subject to achievement of relative total shareholder return
(RTSR) targets, with 33% measured against the ASX 50 and the
remaining 67% tested against an international group of oil and
gas companies. Participants are not entitled to receive dividends
and are not required to make any payments in respect of LTA
awards at grant or at vesting.
Executive Incentive Scheme (EIS)
The EIS was introduced for the 2018 performance year for
all Executives including Executive KMP. The EIS is delivered
in the form of a cash incentive, Restricted Shares and
Performance Rights. The grant date of the Restricted Shares
and Performance Rights has been determined to be subsequent
to the performance year, being the date of the Board of
Directors\u2019 approval. Accordingly, the 2021 Restricted Shares
and Performance Rights were granted on 16 February 2022 for
Executives and 19 May 2022 for the CEO and have been included
in the table below. The expense estimated as at 31 December
2021 in relation to the 2021 performance year was updated to
the fair value on grant date during the period.
The 2022 Restricted Shares and Performance Rights have
not been included in the table below as they have not been
approved as at 31 December 2022. An expense related to the
2022 performance year has been estimated for the Restricted
Shares and Performance Rights, using fair value estimates based
on inputs at 31 December 2022.
Performance Based Pay Plus (PBP Plus)
PBP Plus is available to senior, permanent employees who
are not Executives. Participants receive an annual award of
cash and Restricted Shares based on corporate and individual
performance, recognising and rewarding eligible employees for
high performance.
The grant date of the Restricted Shares has been determined to
be subsequent to the performance year, being the date of the
Board of Directors\u2019 approval. Accordingly, the 2021 Restricted
Shares were granted on 16 February 2022 and have been
included in the table below. The expense estimated as at 31
December 2021 in relation to the 2021 performance year was
updated to the fair value on grant date during the period.
The 2022 Restricted Shares have not been included in the table
below as they have not been approved as at 31 December 2022.
An expense related to the 2022 performance year has been
estimated for the Restricted Shares, using fair value estimates
based on inputs at 31 December 2022.
Recognition and measurement
All compensation under WEP, SWEP and Executive share plans
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 ful\ufb01lled, 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 bene\ufb01t 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 bene\ufb01t
provided for the RTSR PRs 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.
148 | Annual Report 2022
E.2 Employee bene\ufb01ts (cont.)
The number of awards and movements for all share plans are summarised as follows:
Number of performance awards
Employee plans Executive plans
WEP SWEP STA4 LTA4
Year ended 31 December 2022
Opening balance 5,649,783 - 994,436 2,379,220
Granted during the year
1,2,3
3,017,366 3,046,963 495,800 764,171
Vested during the year (1,498,065) (38,146) (450,609) (191,736 )
Forfeited during the year (539,403) (124,741) (46,430) (397,233)
Awards at 31 December 2022 6,629,681 2,884,076 993,197 2,554,422
US$m US$m US$m US$m
Fair value of awards granted during the year 49 60 9 13
Number of performance awards
Employee plans Executive plans
WEP SWEP STA4 LTA4
Year ended 31 December 2021
Opening balance 5,618,603 - 975,295 2,798,305
Granted during the year
1,2,3
2,507,167 - 353,412 553,849
Vested during the year (1,999,676) - (307,402) (322,746)
Forfeited during the year (476,311) - (26,869) (650,188)
Awards at 31 December 2021 5,649,783 - 994,436 2,379,220
US$m US$m US$m US$m
Fair value of awards granted during the year 39 - 7 9
1. For the purpose of valuation, the share price on grant date for the 2022 WEP allocations was $16.30 (2021: $15.17).
2. For the purpose of valuation, the share price on grant date for the 2022 SWEP allocations was $19.74 (2021: nil).
3. For the purpose of valuation, the share price on grant date for Restricted Shares was $19.20 and $19.27 (2021: $20.18) and Performance Rights was $13.08 and $13.71
(2021: $11.66 and $14.44).
4. Includes awards issued under EIP and EIS.
For more detail on these share plans and performance rights issued to KMPs, refer to the Remuneration Report.
Notes to the \ufb01nancial statements E. Other items
for the year ended 31 December 2022
149Woodside Energy Group Ltd |
E.3 Related party transactions
The Group\u2019s related party transactions are predominantly
with associates of the Group. During the period, the transactions
with related parties include purchases of goods/services of
$60.730 million, sale of goods/services of $18.527 million and
dividend income of $8.294 million. As at 31 December 2022,
the total amounts owing to related parties is $1.686 million
and amounts owing from related parties is $2.200 million. All
transactions to/from related parties are made at arm\u2019s length
(normal market rates and on normal commercial terms).
There were no transactions with directors during the year.
Key management personnel compensation is disclosed in
Note E.2(b).
E.4 Auditor remuneration
For the year ended 31 December 2022, the auditor of Woodside
Energy Group Ltd is PricewaterhouseCoopers Australia (PwC)
(2021 and 2020: Ernst & Young (EY)).
2022 2021 2020
US$000 US$000 US$000
(a) Auditors of the Group
Amounts received or due and
receivable to:
PricewaterhouseCoopers (Australia)
Audit and review of \ufb01nancial reports 2,878 - -
Assurance services 129 - -
Other assurance and agreed upon
procedures services 832 - -
Tax services - - -
Other services 41 - -
Other overseas member \ufb01rms of
PricewaterhouseCoopers (Australia)
Audit of the \ufb01nancial reports of
controlled entities 1,274 - -
Other assurance and agreed upon
procedures services - - -
Tax services 258 - -
Other services - - -
5,412 - -
(b) Other auditors and their related
network \ufb01rms
Ernst & Young
Audit and review of \ufb01nancial reports 48 1,732 1,686
Assurance services 611 2,687 -
Other assurance and agreed upon
procedures services 2,335 33 140
Tax services - 129 178
Other services - 19 -
2,994 4,600 2,004
E.5 Events after the end of the reporting
period
The Group has undertaken a review of the depreciation
methodology and asset useful lives for oil and gas properties
in accordance with its accounting policies and the accounting
standards, considering the scale and diversity of the post-
merger portfolio and to ensure alignment with common industry
practice.
In assessing useful lives of certain oil and gas assets, these have
been approximated by reference to either their proved (1P) or
proved plus probable (2P) reserves, which is then used in the
units of production depreciation calculation.
From 1 January 2023, upstream oil and conventional gas assets
will be depreciated over proved reserves (previously proved
plus probable, except for certain assets considered late life).
Upstream LNG assets will continue to be depreciated over
proved plus probable reserves. Multiproduct assets are assessed
on a case-by-case basis and aligned to the most appropriate
representation of useful life.
The indicative impact to depreciation expense in 2023 resulting
from the change in estimate is expected to be an increase of
approximately $600 million. This is an indicative amount and
is based on current forecasts which are subject to assumptions
and uncertainties.
E.6 Joint arrangements
(a) Interest percentage in joint ventures
Group Interest %
Entity Principal activity 2022 2021
North West Shelf Gas Pty
Ltd
Contract administration
services for venturers
for LNG sales to
Japan. Marketing and
administration services
for venturers for gas
processing. 33.33 16.67
North West Shelf Liaison
Company Pty Ltd
Liaison for venturers in the
sale of LNG to the Japanese
market. 33.33 16.67
China Administration
Company Pty Ltd
Contract administration
services for venturers for
LNG sales to China. 33.33 16.67
North West Shelf Shipping
Service Company Pty Ltd LNG vessel \ufb02eet advisor. 33.33 16.67
North West Shelf Lifting
Coordinator Pty Ltd
Allocating, scheduling and
administering the lifting of
LNG and pipeline gas. 33.33 16.67
Notes to the \ufb01nancial statements E. Other items
for the year ended 31 December 2022
150 | Annual Report 2022
E.6 Joint arrangement (cont.)
(b) Interest percentage in joint operations
Group Interest %
2022 2021
Producing and developing assets
Australia
North West Shelf1 25.0 - 66.7 12.5 - 50.0
Greater En\ufb01eld and Vincent 60.0 60.0
Stybarrow2 - 50.0
Balnaves 65.0 65.0
Pluto 90.0 90.0
Wheatstone 13.0 - 65.0 13.0 - 65.0
Scarborough2 - 73.5
Bass Strait1 25.0 - 50.0 -
Macedon1 71.4 -
Pyrenees1 40.0 - 71.4 -
Griffin1 45.0 - 71.0 -
Minerva1 90.0 -
International
Sangomar 82.0 82.0
Atlantis1 44.0 -
Mad Dog1 23.9 -
Shenzi1 72.0 -
Trion1 60.0 -
Greater Angostura1 45.0 - 68.5 -
Calypso1 70.0 -
Exploration and evaluation assets
Oceania
Browse Basin 30.6 30.6
Carnarvon Basin3 31.6 - 70.0 15.8 - 70.0
Scarborough
2,3
- 50.0
Bonaparte Basin 26.7 - 35.0 26.7 - 35.0
Africa
Congo4 22.5 42.5
Senegal 90.0 90.0
Egypt1 25.0 - 45.0 -
Americas
US Gulf of Mexico1 23.9 - 75.0 -
Kitimat 50.0 50.0
Asia
Republic of Korea 50.0 50.0
Myanmar5 40.0 - 45.0 40.0 - 50.0
Caribbean
Barbados1 60.0 -
Trinidad & Tobago1 65.0 - 70.0 -
Other joint operations
Angel6 20.0 -
Bonaparte Basin6 21.0 -
1. Increase in interests due to the merger with BHPP on 1 June 2022.
2. No longer recognised as joint operations as the Group\u2019s interest increased to
100% due to the merger with BHPP on 1 June 2022.
3. The Carnarvon Basin and Scarborough exploration and evaluation assets which
were previously presented on the same line, have been separately presented in
2022. The 2021 Group interests have been reclassi\ufb01ed to be presented on the
same basis.
4. The Group\u2019s interest decreased to 22.5% upon farm-down of interest in June
2022.
5. The Group relinquished permits AD-1 and AD-8 in 2022. Formalities are pending.
6. Carbon Capture Storage titles G-10-AP and G-7-AP granted to the Group in
2022.
The principal activities of the joint operations are exploration,
development and production of hydrocarbons.
Key estimates and judgements
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 signi\ufb01cant in\ufb02uence 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 signi\ufb01cant in\ufb02uence
over the entity, which is then accounted for as an associate.
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
classi\ufb01ed 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 classi\ufb01ed as a joint
operation, and as such the Group recognises its:
\u2022 assets, including its share of any assets held jointly;
\u2022 liabilities, including its share of any liabilities incurred jointly;
\u2022 revenue from the sale of its share of the output arising from
the joint operation;
\u2022 share of revenue from the sale of the output by the joint
operation; and
\u2022 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 classi\ufb01ed 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
AASB 3/ IFRS 3 Business Combinations. Joint arrangements
which are not deemed to be carrying on a business are treated
as asset acquisitions.
Notes to the \ufb01nancial statements E. Other items
for the year ended 31 December 2022
151Woodside Energy Group Ltd |
E.7 Parent entity information
2022 2021
US$m US$m
Woodside Energy Group Ltd:
Current assets 312 456
Non-current assets 34,734 10,037
Current liabilities (1,530) (357)
Non-current liabilities (481) (300)
Net assets 33,035 9,836
Issued and fully paid shares 29,001 9,409
Reserved shares (38) (30)
Employee bene\ufb01ts reserve 150 112
Foreign currency translation reserve 296 296
Distributable pro\ufb01ts reserve 3,541 58
Retained earnings 85 (9)
Total shareholders equity 33,035 9,836
Pro\ufb01t of parent entity 6,665 18
Total comprehensive income of parent entity 6,665 18
Guarantees
Woodside Energy Group Ltd and Woodside Energy Ltd (a
subsidiary company) are parties to a Deed of Cross Guarantee
as disclosed in Note E.8. The effect of the Deed is that Woodside
Energy Group Ltd has guaranteed to pay any de\ufb01ciency in
the event of winding up of the subsidiary company under
certain provisions of the Corporations Act 2001. The subsidiary
company has also given a similar guarantee in the event that
Woodside Energy Group Ltd is wound up.
Woodside Energy Group Ltd has guaranteed the discharge by
a subsidiary company of its \ufb01nancial obligations under debt
facilities disclosed in Note C.2. Woodside Energy Group Ltd
has guaranteed certain obligations of subsidiaries to unrelated
parties on behalf of their performance in contracts. No liabilities
are expected to arise from these guarantees.
Notes to the \ufb01nancial statements E. Other items
for the year ended 31 December 2022
E.8 Subsidiaries
(a) Subsidiaries
Name of entity
Notes
Ultimate Parent Entity
Woodside Energy Group Ltd (1,2,3)
Subsidiaries
Company name
Woodside Energy Ltd (2,3,4)
Woodside Browse Pty Ltd (2,4)
Woodside Burrup Pty Ltd (2,4)
Burrup Facilities Company Pty Ltd (5)
Burrup Train 1 Pty Ltd (5)
Pluto LNG Pty Ltd (5)
Woodside Burrup Train 2 A Pty Ltd (2,4)
Woodside Burrup Train 2 B Pty Ltd (2,4)
Woodside Energy (LNG Fuels and Power) Pty Ltd (2,4)
Woodside Energy (Domestic Gas) Pty Ltd (2,4)
Woodside Energy (Algeria) Pty Ltd (2,4)
Woodside Energy Australia Asia Holdings Pte Ltd y (4)
Woodside Energy Holdings International Pty Ltd (2,4)
Name of entity
Notes
Woodside Energy International (Canada) Limited t (4)
Woodside Energy (Canada LNG) Limited t (4)
Woodside Energy (Canada PTP) Limited t (4)
KM LNG Operating General Partnership t (9)
KM LNG Operating Ltd t (4)
Woodside Energy Holdings Pty Ltd (2,4)
Woodside Energy Holdings (USA) Inc q (4)
Woodside Energy (USA) Inc q (4)
Gryphon Exploration Company q (4)
PT Woodside Energy Indonesia (6)
Woodside Energy (Cameroon) SARL n (4)
Woodside Energy (Gabon) Pty Ltd (2,4)
Woodside Energy (Indonesia) Pty Ltd (2,4)
Woodside Energy (Indonesia II) Pty Ltd (2,4)
Woodside Energy (Malaysia) Pty Ltd (2,4)
Woodside Energy (Ireland) Pty Ltd (2,4)
Woodside Energy (Korea) Pte Ltd y (4)
Woodside Energy (Korea II) Pte Ltd y (4)
Woodside Energy (Myanmar) Pte Ltd y (4)
Woodside Energy (Morocco) Pty Ltd (2,4)
Woodside Energy (New Zealand) Limited z (4)
Woodside Energy (New Zealand 55794) Limited z (4)
Woodside Energy (Peru) Pty Ltd (2,4)
Woodside Energy (Senegal) Pty Ltd (2,4)
Woodside Energy (Tanzania) Limited 3 (7)
Woodside Energy Holdings II Pty Ltd (2,4)
Woodside Power Pty Ltd (2,4)
Woodside Power (Generation) Pty Ltd (2,4)
Woodside Energy Holdings (South America) Pty Ltd (2,4)
Woodside Energia (Brasil) Apoio Administrativo Ltda l (8)
Woodside Energy Holdings (UK) Pty Ltd (2,4)
Woodside Energy (UK) Limited p (4)
Woodside Energy Finance (UK) Limited p (4)
Woodside Energy (Congo) Limited p (4)
Woodside Energy (Bulgaria) Limited p (4)
Woodside Energy Holdings (Senegal) Limited p (4)
Woodside Energy (Senegal) B.V. (4)
Woodside Energy (France) SAS \u00a3 (4)
Woodside Energy Iberia S.A. \u00ba (4)
Woodside Energy (N.A.) Ltd p (4)
Woodside Energy Services (Qingdao) Co Ltd (4)
Woodside Energy Julimar Pty Ltd (2,4)
Woodside Energy (Norway) Pty Ltd (2,4)
Woodside Energy Technologies Pty Ltd (2,4,14)
Woodside Technology Solutions Pty Ltd (2,4)
Woodside Energy Scarborough Pty Ltd (2,4)
Woodside Energy Carbon Holdings Pty Ltd (2,4)
Woodside Energy Carbon (Assets) Pty Ltd (2,4)
Woodside Energy Carbon (Services) Pty Ltd (2,4)
Woodside Energy (Financial Advisory Services) Pty Ltd (2,4)
Woodside Energy Trading Singapore Pte Ltd y (4)
WelCap Insurance Pte Ltd y (4)
Woodside Energy Shipping Singapore Pte Ltd y (4)
Metasource Pty Ltd (2,4)
Mermaid Sound Port and Marine Services Pty Ltd (2,4)
Woodside Finance Limited (2,4)
Woodside Petroleum (Timor Sea 19) Pty Ltd (2,4)
Woodside Petroleum (Timor Sea 20) Pty Ltd (2,4)
Woodside Petroleum Holdings Pty Ltd (2,4,15)
Woodside Energy Global Holdings Pty Ltd (2,4)
152 | Annual Report 2022
Notes to the \ufb01nancial statements E. Other items
for the year ended 31 December 2022
E.8 Subsidiaries (cont.)
Name of entity
Notes
Woodside Energy Global Pty Ltd (2,4)
Perdido Mexico Pipeline Holdings, S.A. de C.V. (10)
Perdido Mexico Pipeline, S. de R.L. de C.V. (10)
Woodside Energy Investments Pty Ltd (2,4)
Woodside Energia Brasil Investimentos Ltda. l (11)
Woodside Energia Brasil Explora\u00e7\u00e3o e Produ\u00e7\u00e3o Ltda. l (4)
Woodside Energy (Great Britain) Limited p (4)
Woodside Energy (North West Shelf) Pty Ltd (2,4)
Woodside Energy (Trinidad) Holdings Ltd (4)
Woodside Energy (Trinidad-3A) Ltd (4)
Woodside Energy USA Operations Inc q (12)
Hamilton Brothers Petroleum Corporation q (4)
Hamilton Oil Company LLC q (4)
Woodside Energy Boliviana Inc. q (4)
Woodside Energy (North America) LLC q (4)
Woodside Energy (Americas) Inc. q (4)
Woodside Energy (GOM) Inc. q (4)
Woodside Energy Hawaii Inc. q (4,16)
Woodside Energy Resources Inc. q (4)
Woodside Energy Holdings (Resources) Inc. q (4)
Woodside Energy USA Services Inc. q (4)
Woodside Energy Marketing Inc. q (4)
Woodside Energy (Deepwater) Inc. q (4,17)
Woodside Energy (Foreign Exploration Holdings) LLC q (4)
Woodside Energy (Trinidad Block 3) Limited p (4)
Woodside Energy (Trinidad Block 6) Limited p (4)
Woodside Energy (Trinidad Block 5) Limited p (4)
Woodside Energy (Trinidad Block 7) Limited p (4)
Woodside Energy (Trinidad Block 14) Limited p (4)
Woodside Energy (Trinidad Block 23A) Limited p (4)
Woodside Energy (Trinidad Block 23B) Limited p (4)
Woodside Energy (Trinidad Block 28) Limited p (4)
Woodside Energy (Trinidad Block 29) Limited p (4)
Woodside Energy (Bimshire) Limited p (4)
Woodside Energy (South Africa 3B/4B) Limited p (4)
Woodside Energy (Egypt) Limited p (4)
Woodside Energy (Carlisle Bay) Limited p (4)
Woodside Energy (Mexico) Limited p (4)
Woodside Energ\u00eda Servicios Administrativos,
S. de R.L. de C.V. (13)
Woodside Energ\u00eda Servicios de M\u00e9xico, S. de R.L. de C.V. (13)
Woodside Energy (Mexico Holdings) LLC q (4)
Operaciones Conjuntas, S. de R.L. de C.V. (13)
Woodside Energ\u00eda Holdings de M\u00e9xico, S. de R.L. de C.V. (13)
Woodside Petr\u00f3leo Operaciones de M\u00e9xico,
S. de R.L. de C.V. (13)
Woodside Energy (Australia) Pty Ltd (2,4)
Woodside Energy (International Exploration) Pty Ltd (2,4)
Woodside Energy (Bass Strait) Pty Ltd (2,4)
Woodside Energy (Victoria) Pty Ltd (2,4)
Woodside Energy Holdings LLC q (4)
Woodside Energy (Trinidad-2C) Ltd t (4)
Woodside Energy (Canada) Corporation t (4)
1. Woodside Energy Group Ltd, previously Woodside Petroleum Ltd, is the ultimate
holding company and the head entity within the tax consolidated group.
2. These companies were members of the Australian tax consolidated group at 31
December 2022.
3. Woodside Energy Group Ltd and Woodside Energy Ltd are parties to a Deed of
Cross Guarantee.
4. All subsidiaries are wholly owned except those referred to in Notes 5 to 13.
5. Kansai Electric Power Australia Pty Ltd and Tokyo Gas Pluto Pty Ltd each hold a
5% interest in the shares of these subsidiaries. These subsidiaries are controlled.
6. PT Woodside Energy Indonesia was incorporated on 27 April 2022. As at 31
December 2022, Woodside Energy Holdings Pty Ltd held a 99% interest in
the shares of PT Woodside Energy Indonesia. Woodside Energy Ltd held the
remaining 1% interest.
7. As at 31 December 2022, Woodside Energy Holdings Pty Ltd held >99.99%
interest in the shares of Woodside Energy (Tanzania) Limited and Woodside
Energy Ltd held the remaining interest.
8. As at 31 December 2022, Woodside Energy Holdings (South America) Pty
Ltd held >99.99% interest in the shares of Woodside Energia (Brasil) Apoio
Administrativo Ltda and Woodside Energy Ltd held the remaining interest.
9. As at 31 December 2022, Woodside Energy International (Canada) Limited and
Woodside Energy (Canada LNG) Limited were the general partners of the KM
LNG Operating General Partnership holding a 99.99% and 0.01% partnership
interest, respectively.
10. As at 31 December 2022, Woodside Energy Global Holdings Pty Ltd held a
99.99% interest in shares of Perdido Mexico Pipeline Holdings, S.A. de C.V. and
Perdido Mexico Pipeline, S. de R.L. de C.V. Woodside Energy Investments Pty Ltd
held the remaining 0.01% interest.
11. As at 31 December 2022, Woodside Energy Investments Pty Ltd held a 99.97%
interest in shares of Woodside Energia Brasil Investimentos Ltda. Woodside
Energy Global Holdings Pty Ltd held the remaining 0.03% interest.
12. As at 31 December 2022, Woodside Energy Global Holdings Pty Ltd held
90% voting interest and 37.67% interest in shares of Woodside Energy USA
Operations Inc. Woodside Energy Holdings LLC held the remaining 10% voting
interest and 62.33% interest in shares.
13. As at 31 December 2022, Woodside Energy (Mexico) Limited held a 99% interest
in shares of Woodside Energ\u00eda Servicios Administrativos, S. de R.L. de C.V.,
Woodside Energ\u00eda Servicios de M\u00e9xico, S. de R.L. de C.V., Operaciones Conjuntas,
S. de R.L. de C.V. and Woodside Petr\u00f3leo Operaciones de M\u00e9xico, S. de R.L. de
C.V. and 99.99% interest in shares of Woodside Energ\u00eda Holdings de M\u00e9xico,
S. de R.L. de C.V. Woodside Energy (Mexico Holdings) LLC held the remaining
0.01%-1% interest.
14. Woodside Energy Technologies Pty Ltd owns 28.50% in Blue Ocean Seismic
Services Limited which is accounted for as an investment in associate.
15. Woodside Energy (North West Shelf) Pty Ltd and Woodside Petroleum Holdings
Pty Ltd owns 16.67% in International Gas Transportation Company Limited
respectively. This investment has been accounted for as an investment in
associate.
16. Woodside Energy Hawaii Inc owns 14.96% in Iwilei District Participating Parties
LLC which is accounted for as an investment in associate.
17. Woodside Energy (Deepwater) Inc owns 25% in Caesar Oil Pipeline Company
LLC, 22% in Cleopatra Gas Gathering Company LLC and 10% in Marine Well
Containment Company LLC. These investments are accounted for as an
investment in associate.
All subsidiaries were incorporated in Australia unless identi\ufb01ed
with one of the following symbols:
Bermuda
l Brazil
n Cameroon
t Canada
China
\u00a3 France
Mexico
Indonesia
The Netherlands
R. of Trinidad and Tobago
z New Zealand
Saint Lucia
y Singapore
\u00ba Spain
3 Tanzania
p United Kingdom
q United States
Classi\ufb01cation
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\u2019s returns.
153Woodside Energy Group Ltd |
E.8 Subsidiaries (cont.)
(b) Subsidiaries with material non-controlling
interests
The Group has two Australian subsidiaries with material
non-controlling interests (NCI).
Name of entity
Principal place of
business
% held
by NCI
Burrup Facilities Company Pty Ltd Australia 10%
Burrup Train 1 Pty Ltd Australia 10%
The NCI in both subsidiaries is 10% held by the same parties
(refer to Note E.8(a) footnote 5 for details).
The summarised \ufb01nancial information (including consolidation
adjustments but before intercompany eliminations) of
subsidiaries with material NCI is as follows:
2022 2021 2020
US$m US$m US$m
Burrup Facilities Company Pty Ltd
Current assets 567 518 425
Non-current assets 5,047 5,038 5,224
Current liabilities (68) (71) (51)
Non-current liabilities (528) (528) (571)
Net assets 5,018 4,957 5,027
Accumulated balance of NCI 502 496 503
Revenue 889 858 859
Pro\ufb01t 489 328 318
Pro\ufb01t allocated to NCI 49 33 32
Dividends paid to NCI (43) (40) (32)
Operating 601 633 652
Investing (45) (111) (69)
Financing (556) (522) (583)
Net increase/(decrease) in cash and cash
equivalents - - -
Burrup Train 1 Pty Ltd
Current assets 429 435 372
Non-current assets 2,900 2,915 3,081
Current liabilities (119) (110) (103)
Non-current liabilities (325) (345) (385)
Net assets 2,885 2,895 2,965
Accumulated balance of NCI 289 290 297
Revenue 1,471 1,421 1,423
Pro\ufb01t 282 200 208
Pro\ufb01t allocated to NCI 28 20 21
Dividends paid to NCI (29) (27) (13)
Operating 391 393 473
Investing (55) (4) (2)
Financing (336) (389) (471)
Net increase/(decrease) in cash and cash
equivalents - - -
(c) Deed of Cross Guarantee and Closed Group
Woodside Energy Group Ltd and Woodside Energy Ltd
are parties to a Deed of Cross Guarantee under which each
company guarantees the debts of the other. The two entities
represent a Closed Group.
The consolidated income statement and consolidated statement
of \ufb01nancial position of the members of the Closed Group are set
out below:
2022 2021
US$m US$m
Closed Group Consolidated Income Statement and
Statement of Retained Earnings
Pro\ufb01t before tax 6,586 1,599
Tax expense (314) (50)
Pro\ufb01t after tax 6,272 1,549
Retained earnings at the beginning of the \ufb01nancial
year 1,660 111
Other comprehensive income 1 -
Transfer of retained earnings to distributable pro\ufb01ts
reserve (5,553) -
Dividends (1,018) -
Retained earnings at the end of the \ufb01nancial year 1,362 1,660
Closed Group Consolidated Statement of Financial
Position
Current assets
Cash and cash equivalents 116 160
Receivables 675 948
Inventories 56 47
Other \ufb01nancial assets 653 173
Other assets 21 22
Total current assets 1,521 1,350
Non-current assets
Receivables 2,171 476
Other \ufb01nancial assets 57,844 36,432
Exploration and evaluation assets 28 31
Oil and gas properties 2,424 2,930
Deferred tax assets 421 579
Lease assets 315 319
Other assets 67 13
Total non-current assets 63,270 40,780
Total assets 64,791 42,130
Current liabilities
Payables 483 186
Other \ufb01nancial liabilities 675 409
Provisions 328 320
Tax payable 1,556 357
Lease liabilities 36 23
Other liabilities 38 34
Total current liabilities 3,116 1,329
Non-current liabilities
Payables 25,524 27,104
Other \ufb01nancial liabilities 68 153
Provisions 1,121 1,179
Lease liabilities 325 360
Other liabilities 11 15
Total non-current liabilities 27,049 28,811
Total liabilities 30,165 30,140
Net assets 34,626 11,990
Equity
Issued and fully paid shares 29,001 9,409
Reserved shares (38) (30)
Other reserves 4,301 951
Retained earnings 1,362 1,660
Total equity 34,626 11,990
Notes to the \ufb01nancial statements E. Other items
for the year ended 31 December 2022
E.9 Other accounting policies (a) Summary of other signi\ufb01cant 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 identi\ufb01ed in Note E.8(a). The tax expense/bene\ufb01t, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax consolidated group are recognised in the separate \ufb01nancial 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 \ufb01nancial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is considered remote. US tax consolidation Woodside Energy USA Operations Inc and its wholly owned USA controlled entities have elected to \ufb01le a consolidated tax return, with Woodside Energy USA Operations Inc as the parent of the tax consolidated group. The tax expense/bene\ufb01t, 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. No amounts have been recognised in the \ufb01nancial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is considered remote. (b) New and amended accounting standards and interpretations issued but not yet effective A number of new standards, amendments of standards and interpretations have recently been issued but are not yet effective and have not been adopted by the Group as at the \ufb01nancial reporting date. The Group has reviewed these standards and interpretations and has determined that none of the new or amended standards will signi\ufb01cantly affect the Group\u2019s accounting policies, \ufb01nancial position or performance. (c) New and amended accounting standards and interpretations adopted As of 1 January 2022, the Group adopted AASB 2020-3 Amendments to AASs \u2013 Annual Improvements 2018-2020 and Other Amendments including: \u2022 Amendments to AASB 3 Reference to the Conceptual Framework \u2022 Amendments to AASB 9 Fees in the \u201810 per cent\u2019 Test for Derecognition of Financial Liabilities \u2022 Amendments to AASB 137 Onerous Contracts \u2013 Costs of Ful\ufb01lling a Contract These amendments did not impact the \ufb01nancial statements of the Group. A number of other new standards are also effective from 1 January 2022 but they do not have a material effect on the Group\u2019s \ufb01nancial statements. Notes to the \ufb01nancial statements E. Other items for the year ended 31 December 2022",
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"fact-749": {
"value": "by shares, incorporated and domiciled in Australia. Its shares ",
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"fact-5": {
"value": "Australia",
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"fact-754": {
"value": "Statement of compliance The \ufb01nancial statements are general purpose \ufb01nancial statements, which have been prepared in accordance with the requirements of the Corporations Act 2001, Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board (AASB). The \ufb01nancial statements comply with 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). Subsequent to the merger with BHPP, BHPP\u2019s accounting policies have been aligned with the Group. The Group\u2019s accounting policies are consistent with those disclosed in the Group\u2019s 2021 Financial Statements except for new policies applicable in 2022. Adoption of new or amended standards and interpretations effective 1 January 2022 did not result in any signi\ufb01cant changes to the Group\u2019s accounting policies. Estimates have been revised, where required, to re\ufb02ect current market conditions including the impact of COVID-19 and climate change. Updated assumptions used for impairment assessments and the measurement of onerous contracts are disclosed in Notes B.4 and D.5 respectively; these assumptions could change in the future. New estimates and judgements for signi\ufb01cant transactions during the period including the recognition of goodwill as a result of the business combination, the allocation of goodwill to the Group\u2019s cash generating units, and the sell-down of Train 2 are disclosed in Notes B.5, B.4 and B.7 respectively. ",
"dimensions": {
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"language": "en",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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},
"fact-755": {
"value": "Currency The 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 \ufb01nancial statements are taken to the income statement. ",
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"fact-790": {
"value": "The functional and presentation currency of Woodside and all its material subsidiaries is the US dollar. ",
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}
},
"fact-756": {
"value": "Rounding of amounts The amounts contained in these \ufb01nancial statements have been rounded to the nearest million dollars under the option available to the Group under Australian Securities and Investments Commission (ASIC) Corporations (Rounding in Financial/ Directors\u2019 Reports) Instrument 2016/191 dated 24 March 2016, unless otherwise stated. ",
"dimensions": {
"concept": "woodsideenergygroupltd:DisclosureOfRoundingOfAmounts",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2021-01-01T00:00:00/2022-01-01T00:00:00"
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},
"fact-757": {
"value": "Basis of preparation The \ufb01nancial statements have been prepared on a historical cost basis, except for derivative \ufb01nancial instruments and certain other \ufb01nancial assets and \ufb01nancial 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 \ufb01nancial assets and \ufb01nancial liabilities does not approximate their fair value, the fair value has been included in the notes to the \ufb01nancial statements. The \ufb01nancial statements comprise the \ufb01nancial position and results of the Group as at and for the year ended 31 December 2022 (refer to Note E.8). 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 subsidiaries of the Group apply the same reporting period and accounting policies as the parent company in their \ufb01nancial statements. All intercompany balances and transactions, including unrealised pro\ufb01ts and losses arising from intra-group transactions, have been eliminated in full. Non-controlling interests are allocated their share of the net pro\ufb01t 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 \ufb01nancial position, separately from parent shareholders\u2019 equity. The consolidated \ufb01nancial statements provide comparative information in respect of the previous periods. Where required, a reclassi\ufb01cation of items in the \ufb01nancial statements of the previous periods has been made in accordance with the classi\ufb01cation of items in the \ufb01nancial statements of the current period. ",
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},
"fact-758": {
"value": "Climate change and energy transition Climate considerations Woodside has considered the impact of climate and the energy transition in assessing the carrying value of its assets and liabilities. This note describes climate-related assumptions that underpin key areas of the \ufb01nancial statements and the potential short- and long-term impacts differing scenarios could have on the \ufb01nancial results and \ufb01nancial position of Woodside. Climate change and energy transition (cont.) 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 ensure we maintain a resilient \ufb01nancial position. The assumptions applied in assessing amounts within the \ufb01nancial statements are in each case calculated in accordance with the requirements of the applicable accounting standards. Our long-term price assumptions re\ufb02ect management\u2019s current \u2018best estimate\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. All price assumptions consider current legislation in the locations where Woodside operates and place some weight on scenarios in which the transition to a low carbon energy system is sufficiently rapid to meet the goals of the Paris Agreement, 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. in\ufb02ation) and which are not related to the Paris goals. Woodside\u2019s facilities are subject to physical risks such as oceanic conditions and are located in regions that experience tropical cyclones, hurricanes and high ambient temperatures. Woodside has signi\ufb01cant experience designing and operating facilities located in harsh environments. Woodside notes that 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 and disclose the risks and their potential impacts with precision. Woodside continues to monitor the uncertainty around climate change risks and will revise commodity and carbon pricing assumptions accordingly. Oil and gas 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 signi\ufb01cance to assets and liabilities than carbon pricing. Impairment of exploration and evaluation, oil and gas properties and goodwill In accordance with IFRS, elements of Woodside\u2019s \ufb01nancial statements are based on reasonable and supportable assumptions that represent management\u2019s 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. Price forecasts are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the impacts of climate policies along with other factors such as industry investment and cost trends. There remains signi\ufb01cant 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 over the medium and long term. The IEA\u2019s World Energy Outlook 2022 (WEO) explores three main climate change scenarios. The IEA scenarios are not predictions and the IEA does not have a single view on the future of the energy system. There is signi\ufb01cant uncertainty as to whether any of these scenarios will eventuate. Because Woodside considers what a market participant would pay to acquire an asset in assessing impairments, these external scenarios are not necessarily consistent with the pricing assumptions used for the Group\u2019s impairment assessment as disclosed in Table A below and Note B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill. The WEO explores three main scenarios1: \u2022 The Net Zero Emissions by 2050 Scenario (NZE) \u2022 The Announced Pledges Scenario (APS) \u2022 The Stated Policies Scenario (STEPS) Table A: Average real terms 2022 oil price (US$/bbl, Brent)2, North Asian LNG price (US$/MMbtu)2 and carbon price (US$/tCO\u2082-e)3 consistent with IEA dataset compared against Woodside\u2019s assumptions: Average Brent (RT US$/bbl) 2023-2026 2027-2031 2032-2036 2037-2040 NZE 59 38 33 31 APS 88 70 65 65 STEPS 92 85 85 88 Woodside 75 70 70 70 Average North Asian LNG (RT US$/MMbtu) 2023-2026 2027-2031 2032-2036 2037-2040 NZE 18 6 6 6 APS 20 9 9 9 STEPS 21 11 11 11 Woodside 23 9 9 9 Average Carbon (RT US$/tonne) 2023-2026 2027-2031 2032-2036 2037-2040 NZE 100 135 169 199 APS 98 130 154 172 STEPS 80 80 80 80 Woodside 80 80 80 80 1. IEA 2022. \u2018World Energy Outlook 2022\u2019. All rights reserved. 2. Based on data from IEA 2022. \u2018World Energy Outlook 2022\u2019 as modi\ufb01ed by Woodside analysis. Woodside used interpolation techniques to estimate Brent annual price points in between the years for which the IEA disclosed price points. For gas pricing assumptions all non-contracted LNG volumes were assessed at IEA\u2019s Japan import price, as a proxy for North Asian LNG spot price. Woodside used interpolation techniques to estimate annual gas price points in between the years for which the IEA disclosed prices. For oil linked LNG contracts, prices are derived from the Brent forecasts and the terms of the contracts. 3. Based on data from IEA 2022. \u2018World Energy Outlook 2022\u2019 as modi\ufb01ed by Woodside analysis. The IEA only provide carbon prices from 2030 onwards. As a result, Woodside used a starting point of US$80/tCO\u2082-e consistent with internal carbon cost pricing. Woodside used the 2022 starting price point and the IEA\u2019s published 2030 and 2040 carbon prices for each scenario to interpolate annual price points through to 2040. Climate change and energy transition (cont.) Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.) Refer to Note B.4 for the sensitivity analysis performed on Woodside\u2019s Brent oil pricing assumptions and the potential impact on the carrying value of Woodside\u2019s non-current assets. The benchmarked pricing above has limitations and is based on a wide range of assumptions. The impact of the benchmark pricing assumptions could be managed by decisions Woodside could make in response such as acquisitions, divestments or cost reductions as well as other consequential changes. The scenarios must therefore not be interpreted as Woodside\u2019s investment guidance. These are scenarios, not forecasts, and no likelihood is assigned to any of these scenarios eventuating. Impact on remaining life of assets Oil and gas properties relating to transferred exploration and evaluation and offshore 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. Restoration and other provisions The energy transition may result in restoration activities occurring earlier than expected. 54% (2021: 65%) of the Group\u2019s 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. Woodside continues to monitor the uncertainty around climate change risks to assess if additional changes to restoration provisions should be recognised. Onerous contracts Closure or early termination of activities may lead to supply contracts becoming onerous. As at 31 December 2022, the Corpus Christi contract is expected to return a positive value and on this basis the onerous contract provision has been reversed to nil (2021: $214 million). This and other contractual arrangements could be impacted by adverse market conditions arising from climate-related factors. 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 2022. The recoverability of deferred tax assets is dependent on the Group\u2019s future taxable income which can be impacted by the uncertainty of commodity and carbon pricing. Regulatory environment Regulation of climate-related emissions can change over time. Woodside is not currently aware of speci\ufb01c proposals that would materially change the assumptions underpinning the \ufb01nancial statements. ",
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"value": "Financial and capital risk management The Board of Directors has overall responsibility for the establishment and oversight of the Group\u2019s risk management framework, including review and approval of the Group\u2019s risk management strategy, policy and key risk parameters. The Board of Directors and the Audit and Risk Committee have oversight of the Group\u2019s internal control system and risk management process, including oversight of the internal audit function. The Group\u2019s management of \ufb01nancial and capital risks is aimed at ensuring that available capital, funding and cash \ufb02ows are sufficient to: \u2022 meet the Group\u2019s \ufb01nancial commitments as and when they fall due; \u2022 maintain the capacity to fund its committed project developments; \u2022 pay a reasonable dividend; and \u2022 maintain a long-term credit rating of not less than \u2018investment grade\u2019. The Group monitors and tests its forecast \ufb01nancial position against these criteria and, in general, will undertake hedging activity when necessary to ensure that these objectives are achieved. Other circumstances that may lead to hedging include the management of exposures relating to trading activities. It is, and has been throughout the period, the Group Treasury policy that no speculative trading in \ufb01nancial instruments shall be undertaken. Refer to Section 3.8 Risk Factors for more information on the Group\u2019s objectives, policies and processes for managing \ufb01nancial risk. The below risks arise in the normal course of the Group\u2019s business. Risk information can be found in the following sections: Section A Commodity price risk management Page 109 Section A Foreign exchange risk management Page 109 Section C Capital risk management Page 132 Section C Liquidity risk management Page 132 Section C Interest rate risk management Page 132 Section D Credit risk management Page 136 Key \ufb01nancial and capital risks in this section Commodity price risk management The Group\u2019s revenue is exposed to commodity price \ufb02uctuations through the sale of hydrocarbons. Commodity price risks are measured by monitoring and stress testing the Group\u2019s forecast \ufb01nancial position to sustained periods of low oil and gas prices. This analysis is regularly performed on the Group\u2019s portfolio and as required for discrete projects and transactions. The Group\u2019s 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 protect the Group against downside price risk within its strategic and trading portfolio. As at the reporting date, the Group held hedging \ufb01nancial instruments with a net liability carrying value of $557 million (2021: $431 million) exposed to commodity price risk. An increase in relevant commodity prices of 10% would increase the instruments\u2019 net liability by $219 million, the effect of which would be recognised within reserves and/or the income statement in accordance with hedge accounting application. A 10% decrease would have the same but opposite effect. This analysis assumes that all other variables remain constant (including the price on underlying physical exposures). Foreign exchange risk management Foreign exchange risk arises from future commitments, \ufb01nancial assets and \ufb01nancial liabilities that are not denominated in US dollars. The majority of the Group\u2019s 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\u2019s 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). As at the reporting date, the Group held hedging \ufb01nancial instruments with a net liability carrying value of $17 million (2021: net asset carrying value of $10 million) exposed to foreign exchange risk. Measuring the exposure to foreign exchange risk is achieved by regularly monitoring and performing sensitivity analysis on the Group\u2019s \ufb01nancial position. A reasonably possible change in the exchange rate of the US dollar to the Australian dollar (+12%/-12% (2021: +12%/-12%)), with all other variables held constant, would not have a material impact on the Group\u2019s equity or the income statement. Refer to Notes C1, C2, D2, D4 and D7 for details of the denominations of cash and cash equivalents, interest-bearing liabilities, receivables, payables and lease liabilities held at 31 December 2022. The Group entered into foreign exchange forward contracts to \ufb01x the Australian dollar to US dollar exchange rate in relation to a portion of the Australian dollar denominated capital expenditure incurred or expected to be incurred under the Scarborough development from 2022 to 2025 (refer to Note D.6). In order to hedge the foreign exchange risk and interest rate risk (refer to Section C) of a Swiss Franc (CHF) denominated medium term note, Woodside holds a number of cross-currency interest rate swaps (refer to Notes C.2 and D.6). The aim of these investments is to convert the \ufb01xed interest CHF bond into variable interest US dollar debt. Key \ufb01nancial and capital risks in this section 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 \ufb02exible supply of funds is available to meet the Group\u2019s operating and capital expenditure requirements. A stable capital base is maintained from which the Group can pursue its growth aspirations, whilst maintaining a \ufb02exible 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 \ufb01nancial metrics are monitored, including gearing and cash \ufb02ow leverage, and Treasury policy breaches and exceptions. Liquidity risk management Liquidity risk arises from the \ufb01nancial liabilities of the Group and the Group\u2019s subsequent ability to meet its obligations to repay \ufb01nancial 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 \ufb01nancial commitments in a timely and cost-effective manner. The Group\u2019s liquidity is continually reviewed, including cash \ufb02ow forecasts to determine the forecast liquidity position and maintain appropriate liquidity levels. At 31 December 2022, the Group had a total of $10,239 million (2021: $6,125 million) of available undrawn facilities and cash at its disposal. The maturity pro\ufb01le 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. Interest rate risk management Interest rate risk is the risk that the Group\u2019s \ufb01nancial position will \ufb02uctuate due to changes in market interest rates. The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to \ufb01nancial instruments with \ufb02oating 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 \ufb01xed and \ufb02oating rate debt. To manage the ratio of \ufb01xed rate debt to \ufb02oating rate debt, the Group may enter into interest rate swaps. The Group holds cross-currency interest rate swaps to hedge the foreign exchange risk (refer to Section A) and interest rate risk of the CHF denominated medium term note. The Group also 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 \ufb02ow hedges, primarily through $6,143 million (2021: $2,962 million) on cash and cash equivalents, $83 million (2021: $367 million) on interest- bearing liabilities (excluding transaction costs), $167 million of other \ufb01nancial assets (2021: nil) and $5 million (2021: $9 million) on cross-currency interest rate swaps. A reasonably possible change in the USD London Interbank Offered Rate (USD LIBOR) (+1.5%/-1.5% (2021: +1.0%/-1.0%)), with all variables held constant, would not have a material impact on the Group\u2019s equity or the income statement in the current period. The transition of a number of the Group\u2019s \ufb01nancial liabilities from USD LIBOR to SOFR during the year ended 31 December 2022 did not result in a material impact to the Group. The Group\u2019s Treasury function continues to execute the transition of the remaining \ufb01nancial instruments from current benchmark rates to alternative benchmark rates. Key \ufb01nancial and capital risks in this section Credit risk management Credit risk is the risk that a counterparty will not meet its obligation under a \ufb01nancial instrument or customer contract, leading to a \ufb01nancial loss to the Group. Credit risk arises from the \ufb01nancial assets of the Group, which comprise trade and other receivables, loans receivables and deposits with banks and \ufb01nancial institutions. The Group manages its credit risk on trade receivables and \ufb01nancial instruments by predominantly dealing with counterparties with an investment grade credit rating. Sufficient collateral is obtained to mitigate the risk of \ufb01nancial loss when transacting with counterparties with below investment grade credit ratings. Customers who wish to trade on unsecured credit terms are subject to credit veri\ufb01cation procedures. Receivable balances are monitored on an ongoing basis. As a result, the Group\u2019s exposure to bad debts is not signi\ufb01cant. The Group\u2019s maximum credit risk is limited to the carrying amount of its \ufb01nancial assets. Customer credit risk is managed by the Treasury function subject to the Group\u2019s established policy, procedures and controls relating to customer credit risk management. Credit quality of a customer is assessed based on an extensive credit rating scorecard and individual credit limits are de\ufb01ned in accordance with this assessment. Outstanding customer receivables are regularly monitored. At 31 December 2022, the Group had nineteen customers (2021: four customers) that owed the Group more than $10 million each and accounted for approximately 79% (2021: 88%) of all trade receivables. Depending on the product, settlement terms are 8 to 30 days from the date of invoice or bill of lading unless otherwise stated in the agreed payment terms. The Group considers the probability of default upon initial recognition of the asset and whether there has been a signi\ufb01cant depreciation in credit quality on an ongoing basis. A signi\ufb01cant decrease in credit quality is de\ufb01ned 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 simpli\ufb01ed approach and are measured at an amount equal to lifetime expected loss. Under the simpli\ufb01ed 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 \ufb01nancial assets is considered to be when the counterparty fails to make contractual payments within 60 days of when they fall due. At 31 December 2022, the Group had a provision for credit losses of nil (2021: nil). Subsequent to 31 December 2022, 99% (2021: 100%) of the trade receivables balance of $1,067 million (2021: $152 million) has been received. Credit risk from balances with banks is managed by the Treasury function in accordance with the Group\u2019s policy. The Group\u2019s main funds are placed as short-term deposits with reputable \ufb01nancial institutions with strong investment grade credit ratings. At 31 December 2022 and 31 December 2021, there were no signi\ufb01cant concentrations of credit risk within the Group and \ufb01nancial instruments are spread amongst a number of \ufb01nancial institutions to minimise the risk of counterparty default. The maximum exposure to \ufb01nancial 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\u2019s counterparty credit policy limits this exposure to commercial and investment banks, according to approved credit limits based on the counterparty\u2019s credit rating. ",
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"value": "Key estimates and judgements In applying the Group\u2019s accounting policies, management continually evaluates judgements, estimates and assumptions based on experience and other factors, including expectations of future events that may have an impact on the Group. All judgements, estimates and assumptions made are believed to be reasonable based on the most current set of circumstances known to management, and actual results may differ. Signi\ufb01cant judgements, estimates and assumptions made by management in the preparation of these \ufb01nancial statements are found in the following notes: Note A.1 Revenue from contracts with customers Page 110 Note A.5 Taxes Page 115 Note B.2 Exploration and evaluation Page 120 Note B.3 Oil and gas properties Page 121 Note B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill Page 123 Note B.5 Business combination Page 128 Note B.6 Signi\ufb01cant production and growth asset acquisitions Page 130 Note B.7 Disposal of assets Page 131 Note D.5 Provisions Page 138 Note D.6 Other \ufb01nancial assets and liabilities Page 140 Note D.7 Leases Page 143 Note E.6 Joint arrangements Page 149 Key estimates and judgements 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 signi\ufb01cant 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. Key estimates and judgements (a) Income tax classi\ufb01cation 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 the USA Tax Consolidation Group (USA TCG) of $1,371 million (2021: nil) and $93 million (2021: nil) arising from regions 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 within those regions. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $250 million from the USA TCG, $146 million from USA entities outside of the USA TCG and $1,061 million from regions other than Australia and the USA have not been recognised as it is not currently probable that the assets will be utilised based on current planned activities in those regions (2021: $497 million unrecognised DTAs). PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. As a result of higher actual and forecast assessable revenues supporting future recoverability of unrecognised quarantined exploration and general expenditure, the Pluto PRRT DTA has increased by $1,362 million. In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable pro\ufb01ts are risk-adjusted where appropriate by a market premium risk rate to re\ufb02ect uncertainty inherent in long-term forecasts. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 pro\ufb01ts. $6,523 million (2021: $4,507 million) relates to the North West Shelf Project, $189 million (2021: $1,432 million) relates to remaining Pluto quarantined exploration expenditure and $831 million (2021: $1,071 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 bene\ufb01t 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 AASB 112/ 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 out\ufb02ows 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 re\ufb02ected as increases or decreases to tax expense in the period in which new information is available. Key estimates and judgements (a) Area of interest Typically, an area of interest (AOI) is de\ufb01ned 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. Key estimates and judgements (a) Reserves The estimation of reserves requires signi\ufb01cant 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\u2019s oil and gas properties. Judgement is used in determining the economic reserve base applied to each asset. Typically, late life oil assets use proved reserves. Estimates are reviewed at least annually or when there are changes in the economic circumstances impacting speci\ufb01c assets or asset groups. These changes may impact depreciation, asset carrying values, restoration provisions and deferred tax balances. If proved plus probable (2P) reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the asset\u2019s carrying value. (b) Depreciation and amortisation Judgement is required to determine when assets are available for use to commence depreciation and amortisation. Depreciation and amortisation generally commences on \ufb01rst production. Key estimates and judgements CGU determination Identi\ufb01cation of a CGU requires management judgement. In determining CGUs for acquired assets during the reporting period, management has assessed based on the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or groups of assets. Allocation of goodwill Allocation of goodwill to the relevant CGUs requires management judgement. The goodwill arising from the merger has been allocated to relevant CGUs which are expected to bene\ufb01t from the expected synergies as a result of the merger. Recoverable amount calculation key assumptions In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash \ufb02ows when determining the FVLCD. These estimates require signi\ufb01cant 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 \ufb02ow estimates. The basis for each estimate used to determine recoverable amounts as at 31 December 2022 is set out below: \u2022 Resource estimates \u2013 2P and a portion of 2C reserves (where applicable) for oil and gas properties. The reserves are as disclosed in the Reserves and Resources Statement in the 31 December 2022 Annual Report. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied for US based assets and 2.5% for Australian based assets. \u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on management\u2019s view of long-term exchange rates. Key estimates and judgements (cont.) Recoverable amount calculation key assumptions (cont.) \u2022 Discount rates \u2013 a range of post-tax discount rates between 8% and 11.5% for CGUs has been applied. The discount rate re\ufb02ects an assessment of the risks speci\ufb01c to the asset. \u2022 Carbon pricing \u2013 a long-term price of US$80/tonne of emissions (real terms 2022) is based on management\u2019s assumptions on carbon cost pricing and incorporates an evaluation of climate risk. This is applicable to Australian emissions that exceed facility- speci\ufb01c baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. Refer to Climate change and energy transition section within the basis of preparation for further information. \u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. \u2022 Brent oil prices \u2013 derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is signi\ufb01cant uncertainty around how society will respond to the climate challenge; Woodside\u2019s pricing assumptions re\ufb02ect a \u2018best estimate\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in the Climate change and energy transition section within the basis of preparation. The nominal Brent oil prices (US$/bbl) used were: 2023 2024 2025 2026 2027 2028 31 December 20221 87 78 74 76 77 79 31 December 20212 71 68 69 70 72 73 1. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 2. Long-term oil prices are based on US$65/bbl (2022 real terms) from 2024 and prices are escalated at 2.0% onwards. Key estimates and judgements CGU determination Identi\ufb01cation of a CGU requires management judgement. For the year ended 31 December 2021, management has determined that the Scarborough and Pluto Train 2 development concept integrates with the existing Pluto onshore assets and is the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or group of assets. Recoverable amount calculation key assumptions In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash \ufb02ows when determining the VIU. These estimates require signi\ufb01cant 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 \ufb02ow estimates. The basis for each estimate used to determine recoverable amounts as at 31 December 2021 is set out below: \u2022 Resource estimates \u2013 2P reserves for oil and gas properties, except for NWS Oil (Okha) which is based on 1P reserves due to the reclassi\ufb01cation to a late life asset. The reserves are as disclosed in the Reserves and resources statement in the 31 December 2021 Annual Report on pages 55-59. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied. \u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on management\u2019s view of long-term exchange rates. \u2022 Discount rates \u2013 a range of pre-tax discount rates between 8.9% and 11.6% (post-tax discount rate 7.5%-8.5%) for CGUs has been applied. The discount rate re\ufb02ects an assessment of the risks speci\ufb01c to the asset. \u2022 An evaluation of climate risk is re\ufb02ected in Woodside's assumptions on carbon cost pricing, including a long-term Australian carbon price of US$80/tonne of emissions (real terms 2022). This is applicable to Australian emissions that exceed facility-speci\ufb01c baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. \u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. \u2022 Brent oil prices \u2013 derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is signi\ufb01cant uncertainty around how society will respond to the climate challenge; Woodside\u2019s pricing assumptions re\ufb02ect a \u2018most-likely\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in Woodside\u2019s Climate Report 2021. The nominal Brent oil prices (US$/bbl) used were: 2022 2023 2024 2025 2026 2027 31 December 20211 73 71 68 69 70 72 30 June 20202 57 62 67 72 73 75 1. Based on US$65/bbl (2022 real terms) from 2024 with prices escalated at 2.0% annually thereafter. 2. Based on US$65/bbl (2020 real terms) from 2025 with prices escalated at 2.0% annually thereafter. Key estimates and judgements (a) 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 \ufb02ow model to estimate the expected future cash \ufb02ows of the oil and gas assets acquired, based on reserves and resources at acquisition date and the discount rate used. The expected future cash \ufb02ows are based on estimates of future production, commodity and carbon prices, operating costs, and forecast capital expenditures at acquisition date. Restoration provisions require judgemental assumptions regarding removal date, environmental legislation and regulations and the extent of restoration activities required in determining the cost estimate. Carry forward tax losses are recognised only if it is probable that sufficient future taxable income will be available to utilise the losses. (b) Goodwill allocation Judgement is required in the allocation of goodwill to the Group\u2019s CGUs that are expected to bene\ufb01t from the synergies of the business combination. Refer to Note B.4 for the details of the goodwill allocation. Key estimates and judgements Nature of acquisition Judgement was required to determine if the transaction was the acquisition of an asset or a business combination. The Sangomar project was in the early phase of development and a substantive process that had the ability to convert inputs to outputs was not present and therefore the acquisition in 2021 was treated as asset acquisitions. Key estimates and judgements Sell-down of Train 2 Given the arrangements include provisions for GIP to sell its 49% interest back to Woodside if the status of key regulatory environmental approvals materially changes and the requirement for Woodside to fund up to $822 million of GIP\u2019s share in the event of a cost overrun, judgement is required to determine if the sell- down of Train 2 constitutes a sale and if a portion of the transaction price should be considered a variable consideration. Judgement was used to determine that the sell-down of Train 2 constituted a sale given the various conditions included in the sale and purchase agreement. The Group determined that a sale occurred as control of the 49% interest was passed to GIP on completion date. Control is determined as the ability to direct the use of, and obtain substantially all of the economic bene\ufb01ts of, the associated interest. Judgement was used to determine if it is highly probable that a signi\ufb01cant reversal will not occur in relation to the consideration received. The Group estimated the variable consideration based on the construction capital expenditure cost pro\ufb01le, the development schedule, and assessing the probability and impact of any event which may result in a signi\ufb01cant reversal. The constraining estimates of variable consideration have been applied resulting in the initial pre-tax gain on sale of $427 million. The variable consideration is remeasured at each reporting period with any changes recognised through the consolidated income statement. As at 31 December 2022, the variable consideration has been remeasured with a $71 million revaluation gain recognised as other income. Key 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. In many instances, decommissioning of assets occurs many years into the future. The Group\u2019s 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. The Group maintains technical expertise to ensure that industry learnings, scienti\ufb01c research and local and international guidelines are reviewed in assessing its restoration obligations. The restoration obligation requires judgemental assumptions regarding removal date, environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating cost, technologies used in determining the decommissioning cost, and liability-speci\ufb01c discount rates to determine the present value of these cash \ufb02ows. The Group applies either the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in assessing the cost estimate, re\ufb02ecting a difference in approach to cost estimation for heritage Woodside and heritage BHPP assets. Both approaches are supported by AASB 137/ IAS 37 Provisions, Contingent Liabilities and Contingent Assets, produce reliable estimates and are widely used in practice. Heritage Woodside assets refer to assets held by the Group prior to the BHPP merger. Heritage BHPP assets refers to assets acquired from BHP but excludes the commonly held assets by both heritage entities. Expected outcome approach This approach is used for heritage Woodside assets, and those assets commonly held by both heritage entities. The following cost assumptions are applied: \u2022 for onshore assets, provision has been made for the removal of production facilities and above ground pipelines using current restoration standards and techniques and taking into account risks and uncertainties; and \u2022 for offshore assets, provision has been made for the plug and abandonment of wells and the removal of offshore platform topsides, \ufb02oating production storage offloading (FPSO) and some subsea infrastructure. It is currently the Group\u2019s assumption that in some regulatory jurisdictions and environments, certain pipelines and infrastructure, parts of offshore platform substructures, and certain subsea infrastructure 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. Expected value approach This approach is used for heritage BHPP assets (excluding those commonly held by both heritage entities). 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. Individual site provisions are an estimate of the expected value of future cash \ufb02ows 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 country speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows. 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 re\ufb02ect the Group\u2019s best estimate based on current knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be performed near the end of their operational life and/or when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash out\ufb02ows 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 2022. A range of pre-tax discount rates between 3.4% and 4.7% (2021: 0.4% to 2.4%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $316 million higher. If the cost estimates were increased by 10% then the provision would be $627 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 54% (2021: 65%). (b) Legal case outcomes Provisions for legal cases are measured at the present value of the amount expected to settle the claim. Management is required to use judgement when assessing the likely outcome of legal cases, estimating the risked amount and whether a provision or contingent liability should be recognised. (c) Onerous contracts The onerous contract provision assessment requires management to make certain estimates regarding the unavoidable costs and the expected economic bene\ufb01ts from the contract. These estimates require signi\ufb01cant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions. As at 31 December 2022, the Corpus Christi contract is expected to return a positive value and on this basis the provision has been reversed to nil (2021: $214 million). Changes in assumptions predominantly relating to the narrowing of the spread between the sales price and purchase price could result in the contract becoming onerous in the future. Assumptions used to determine the present value as at 31 December 2022 are set out below: \u2022 Remaining contract term \u2013 18 years. \u2022 Discount rate \u2013 a pre-tax, risk free US government bond rate of 4.10% (2021: 1.855%) has been applied. \u2022 LNG pricing \u2013 forecast sales and purchase prices are subject to a number of price markers. Price assumptions are based on the best information on the market available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The forecasted sales are linked to gas hub prices (Title Transfer Facility (TTF)) at which physical sales are expected to occur and incorporate known sales pricing information . The long-term gas sales price is estimated on the basis of the Group\u2019s Brent price forecast. The estimated purchase price is linked to US gas hub prices (Henry Hub (HH)) at which physical purchases are expected to occur. The nominal TTF, Brent oil prices and HH gas prices used at 31 December 2022 were: 2023 2024 2025 2026 2027 TTF (US$/MMBtu) 47.9 36.4 22.3 8.8 9.0 Brent (US$/bbl) 87 78 74 76 77\u00b2 HH (US$/MMBtu) 6.1 4.7 4.0 4.1 4.23 1. For committed volumes, contracted pricing has been applied. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 3. Long-term gas prices are based on US$3.8/MMBtu (2022 real terms) from 2025. All long-term prices are escalated at 2.0%. Key estimates and judgements Fair value of other \ufb01nancial assets and liabilities Estimates have been applied in the measurement of other \ufb01nancial assets and liabilities and, where required, judgement is applied in the settlement of any \ufb01nancial assets or liabilities. In the current period, this included a $3 million periodic adjustment relating to timing which increased other \ufb01nancial liabilities, re\ufb02ecting the arrangements governing Wheatstone LNG sales (2021: $56 million increase). Key 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 identi\ufb01ed asset and obtain substantially all the economic bene\ufb01ts 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 signi\ufb01cant change in circumstances occurs. On this basis, possible additional lease payments amounting to $2,323 million (2021: $1,654 million) were not included in the measurement of lease liabilities. (c) lnterest in joint arrangements Judgement is required to determine the Group\u2019s rights and obligations for lease contracts within joint operations, to assess whether lease liabilities are recognised gross (100%) or in proportion to the Group\u2019s 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\u2019s 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\u2019s borrowing portfolio at the inception of the arrangement or the time of the modi\ufb01cation. Key estimates and judgements 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 signi\ufb01cant in\ufb02uence 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 signi\ufb01cant in\ufb02uence over the entity, which is then accounted for as an associate. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-791": {
"value": "Commodity price risk management The Group\u2019s revenue is exposed to commodity price \ufb02uctuations through the sale of hydrocarbons. Commodity price risks are measured by monitoring and stress testing the Group\u2019s forecast \ufb01nancial position to sustained periods of low oil and gas prices. This analysis is regularly performed on the Group\u2019s portfolio and as required for discrete projects and transactions. The Group\u2019s 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 protect the Group against downside price risk within its strategic and trading portfolio. As at the reporting date, the Group held hedging \ufb01nancial instruments with a net liability carrying value of $557 million (2021: $431 million) exposed to commodity price risk. An increase in relevant commodity prices of 10% would increase the instruments\u2019 net liability by $219 million, the effect of which would be recognised within reserves and/or the income statement in accordance with hedge accounting application. A 10% decrease would have the same but opposite effect. This analysis assumes that all other variables remain constant (including the price on underlying physical exposures). ",
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"period": "2021-01-01T00:00:00/2022-01-01T00:00:00"
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},
"fact-792": {
"value": "Foreign exchange risk management Foreign exchange risk arises from future commitments, \ufb01nancial assets and \ufb01nancial liabilities that are not denominated in US dollars. The majority of the Group\u2019s 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\u2019s 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). As at the reporting date, the Group held hedging \ufb01nancial instruments with a net liability carrying value of $17 million (2021: net asset carrying value of $10 million) exposed to foreign exchange risk. Measuring the exposure to foreign exchange risk is achieved by regularly monitoring and performing sensitivity analysis on the Group\u2019s \ufb01nancial position. A reasonably possible change in the exchange rate of the US dollar to the Australian dollar (+12%/-12% (2021: +12%/-12%)), with all other variables held constant, would not have a material impact on the Group\u2019s equity or the income statement. Refer to Notes C1, C2, D2, D4 and D7 for details of the denominations of cash and cash equivalents, interest-bearing liabilities, receivables, payables and lease liabilities held at 31 December 2022. The Group entered into foreign exchange forward contracts to \ufb01x the Australian dollar to US dollar exchange rate in relation to a portion of the Australian dollar denominated capital expenditure incurred or expected to be incurred under the Scarborough development from 2022 to 2025 (refer to Note D.6). In order to hedge the foreign exchange risk and interest rate risk (refer to Section C) of a Swiss Franc (CHF) denominated medium term note, Woodside holds a number of cross-currency interest rate swaps (refer to Notes C.2 and D.6). The aim of these investments is to convert the \ufb01xed interest CHF bond into variable interest US dollar debt.",
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"concept": "woodsideenergygroupltd:DisclosureOfForeignExchangeRiskManagement",
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"period": "2021-01-01T00:00:00/2022-01-01T00:00:00"
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},
"fact-760": {
"value": "A.1 Segment revenue and expenses Operating segment information The Group has identi\ufb01ed its operating segments based on the internal reports that are reviewed and used by the Chief Executive Officer (Chief Operating Decision Maker) in assessing performance and determining the allocation of resources. As a result of the merger with BHPP on 1 June 2022, the Group has transformed into a global energy company which has led to a change in how \ufb01nancial information is reported in the Group. The disclosed operating segments have been updated to re\ufb02ect this change and the 2021 and 2020 amounts have been restated to be presented on the same basis. Operating segments outlined below are identi\ufb01ed by management based on the nature and geographical location of the business and venture. Australia: Exploration, evaluation, development, production and sale of liqui\ufb01ed natural gas, pipeline gas, crude oil and condensate and natural gas liquids in Australia. International: Exploration, evaluation, development, production and sale of pipeline gas, crude oil and condensate and natural gas liquids in international jurisdictions outside of Australia. Marketing: Marketing, Shipping and Trading of Woodside\u2019s oil and gas portfolio (including non-produced volumes) and optimisation activities attributed to Marketing which have generated incremental value. Corporate/Other items: Corporate/Other items comprise primarily corporate non- segmental items of revenue and expenses and associated assets and liabilities not allocated to operating segments as they are not considered part of the core operations of any segment. In addition to the updated segments, the Group has reassessed the reporting of revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis. With the Marketing segment separately reported for the year ended 31 December 2022, the Group will no longer report revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis to better represent the revenues and margins generated by each segment. 2021 and 2020 amounts have been restated to be presented on the same basis. Major customer information The Group has two major customers which respectively account for 12% and 9% of the Group\u2019s external revenue. The sales are generated by the Australia and Marketing operating segments (2021: two major customers; 8% and 6% generated by the Australia operating segment and 2020: two major customers; 15% and 13% generated by the Australia operating segment). Geographical information Revenue from external customers1 Non-current assets2 2022 2021 2020 2022 2021 US$m US$m US$m US$m US$m Asia Paci\ufb01c 12,521 6,342 3,362 36,966 18,386 Americas 1,545 - - 7,057 1 Africa - - - 4,049 2,802 Europe 2,751 620 238 - - Consolidated 16,817 6,962 3,600 48,072 21,189 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,959 million (2021: $1,007 million). Recognition and measurement 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 signi\ufb01cant reversal will not occur. \u2022 Revenue from sale of hydrocarbons \u2013 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. \u2022 Other operating revenue \u2013 Revenue earned from LNG processing and other services is recognised over time as the services are rendered. Expenses \u2022 Royalties, excise and levies \u2013 Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group\u2019s entitlement to physical production. \u2022 Depreciation and amortisation \u2013 Refer to Note B.3. \u2022 Impairment and impairment reversals \u2013 Refer to Note B.4. \u2022 Leases \u2013 Refer to Note D.7. \u2022 Employee bene\ufb01ts \u2013 Refer to Note E.2. Key estimates and judgements 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 signi\ufb01cant 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. A.1 Segment revenue and expenses (cont.) Australia International Marketing Corporate/ Other Consolidated 2022 2022 2022 2022 2022 US$m US$m US$m US$m US$m Lique\ufb01ed natural gas 8,855 - 2,434 - 11,289 Pipeline gas 1,086 276 - - 1,362 Crude oil and condensate 2,467 1,273 18 - 3,758 Natural gas liquids 171 26 9 - 206 Revenue from sale of hydrocarbons 12,579 1,575 2,461 - 16,615 Intersegment revenue1 (455) (5) 460 - - Processing and services revenue 175 - - - 175 Shipping and other revenue - - 27 - 27 Other revenue (280) (5) 487 - 202 Operating revenue2 12,299 1,570 2,948 - 16,817 Production costs (975) (313) - 7 (1,281 Royalties, excise and levies (540) (39) - (17) (596) Insurance (35) (7) - (1) (43) Inventory movement 44 (3) - - 41 Costs of production (1,506) (362) - (11) (1,879) Land and buildings (51) (3) - - (54) Transferred exploration and evaluation (107) - - - (107 Plant and equipment (2,168) (436) - (33) (2,637) Oil and gas properties depreciation and amortisation (2,326) (439) - (33) (2,798 Shipping and direct sales costs (312) (36) (73) 142 (279 Trading costs (14) - (1,763) - (1,777 Other hydrocarbon costs (19) - - - (19) Other cost of sales (4) - - - (4) Movement in onerous contract provision3 - - 216 - 216 Other cost of sales (349) (36) (1,620) 142 (1,863) Cost of sales (4,181) (837) (1,620) 98 (6,540) Gross pro\ufb01t 8,118 733 1,328 98 10,277 Other income4 722 4 5 4 735 Exploration and evaluation expenditure5 (20) (277) - 1 (296) Amortisation of permit acquisition (1) (9) - - (10) Write-offs6 - (164) - - (164) Exploration and evaluation (21) (450) - 1 (470) General, administrative and other costs7 (13) (21) (10) (747) (791) Depreciation of other plant and equipment - - - - - Depreciation of lease assets (49) (11) - (80) (140) Restoration movement (234) (46) - 8 (272 Other8 (8) (84) (475) (486) (1,053) Other costs (304) (162) (485) (1,305) (2,256) Other expenses (325) (612) (485) (1,304) (2,726) Impairment losses - - - - - Impairment reversals 9 900 - - - 900 Pro\ufb01t/(loss) before tax and net \ufb01nance costs 9,415 125 848 (1,202) 9,186 1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 2. Operating revenue includes revenue from contracts with customers of $16,790 million and sub-lease income of $27 million disclosed within shipping and other revenue. 3. Comprises changes in estimates of $245 million offset by provisions used of $29 million. Refer to Note D.5 for further details. 4. Includes initial gain on Train 2 sell-down of $427 million, revaluation gain on the remeasurement of the Train 2 sell-down variable consideration of $71 million, fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business. 5. Includes $142 million for various costs relating to the Group\u2019s exit from the Orphan Basin exploration licences in Canada. 6. $125 million relates to costs of unsuccessful wells that have been written off. Refer to Note B.2. 7. Transaction costs of $419 million incurred as a result of the BHPP merger on 1 June 2022 are included in the Corporate/Other segment. Refer to Note B.5 for details. 8. Includes losses on hedging activities and changes in fair value of derivative \ufb01nancial instruments of $960 million in the Marketing and Corporate/Other segments and other expenses not associated with the ongoing operations of the business. 9. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details. A.1 Segment revenue and expenses (cont.) Australia International Marketing Corporate/ Other Consolidated 20218 20218 20218 20218 2021 US$m US$m US$m US$m US$m Lique\ufb01ed natural gas 3,910 - 1,449 - 5,359 Pipeline gas 43 - - - 43 Crude oil and condensate 1,316 - - - 1,316 Natural gas liquids 60 - - - 60 Revenue from sale of hydrocarbons 5,329 - 1,449 - 6,778 Intersegment revenue1 (236) - 236 - - Processing and services revenue 143 - - - 143 Shipping and other revenue 4 - 37 - 41 Other revenue (89) - 273 - 184 Operating revenue2 5,240 - 1,722 - 6,962 Production costs (489) - - 8 (481 Royalties, excise and levies (218) - - - (218 Insurance (32) - - 1 (31 Inventory movement 17 - - - 17 Costs of production (722) - - 9 (713 Land and buildings (51) - - - (51) Transferred exploration and evaluation (79) - - - (79 Plant and equipment (1,419) - - - (1,419 Oil and gas properties depreciation and amortisation (1,549) - - - (1,549 Shipping and direct sales costs (197) - (45) 32 (210) Trading costs (3) - (1,492) - (1,495 Other hydrocarbon costs (6) - - - (6) Other cost of sales (11) - - (1) (12 Movement in onerous contract provision3 - - 140 - 140 Other cost of sales (217) - (1,397) 31 (1,583) Cost of sales (2,488) - (1,397) 40 (3,845 Gross pro\ufb01t/(loss) 2,752 - 325 40 3,117 Other income4 97 (2) 1 43 139 Exploration and evaluation expenditure (16) (27) - (11) (54 Amortisation of permit acquisition - (2) - (1) (3 Write-offs5 - (265) - - (265 Exploration and evaluation (16) (294) - (12) (322 General, administrative and other costs (5) (1) - (152) (158) Depreciation of other plant and equipment - - - (30) (30 Depreciation of lease assets (28) - - (80) (108 Restoration movement (80) 12 - - (68 Other6 (57) (32) 28 (64) (125 Other costs (170) (21) 28 (326) (489 Other expenses (186) (315) 28 (338) (811) Impairment losses (10) - - - (10) Impairment reversals 7 1,058 - - - 1,058 Pro\ufb01t/(loss) before tax and net \ufb01nance costs 3,711 (317) 354 (255) 3,493 1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 2. Operating revenue includes revenue from contracts with customers of $6,923 million and sub-lease income of $39 million disclosed within shipping and other revenue. 3. Comprises provisions used of $45 million and changes in estimates of $95 million. Refer to Note D.5 for further details. 4. Includes other income of $67 million relating to Pluto volumes delivered into Wheatstone\u2019s sales commitments and net foreign exchange gains of $44 million. 5. $56 million relates to costs of unsuccessful wells. $209 million relates to capitalised costs written off due to the Group\u2019s decision to withdraw from its interests in Myanmar. Refer to Note B.2. 6. Includes net loss on hedging activities of $91 million, various costs relating to Woodside\u2019s exit from the Kitimat LNG development of $33 million and other expenses not associated with the ongoing operations of the business. 7. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details. 8. The 2021 amounts have been restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue. A.1 Segment revenue and expenses (cont.) Australia International Marketing Corporate/ Other Consolidated 20206 20206 20206 20206 2020 US$m US$m US$m US$m US$m Lique\ufb01ed natural gas1 2,390 - 129 - 2,519 Pipeline gas 73 - - - 73 Crude oil and condensate 843 - - - 843 Natural gas liquids 16 - - - 16 Revenue from sale of hydrocarbons 3,322 - 129 - 3,451 Intersegment revenue2 (47) - 47 - - Processing and services revenue 142 - - - 142 Shipping and other revenue 4 - 3 - 7 Other revenue 99 - 50 - 149 Operating revenue 3,421 - 179 - 3,600 Production costs (486) - - 8 (478) Royalties, excise and levies (82) - - - (82) Insurance (32) - - 1 (31) Inventory movement (32) - - - (32) Costs of production (632) - - 9 (623) Land and buildings (55) - - - (55) Transferred exploration and evaluation (99) - - - (99) Plant and equipment (1,535) - - - (1,535) Oil and gas properties depreciation and amortisation (1,689) - - - (1,689) Shipping and direct sales costs (146) - (3) 38 (111) Trading costs (4) - (207) - (211) Other hydrocarbon costs (4) - - - (4) Other cost of sales - - - - - Movement in onerous contract provision3 - - (347) - (347) Other cost of sales (154) - (557) 38 (673) Cost of sales (2,475) - (557) 47 (2,985) Gross pro\ufb01t/(loss) 946 - (378) 47 615 Other income4 3 (1) 1 (39) (36) Exploration and evaluation expenditure (26) (32) - (9) (67) Amortisation of permit acquisition (6) (5) - (1) (12) Write-offs - (2) - - (2) Exploration and evaluation (32) (39) - (10) (81) General, administrative and other costs (7) (14) - (169) (190) Depreciation of other plant and equipment - - - (29) (29) Depreciation of lease assets (26) - - (68) (94) Restoration movement (65) 37 - - (28) Other4 (8) - - (51) (59) Other costs (106) 23 - (317) (400) Other expenses (138) (16) - (327) (481) Impairment losses5 (3,971) (1,298) - - (5,269) Impairment reversals - - - - - Loss before tax and net \ufb01nance costs (3,160) (1,315) (377) (319) (5,171) 1. Includes an adjustment of $113 million related to price reviews under negotiation for multiple contracts in the Australia segment, reducing revenue recognised in the current and prior periods and increasing other liabilities. 2. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 3. Comprised of the recognition of an onerous contract provision $447 million, offset by changes in estimates of $54 million, provisions used of $41 million and a revision of discount rates of $5 million. 4. Includes foreign exchange gains and losses, gains and losses on hedging activities, cancellation costs and other expenses not associated with the ongoing operations of the business. 5. The impairment losses represent charges on exploration and evaluation of $1,557 million and oil and gas properties of $3,712 million. 6. The 2020 amounts have been restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue. Refer to Note A.1 for descriptions of the Group\u2019s segments and geographical regions. Australia International Marketing Corporate/ Other Consolidated 2022 2022 2022 2022 2022 US$m US$m US$m US$m US$m Balance as at 31 December Asia Paci\ufb01c 529 - - - 529 Americas - 240 - - 240 Africa - 38 - - 38 Total exploration and evaluation 529 278 - - 807 Balance as at 31 December Land and buildings 802 37 - 1 840 Transferred exploration and evaluation 481 - - - 481 Plant and equipment 18,249 4,647 - 161 23,057 Projects in development1 5,623 9,795 - 123 15,541 Total oil and gas properties 25,155 14,479 - 285 39,919 Balance as at 31 December Land and buildings 93 107 - 264 464 Plant and equipment 214 131 - 455 800 Total lease assets 307 238 - 719 1,264 Additions to exploration and evaluation2: Exploration 1 121 - - 122 Evaluation 19 100 - - 119 Restoration3 (1) - - - (1 19 221 - - 240 Additions to oil and gas properties 2: Oil and gas properties 2,252 1,560 - 92 3,904 Capitalised borrowings costs4 115 179 - - 294 Restoration3 (346) (28) - - (374) 2,021 1,711 - 92 3,824 Additions to lease assets 2 : Land and buildings 4 - - - 4 Plant and equipment 139 90 - 9 238 143 90 - 9 242 1. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations. 2. Additions exclude acquisitions through business combinations. 3. Relates to changes in restoration provision assumptions. 4. Borrowing costs capitalised were at a weighted average interest rate of 3.8%. B.1 Segment production and growth assets B.1 Segment production and growth assets (cont.) Australia International Marketing Corporate/ Other Consolidated 20212 20212 20212 20212 2021 US$m US$m US$m US$m US$m Balance as at 31 December Asia Paci\ufb01c 546 - - - 546 Americas - - - - - Africa - 68 - - 68 Total exploration and evaluation 546 68 - - 614 Balance as at 31 December Land and buildings 738 - - 1 739 Transferred exploration and evaluation 526 - - - 526 Plant and equipment 12,316 3 - 146 12,465 Projects in development 2,646 2,195 - 78 4,919 Total oil and gas properties 16,226 2,198 - 225 18,649 Balance as at 31 December Land and buildings 76 11 1 289 377 Plant and equipment 133 176 - 394 703 Total lease assets 209 187 1 683 1,080 Additions to exploration and evaluation: Exploration 1 41 - - 42 Evaluation 451 2 - - 453 Restoration 6 - - - 6 458 43 - - 501 Additions to oil and gas properties: Oil and gas properties 1,071 1,051 - 57 2,179 Capitalised borrowings costs1 46 77 - - 123 Restoration 18 14 - - 32 1,135 1,142 - 57 2,334 Additions to lease assets: Land and buildings - 14 - - 14 Plant and equipment - 214 - - 214 - 228 - - 228 1. Borrowing costs capitalised were at a weighted average interest rate of 3.6%. 2. The 2021 amounts have been restated to re\ufb02ect the changes in operating segments. Refer to \u2018Operating segment information\u2019 in Note A.1 for details. In addition, oil and gas properties includes other plant and equipment which is no longer separately presented in the consolidated statement of \ufb01nancial position. The 2021 amounts have been reclassi\ufb01ed to be presented on the same basis. D.1 Segment assets and liabilities 2022 20212 US$m US$m (a) Segment assets 1 Australia 31,240 18,163 International 18,084 2,877 Marketing 182 217 Corporate/Other 9,815 5,217 59,321 26,474 2022 20212 US$m US$m (b) Segment liabilities1 Australia 8,104 2,889 International 2,677 435 Marketing 561 639 Corporate/Other 10,852 8,282 22,194 12,245 1. Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is obtained within 12 months from the acquisition date. Refer to Note B.5 for details. 2. The 2021 amounts have been restated to re\ufb02ect the changes in operating segments. Refer to \u2018Operating segment information\u2019 in Note A.1 for details. Refer to Note A.1 for descriptions of the Group\u2019s segments. Corporate/other assets mainly comprise cash and cash equivalents, deferred tax assets and lease assets. Corporate/ other liabilities mainly comprise interest-bearing liabilities, deferred tax liabilities and lease liabilities. ",
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},
"fact-793": {
"value": "A.1 Segment revenue and expenses Operating segment information The Group has identi\ufb01ed its operating segments based on the internal reports that are reviewed and used by the Chief Executive Officer (Chief Operating Decision Maker) in assessing performance and determining the allocation of resources. As a result of the merger with BHPP on 1 June 2022, the Group has transformed into a global energy company which has led to a change in how \ufb01nancial information is reported in the Group. The disclosed operating segments have been updated to re\ufb02ect this change and the 2021 and 2020 amounts have been restated to be presented on the same basis. Operating segments outlined below are identi\ufb01ed by management based on the nature and geographical location of the business and venture. Australia: Exploration, evaluation, development, production and sale of liqui\ufb01ed natural gas, pipeline gas, crude oil and condensate and natural gas liquids in Australia. International: Exploration, evaluation, development, production and sale of pipeline gas, crude oil and condensate and natural gas liquids in international jurisdictions outside of Australia. Marketing: Marketing, Shipping and Trading of Woodside\u2019s oil and gas portfolio (including non-produced volumes) and optimisation activities attributed to Marketing which have generated incremental value. Corporate/Other items: Corporate/Other items comprise primarily corporate non- segmental items of revenue and expenses and associated assets and liabilities not allocated to operating segments as they are not considered part of the core operations of any segment. In addition to the updated segments, the Group has reassessed the reporting of revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis. With the Marketing segment separately reported for the year ended 31 December 2022, the Group will no longer report revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis to better represent the revenues and margins generated by each segment. 2021 and 2020 amounts have been restated to be presented on the same basis. Major customer information The Group has two major customers which respectively account for 12% and 9% of the Group\u2019s external revenue. The sales are generated by the Australia and Marketing operating segments (2021: two major customers; 8% and 6% generated by the Australia operating segment and 2020: two major customers; 15% and 13% generated by the Australia operating segment). Geographical information Revenue from external customers1 Non-current assets2 2022 2021 2020 2022 2021 US$m US$m US$m US$m US$m Asia Paci\ufb01c 12,521 6,342 3,362 36,966 18,386 Americas 1,545 - - 7,057 1 Africa - - - 4,049 2,802 Europe 2,751 620 238 - - Consolidated 16,817 6,962 3,600 48,072 21,189 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,959 million (2021: $1,007 million). Recognition and measurement 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 signi\ufb01cant reversal will not occur. \u2022 Revenue from sale of hydrocarbons \u2013 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. \u2022 Other operating revenue \u2013 Revenue earned from LNG processing and other services is recognised over time as the services are rendered. Expenses \u2022 Royalties, excise and levies \u2013 Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group\u2019s entitlement to physical production. \u2022 Depreciation and amortisation \u2013 Refer to Note B.3. \u2022 Impairment and impairment reversals \u2013 Refer to Note B.4. \u2022 Leases \u2013 Refer to Note D.7. \u2022 Employee bene\ufb01ts \u2013 Refer to Note E.2. Key estimates and judgements 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 signi\ufb01cant 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. A.1 Segment revenue and expenses (cont.) Australia International Marketing Corporate/ Other Consolidated 2022 2022 2022 2022 2022 US$m US$m US$m US$m US$m Lique\ufb01ed natural gas 8,855 - 2,434 - 11,289 Pipeline gas 1,086 276 - - 1,362 Crude oil and condensate 2,467 1,273 18 - 3,758 Natural gas liquids 171 26 9 - 206 Revenue from sale of hydrocarbons 12,579 1,575 2,461 - 16,615 Intersegment revenue1 (455) (5) 460 - - Processing and services revenue 175 - - - 175 Shipping and other revenue - - 27 - 27 Other revenue (280) (5) 487 - 202 Operating revenue2 12,299 1,570 2,948 - 16,817 Production costs (975) (313) - 7 (1,281 Royalties, excise and levies (540) (39) - (17) (596) Insurance (35) (7) - (1) (43) Inventory movement 44 (3) - - 41 Costs of production (1,506) (362) - (11) (1,879) Land and buildings (51) (3) - - (54) Transferred exploration and evaluation (107) - - - (107 Plant and equipment (2,168) (436) - (33) (2,637) Oil and gas properties depreciation and amortisation (2,326) (439) - (33) (2,798 Shipping and direct sales costs (312) (36) (73) 142 (279 Trading costs (14) - (1,763) - (1,777 Other hydrocarbon costs (19) - - - (19) Other cost of sales (4) - - - (4) Movement in onerous contract provision3 - - 216 - 216 Other cost of sales (349) (36) (1,620) 142 (1,863) Cost of sales (4,181) (837) (1,620) 98 (6,540) Gross pro\ufb01t 8,118 733 1,328 98 10,277 Other income4 722 4 5 4 735 Exploration and evaluation expenditure5 (20) (277) - 1 (296) Amortisation of permit acquisition (1) (9) - - (10) Write-offs6 - (164) - - (164) Exploration and evaluation (21) (450) - 1 (470) General, administrative and other costs7 (13) (21) (10) (747) (791) Depreciation of other plant and equipment - - - - - Depreciation of lease assets (49) (11) - (80) (140) Restoration movement (234) (46) - 8 (272 Other8 (8) (84) (475) (486) (1,053) Other costs (304) (162) (485) (1,305) (2,256) Other expenses (325) (612) (485) (1,304) (2,726) Impairment losses - - - - - Impairment reversals 9 900 - - - 900 Pro\ufb01t/(loss) before tax and net \ufb01nance costs 9,415 125 848 (1,202) 9,186 1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 2. Operating revenue includes revenue from contracts with customers of $16,790 million and sub-lease income of $27 million disclosed within shipping and other revenue. 3. Comprises changes in estimates of $245 million offset by provisions used of $29 million. Refer to Note D.5 for further details. 4. Includes initial gain on Train 2 sell-down of $427 million, revaluation gain on the remeasurement of the Train 2 sell-down variable consideration of $71 million, fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business. 5. Includes $142 million for various costs relating to the Group\u2019s exit from the Orphan Basin exploration licences in Canada. 6. $125 million relates to costs of unsuccessful wells that have been written off. Refer to Note B.2. 7. Transaction costs of $419 million incurred as a result of the BHPP merger on 1 June 2022 are included in the Corporate/Other segment. Refer to Note B.5 for details. 8. Includes losses on hedging activities and changes in fair value of derivative \ufb01nancial instruments of $960 million in the Marketing and Corporate/Other segments and other expenses not associated with the ongoing operations of the business. 9. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details. A.1 Segment revenue and expenses (cont.) Australia International Marketing Corporate/ Other Consolidated 20218 20218 20218 20218 2021 US$m US$m US$m US$m US$m Lique\ufb01ed natural gas 3,910 - 1,449 - 5,359 Pipeline gas 43 - - - 43 Crude oil and condensate 1,316 - - - 1,316 Natural gas liquids 60 - - - 60 Revenue from sale of hydrocarbons 5,329 - 1,449 - 6,778 Intersegment revenue1 (236) - 236 - - Processing and services revenue 143 - - - 143 Shipping and other revenue 4 - 37 - 41 Other revenue (89) - 273 - 184 Operating revenue2 5,240 - 1,722 - 6,962 Production costs (489) - - 8 (481 Royalties, excise and levies (218) - - - (218 Insurance (32) - - 1 (31 Inventory movement 17 - - - 17 Costs of production (722) - - 9 (713 Land and buildings (51) - - - (51) Transferred exploration and evaluation (79) - - - (79 Plant and equipment (1,419) - - - (1,419 Oil and gas properties depreciation and amortisation (1,549) - - - (1,549 Shipping and direct sales costs (197) - (45) 32 (210) Trading costs (3) - (1,492) - (1,495 Other hydrocarbon costs (6) - - - (6) Other cost of sales (11) - - (1) (12 Movement in onerous contract provision3 - - 140 - 140 Other cost of sales (217) - (1,397) 31 (1,583) Cost of sales (2,488) - (1,397) 40 (3,845 Gross pro\ufb01t/(loss) 2,752 - 325 40 3,117 Other income4 97 (2) 1 43 139 Exploration and evaluation expenditure (16) (27) - (11) (54 Amortisation of permit acquisition - (2) - (1) (3 Write-offs5 - (265) - - (265 Exploration and evaluation (16) (294) - (12) (322 General, administrative and other costs (5) (1) - (152) (158) Depreciation of other plant and equipment - - - (30) (30 Depreciation of lease assets (28) - - (80) (108 Restoration movement (80) 12 - - (68 Other6 (57) (32) 28 (64) (125 Other costs (170) (21) 28 (326) (489 Other expenses (186) (315) 28 (338) (811) Impairment losses (10) - - - (10) Impairment reversals 7 1,058 - - - 1,058 Pro\ufb01t/(loss) before tax and net \ufb01nance costs 3,711 (317) 354 (255) 3,493 1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 2. Operating revenue includes revenue from contracts with customers of $6,923 million and sub-lease income of $39 million disclosed within shipping and other revenue. 3. Comprises provisions used of $45 million and changes in estimates of $95 million. Refer to Note D.5 for further details. 4. Includes other income of $67 million relating to Pluto volumes delivered into Wheatstone\u2019s sales commitments and net foreign exchange gains of $44 million. 5. $56 million relates to costs of unsuccessful wells. $209 million relates to capitalised costs written off due to the Group\u2019s decision to withdraw from its interests in Myanmar. Refer to Note B.2. 6. Includes net loss on hedging activities of $91 million, various costs relating to Woodside\u2019s exit from the Kitimat LNG development of $33 million and other expenses not associated with the ongoing operations of the business. 7. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details. 8. The 2021 amounts have been restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue. A.1 Segment revenue and expenses (cont.) Australia International Marketing Corporate/ Other Consolidated 20206 20206 20206 20206 2020 US$m US$m US$m US$m US$m Lique\ufb01ed natural gas1 2,390 - 129 - 2,519 Pipeline gas 73 - - - 73 Crude oil and condensate 843 - - - 843 Natural gas liquids 16 - - - 16 Revenue from sale of hydrocarbons 3,322 - 129 - 3,451 Intersegment revenue2 (47) - 47 - - Processing and services revenue 142 - - - 142 Shipping and other revenue 4 - 3 - 7 Other revenue 99 - 50 - 149 Operating revenue 3,421 - 179 - 3,600 Production costs (486) - - 8 (478) Royalties, excise and levies (82) - - - (82) Insurance (32) - - 1 (31) Inventory movement (32) - - - (32) Costs of production (632) - - 9 (623) Land and buildings (55) - - - (55) Transferred exploration and evaluation (99) - - - (99) Plant and equipment (1,535) - - - (1,535) Oil and gas properties depreciation and amortisation (1,689) - - - (1,689) Shipping and direct sales costs (146) - (3) 38 (111) Trading costs (4) - (207) - (211) Other hydrocarbon costs (4) - - - (4) Other cost of sales - - - - - Movement in onerous contract provision3 - - (347) - (347) Other cost of sales (154) - (557) 38 (673) Cost of sales (2,475) - (557) 47 (2,985) Gross pro\ufb01t/(loss) 946 - (378) 47 615 Other income4 3 (1) 1 (39) (36) Exploration and evaluation expenditure (26) (32) - (9) (67) Amortisation of permit acquisition (6) (5) - (1) (12) Write-offs - (2) - - (2) Exploration and evaluation (32) (39) - (10) (81) General, administrative and other costs (7) (14) - (169) (190) Depreciation of other plant and equipment - - - (29) (29) Depreciation of lease assets (26) - - (68) (94) Restoration movement (65) 37 - - (28) Other4 (8) - - (51) (59) Other costs (106) 23 - (317) (400) Other expenses (138) (16) - (327) (481) Impairment losses5 (3,971) (1,298) - - (5,269) Impairment reversals - - - - - Loss before tax and net \ufb01nance costs (3,160) (1,315) (377) (319) (5,171) 1. Includes an adjustment of $113 million related to price reviews under negotiation for multiple contracts in the Australia segment, reducing revenue recognised in the current and prior periods and increasing other liabilities. 2. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 3. Comprised of the recognition of an onerous contract provision $447 million, offset by changes in estimates of $54 million, provisions used of $41 million and a revision of discount rates of $5 million. 4. Includes foreign exchange gains and losses, gains and losses on hedging activities, cancellation costs and other expenses not associated with the ongoing operations of the business. 5. The impairment losses represent charges on exploration and evaluation of $1,557 million and oil and gas properties of $3,712 million. 6. The 2020 amounts have been restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue. ",
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"fact-819": {
"value": "A.1 Segment revenue and expenses Operating segment information The Group has identi\ufb01ed its operating segments based on the internal reports that are reviewed and used by the Chief Executive Officer (Chief Operating Decision Maker) in assessing performance and determining the allocation of resources. As a result of the merger with BHPP on 1 June 2022, the Group has transformed into a global energy company which has led to a change in how \ufb01nancial information is reported in the Group. The disclosed operating segments have been updated to re\ufb02ect this change and the 2021 and 2020 amounts have been restated to be presented on the same basis. Operating segments outlined below are identi\ufb01ed by management based on the nature and geographical location of the business and venture. Australia: Exploration, evaluation, development, production and sale of liqui\ufb01ed natural gas, pipeline gas, crude oil and condensate and natural gas liquids in Australia. International: Exploration, evaluation, development, production and sale of pipeline gas, crude oil and condensate and natural gas liquids in international jurisdictions outside of Australia. Marketing: Marketing, Shipping and Trading of Woodside\u2019s oil and gas portfolio (including non-produced volumes) and optimisation activities attributed to Marketing which have generated incremental value. Corporate/Other items: Corporate/Other items comprise primarily corporate non- segmental items of revenue and expenses and associated assets and liabilities not allocated to operating segments as they are not considered part of the core operations of any segment. In addition to the updated segments, the Group has reassessed the reporting of revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis. With the Marketing segment separately reported for the year ended 31 December 2022, the Group will no longer report revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis to better represent the revenues and margins generated by each segment. 2021 and 2020 amounts have been restated to be presented on the same basis. Major customer information The Group has two major customers which respectively account for 12% and 9% of the Group\u2019s external revenue. The sales are generated by the Australia and Marketing operating segments (2021: two major customers; 8% and 6% generated by the Australia operating segment and 2020: two major customers; 15% and 13% generated by the Australia operating segment). Geographical information Revenue from external customers1 Non-current assets2 2022 2021 2020 2022 2021 US$m US$m US$m US$m US$m Asia Paci\ufb01c 12,521 6,342 3,362 36,966 18,386 Americas 1,545 - - 7,057 1 Africa - - - 4,049 2,802 Europe 2,751 620 238 - - Consolidated 16,817 6,962 3,600 48,072 21,189 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,959 million (2021: $1,007 million). Recognition and measurement 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 signi\ufb01cant reversal will not occur. \u2022 Revenue from sale of hydrocarbons \u2013 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. \u2022 Other operating revenue \u2013 Revenue earned from LNG processing and other services is recognised over time as the services are rendered. Expenses \u2022 Royalties, excise and levies \u2013 Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group\u2019s entitlement to physical production. \u2022 Depreciation and amortisation \u2013 Refer to Note B.3. \u2022 Impairment and impairment reversals \u2013 Refer to Note B.4. \u2022 Leases \u2013 Refer to Note D.7. \u2022 Employee bene\ufb01ts \u2013 Refer to Note E.2. Key estimates and judgements 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 signi\ufb01cant 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. A.1 Segment revenue and expenses (cont.) Australia International Marketing Corporate/ Other Consolidated 2022 2022 2022 2022 2022 US$m US$m US$m US$m US$m Lique\ufb01ed natural gas 8,855 - 2,434 - 11,289 Pipeline gas 1,086 276 - - 1,362 Crude oil and condensate 2,467 1,273 18 - 3,758 Natural gas liquids 171 26 9 - 206 Revenue from sale of hydrocarbons 12,579 1,575 2,461 - 16,615 Intersegment revenue1 (455) (5) 460 - - Processing and services revenue 175 - - - 175 Shipping and other revenue - - 27 - 27 Other revenue (280) (5) 487 - 202 Operating revenue2 12,299 1,570 2,948 - 16,817 Production costs (975) (313) - 7 (1,281 Royalties, excise and levies (540) (39) - (17) (596) Insurance (35) (7) - (1) (43) Inventory movement 44 (3) - - 41 Costs of production (1,506) (362) - (11) (1,879) Land and buildings (51) (3) - - (54) Transferred exploration and evaluation (107) - - - (107 Plant and equipment (2,168) (436) - (33) (2,637) Oil and gas properties depreciation and amortisation (2,326) (439) - (33) (2,798 Shipping and direct sales costs (312) (36) (73) 142 (279 Trading costs (14) - (1,763) - (1,777 Other hydrocarbon costs (19) - - - (19) Other cost of sales (4) - - - (4) Movement in onerous contract provision3 - - 216 - 216 Other cost of sales (349) (36) (1,620) 142 (1,863) Cost of sales (4,181) (837) (1,620) 98 (6,540) Gross pro\ufb01t 8,118 733 1,328 98 10,277 Other income4 722 4 5 4 735 Exploration and evaluation expenditure5 (20) (277) - 1 (296) Amortisation of permit acquisition (1) (9) - - (10) Write-offs6 - (164) - - (164) Exploration and evaluation (21) (450) - 1 (470) General, administrative and other costs7 (13) (21) (10) (747) (791) Depreciation of other plant and equipment - - - - - Depreciation of lease assets (49) (11) - (80) (140) Restoration movement (234) (46) - 8 (272 Other8 (8) (84) (475) (486) (1,053) Other costs (304) (162) (485) (1,305) (2,256) Other expenses (325) (612) (485) (1,304) (2,726) Impairment losses - - - - - Impairment reversals 9 900 - - - 900 Pro\ufb01t/(loss) before tax and net \ufb01nance costs 9,415 125 848 (1,202) 9,186 1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 2. Operating revenue includes revenue from contracts with customers of $16,790 million and sub-lease income of $27 million disclosed within shipping and other revenue. 3. Comprises changes in estimates of $245 million offset by provisions used of $29 million. Refer to Note D.5 for further details. 4. Includes initial gain on Train 2 sell-down of $427 million, revaluation gain on the remeasurement of the Train 2 sell-down variable consideration of $71 million, fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business. 5. Includes $142 million for various costs relating to the Group\u2019s exit from the Orphan Basin exploration licences in Canada. 6. $125 million relates to costs of unsuccessful wells that have been written off. Refer to Note B.2. 7. Transaction costs of $419 million incurred as a result of the BHPP merger on 1 June 2022 are included in the Corporate/Other segment. Refer to Note B.5 for details. 8. Includes losses on hedging activities and changes in fair value of derivative \ufb01nancial instruments of $960 million in the Marketing and Corporate/Other segments and other expenses not associated with the ongoing operations of the business. 9. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details. A.1 Segment revenue and expenses (cont.) Australia International Marketing Corporate/ Other Consolidated 20218 20218 20218 20218 2021 US$m US$m US$m US$m US$m Lique\ufb01ed natural gas 3,910 - 1,449 - 5,359 Pipeline gas 43 - - - 43 Crude oil and condensate 1,316 - - - 1,316 Natural gas liquids 60 - - - 60 Revenue from sale of hydrocarbons 5,329 - 1,449 - 6,778 Intersegment revenue1 (236) - 236 - - Processing and services revenue 143 - - - 143 Shipping and other revenue 4 - 37 - 41 Other revenue (89) - 273 - 184 Operating revenue2 5,240 - 1,722 - 6,962 Production costs (489) - - 8 (481 Royalties, excise and levies (218) - - - (218 Insurance (32) - - 1 (31 Inventory movement 17 - - - 17 Costs of production (722) - - 9 (713 Land and buildings (51) - - - (51) Transferred exploration and evaluation (79) - - - (79 Plant and equipment (1,419) - - - (1,419 Oil and gas properties depreciation and amortisation (1,549) - - - (1,549 Shipping and direct sales costs (197) - (45) 32 (210) Trading costs (3) - (1,492) - (1,495 Other hydrocarbon costs (6) - - - (6) Other cost of sales (11) - - (1) (12 Movement in onerous contract provision3 - - 140 - 140 Other cost of sales (217) - (1,397) 31 (1,583) Cost of sales (2,488) - (1,397) 40 (3,845 Gross pro\ufb01t/(loss) 2,752 - 325 40 3,117 Other income4 97 (2) 1 43 139 Exploration and evaluation expenditure (16) (27) - (11) (54 Amortisation of permit acquisition - (2) - (1) (3 Write-offs5 - (265) - - (265 Exploration and evaluation (16) (294) - (12) (322 General, administrative and other costs (5) (1) - (152) (158) Depreciation of other plant and equipment - - - (30) (30 Depreciation of lease assets (28) - - (80) (108 Restoration movement (80) 12 - - (68 Other6 (57) (32) 28 (64) (125 Other costs (170) (21) 28 (326) (489 Other expenses (186) (315) 28 (338) (811) Impairment losses (10) - - - (10) Impairment reversals 7 1,058 - - - 1,058 Pro\ufb01t/(loss) before tax and net \ufb01nance costs 3,711 (317) 354 (255) 3,493 1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 2. Operating revenue includes revenue from contracts with customers of $6,923 million and sub-lease income of $39 million disclosed within shipping and other revenue. 3. Comprises provisions used of $45 million and changes in estimates of $95 million. Refer to Note D.5 for further details. 4. Includes other income of $67 million relating to Pluto volumes delivered into Wheatstone\u2019s sales commitments and net foreign exchange gains of $44 million. 5. $56 million relates to costs of unsuccessful wells. $209 million relates to capitalised costs written off due to the Group\u2019s decision to withdraw from its interests in Myanmar. Refer to Note B.2. 6. Includes net loss on hedging activities of $91 million, various costs relating to Woodside\u2019s exit from the Kitimat LNG development of $33 million and other expenses not associated with the ongoing operations of the business. 7. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details. 8. The 2021 amounts have been restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue. A.1 Segment revenue and expenses (cont.) Australia International Marketing Corporate/ Other Consolidated 20206 20206 20206 20206 2020 US$m US$m US$m US$m US$m Lique\ufb01ed natural gas1 2,390 - 129 - 2,519 Pipeline gas 73 - - - 73 Crude oil and condensate 843 - - - 843 Natural gas liquids 16 - - - 16 Revenue from sale of hydrocarbons 3,322 - 129 - 3,451 Intersegment revenue2 (47) - 47 - - Processing and services revenue 142 - - - 142 Shipping and other revenue 4 - 3 - 7 Other revenue 99 - 50 - 149 Operating revenue 3,421 - 179 - 3,600 Production costs (486) - - 8 (478) Royalties, excise and levies (82) - - - (82) Insurance (32) - - 1 (31) Inventory movement (32) - - - (32) Costs of production (632) - - 9 (623) Land and buildings (55) - - - (55) Transferred exploration and evaluation (99) - - - (99) Plant and equipment (1,535) - - - (1,535) Oil and gas properties depreciation and amortisation (1,689) - - - (1,689) Shipping and direct sales costs (146) - (3) 38 (111) Trading costs (4) - (207) - (211) Other hydrocarbon costs (4) - - - (4) Other cost of sales - - - - - Movement in onerous contract provision3 - - (347) - (347) Other cost of sales (154) - (557) 38 (673) Cost of sales (2,475) - (557) 47 (2,985) Gross pro\ufb01t/(loss) 946 - (378) 47 615 Other income4 3 (1) 1 (39) (36) Exploration and evaluation expenditure (26) (32) - (9) (67) Amortisation of permit acquisition (6) (5) - (1) (12) Write-offs - (2) - - (2) Exploration and evaluation (32) (39) - (10) (81) General, administrative and other costs (7) (14) - (169) (190) Depreciation of other plant and equipment - - - (29) (29) Depreciation of lease assets (26) - - (68) (94) Restoration movement (65) 37 - - (28) Other4 (8) - - (51) (59) Other costs (106) 23 - (317) (400) Other expenses (138) (16) - (327) (481) Impairment losses5 (3,971) (1,298) - - (5,269) Impairment reversals - - - - - Loss before tax and net \ufb01nance costs (3,160) (1,315) (377) (319) (5,171) 1. Includes an adjustment of $113 million related to price reviews under negotiation for multiple contracts in the Australia segment, reducing revenue recognised in the current and prior periods and increasing other liabilities. 2. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment\u2019s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 3. Comprised of the recognition of an onerous contract provision $447 million, offset by changes in estimates of $54 million, provisions used of $41 million and a revision of discount rates of $5 million. 4. Includes foreign exchange gains and losses, gains and losses on hedging activities, cancellation costs and other expenses not associated with the ongoing operations of the business. 5. The impairment losses represent charges on exploration and evaluation of $1,557 million and oil and gas properties of $3,712 million. 6. The 2020 amounts have been restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue. ",
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"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-829": {
"value": "A.1 Segment revenue and expenses Operating segment information The Group has identi\ufb01ed its operating segments based on the internal reports that are reviewed and used by the Chief Executive Officer (Chief Operating Decision Maker) in assessing performance and determining the allocation of resources. As a result of the merger with BHPP on 1 June 2022, the Group has transformed into a global energy company which has led to a change in how \ufb01nancial information is reported in the Group. The disclosed operating segments have been updated to re\ufb02ect this change and the 2021 and 2020 amounts have been restated to be presented on the same basis. Operating segments outlined below are identi\ufb01ed by management based on the nature and geographical location of the business and venture. Australia: Exploration, evaluation, development, production and sale of liqui\ufb01ed natural gas, pipeline gas, crude oil and condensate and natural gas liquids in Australia. International: Exploration, evaluation, development, production and sale of pipeline gas, crude oil and condensate and natural gas liquids in international jurisdictions outside of Australia. Marketing: Marketing, Shipping and Trading of Woodside\u2019s oil and gas portfolio (including non-produced volumes) and optimisation activities attributed to Marketing which have generated incremental value. Corporate/Other items: Corporate/Other items comprise primarily corporate non- segmental items of revenue and expenses and associated assets and liabilities not allocated to operating segments as they are not considered part of the core operations of any segment. In addition to the updated segments, the Group has reassessed the reporting of revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis. With the Marketing segment separately reported for the year ended 31 December 2022, the Group will no longer report revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis to better represent the revenues and margins generated by each segment. 2021 and 2020 amounts have been restated to be presented on the same basis. Major customer information The Group has two major customers which respectively account for 12% and 9% of the Group\u2019s external revenue. The sales are generated by the Australia and Marketing operating segments (2021: two major customers; 8% and 6% generated by the Australia operating segment and 2020: two major customers; 15% and 13% generated by the Australia operating segment). Geographical information Revenue from external customers1 Non-current assets2 2022 2021 2020 2022 2021 US$m US$m US$m US$m US$m Asia Paci\ufb01c 12,521 6,342 3,362 36,966 18,386 Americas 1,545 - - 7,057 1 Africa - - - 4,049 2,802 Europe 2,751 620 238 - - Consolidated 16,817 6,962 3,600 48,072 21,189 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,959 million (2021: $1,007 million). Recognition and measurement 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 signi\ufb01cant reversal will not occur. \u2022 Revenue from sale of hydrocarbons \u2013 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. \u2022 Other operating revenue \u2013 Revenue earned from LNG processing and other services is recognised over time as the services are rendered. Expenses \u2022 Royalties, excise and levies \u2013 Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group\u2019s entitlement to physical production. \u2022 Depreciation and amortisation \u2013 Refer to Note B.3. \u2022 Impairment and impairment reversals \u2013 Refer to Note B.4. \u2022 Leases \u2013 Refer to Note D.7. \u2022 Employee bene\ufb01ts \u2013 Refer to Note E.2. Key estimates and judgements 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 signi\ufb01cant 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForSegmentReportingExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-832": {
"value": "A.1 Segment revenue and expenses Operating segment information The Group has identi\ufb01ed its operating segments based on the internal reports that are reviewed and used by the Chief Executive Officer (Chief Operating Decision Maker) in assessing performance and determining the allocation of resources. As a result of the merger with BHPP on 1 June 2022, the Group has transformed into a global energy company which has led to a change in how \ufb01nancial information is reported in the Group. The disclosed operating segments have been updated to re\ufb02ect this change and the 2021 and 2020 amounts have been restated to be presented on the same basis. Operating segments outlined below are identi\ufb01ed by management based on the nature and geographical location of the business and venture. Australia: Exploration, evaluation, development, production and sale of liqui\ufb01ed natural gas, pipeline gas, crude oil and condensate and natural gas liquids in Australia. International: Exploration, evaluation, development, production and sale of pipeline gas, crude oil and condensate and natural gas liquids in international jurisdictions outside of Australia. Marketing: Marketing, Shipping and Trading of Woodside\u2019s oil and gas portfolio (including non-produced volumes) and optimisation activities attributed to Marketing which have generated incremental value. Corporate/Other items: Corporate/Other items comprise primarily corporate non- segmental items of revenue and expenses and associated assets and liabilities not allocated to operating segments as they are not considered part of the core operations of any segment. In addition to the updated segments, the Group has reassessed the reporting of revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis. With the Marketing segment separately reported for the year ended 31 December 2022, the Group will no longer report revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis to better represent the revenues and margins generated by each segment. 2021 and 2020 amounts have been restated to be presented on the same basis. Major customer information The Group has two major customers which respectively account for 12% and 9% of the Group\u2019s external revenue. The sales are generated by the Australia and Marketing operating segments (2021: two major customers; 8% and 6% generated by the Australia operating segment and 2020: two major customers; 15% and 13% generated by the Australia operating segment). Geographical information Revenue from external customers1 Non-current assets2 2022 2021 2020 2022 2021 US$m US$m US$m US$m US$m Asia Paci\ufb01c 12,521 6,342 3,362 36,966 18,386 Americas 1,545 - - 7,057 1 Africa - - - 4,049 2,802 Europe 2,751 620 238 - - Consolidated 16,817 6,962 3,600 48,072 21,189 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,959 million (2021: $1,007 million). Recognition and measurement 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 signi\ufb01cant reversal will not occur. \u2022 Revenue from sale of hydrocarbons \u2013 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. \u2022 Other operating revenue \u2013 Revenue earned from LNG processing and other services is recognised over time as the services are rendered. Expenses \u2022 Royalties, excise and levies \u2013 Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group\u2019s entitlement to physical production. \u2022 Depreciation and amortisation \u2013 Refer to Note B.3. \u2022 Impairment and impairment reversals \u2013 Refer to Note B.4. \u2022 Leases \u2013 Refer to Note D.7. \u2022 Employee bene\ufb01ts \u2013 Refer to Note E.2. Key estimates and judgements 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 signi\ufb01cant 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-834": {
"value": "A.1 Segment revenue and expenses Operating segment information The Group has identi\ufb01ed its operating segments based on the internal reports that are reviewed and used by the Chief Executive Officer (Chief Operating Decision Maker) in assessing performance and determining the allocation of resources. As a result of the merger with BHPP on 1 June 2022, the Group has transformed into a global energy company which has led to a change in how \ufb01nancial information is reported in the Group. The disclosed operating segments have been updated to re\ufb02ect this change and the 2021 and 2020 amounts have been restated to be presented on the same basis. Operating segments outlined below are identi\ufb01ed by management based on the nature and geographical location of the business and venture. Australia: Exploration, evaluation, development, production and sale of liqui\ufb01ed natural gas, pipeline gas, crude oil and condensate and natural gas liquids in Australia. International: Exploration, evaluation, development, production and sale of pipeline gas, crude oil and condensate and natural gas liquids in international jurisdictions outside of Australia. Marketing: Marketing, Shipping and Trading of Woodside\u2019s oil and gas portfolio (including non-produced volumes) and optimisation activities attributed to Marketing which have generated incremental value. Corporate/Other items: Corporate/Other items comprise primarily corporate non- segmental items of revenue and expenses and associated assets and liabilities not allocated to operating segments as they are not considered part of the core operations of any segment. In addition to the updated segments, the Group has reassessed the reporting of revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis. With the Marketing segment separately reported for the year ended 31 December 2022, the Group will no longer report revenue from the sale of liqui\ufb01ed natural gas on a portfolio basis to better represent the revenues and margins generated by each segment. 2021 and 2020 amounts have been restated to be presented on the same basis. Major customer information The Group has two major customers which respectively account for 12% and 9% of the Group\u2019s external revenue. The sales are generated by the Australia and Marketing operating segments (2021: two major customers; 8% and 6% generated by the Australia operating segment and 2020: two major customers; 15% and 13% generated by the Australia operating segment). Geographical information Revenue from external customers1 Non-current assets2 2022 2021 2020 2022 2021 US$m US$m US$m US$m US$m Asia Paci\ufb01c 12,521 6,342 3,362 36,966 18,386 Americas 1,545 - - 7,057 1 Africa - - - 4,049 2,802 Europe 2,751 620 238 - - Consolidated 16,817 6,962 3,600 48,072 21,189 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,959 million (2021: $1,007 million). Recognition and measurement 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 signi\ufb01cant reversal will not occur. \u2022 Revenue from sale of hydrocarbons \u2013 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. \u2022 Other operating revenue \u2013 Revenue earned from LNG processing and other services is recognised over time as the services are rendered. Expenses \u2022 Royalties, excise and levies \u2013 Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group\u2019s entitlement to physical production. \u2022 Depreciation and amortisation \u2013 Refer to Note B.3. \u2022 Impairment and impairment reversals \u2013 Refer to Note B.4. \u2022 Leases \u2013 Refer to Note D.7. \u2022 Employee bene\ufb01ts \u2013 Refer to Note E.2. Key estimates and judgements 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 signi\ufb01cant 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForExpensesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-761": {
"value": "A.2 Finance costs 2022 2021 2020 US$m US$m US$m Interest on interest-bearing liabilities 212 201 237 Interest on lease liabilities 103 97 86 Accretion charge 110 29 32 Other \ufb01nance costs 36 26 29 Less: Finance costs capitalised against qualifying assets (294) (123) (57) 167 230 327 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceCostExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-762": {
"value": "A.3 Dividends paid and proposed Woodside Energy Group Ltd, the parent entity, paid and proposed dividends set out below: 2022 2021 2020 US$m US$m US$m (a) Dividends paid during the \ufb01nancial year Prior year fully franked \ufb01nal dividend1 1,018 115 518 Current year fully franked interim dividend2 2,070 289 248 3,088 404 766 (b) Dividend declared subsequent to the reporting period (not recorded as a liability) Final dividend3 2,734 1,018 115 (c) Other information Franking credits available for subsequent periods 1,406 1,744 1,823 Current year dividends per share (US cents) 253 135 38 1. 2022: US$1.05, paid on 23 March 2022 2021: US$0.12, paid on 24 March 2021 2020: US$0.55, paid on 20 March 2020 2. 2022: US$1.09, paid on 6 October 2022 2021: US$0.30, paid on 24 September 2021 2020: US$0.26, paid on 18 September 2020 3. 2022: US$1.44, to be paid on 5 April 2023 2021: US$1.05, paid on 23 March 2022 2020: US$0.12, paid on 24 March 2021 The Dividend Reinvestment Plan (DRP) was approved by the shareholders at the Annual General Meeting in 2003 for activation as required to fund future growth. The DRP was reactivated in 2019 and suspended by the Board of Directors on 27 February 2023. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDividendsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-763": {
"value": "A.4 Earnings/(losses) per share 2022 2021 2020 Pro\ufb01t/(loss) attributable to equity holders of the parent (US$m) 6,498 1,983 (4,028) Weighted average number of shares on issue for basic earnings/(loss) per share 1,511,257,404 962,604,811 951,113,086 Effect of dilution from contingently issuable shares 13,061,376 9,023,439 - Weighted average number of shares on issue adjusted for the effect of dilution1 1,524,318,780 971,628,250 951,113,086 Basic earnings/(losses) per share (US cents) 430.0 206.0 (423.5) Diluted earnings/(losses) per share (US cents) 426.3 204.1 (423.5) 1. The contingently issuable shares in 2020 have an anti-dilutive impact. Earnings/(losses) per share is calculated by dividing the pro\ufb01t/ (loss) for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares on issue during the year. The weighted average number of shares makes allowance for shares reserved for employee share plans. Diluted earnings/(losses) per share is calculated by adjusting basic earnings/(losses) per share by the number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares into ordinary shares. At 31 December 2022, 13,061,376 awards (2021: 9,023,439 awards) granted under the Woodside employee share plans are considered dilutive. Total outstanding share awards as at 31 December 2020 were 9,392,203 and considered anti-dilutive due to the loss position in 2020. There have been no signi\ufb01cant transactions involving ordinary shares between the reporting date and the date of completion of these \ufb01nancial statements. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-794": {
"value": "Earnings/(losses) per share is calculated by dividing the pro\ufb01t/ (loss) for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares on issue during the year. The weighted average number of shares makes allowance for shares reserved for employee share plans. Diluted earnings/(losses) per share is calculated by adjusting basic earnings/(losses) per share by the number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares into ordinary shares. At 31 December 2022, 13,061,376 awards (2021: 9,023,439 awards) granted under the Woodside employee share plans are considered dilutive. Total outstanding share awards as at 31 December 2020 were 9,392,203 and considered anti-dilutive due to the loss position in 2020. There have been no signi\ufb01cant transactions involving ordinary shares between the reporting date and the date of completion of these \ufb01nancial statements. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForEarningsPerShareExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-764": {
"value": "2022 2021 2020 US$m US$m US$m (a) Tax expense comprises Petroleum resource rent tax (PRRT) Current tax expense 501 - - Deferred tax (bene\ufb01t)/expense (814) 297 (439) PRRT (bene\ufb01t)/expense (313) 297 (439) Income tax Current year Current tax expense 2,256 658 275 Deferred tax expense/(bene\ufb01t) 701 301 (1,308) Adjustment to prior years Current tax (bene\ufb01t)/expense (276) (20) 16 Deferred tax expense/(bene\ufb01t) 231 18 (9) Income tax expense/(bene\ufb01t) 2,912 957 (1,026) Tax expense/(bene\ufb01t) 2,599 1,254 (1,465) (b) Reconciliation of income tax expense Pro\ufb01t/(loss) before tax 9,174 3,290 (5,440) PRRT bene\ufb01t/(expense) 313 (297) 439 Pro\ufb01t/(loss) before income tax 9,487 2,993 (5,001) Income tax expense/(bene\ufb01t) calculated at 30% 2,847 898 (1,500) Effect of tax rate differentials (141) (42) 192 Effect of deferred tax assets not recognised 150 114 270 Foreign exchange impact on tax (bene\ufb01t)/ expense (44) (18) 3 Adjustment to prior years (45) (2) 7 Integration and transaction costs non- deductible 142 - - Other 3 7 2 Income tax expense/(bene\ufb01t) 2,912 957 (1,026) (c) Reconciliation of PRRT bene\ufb01t Pro\ufb01t/(loss) before tax 9,174 3,290 (5,440) Non-PRRT assessable (pro\ufb01t)/loss (6,197) (2,134) 3,080 PRRT projects pro\ufb01t/(loss) before tax 2,977 1,156 (2,360) PRRT expense/(bene\ufb01t) calculated at 40% 1,191 462 (944) (Recognition)/derecognition of Pluto general expenditure1 (1,362) - 627 Augmentation (175) (166) (138) Other 33 1 16 PRRT (bene\ufb01t)/expense (313) 297 (439) (d) Deferred tax income statement reconciliation PRRT Production and growth assets (710) 455 (242) Augmentation for current year (175) (166) (138) Provisions (12) (29) (32) Other 83 37 (27) PRRT (bene\ufb01t)/expense (814) 297 (439) Income tax Oil and gas properties 292 674 (981) Exploration and evaluation assets 14 (204) (210) Lease assets and liabilities 25 1 (16) Provisions 151 (10) (106) PRRT assets and liabilities 236 (88) 134 Unused tax losses and tax credits 19 149 (149) Assets held for sale 205 (205) - Derivatives 21 (11) 16 Other (31) 13 (5) Income tax deferred tax expense/(bene\ufb01t) 932 319 (1,317) Deferred tax expense/(bene\ufb01t) 118 616 (1,756) (e) Deferred tax other comprehensive income reconciliation Income tax Derivatives (64) 5 (25) Other (2) 5 6 Deferred income tax (bene\ufb01t)/expense via other comprehensive income (66) 10 (19) A.5 Taxes 2022 2021 2020 % % % (f) Effective income tax rate: Australian and global operations Effective income tax rate2 Australia 30.0% 30.6% 29.6% Global 30.7% 32.0% 20.5% 1. The $1,362 million increase of the Pluto PRRT deferred tax asset is due to the recognition of previously unrecognised deductible expenditure that is now expected to be utilised to offset future taxable pro\ufb01ts. 2. The global operations effective income tax rate (ETR) is calculated as the Group\u2019s income tax expense divided by pro\ufb01t before income tax. The Australian operations ETR is calculated with reference to all Australian companies and excludes foreign exchange on settlement and revaluation of income tax liabilities. 2022 2021 US$m US$m (g) Deferred tax balance sheet reconciliation Deferred tax assets PRRT Production and growth assets 1,460 767 Augmentation for current year 113 166 Provisions 271 75 Other (23) (1) PRRT deferred tax assets 1,821 1,007 Income tax3 Oil and gas properties (1,496) - Exploration and evaluation assets 30 - Lease assets and liabilities 23 - Unused tax losses and tax credits 1,464 - Derivatives 23 - Provisions 60 - Other 34 - Income tax deferred tax assets 138 - Deferred tax assets 1,959 1,007 Deferred tax liabilities PRRT4 Production and growth assets 1,281 - Augmentation for current year (62) - Provisions (743) - Other 137 - PRRT deferred tax liabilities 613 - Income tax Oil and gas properties 2,857 1,520 Exploration and evaluation assets 67 51 Lease assets and liabilities (22) (38) Provisions (1,280) (706) PRRT assets and liabilities 347 303 Assets held for sale - (205) Derivatives (36) (15) Other (89) (32) Income tax deferred tax liabilities 1,844 878 Deferred tax liabilities 2,457 878 3. The Group was in a net income tax deferred tax liability position in 2021. 4. The Group was in a net PRRT deferred tax asset position in 2021. Key estimates and judgements (a) Income tax classi\ufb01cation 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 the USA Tax Consolidation Group (USA TCG) of $1,371 million (2021: nil) and $93 million (2021: nil) arising from regions 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 within those regions. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $250 million from the USA TCG, $146 million from USA entities outside of the USA TCG and $1,061 million from regions other than Australia and the USA have not been recognised as it is not currently probable that the assets will be utilised based on current planned activities in those regions (2021: $497 million unrecognised DTAs). PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. As a result of higher actual and forecast assessable revenues supporting future recoverability of unrecognised quarantined exploration and general expenditure, the Pluto PRRT DTA has increased by $1,362 million. In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable pro\ufb01ts are risk-adjusted where appropriate by a market premium risk rate to re\ufb02ect uncertainty inherent in long-term forecasts. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 pro\ufb01ts. $6,523 million (2021: $4,507 million) relates to the North West Shelf Project, $189 million (2021: $1,432 million) relates to remaining Pluto quarantined exploration expenditure and $831 million (2021: $1,071 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 bene\ufb01t 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 AASB 112/ 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 out\ufb02ows 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 re\ufb02ected as increases or decreases to tax expense in the period in which new information is available. A.5 Taxes (cont.) Tax transparency code Woodside participates in the Australian Board of Taxation\u2019s voluntary Tax Transparency Code (TTC). To increase public con\ufb01dence in the contributions and compliance of corporate taxpayers, the TTC recommends public disclosure of tax information. Part A of the recommended disclosures are addressed within this Taxes note and Part B within our Sustainable Development Report, supported by additional information on our website. 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 substantially 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 \ufb01nancial 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 pro\ufb01t nor the taxable pro\ufb01t. In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable pro\ufb01ts when assessing the extent to which a deferred tax asset can be recognised in the consolidated statement of \ufb01nancial 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory",
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}
},
"fact-795": {
"value": "2022 2021 2020 US$m US$m US$m (a) Tax expense comprises Petroleum resource rent tax (PRRT) Current tax expense 501 - - Deferred tax (bene\ufb01t)/expense (814) 297 (439) PRRT (bene\ufb01t)/expense (313) 297 (439) Income tax Current year Current tax expense 2,256 658 275 Deferred tax expense/(bene\ufb01t) 701 301 (1,308) Adjustment to prior years Current tax (bene\ufb01t)/expense (276) (20) 16 Deferred tax expense/(bene\ufb01t) 231 18 (9) Income tax expense/(bene\ufb01t) 2,912 957 (1,026) Tax expense/(bene\ufb01t) 2,599 1,254 (1,465) (b) Reconciliation of income tax expense Pro\ufb01t/(loss) before tax 9,174 3,290 (5,440) PRRT bene\ufb01t/(expense) 313 (297) 439 Pro\ufb01t/(loss) before income tax 9,487 2,993 (5,001) Income tax expense/(bene\ufb01t) calculated at 30% 2,847 898 (1,500) Effect of tax rate differentials (141) (42) 192 Effect of deferred tax assets not recognised 150 114 270 Foreign exchange impact on tax (bene\ufb01t)/ expense (44) (18) 3 Adjustment to prior years (45) (2) 7 Integration and transaction costs non- deductible 142 - - Other 3 7 2 Income tax expense/(bene\ufb01t) 2,912 957 (1,026) (c) Reconciliation of PRRT bene\ufb01t Pro\ufb01t/(loss) before tax 9,174 3,290 (5,440) Non-PRRT assessable (pro\ufb01t)/loss (6,197) (2,134) 3,080 PRRT projects pro\ufb01t/(loss) before tax 2,977 1,156 (2,360) PRRT expense/(bene\ufb01t) calculated at 40% 1,191 462 (944) (Recognition)/derecognition of Pluto general expenditure1 (1,362) - 627 Augmentation (175) (166) (138) Other 33 1 16 PRRT (bene\ufb01t)/expense (313) 297 (439) (d) Deferred tax income statement reconciliation PRRT Production and growth assets (710) 455 (242) Augmentation for current year (175) (166) (138) Provisions (12) (29) (32) Other 83 37 (27) PRRT (bene\ufb01t)/expense (814) 297 (439) Income tax Oil and gas properties 292 674 (981) Exploration and evaluation assets 14 (204) (210) Lease assets and liabilities 25 1 (16) Provisions 151 (10) (106) PRRT assets and liabilities 236 (88) 134 Unused tax losses and tax credits 19 149 (149) Assets held for sale 205 (205) - Derivatives 21 (11) 16 Other (31) 13 (5) Income tax deferred tax expense/(bene\ufb01t) 932 319 (1,317) Deferred tax expense/(bene\ufb01t) 118 616 (1,756) (e) Deferred tax other comprehensive income reconciliation Income tax Derivatives (64) 5 (25) Other (2) 5 6 Deferred income tax (bene\ufb01t)/expense via other comprehensive income (66) 10 (19) A.5 Taxes 2022 2021 2020 % % % (f) Effective income tax rate: Australian and global operations Effective income tax rate2 Australia 30.0% 30.6% 29.6% Global 30.7% 32.0% 20.5% 1. The $1,362 million increase of the Pluto PRRT deferred tax asset is due to the recognition of previously unrecognised deductible expenditure that is now expected to be utilised to offset future taxable pro\ufb01ts. 2. The global operations effective income tax rate (ETR) is calculated as the Group\u2019s income tax expense divided by pro\ufb01t before income tax. The Australian operations ETR is calculated with reference to all Australian companies and excludes foreign exchange on settlement and revaluation of income tax liabilities. 2022 2021 US$m US$m (g) Deferred tax balance sheet reconciliation Deferred tax assets PRRT Production and growth assets 1,460 767 Augmentation for current year 113 166 Provisions 271 75 Other (23) (1) PRRT deferred tax assets 1,821 1,007 Income tax3 Oil and gas properties (1,496) - Exploration and evaluation assets 30 - Lease assets and liabilities 23 - Unused tax losses and tax credits 1,464 - Derivatives 23 - Provisions 60 - Other 34 - Income tax deferred tax assets 138 - Deferred tax assets 1,959 1,007 Deferred tax liabilities PRRT4 Production and growth assets 1,281 - Augmentation for current year (62) - Provisions (743) - Other 137 - PRRT deferred tax liabilities 613 - Income tax Oil and gas properties 2,857 1,520 Exploration and evaluation assets 67 51 Lease assets and liabilities (22) (38) Provisions (1,280) (706) PRRT assets and liabilities 347 303 Assets held for sale - (205) Derivatives (36) (15) Other (89) (32) Income tax deferred tax liabilities 1,844 878 Deferred tax liabilities 2,457 878 3. The Group was in a net income tax deferred tax liability position in 2021. 4. The Group was in a net PRRT deferred tax asset position in 2021. Key estimates and judgements (a) Income tax classi\ufb01cation 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 the USA Tax Consolidation Group (USA TCG) of $1,371 million (2021: nil) and $93 million (2021: nil) arising from regions 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 within those regions. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $250 million from the USA TCG, $146 million from USA entities outside of the USA TCG and $1,061 million from regions other than Australia and the USA have not been recognised as it is not currently probable that the assets will be utilised based on current planned activities in those regions (2021: $497 million unrecognised DTAs). PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. As a result of higher actual and forecast assessable revenues supporting future recoverability of unrecognised quarantined exploration and general expenditure, the Pluto PRRT DTA has increased by $1,362 million. In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable pro\ufb01ts are risk-adjusted where appropriate by a market premium risk rate to re\ufb02ect uncertainty inherent in long-term forecasts. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 pro\ufb01ts. $6,523 million (2021: $4,507 million) relates to the North West Shelf Project, $189 million (2021: $1,432 million) relates to remaining Pluto quarantined exploration expenditure and $831 million (2021: $1,071 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 bene\ufb01t 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 AASB 112/ 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 out\ufb02ows 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 re\ufb02ected as increases or decreases to tax expense in the period in which new information is available. A.5 Taxes (cont.) Tax transparency code Woodside participates in the Australian Board of Taxation\u2019s voluntary Tax Transparency Code (TTC). To increase public con\ufb01dence in the contributions and compliance of corporate taxpayers, the TTC recommends public disclosure of tax information. Part A of the recommended disclosures are addressed within this Taxes note and Part B within our Sustainable Development Report, supported by additional information on our website. 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 substantially 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 \ufb01nancial 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 pro\ufb01t nor the taxable pro\ufb01t. In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable pro\ufb01ts when assessing the extent to which a deferred tax asset can be recognised in the consolidated statement of \ufb01nancial 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory",
"language": "en",
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},
"fact-820": {
"value": "Key estimates and judgements (a) Income tax classi\ufb01cation 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 the USA Tax Consolidation Group (USA TCG) of $1,371 million (2021: nil) and $93 million (2021: nil) arising from regions 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 within those regions. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $250 million from the USA TCG, $146 million from USA entities outside of the USA TCG and $1,061 million from regions other than Australia and the USA have not been recognised as it is not currently probable that the assets will be utilised based on current planned activities in those regions (2021: $497 million unrecognised DTAs). PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. As a result of higher actual and forecast assessable revenues supporting future recoverability of unrecognised quarantined exploration and general expenditure, the Pluto PRRT DTA has increased by $1,362 million. In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable pro\ufb01ts are risk-adjusted where appropriate by a market premium risk rate to re\ufb02ect uncertainty inherent in long-term forecasts. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 pro\ufb01ts. $6,523 million (2021: $4,507 million) relates to the North West Shelf Project, $189 million (2021: $1,432 million) relates to remaining Pluto quarantined exploration expenditure and $831 million (2021: $1,071 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 bene\ufb01t 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 AASB 112/ 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 out\ufb02ows 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 re\ufb02ected as increases or decreases to tax expense in the period in which new information is available. A.5 Taxes (cont.) Tax transparency code Woodside participates in the Australian Board of Taxation\u2019s voluntary Tax Transparency Code (TTC). To increase public con\ufb01dence in the contributions and compliance of corporate taxpayers, the TTC recommends public disclosure of tax information. Part A of the recommended disclosures are addressed within this Taxes note and Part B within our Sustainable Development Report, supported by additional information on our website. 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 substantially 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 \ufb01nancial 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 pro\ufb01t nor the taxable pro\ufb01t. In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable pro\ufb01ts when assessing the extent to which a deferred tax asset can be recognised in the consolidated statement of \ufb01nancial 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory",
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"entity": "scheme:2549005ZC5RXAOO7FH41",
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},
"fact-830": {
"value": "Key estimates and judgements (a) Income tax classi\ufb01cation 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 the USA Tax Consolidation Group (USA TCG) of $1,371 million (2021: nil) and $93 million (2021: nil) arising from regions 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 within those regions. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $250 million from the USA TCG, $146 million from USA entities outside of the USA TCG and $1,061 million from regions other than Australia and the USA have not been recognised as it is not currently probable that the assets will be utilised based on current planned activities in those regions (2021: $497 million unrecognised DTAs). PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. As a result of higher actual and forecast assessable revenues supporting future recoverability of unrecognised quarantined exploration and general expenditure, the Pluto PRRT DTA has increased by $1,362 million. In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable pro\ufb01ts are risk-adjusted where appropriate by a market premium risk rate to re\ufb02ect uncertainty inherent in long-term forecasts. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 pro\ufb01ts. $6,523 million (2021: $4,507 million) relates to the North West Shelf Project, $189 million (2021: $1,432 million) relates to remaining Pluto quarantined exploration expenditure and $831 million (2021: $1,071 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2021: 1.5%) 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 bene\ufb01t 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 AASB 112/ 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 out\ufb02ows 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 re\ufb02ected as increases or decreases to tax expense in the period in which new information is available. A.5 Taxes (cont.) Tax transparency code Woodside participates in the Australian Board of Taxation\u2019s voluntary Tax Transparency Code (TTC). To increase public con\ufb01dence in the contributions and compliance of corporate taxpayers, the TTC recommends public disclosure of tax information. Part A of the recommended disclosures are addressed within this Taxes note and Part B within our Sustainable Development Report, supported by additional information on our website. 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 substantially 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 \ufb01nancial 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 pro\ufb01t nor the taxable pro\ufb01t. In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable pro\ufb01ts when assessing the extent to which a deferred tax asset can be recognised in the consolidated statement of \ufb01nancial 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. ",
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"fact-765": {
"value": "B.2 Exploration and evaluation Asia Paci\ufb01c Americas Africa Total US$m US$m US$m US$m Year ended 31 December 2022 Carrying amount at 1 January 2022 546 - 68 614 Acquisitions through business combination1 - 180 - 180 Additions 19 204 17 240 Disposals - (10) - (10) Amortisation of licence acquisition costs - (8) (2) (10) Expensed2 - (126) (45) (171) Transferred exploration and evaluation (36) - - (36) Carrying amount at 31 December 2022 529 240 38 807 Year ended 31 December 20213 Carrying amount at 1 January 2021 1,981 - 64 2,045 Additions 494 - 7 501 Amortisation of licence acquisition costs - - (3) (3) Expensed2 (265) - - (265) Transferred exploration and evaluation (1,664) - - (1,664) Carrying amount at 31 December 2021 546 - 68 614 Exploration commitments Year ended 31 December 2022 1 1 27 29 Year ended 31 December 20213 16 1 77 94 1. Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is obtained within 12 months from the acquisition date. Refer to Note B.5 for details. 2. $125 million (2021: $56 million) relates to costs of unsuccessful wells. For the year ended 31 December 2021, $209 million relates to capitalised costs written off due to the Group\u2019s decision to withdraw its interests in Myanmar. 3. Oceania and Asia have been presented within Asia Paci\ufb01c for the year ended 31 December 2022. The 2021 amounts have been reclassi\ufb01ed to be presented on the same basis. Recognition and measurement Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method. Areas of interest 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: \u2022 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 \u2022 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 oil and gas properties. In the consolidated statement of cash \ufb02ows, those cash \ufb02ows associated with capitalised exploration and evaluation expenditure, including unsuccessful wells, are classi\ufb01ed as cash \ufb02ows used in investing activities. Exploration commitments The Group has exploration expenditure obligations which are contracted for, but not provided for in the \ufb01nancial statements. These obligations may be varied from time to time and are expected to be ful\ufb01lled in the normal course of the Group\u2019s operations. Impairment Refer to Note B.4 for details on impairment, including any write-offs. Key estimates and judgements (a) Area of interest Typically, an area of interest (AOI) is de\ufb01ned 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. ",
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"fact-796": {
"value": "Recognition and measurement Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method. Areas of interest 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: \u2022 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 \u2022 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 oil and gas properties. In the consolidated statement of cash \ufb02ows, those cash \ufb02ows associated with capitalised exploration and evaluation expenditure, including unsuccessful wells, are classi\ufb01ed as cash \ufb02ows used in investing activities. Exploration commitments The Group has exploration expenditure obligations which are contracted for, but not provided for in the \ufb01nancial statements. These obligations may be varied from time to time and are expected to be ful\ufb01lled in the normal course of the Group\u2019s operations. Impairment Refer to Note B.4 for details on impairment, including any write-offs. Key estimates and judgements (a) Area of interest Typically, an area of interest (AOI) is de\ufb01ned 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. ",
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"fact-766": {
"value": "Land and buildings Transferred exploration and evaluation Plant and equipment Projects in development Total US$m US$m US$m US$m US$m Year ended 31 December 2022 Carrying amount at 1 January 2022 739 526 12,465 4,919 18,649 Acquisitions through business combinations1 64 - 11,952 7,337 19,353 Additions2 - - (508) 4,332 3,824 Disposals at written down value (3) (10) (32) - (45) Depreciation and amortisation (54) (107) (2,637) - (2,798) Impairment reversal3 87 30 783 - 900 Completions and transfers 7 42 1,034 (1,047) 36 Carrying amount at 31 December 2022 840 481 23,057 15,541 39,919 At 31 December 2022 Historical cost 1,765 1,538 45,273 15,937 64,513 Accumulated depreciation and impairment (925) (1,057) (22,216) (396) (24,594) Net carrying amount 840 481 23,057 15,541 39,919 Year ended 31 December 20214 Carrying amount at 1 January 2021 749 431 12,091 2,195 15,466 Additions - - 13 2,321 2,334 Disposals at written down value (2) - (6) (22) (30) Depreciation and amortisation (51) (79) (1,449) - (1,579) Impairment losses3 (10) - - - (10) Impairment reversal3 44 66 911 37 1,058 Completions and transfers 11 108 905 640 1,664 Transfer to assets held for sale5 (2) - - (252) (254) Carrying amount at 31 December 2021 739 526 12,465 4,919 18,649 At 31 December 20214 Historical cost 1,701 1,495 32,796 5,321 41,313 Accumulated depreciation and impairment (962) (969) (20,331) (402) (22,664) Net carrying amount 739 526 12,465 4,919 18,649 1. Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is obtained within 12 months from the acquisition date. Refer to Note B.5 for details. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations. 2. Includes $3,904 million of capital additions and $294 million of capitalised borrowing costs offset by $374 million following changes in restoration provision assumptions. 3. Refer to Note B.4 for details on impairment losses and impairment reversals. 4. Oil and gas properties includes other plant and equipment which is no longer separately presented in the consolidated statement of \ufb01nancial position. The 2021 amounts have been reclassi\ufb01ed to be presented on the same basis. 5. Refer to Note B.7 for details on assets held for sale. B.3 Oil and gas properties Key estimates and judgements (a) Reserves The estimation of reserves requires signi\ufb01cant 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\u2019s oil and gas properties. Judgement is used in determining the economic reserve base applied to each asset. Typically, late life oil assets use proved reserves. Estimates are reviewed at least annually or when there are changes in the economic circumstances impacting speci\ufb01c assets or asset groups. These changes may impact depreciation, asset carrying values, restoration provisions and deferred tax balances. If proved plus probable (2P) reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the asset\u2019s carrying value. (b) Depreciation and amortisation Judgement is required to determine when assets are available for use to commence depreciation and amortisation. Depreciation and amortisation generally commences on \ufb01rst production. B.3 Oil and gas properties (cont.) Recognition and measurement Oil and gas properties are stated at cost less accumulated depreciation and impairment charges. Oil and gas properties 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. Subsequent capital costs, including major maintenance, are included in the asset\u2019s carrying amount only when it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group and the cost of the item can be reliably measured. Depreciation and amortisation Oil and gas properties are depreciated to their estimated residual values at rates based on their expected useful lives. Transferred exploration and evaluation and offshore plant and equipment are depreciated using the unit of production basis over proved plus probable reserves or proved reserves for late life assets. The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. For certain offshore assets, methodologies using proved and probable reserves are adjusted to best re\ufb02ect the expected pattern of consumption. Onshore plant and equipment is 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 oil and gas properties are depreciated using the straight-line method over their useful life. They are depreciated as follows: \u2022 Buildings \u2013 24-50 years; \u2022 Plant and equipment \u2013 2-40 years; and \u2022 Land is not depreciated. Impairment Refer to Note B.4 for details on impairment. Capital commitments The Group has capital expenditure commitments contracted for, but not provided for in the \ufb01nancial statements, of $7,762 million as at 31 December 2022 (2021: $7,875 million). Capital expenditure commitments relate predominantly to the Scarborough and Sangomar projects. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-797": {
"value": "Key estimates and judgements (a) Reserves The estimation of reserves requires signi\ufb01cant 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\u2019s oil and gas properties. Judgement is used in determining the economic reserve base applied to each asset. Typically, late life oil assets use proved reserves. Estimates are reviewed at least annually or when there are changes in the economic circumstances impacting speci\ufb01c assets or asset groups. These changes may impact depreciation, asset carrying values, restoration provisions and deferred tax balances. If proved plus probable (2P) reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the asset\u2019s carrying value. (b) Depreciation and amortisation Judgement is required to determine when assets are available for use to commence depreciation and amortisation. Depreciation and amortisation generally commences on \ufb01rst production. B.3 Oil and gas properties (cont.) Recognition and measurement Oil and gas properties are stated at cost less accumulated depreciation and impairment charges. Oil and gas properties 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. Subsequent capital costs, including major maintenance, are included in the asset\u2019s carrying amount only when it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group and the cost of the item can be reliably measured. Depreciation and amortisation Oil and gas properties are depreciated to their estimated residual values at rates based on their expected useful lives. Transferred exploration and evaluation and offshore plant and equipment are depreciated using the unit of production basis over proved plus probable reserves or proved reserves for late life assets. The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. For certain offshore assets, methodologies using proved and probable reserves are adjusted to best re\ufb02ect the expected pattern of consumption. Onshore plant and equipment is 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 oil and gas properties are depreciated using the straight-line method over their useful life. They are depreciated as follows: \u2022 Buildings \u2013 24-50 years; \u2022 Plant and equipment \u2013 2-40 years; and \u2022 Land is not depreciated. Impairment Refer to Note B.4 for details on impairment. Capital commitments The Group has capital expenditure commitments contracted for, but not provided for in the \ufb01nancial statements, of $7,762 million as at 31 December 2022 (2021: $7,875 million). Capital expenditure commitments relate predominantly to the Scarborough and Sangomar projects. ",
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"fact-821": {
"value": "Recognition and measurement Oil and gas properties are stated at cost less accumulated depreciation and impairment charges. Oil and gas properties 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. Subsequent capital costs, including major maintenance, are included in the asset\u2019s carrying amount only when it is probable that future economic bene\ufb01ts associated with the item will \ufb02ow to the Group and the cost of the item can be reliably measured. Depreciation and amortisation Oil and gas properties are depreciated to their estimated residual values at rates based on their expected useful lives. Transferred exploration and evaluation and offshore plant and equipment are depreciated using the unit of production basis over proved plus probable reserves or proved reserves for late life assets. The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. For certain offshore assets, methodologies using proved and probable reserves are adjusted to best re\ufb02ect the expected pattern of consumption. Onshore plant and equipment is 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 oil and gas properties are depreciated using the straight-line method over their useful life. They are depreciated as follows: \u2022 Buildings \u2013 24-50 years; \u2022 Plant and equipment \u2013 2-40 years; and \u2022 Land is not depreciated. ",
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"fact-822": {
"value": "Capital commitments The Group has capital expenditure commitments contracted for, but not provided for in the \ufb01nancial statements, of $7,762 million as at 31 December 2022 (2021: $7,875 million). Capital expenditure commitments relate predominantly to the Scarborough and Sangomar projects. ",
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"fact-767": {
"value": "B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill 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 oil and gas properties. Impairment calculations The recoverable amounts of exploration and evaluation assets are determined using FVLCD, as there is no value in use (VIU). Costs to dispose are the incremental costs directly attributable to the disposal of an asset, excluding \ufb01nance costs and income tax expense. 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. For assets previously impaired, if the recoverable amount exceeds the carrying amount, the impairment is reversed, but only to the extent that the asset\u2019s carrying amount does not exceed the carrying amount that would have been recognised if no impairment had occurred. Oil and gas properties Impairment testing The carrying amounts of oil and gas properties 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, expected future sales prices or costs. Oil and gas properties 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 \ufb01elds. If there is an indicator of impairment or impairment reversal for a CGU, its recoverable amount is calculated and compared with the CGU\u2019s 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\u2019s cash-generating units (CGUs) that are expected to bene\ufb01t 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 oil and gas impairment calculations The recoverable amount of an asset or CGU is determined as the higher of its VIU and FVLCD. VIU is determined by estimating future cash \ufb02ows after taking into account the risks speci\ufb01c 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 re\ufb02ect the effects of factors that may be speci\ufb01c to the Group. In determining FVLCD, recent market transactions are considered. If no such transactions can be identi\ufb01ed, an appropriate valuation model, such as discounted cash \ufb02ow techniques, are 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 \ufb01rst 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 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 or amortisation, if no impairment had been recognised. Impairments of goodwill are not reversed. B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.) For the year ended 31 December 2022 Goodwill allocation The Group performed its annual goodwill impairment test as at 31 December 2022. The carrying amount of goodwill allocated to each CGU, or groups of CGUs and excess recoverable amounts are as follows: Segment CGU Goodwill carrying amount1 Excess of recoverable amount over CGU carrying amount2 US$m US$m Australia Pluto-Scarborough 2,955 7,656 Australia NWS Gas 394 1,399 International Shenzi 469 401 International Atlantis 513 189 International Other goodwill 283 107 Total 4,614 1. Carrying amount of goodwill as at 31 December 2021 was nil. 2. Amounts are with reference to the total CGU value including goodwill. Other goodwill of $283 million (2021: nil) has been allocated across a number of CGUs within the International segment. This represents less than one percent of net assets as at 31 December 2022. Recognised impairment and impairment reversals As at 31 December 2022, the Group assessed each AOI and CGU to determine whether an indicator of impairment or impairment reversal existed. The Group identi\ufb01ed the following indicators of impairment reversals: \u2022 Wheatstone CGU \u2013 revision in short- and long-term LNG price assumptions and updated cost and production pro\ufb01les. For CGUs where goodwill has been allocated, no impairment was recognised as the recoverable amount exceeds the carrying amount of the CGU. An impairment reversal was recognised for Wheatstone (refer to Note A.1), with results as follows: Impairment reversal Oil and gas properties Recoverable amount Land and buildings Transferred exploration and evaluation Plant and equipment Total Segment CGU US$m US$m US$m US$m US$m Australia Wheatstone 3,456 87 30 783 900 Recoverable amounts have been determined using the FVLCD method using discounted cash \ufb02ow projections, classi\ufb01ed as Level 3 on the fair value hierarchy. The carrying amount of each CGU includes all assets allocated to the respective CGU. Refer to key estimates and judgements for further details. Sensitivity analysis Recoverable amount valuations are sensitive to changes in certain key accounting estimates and judgements (refer to key estimates and judgements for further details). Reasonable possible changes to these key assumptions are set out below: \u2022 Post tax discount rate \u2013 plus or minus 1.5% (representing a change of 150 basis points) \u2022 Commodity pricing \u2013 plus or minus 10% \u2022 Foreign exchange (FX) rate \u2013 plus or minus 12% \u2022 Production volumes \u2013 plus or minus 4% Management\u2019s analysis on the impact of reasonable possible changes to these assumptions on recoverable amounts is detailed below. B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.) For the year ended 31 December 2022 (cont.) Sensitivity analysis (cont.) CGUs with impairment or impairment reversals Changes in the following key assumptions have been estimated to result in a higher or lower carrying amount1 than what was determined as at 31 December 2022: Sensitivity (US$m)2 CGU Discount rate increase\u00b3 Discount rate decrease\u00b3 Brent price increase Brent price decrease FX increase FX increase Production increase\u2074 Production decrease\u2074 Wheatstone (117) 127 294 (294) (79) 79 116 (43) 1. Increases to carrying amounts are limited to historical impairment losses recognised, net of depreciation and amortisation, that would have been recognised had no impairment taken place. 2. The sensitivities represent the reasonable possible changes to discount rate, oil price, FX and production volumes assumptions. 3. The relationship between the discount rate and the carrying amount is non-linear and as such, sensitivities are unlikely to result in a symmetrical impact. Due to the non- linear relationship, the impact of changing the discount rate is likely to be greater at a lower discount rate than at a higher discount rate. 4. The relationship between production and the carrying amount is non-linear due to the proportion of \ufb01xed costs. Sensitivities are therefore unlikely to result in a symmetrical impact. A signi\ufb01cant change in production volumes would typically require a reassessment of the asset concept and should not be interpreted in isolation. A change in any of the above assumptions would likely have an impact on other assumptions which, when considered together, may offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions. CGUs with goodwill The valuation of CGUs with goodwill are most sensitive to changes in commodity prices and discount rates. Reasonably possible changes in these estimates which could result in the estimated recoverable amount being equal to the carrying amount, assuming all other variables are held constant, are as follows: CGU Commodity price1 Nominal discount rate % change (absolute terms) Oil and gas properties Pluto-Scarborough N/A\u00b2 N/A\u00b2 Oil and gas properties NWS Gas N/A\u00b2 N/A\u00b2 Oil and gas properties Shenzi (7%) N/A \u00b2 Oil and gas properties Atlantis (2%) 10% 1. Brent price applies to Pluto-Scarborough and NWS Gas. WTI price (Brent - $3/bbl) applies to Shenzi and Atlantis. 2. Management considers there to be no reasonably possible change in the respective estimate which, in isolation, would result in the estimated recoverable amount being equal to the carrying amount. A change in any of the above assumptions would have an impact on other assumptions which when considered together may offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions. Management considers there to be no reasonably possible changes in production volumes, carbon prices or foreign exchange rates that would, in isolation result in the estimated recoverable amount being equal to the carrying amount. Analysis of key assumptions which could result in the carrying value to equal the recoverable value provides a basis to assess the magnitude of a reasonable possible change to the carrying amounts of respective CGUs. Key estimates and judgements CGU determination Identi\ufb01cation of a CGU requires management judgement. In determining CGUs for acquired assets during the reporting period, management has assessed based on the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or groups of assets. Allocation of goodwill Allocation of goodwill to the relevant CGUs requires management judgement. The goodwill arising from the merger has been allocated to relevant CGUs which are expected to bene\ufb01t from the expected synergies as a result of the merger. Recoverable amount calculation key assumptions In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash \ufb02ows when determining the FVLCD. These estimates require signi\ufb01cant 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 \ufb02ow estimates. The basis for each estimate used to determine recoverable amounts as at 31 December 2022 is set out below: \u2022 Resource estimates \u2013 2P and a portion of 2C reserves (where applicable) for oil and gas properties. The reserves are as disclosed in the Reserves and Resources Statement in the 31 December 2022 Annual Report. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied for US based assets and 2.5% for Australian based assets. \u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on management\u2019s view of long-term exchange rates. For the year ended 31 December 2021 Recognised impairment and impairment reversals As at 31 December 2021, the Group identi\ufb01ed the following indicators for impairment and impairment reversals: \u2022 Pluto-Scarborough and Wheatstone CGU \u2013 a reduction of 2P total reserves within the Greater Pluto and Wheatstone reserves and resources estimates. \u2022 Pluto-Scarborough CGU \u2013 additional value generated by Scarborough and Pluto Train 2, which have been combined with Pluto into a new Pluto-Scarborough CGU following the \ufb01nal investment decision for Scarborough and Pluto Train 2 in November 2021. \u2022 North West Shelf CGU \u2013 updated cost and production pro\ufb01les, including the impact of third-party processing agreements, and short-term pricing assumptions. \u2022 NWS Oil (Okha) CGU \u2013 the reclassi\ufb01cation to a late life oil asset due to natural reservoir decline and short-term pricing assumptions. No impairment was recognised for Wheatstone and NWS Oil (Okha) as the recoverable amount exceeds the carrying amount of the CGU. Impairment reversals were recognised for Pluto-Scarborough and NWS Gas (refer to Note A.1). The results were as follows: Impairment reversal Oil and gas properties Recoverable amount Land and buildings Transferred exploration and evaluation Plant and equipment Projects in development Total Segment CGU US$m US$m US$m US$m US$m US$m Producing and Development Pluto-Scarborough 17,474 42 53 563 24 682 Producing North West Shelf 2,425 2 13 348 13 376 Total 19,899 44 66 911 37 1,058 The recoverable amounts were determined using the VIU method. The carrying amounts of the CGUs include all assets allocated to the CGU. Refer to key estimates and judgements for further details. Key estimates and judgements (cont.) Recoverable amount calculation key assumptions (cont.) \u2022 Discount rates \u2013 a range of post-tax discount rates between 8% and 11.5% for CGUs has been applied. The discount rate re\ufb02ects an assessment of the risks speci\ufb01c to the asset. \u2022 Carbon pricing \u2013 a long-term price of US$80/tonne of emissions (real terms 2022) is based on management\u2019s assumptions on carbon cost pricing and incorporates an evaluation of climate risk. This is applicable to Australian emissions that exceed facility- speci\ufb01c baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. Refer to Climate change and energy transition section within the basis of preparation for further information. \u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. \u2022 Brent oil prices \u2013 derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is signi\ufb01cant uncertainty around how society will respond to the climate challenge; Woodside\u2019s pricing assumptions re\ufb02ect a \u2018best estimate\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in the Climate change and energy transition section within the basis of preparation. The nominal Brent oil prices (US$/bbl) used were: 2023 2024 2025 2026 2027 2028 31 December 20221 87 78 74 76 77 79 31 December 20212 71 68 69 70 72 73 1. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 2. Long-term oil prices are based on US$65/bbl (2022 real terms) from 2024 and prices are escalated at 2.0% onwards. B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.) For the year ended 31 December 2022 (cont.) B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill (cont.) For the year ended 31 December 2021 (cont.) Sensitivity analysis Changes in the following key assumptions were estimated to result in a higher or lower carrying amounts1 than what was determined as at 31 December 2021: Sensitivity (US$m)2 Discount rate: increase of 1% 3,4 Discount rate: decrease of 1% Brent price: increase of 10% Brent price: decrease of 10% FX: increase of 12%5 FX: decrease of 12% Oil and gas properties Producing and Development Pluto- Scarborough - - - - - - Producing North West Shelf - - - (13) - - Wheatstone (159) 178 438 (438) (122) 122 NWS Oil (Okha) (4) 4 39 (39) (28) 28 1. Increases to carrying amounts are limited to historical impairment losses recognised, net of depreciation and amortisation that would have been incurred had no impairment taken place. 2. The sensitivities represent reasonable possible changes to the discount rate, oil price and FX assumptions. 3. A change of 1% represents 100 basis points. 4. The relationship between the discount rate and carrying amount is non-linear and as such, the sensitivities are unlikely to result in a symmetrical impact. Due to the non-linear relationship, the impact of changing the discount rate is likely to be greater at a lower discount rate than at a higher discount rate. 5. FX sensitivity of +12%/-12% was determined based on historical 5-year standard deviation of AU$/US$. Impairment on non-current assets held for sale The sale of a portion of the Wheatstone Construction Village resulted in an impairment loss of $10 million as the asset\u2019s carrying value exceeded its FVLCD, which was determined based on the underlying sale agreements, classi\ufb01ed as Level 3 on the fair value hierarchy. For the year ended 31 December 2021, an impairment loss of $10 million was recognised in the Australia operating segment of Note A.1. Key estimates and judgements CGU determination Identi\ufb01cation of a CGU requires management judgement. For the year ended 31 December 2021, management has determined that the Scarborough and Pluto Train 2 development concept integrates with the existing Pluto onshore assets and is the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or group of assets. Recoverable amount calculation key assumptions In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash \ufb02ows when determining the VIU. These estimates require signi\ufb01cant 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 \ufb02ow estimates. The basis for each estimate used to determine recoverable amounts as at 31 December 2021 is set out below: \u2022 Resource estimates \u2013 2P reserves for oil and gas properties, except for NWS Oil (Okha) which is based on 1P reserves due to the reclassi\ufb01cation to a late life asset. The reserves are as disclosed in the Reserves and resources statement in the 31 December 2021 Annual Report on pages 55-59. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied. \u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on management\u2019s view of long-term exchange rates. \u2022 Discount rates \u2013 a range of pre-tax discount rates between 8.9% and 11.6% (post-tax discount rate 7.5%-8.5%) for CGUs has been applied. The discount rate re\ufb02ects an assessment of the risks speci\ufb01c to the asset. \u2022 An evaluation of climate risk is re\ufb02ected in Woodside's assumptions on carbon cost pricing, including a long-term Australian carbon price of US$80/tonne of emissions (real terms 2022). This is applicable to Australian emissions that exceed facility-speci\ufb01c baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. \u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. \u2022 Brent oil prices \u2013 derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is signi\ufb01cant uncertainty around how society will respond to the climate challenge; Woodside\u2019s pricing assumptions re\ufb02ect a \u2018most-likely\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in Woodside\u2019s Climate Report 2021. The nominal Brent oil prices (US$/bbl) used were: 2022 2023 2024 2025 2026 2027 31 December 20211 73 71 68 69 70 72 30 June 20202 57 62 67 72 73 75 1. Based on US$65/bbl (2022 real terms) from 2024 with prices escalated at 2.0% annually thereafter. 2. Based on US$65/bbl (2020 real terms) from 2025 with prices escalated at 2.0% annually thereafter. ",
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"value": "B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill 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 oil and gas properties. Impairment calculations The recoverable amounts of exploration and evaluation assets are determined using FVLCD, as there is no value in use (VIU). Costs to dispose are the incremental costs directly attributable to the disposal of an asset, excluding \ufb01nance costs and income tax expense. 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. For assets previously impaired, if the recoverable amount exceeds the carrying amount, the impairment is reversed, but only to the extent that the asset\u2019s carrying amount does not exceed the carrying amount that would have been recognised if no impairment had occurred. Oil and gas properties Impairment testing The carrying amounts of oil and gas properties 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, expected future sales prices or costs. Oil and gas properties 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 \ufb01elds. If there is an indicator of impairment or impairment reversal for a CGU, its recoverable amount is calculated and compared with the CGU\u2019s 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\u2019s cash-generating units (CGUs) that are expected to bene\ufb01t 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 oil and gas impairment calculations The recoverable amount of an asset or CGU is determined as the higher of its VIU and FVLCD. VIU is determined by estimating future cash \ufb02ows after taking into account the risks speci\ufb01c 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 re\ufb02ect the effects of factors that may be speci\ufb01c to the Group. In determining FVLCD, recent market transactions are considered. If no such transactions can be identi\ufb01ed, an appropriate valuation model, such as discounted cash \ufb02ow techniques, are 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 \ufb01rst 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 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 or amortisation, if no impairment had been recognised. Impairments of goodwill are not reversed. Key estimates and judgements CGU determination Identi\ufb01cation of a CGU requires management judgement. In determining CGUs for acquired assets during the reporting period, management has assessed based on the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or groups of assets. Allocation of goodwill Allocation of goodwill to the relevant CGUs requires management judgement. The goodwill arising from the merger has been allocated to relevant CGUs which are expected to bene\ufb01t from the expected synergies as a result of the merger. Recoverable amount calculation key assumptions In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash \ufb02ows when determining the FVLCD. These estimates require signi\ufb01cant 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 \ufb02ow estimates. The basis for each estimate used to determine recoverable amounts as at 31 December 2022 is set out below: \u2022 Resource estimates \u2013 2P and a portion of 2C reserves (where applicable) for oil and gas properties. The reserves are as disclosed in the Reserves and Resources Statement in the 31 December 2022 Annual Report. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied for US based assets and 2.5% for Australian based assets. \u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on management\u2019s view of long-term exchange rates. Key estimates and judgements (cont.) Recoverable amount calculation key assumptions (cont.) \u2022 Discount rates \u2013 a range of post-tax discount rates between 8% and 11.5% for CGUs has been applied. The discount rate re\ufb02ects an assessment of the risks speci\ufb01c to the asset. \u2022 Carbon pricing \u2013 a long-term price of US$80/tonne of emissions (real terms 2022) is based on management\u2019s assumptions on carbon cost pricing and incorporates an evaluation of climate risk. This is applicable to Australian emissions that exceed facility- speci\ufb01c baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. Refer to Climate change and energy transition section within the basis of preparation for further information. \u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. \u2022 Brent oil prices \u2013 derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is signi\ufb01cant uncertainty around how society will respond to the climate challenge; Woodside\u2019s pricing assumptions re\ufb02ect a \u2018best estimate\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in the Climate change and energy transition section within the basis of preparation. The nominal Brent oil prices (US$/bbl) used were: 2023 2024 2025 2026 2027 2028 31 December 20221 87 78 74 76 77 79 31 December 20212 71 68 69 70 72 73 1. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 2. Long-term oil prices are based on US$65/bbl (2022 real terms) from 2024 and prices are escalated at 2.0% onwards. Key estimates and judgements CGU determination Identi\ufb01cation of a CGU requires management judgement. For the year ended 31 December 2021, management has determined that the Scarborough and Pluto Train 2 development concept integrates with the existing Pluto onshore assets and is the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or group of assets. Recoverable amount calculation key assumptions In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash \ufb02ows when determining the VIU. These estimates require signi\ufb01cant 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 \ufb02ow estimates. The basis for each estimate used to determine recoverable amounts as at 31 December 2021 is set out below: \u2022 Resource estimates \u2013 2P reserves for oil and gas properties, except for NWS Oil (Okha) which is based on 1P reserves due to the reclassi\ufb01cation to a late life asset. The reserves are as disclosed in the Reserves and resources statement in the 31 December 2021 Annual Report on pages 55-59. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% has been applied. \u2022 Foreign exchange rates \u2013 a rate of $0.75 US$:AU$ is based on management\u2019s view of long-term exchange rates. \u2022 Discount rates \u2013 a range of pre-tax discount rates between 8.9% and 11.6% (post-tax discount rate 7.5%-8.5%) for CGUs has been applied. The discount rate re\ufb02ects an assessment of the risks speci\ufb01c to the asset. \u2022 An evaluation of climate risk is re\ufb02ected in Woodside's assumptions on carbon cost pricing, including a long-term Australian carbon price of US$80/tonne of emissions (real terms 2022). This is applicable to Australian emissions that exceed facility-speci\ufb01c baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. \u2022 LNG price \u2013 the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. \u2022 Brent oil prices \u2013 derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is signi\ufb01cant uncertainty around how society will respond to the climate challenge; Woodside\u2019s pricing assumptions re\ufb02ect a \u2018most-likely\u2019 scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in Woodside\u2019s Climate Report 2021. The nominal Brent oil prices (US$/bbl) used were: 2022 2023 2024 2025 2026 2027 31 December 20211 73 71 68 69 70 72 30 June 20202 57 62 67 72 73 75 1. Based on US$65/bbl (2022 real terms) from 2024 with prices escalated at 2.0% annually thereafter. 2. Based on US$65/bbl (2020 real terms) from 2025 with prices escalated at 2.0% annually thereafter. ",
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"fact-768": {
"value": "B.5 Business combination BHP Petroleum merger On 17 August 2021, Woodside and BHP Group (BHP) entered into a merger commitment deed to combine their respective oil and gas portfolios by an all-stock merger. The Share Sale Agreement (SSA) and the integration and transition services agreement were executed on 22 November 2021. Under the SSA, the merger took economic effect from 1 July 2021 and Woodside became entitled to the economic bene\ufb01ts and risks of the assets and liabilities that were the subject of the merger from that date. On 19 May 2022, 98.66% of Woodside shareholders voted in favour of the merger at Woodside\u2019s Annual General Meeting. On 1 June 2022, the transaction was completed with the Group acquiring 100% of the issued share capital of BHP Petroleum International Pty Ltd (subsequently renamed Woodside Energy Global Holdings Pty Ltd), which held BHP\u2019s oil and gas business. In exchange, the Group issued 914,768,948 new Woodside shares to BHP as part of the merger consideration. The transaction has been accounted for as a business combination with an acquisition date of 1 June 2022. The Group\u2019s net pro\ufb01t after tax for the year ended 31 December 2022 incorporates BHPP results from acquisition date. The merger is expected to create opportunities to realise ongoing synergies. Due to the size, complexity and timing of the transaction, the assets acquired and liabilities assumed are measured on a provisional basis. As at 31 December 2022, the Allocable Cost Amount (ACA) tax valuation process has been substantially completed with potential adjustments if new information is obtained within 12 months from the acquisition date about facts and circumstances that existed at the acquisition date. Adjustments will be made to the provisional amounts recognised including the value of goodwill. The merged Group\u2019s \ufb01nancial results could be adversely affected by impairments of goodwill or other intangible assets, the application of future accounting policies or interpretations of existing accounting policies including by regulatory direction, and changes in estimates of decommissioning costs. Details and risks have been included in the Merger Explanatory Memorandum released on 8 April 2022. Given the purchase consideration was agreed on 22 November 2021 based on a \ufb01xed number of shares, the \ufb01nal value of consideration paid was subject to \ufb02uctuations in share price until completion on 1 June 2022. This has resulted in a material goodwill number which will be subject to impairment in future, for example should commodity prices decrease. Details of the purchase consideration and the provisional fair value of goodwill, identi\ufb01able assets and liabilities of BHPP acquired are as follows: Provisional fair value of net identi\ufb01able assets and goodwill arising on acquisition date US$m Cash and cash equivalents 399 Receivables 1,164 Inventories 295 Investments accounted for using the equity method 267 Other \ufb01nancial assets 59 Other assets 114 Exploration and evaluation assets 180 Oil and gas properties 19,353 Lease assets 142 Payables (910) Provisions (4,804) Tax payable (365) Deferred tax liabilities (576) Lease liabilities (268) Other liabilities (1,054) Net identi\ufb01able assets acquired 13,996 Goodwill arising on acquisition 4,614 Purchase consideration 18,610 Purchase consideration US$m Shares issued, at fair value 19,265 Other reserves (share replacement awards) 18 Provisional locked box payment received1 (683) Adjustments to locked box payment 10 Total purchase consideration 18,610 1. Represents the positive net cash \ufb02ow of $1,513 million generated by BHPP assets from the effective date of the business combination offset by the notional dividend distribution of $830 million paid to BHP. Analysis of cash \ufb02ows on acquisition US$m Cash acquired on acquisition 399 Provisional locked box payment received 683 Net cash \ufb02ow on acquisition (included in the consolidated statement of cash \ufb02ows as investing activities) 1,082 Acquisition-related costs of $419 million that were not directly attributable to the issue of shares are included as an expense in general, administration and other costs in the consolidated income statement. $357 million has been paid and included in the consolidated statement of cash \ufb02ows as operating activities. Acquisition-related costs of $5 million directly attributable to the issue of shares are included in contributed equity and included in the consolidated statement of cash \ufb02ows as \ufb01nancing activities. Shares issued, at fair value The fair value of 914,768,948 shares issued as part of the consideration paid to BHP was $19,265 million. This was based on the published share price on 1 June 2022 of US$21.06 per share. B.5 Business comination (cont.) Provisional locked box payment received The Group received $683 million as part of the merger consideration which includes the locked box payment of $1,513 million representing the positive net cash \ufb02ow generated by BHPP assets from the effective date of the transaction to completion date offset by the notional dividend distribution of $830 million paid to BHP. The $683 million of provisional locked box payment received and the $399 million of cash and cash equivalents acquired as part of the merger have been included within investing activities in the consolidated statement of cash \ufb02ows. Revenue and contribution to the Group The acquired business contributed operating revenue of $4,653 million and pro\ufb01t before tax of $2,042 million to the Group from the acquisition date to 31 December 2022. If the acquisition had occurred on 1 January 2022, consolidated operating revenue and pro\ufb01t before tax would have been higher by $3,115 million and $1,265 million respectively. Acquired receivables The fair value of receivables approximates the gross amount of trade receivables. None of the receivables have been impaired and the full contractual amounts are expected to be collected. Other liabilities The Group recognised contingent liabilities of $79 million within other liabilities. This is based on the Group\u2019s assessment of the fair value of contingent liabilities acquired on acquisition, taking into account a range of possible outcomes. As at 31 December 2022, there have been no changes to the amount recognised on acquisition date. Goodwill Goodwill arising from the acquisition has been recognised as the excess of consideration paid above the fair value of the assets acquired and liabilities assumed as part of the business combination. $1,958 million of the goodwill arises from the deferred tax liability recognised on acquisition as a consequence of asset tax bases received in the merger being lower than the fair value of the assets acquired. The remaining goodwill of $2,656 million re\ufb02ects the value expected to be generated from the Pluto-Scarborough CGU as a result of the merger. The goodwill is not deductible for tax purposes. 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\u2019s CGUs or groups of CGUs no larger than an operating segment that are expected to bene\ufb01t 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. Share replacement awards In accordance with the terms of the SSA, the Group exchanged equity-settled share-based payment awards held by employees of BHPP for equity-settled share-based payment awards of Woodside. The replacement awards are based on service conditions with a vesting date of 31 August 2023 and 31 August 2024. The fair value of the replacement awards on acquisition is $49 million based on a forfeiture rate of 3%. $18 million has been included as part of the purchase consideration and the remaining amount will be recognised as post-acquisition compensation cost. Business combination accounting The acquisition method of accounting is used to account for all business combinations, including business combinations involving entities or businesses under common control, regardless of whether equity instruments are issued or liabilities incurred or assumed at the date of exchange. Where equity instruments are issued in an acquisition, the fair value of the instruments is their published market price as at the date of exchange. Transaction costs arising on the issue of equity instruments are recognised directly in equity. Transaction costs that were not directly attributable to the issue of shares are expensed as incurred. Contractual assets and liabilities in respect of sales agreements are recognised at fair value. Restoration provisions are recognised on acquisition at fair value. Key estimates and judgements (a) 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 \ufb02ow model to estimate the expected future cash \ufb02ows of the oil and gas assets acquired, based on reserves and resources at acquisition date and the discount rate used. The expected future cash \ufb02ows are based on estimates of future production, commodity and carbon prices, operating costs, and forecast capital expenditures at acquisition date. Restoration provisions require judgemental assumptions regarding removal date, environmental legislation and regulations and the extent of restoration activities required in determining the cost estimate. Carry forward tax losses are recognised only if it is probable that sufficient future taxable income will be available to utilise the losses. (b) Goodwill allocation Judgement is required in the allocation of goodwill to the Group\u2019s CGUs that are expected to bene\ufb01t from the synergies of the business combination. Refer to Note B.4 for the details of the goodwill allocation. ",
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"fact-799": {
"value": "Business combination accounting The acquisition method of accounting is used to account for all business combinations, including business combinations involving entities or businesses under common control, regardless of whether equity instruments are issued or liabilities incurred or assumed at the date of exchange. Where equity instruments are issued in an acquisition, the fair value of the instruments is their published market price as at the date of exchange. Transaction costs arising on the issue of equity instruments are recognised directly in equity. Transaction costs that were not directly attributable to the issue of shares are expensed as incurred. Contractual assets and liabilities in respect of sales agreements are recognised at fair value. Restoration provisions are recognised on acquisition at fair value. Key estimates and judgements (a) 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 \ufb02ow model to estimate the expected future cash \ufb02ows of the oil and gas assets acquired, based on reserves and resources at acquisition date and the discount rate used. The expected future cash \ufb02ows are based on estimates of future production, commodity and carbon prices, operating costs, and forecast capital expenditures at acquisition date. Restoration provisions require judgemental assumptions regarding removal date, environmental legislation and regulations and the extent of restoration activities required in determining the cost estimate. Carry forward tax losses are recognised only if it is probable that sufficient future taxable income will be available to utilise the losses. (b) Goodwill allocation Judgement is required in the allocation of goodwill to the Group\u2019s CGUs that are expected to bene\ufb01t from the synergies of the business combination. Refer to Note B.4 for the details of the goodwill allocation. ",
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"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-769": {
"value": "B.6 Signi\ufb01cant production and growth asset acquisitions (a) Sangomar \u2013 Acquisition from FAR Senegal RSSD SA On 7 July 2021, Woodside completed the acquisition of FAR Senegal RSSD SA\u2019s interest in the RSSD Joint Venture (13.67% interest in the Sangomar exploitation area and 15% interest in the remaining RSSD evaluation area), for an aggregate purchase price of $212 million. The transaction was accounted for as an asset acquisition. Additional payments of up to $55 million are contingent on future commodity prices and timing of \ufb01rst oil. The contingent payments terminate on the earliest of 31 December 2027, three years from \ufb01rst oil being sold, and a total contingent payment of $55 million being reached. The contingent payments are accounted for as contingent liabilities in accordance with the Group\u2019s accounting policies. As at 31 December 2021, Woodside held an 82% interest in the Sangomar exploitation area (2020: 68.33%) and a 90% interest in the remaining RSSD evaluation area (2020: 75%). Assets acquired and liabilities assumed The identi\ufb01able assets and liabilities acquired as at the date of the acquisition inclusive of transaction costs are: US$m Oil and gas properties 205 Exploration and evaluation 7 Cash acquired 3 Payables (13) Net other assets and liabilities assumed 10 Total identi\ufb01able net assets at acquisition 212 Cash \ufb02ows on acquisition US$m Purchase cash consideration 212 Transaction costs - Total purchase consideration 212 Net cash out\ufb02ows on acquisition 212 Key estimates and judgements Nature of acquisition Judgement was required to determine if the transaction was the acquisition of an asset or a business combination. The Sangomar project was in the early phase of development and a substantive process that had the ability to convert inputs to outputs was not present and therefore the acquisition in 2021 was treated as asset acquisitions. (b) Sangomar \u2013 Acquisition from Capricorn Senegal Limited On 22 December 2020, Woodside completed the acquisition of Capricorn Senegal Limited\u2019s (Cairn\u2019s) interest in the RSSD Joint Venture (36.44% interest in the Sangomar exploitation area and 40% interest in the remaining RSSD evaluation area) for an aggregate purchase price of $527 million. The transaction was accounted for as an asset acquisition. Additional payments of up to $100 million are contingent on future commodity prices and the occurrence of \ufb01rst oil prior to 2025. The contingent payments are accounted for as contingent liabilities in accordance with the Group\u2019s accounting policies. Assets acquired and liabilities assumed The identi\ufb01able assets and liabilities acquired as at the date of the acquisition inclusive of transaction costs were: US$m Oil and gas properties 540 Exploration and evaluation 26 Cash acquired 5 Payables (51) Net other assets and liabilities assumed 7 Total identi\ufb01able net assets at acquisition 527 Cash \ufb02ows on acquisition US$m Purchase cash consideration 525 Transaction costs 2 Total purchase consideration 527 Net cash out\ufb02ows on acquisition 527",
"dimensions": {
"concept": "woodsideenergygroupltd:DisclosureOfSignificantProductionAndGrowthAssetAcquisitions",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-770": {
"value": "B.7 Disposal of assets Sell-down of Train 2 On 15 November 2021 the Group entered into a sale and purchase agreement with Global Infrastructure Partners (GIP) for the sale of a 49% non-operating participating interest in the Pluto Train 2 Joint Venture. As at 31 December 2021, the Group reclassi\ufb01ed the carrying value of the 49% interest in the Pluto Train 2 assets to assets held for sale. There were no recognised liabilities associated with the assets held for sale. The transaction completed on 18 January 2022, reducing the Group\u2019s participating interest from 100% to 51%. The Group recognised an initial pre-tax gain on sale of $427 million. The arrangements require GIP to fund its 49% share of capital expenditure from 1 October 2021 and an additional amount of construction capital expenditure of $822 million on behalf of the Group. If the total capital expenditure incurred is less than $5,800 million, GIP will pay Woodside an additional amount equal to 49% of the under-spend. In the event of a cost overrun, Woodside will fund up to $822 million of GIP\u2019s share of the overrun. Delays to the expected start-up of production will result in payments by Woodside to GIP in certain circumstances. The arrangements include provisions for GIP to be compensated for exposure to additional Scope 1 emissions liabilities above agreed baselines, and to sell its 49% interest back to Woodside if the status of key regulatory approvals materially changes. Given judgement was used to determine the consideration received, the Group is required to remeasure the variable consideration at each reporting period. As at 31 December 2022, the variable consideration has been remeasured with a $71 million revaluation gain recognised as other income, with a corresponding reduction to other liabilities. The fair value of the remaining unpaid funding from GIP has been netted against the other liabilities and will be recognised as oil and gas properties in the future. Key estimates and judgements Sell-down of Train 2 Given the arrangements include provisions for GIP to sell its 49% interest back to Woodside if the status of key regulatory environmental approvals materially changes and the requirement for Woodside to fund up to $822 million of GIP\u2019s share in the event of a cost overrun, judgement is required to determine if the sell- down of Train 2 constitutes a sale and if a portion of the transaction price should be considered a variable consideration. Judgement was used to determine that the sell-down of Train 2 constituted a sale given the various conditions included in the sale and purchase agreement. The Group determined that a sale occurred as control of the 49% interest was passed to GIP on completion date. Control is determined as the ability to direct the use of, and obtain substantially all of the economic bene\ufb01ts of, the associated interest. Judgement was used to determine if it is highly probable that a signi\ufb01cant reversal will not occur in relation to the consideration received. The Group estimated the variable consideration based on the construction capital expenditure cost pro\ufb01le, the development schedule, and assessing the probability and impact of any event which may result in a signi\ufb01cant reversal. The constraining estimates of variable consideration have been applied resulting in the initial pre-tax gain on sale of $427 million. The variable consideration is remeasured at each reporting period with any changes recognised through the consolidated income statement. As at 31 December 2022, the variable consideration has been remeasured with a $71 million revaluation gain recognised as other income. ",
"dimensions": {
"concept": "woodsideenergygroupltd:DisclosureOfDisposalOfAssets",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-800": {
"value": "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 \ufb02exible supply of funds is available to meet the Group\u2019s operating and capital expenditure requirements. A stable capital base is maintained from which the Group can pursue its growth aspirations, whilst maintaining a \ufb02exible 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 \ufb01nancial metrics are monitored, including gearing and cash \ufb02ow leverage, and Treasury policy breaches and exceptions. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-801": {
"value": "Liquidity risk management Liquidity risk arises from the \ufb01nancial liabilities of the Group and the Group\u2019s subsequent ability to meet its obligations to repay \ufb01nancial 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 \ufb01nancial commitments in a timely and cost-effective manner. The Group\u2019s liquidity is continually reviewed, including cash \ufb02ow forecasts to determine the forecast liquidity position and maintain appropriate liquidity levels. At 31 December 2022, the Group had a total of $10,239 million (2021: $6,125 million) of available undrawn facilities and cash at its disposal. The maturity pro\ufb01le 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. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-802": {
"value": "Interest rate risk management Interest rate risk is the risk that the Group\u2019s \ufb01nancial position will \ufb02uctuate due to changes in market interest rates. The Group\u2019s exposure to the risk of changes in market interest rates relates primarily to \ufb01nancial instruments with \ufb02oating 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 \ufb01xed and \ufb02oating rate debt. To manage the ratio of \ufb01xed rate debt to \ufb02oating rate debt, the Group may enter into interest rate swaps. The Group holds cross-currency interest rate swaps to hedge the foreign exchange risk (refer to Section A) and interest rate risk of the CHF denominated medium term note. The Group also 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 \ufb02ow hedges, primarily through $6,143 million (2021: $2,962 million) on cash and cash equivalents, $83 million (2021: $367 million) on interest- bearing liabilities (excluding transaction costs), $167 million of other \ufb01nancial assets (2021: nil) and $5 million (2021: $9 million) on cross-currency interest rate swaps. A reasonably possible change in the USD London Interbank Offered Rate (USD LIBOR) (+1.5%/-1.5% (2021: +1.0%/-1.0%)), with all variables held constant, would not have a material impact on the Group\u2019s equity or the income statement in the current period. The transition of a number of the Group\u2019s \ufb01nancial liabilities from USD LIBOR to SOFR during the year ended 31 December 2022 did not result in a material impact to the Group. The Group\u2019s Treasury function continues to execute the transition of the remaining \ufb01nancial instruments from current benchmark rates to alternative benchmark rates. ",
"dimensions": {
"concept": "woodsideenergygroupltd:DisclosureOfInterestRateRiskManagement",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-771": {
"value": "C.1 Cash and cash equivalents 2022 2021 US$m US$m Cash and cash equivalents Cash at bank 1,222 300 Term deposits 4,967 2,725 Restricted cash 12 - Total cash and cash equivalents 6,201 3,025 Recognition and measurement Cash and cash equivalents in the consolidated statement of \ufb01nancial 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 \ufb01nancial position. Cash and cash equivalents include $12 million (2021: nil) restricted by legal or contractual arrangements. Foreign exchange risk The following table summarises the Group's cash and cash equivalents by currency. 2022 2021 US$m US$m US dollar 5,886 2,917 Australian dollar 182 63 Other 133 45 Total cash and cash equivalents 6,201 3,025",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-803": {
"value": "Recognition and measurement Cash and cash equivalents in the consolidated statement of \ufb01nancial 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 \ufb01nancial position. Cash and cash equivalents include $12 million (2021: nil) restricted by legal or contractual arrangements. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-772": {
"value": "C.2 Interest-bearing liabilities and \ufb01nancing facilities Bilateral Facilities Syndicated Facilities JBIC Facility US Bonds Medium Term Notes Total US$m US$m US$m US$m US$m US$m Year ended 31 December 2022 At 1 January 2022 (4) 595 166 4,081 592 5,430 Repayments1 - - (83) - (200) (283) Fair value adjustment and foreign exchange movement - - - - (7) (7 Transaction costs capitalised and amortised (1) (4) - 3 - (2 Carrying amount at 31 December 2022 (5) 591 83 4,084 385 5,138 Current (2) (3) 83 (3) 185 260 Non-current (3) 594 - 4,087 200 4,878 Carrying amount at 31 December 2022 (5) 591 83 4,084 385 5,138 Undrawn balance at 31 December 2022 2,050 2,000 - - - 4,050 Year ended 31 December 2021 At 1 January 2021 (4) 593 250 4,778 597 6,214 Repayments1 - - (84) (700) - (784 Fair value adjustment and foreign exchange movement - - - - (5) (5 Capitalised borrowing costs - 2 - 3 - 5 Carrying amount at 31 December 2021 (4) 595 166 4,081 592 5,430 Current (2) (2) 83 (2) 200 277 Non-current (2) 597 83 4,083 392 5,153 Carrying amount at 31 December 2021 (4) 595 166 4,081 592 5,430 Undrawn balance at 31 December 2021 1,900 1,200 - - - 3,100 1. Included in cash \ufb02ows classi\ufb01ed within \ufb01nancing activities in the consolidated statement of cash \ufb02ows. 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. The changes in the fair value risks of the hedged item resulted in a gain of $7 million being recorded (2021: gain of $5 million), and a loss of $7 million recorded on the hedging instrument (2021: loss of $7 million). 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. C.2 Interest-bearing liabilities and \ufb01nancing facilities (cont.) Fair value The carrying amount of interest-bearing liabilities approximates their fair value, with the exception of the Group\u2019s unsecured bonds and the medium term notes. The unsecured bonds have a carrying amount of $4,084 million (2021: $4,081 million) and a fair value of $3,852 million (2021: $4,443 million). The medium term notes have a carrying amount of $385 million (2021: $592 million) and a fair value of $372 million (2021: $604 million). Fair value is calculated based on the present value of future principal and interest cash \ufb02ows, discounted at the market rate of interest at the reporting date and classi\ufb01ed as Level 1 on the fair value hierarchy. Where these cash \ufb02ows are in a foreign currency, the present value is converted to US dollars at the foreign exchange spot rate prevailing at the reporting date. The Group\u2019s repayment obligations remain unchanged. Foreign exchange risk All interest-bearing liabilities are denominated in US dollars, excluding the CHF175 million medium term note. Maturity pro\ufb01le of interest-bearing liabilities The table below presents the contractual undiscounted cash \ufb02ows associated with the Group\u2019s interest-bearing liabilities, representing principal and interest. The \ufb01gures will not necessarily reconcile with the amounts disclosed in the consolidated statement of \ufb01nancial position. 2022 2021 US$m US$m Due for payment in: 1 year or less 483 470 1-2 years 206 462 2-3 years 1,181 188 3-4 years 962 1,169 4-5 years 908 951 More than 5 years 2,416 3,320 6,156 6,560 Amounts exclude transaction costs. Bilateral facilities The Group has 14 bilateral loan facilities totalling $2,050 million (2021: 14 bilateral loan facilities totalling $1,900 million). Details of bilateral loan facilities at the reporting date are as follows: Number of facilities Term (years) Currency Extension option 1 5 - 6 US$ Evergreen 5 4 - 5 US$ Evergreen 4 3 - 4 US$ Evergreen 4 3 years or less US$ Evergreen Interest rates are based on USD LIBOR or Secured Overnight Financing Rate (SOFR) and margins are \ufb01xed at the commencement of the drawdown period. Interest is paid at the end of the drawdown period. Evergreen facilities may be extended continually by a year subject to the bank\u2019s agreement. Syndicated facility During the period, Woodside re\ufb01nanced and increased the existing facilities to $2,000 million, with $800 million expiring on 11 October 2024, $600 million expiring on 12 July 2025 and $600 million expiring on 12 July 2027. Interest rates are based on SOFR and margins are \ufb01xed at the commencement of the drawdown period. On 17 January 2020, the Group completed a $600 million syndicated facility with a term of seven years. Interest is based on the USD LIBOR plus 1.2%. Interest is paid on a quarterly basis. Japan Bank for International Cooperation (JBIC) facility On 24 June 2008, the Group entered into a two tranche committed loan facility of $1,000 million and $500 million respectively. The $500 million tranche was repaid in 2013. There is a prepayment option for the remaining balance. Interest rates are based on USD LIBOR. Interest is payable semi-annually in arrears and the principal amortises on a straight-line basis, with equal instalments of principal due on each interest payment date (every six months). Under this facility, 90% of the receivables from designated Pluto LNG sale and purchase agreements are secured in favour of the lenders through a trust structure, with a required reserve amount of $30 million. To the extent that this reserve amount remains fully funded and no default notice or acceleration notice has been given, the revenue from Pluto LNG continues to \ufb02ow directly to the Group from the trust account. Medium term notes On 28 August 2015, the Group established a $3,000 million Global Medium Term Notes Programme listed on the Singapore Stock Exchange. Two notes have been issued under this programme as set out below: Maturity date Currency Carrying amount (million) Nominal interest rate 11 December 2023 CHF 185 1.00% 29 January 2027 US$ 200 3.07% The unutilised program is not considered to be an unused facility. US bonds The Group has four unsecured bonds issued in the United States of America as de\ufb01ned in Rule 144A of the US Securities Act of 1933 as set out below: Maturity date Carrying amount US$m Nominal interest rate 5 March 2025 1,000 3.65% 15 September 2026 800 3.70% 15 March 2028 800 3.70% 4 March 2029 1,500 4.50% Interest on the bonds is payable semi-annually in arrears. During the period, the Group repaid $200 million of the Yucho 2022 Medium Term Note and $83 million on the JBIC facility.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBorrowingsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-804": {
"value": "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. The changes in the fair value risks of the hedged item resulted in a gain of $7 million being recorded (2021: gain of $5 million), and a loss of $7 million recorded on the hedging instrument (2021: loss of $7 million). All bonds, notes and facilities are subject to various covenants and negative pledges restricting future secured borrowings, subject to a number of permitted lien exceptions. Neither the covenants nor the negative pledges have been breached at any time during the reporting period. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-805": {
"value": "C.3 Contributed equity Recognition and measurement Issued capital Ordinary shares are classi\ufb01ed as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds. Reserved shares Reserved shares are the Group\u2019s own equity instruments, which are reacquired for later use in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). These shares are deducted from equity. No gain or loss is recognised in the income statement on the purchase, sale, issue or cancellation of the Group\u2019s own equity instruments. (a) Issued and fully paid shares Number of shares US$m Year ended 31 December 2022 Opening balance 969,631,826 9,409 DRP \u2013 ordinary shares issued at US$23.14 (2021 \ufb01nal dividend)1 14,348,997 332 Ordinary shares issued at US$21.06 for the acquisition of BHPP2 914,768,948 19,265 Transaction costs associated to the issue of shares - (5) Amounts as at 31 December 2022 1,898,749,771 29,001 Year ended 31 December 2021 Opening balance 962,225,814 9,297 DRP \u2013 ordinary shares issued at US$19.03 (2020 \ufb01nal dividend) 1,354,072 26 DRP \u2013 ordinary shares issued at US$14.21 (2021 interim dividend) 6,051,940 86 Amounts as at 31 December 2021 969,631,826 9,409 Year ended 31 December 2020 Opening balance 942,286,900 9,010 DRP \u2013 ordinary shares issued at A$25.61 (2019 \ufb01nal dividend) 12,072,034 181 DRP \u2013 ordinary shares issued at A$18.79 (2020 interim dividend) 6,091,035 83 Employee share plan \u2013 ordinary shares issued at A$18.27 (2017 Woodside equity plan) 1,775,845 23 Amounts as at 31 December 2020 962,225,814 9,297 1. Relates to ordinary shares issued for the DRP as part of the 2021 \ufb01nal dividend. The Group purchased on-market shares for the issuance of DRP as part of the 2022 interim dividend. Refer to Note C.3(b) for details of the on-market purchases and allocation. 2. 914,768,948 new Woodside shares were issued as consideration for the BHPP merger. Refer to Note B.5 for details. All shares are a single class with equal rights to dividends, capital, distributions and voting. The Company does not have authorised capital nor par value in relation to its issued shares. (b) Reserved shares Employee share plans Dividend reinvestment plan Number of shares US$m Number of shares US$m Year ended 31 December 2022 Opening balance 1,819,744 (30) - - Purchases during the year 2,232,589 (45) 6,823,092 (144) Vested/allocated during the year (2,178,556) 37 (6,823,092) 144 Amounts at 31 December 2022 1,873,777 (38) - - Year ended 31 December 2021 Opening balance 1,766,099 (23) - - Purchases during the year 2,683,469 (47) - - Vested during the year (2,629,824) 40 - - Amounts at 31 December 2021 1,819,744 (30) - - Year ended 31 December 2020 Opening balance 1,985,306 (39) - - Purchases during the year 2,242,345 (32) - - Vested during the year (2,461,552) 48 - - Amounts at 31 December 2020 1,766,099 (23) ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-773": {
"value": "C.3 Contributed equity Recognition and measurement Issued capital Ordinary shares are classi\ufb01ed as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds. Reserved shares Reserved shares are the Group\u2019s own equity instruments, which are reacquired for later use in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). These shares are deducted from equity. No gain or loss is recognised in the income statement on the purchase, sale, issue or cancellation of the Group\u2019s own equity instruments. (a) Issued and fully paid shares Number of shares US$m Year ended 31 December 2022 Opening balance 969,631,826 9,409 DRP \u2013 ordinary shares issued at US$23.14 (2021 \ufb01nal dividend)1 14,348,997 332 Ordinary shares issued at US$21.06 for the acquisition of BHPP2 914,768,948 19,265 Transaction costs associated to the issue of shares - (5) Amounts as at 31 December 2022 1,898,749,771 29,001 Year ended 31 December 2021 Opening balance 962,225,814 9,297 DRP \u2013 ordinary shares issued at US$19.03 (2020 \ufb01nal dividend) 1,354,072 26 DRP \u2013 ordinary shares issued at US$14.21 (2021 interim dividend) 6,051,940 86 Amounts as at 31 December 2021 969,631,826 9,409 Year ended 31 December 2020 Opening balance 942,286,900 9,010 DRP \u2013 ordinary shares issued at A$25.61 (2019 \ufb01nal dividend) 12,072,034 181 DRP \u2013 ordinary shares issued at A$18.79 (2020 interim dividend) 6,091,035 83 Employee share plan \u2013 ordinary shares issued at A$18.27 (2017 Woodside equity plan) 1,775,845 23 Amounts as at 31 December 2020 962,225,814 9,297 1. Relates to ordinary shares issued for the DRP as part of the 2021 \ufb01nal dividend. The Group purchased on-market shares for the issuance of DRP as part of the 2022 interim dividend. Refer to Note C.3(b) for details of the on-market purchases and allocation. 2. 914,768,948 new Woodside shares were issued as consideration for the BHPP merger. Refer to Note B.5 for details. All shares are a single class with equal rights to dividends, capital, distributions and voting. The Company does not have authorised capital nor par value in relation to its issued shares. (b) Reserved shares Employee share plans Dividend reinvestment plan Number of shares US$m Number of shares US$m Year ended 31 December 2022 Opening balance 1,819,744 (30) - - Purchases during the year 2,232,589 (45) 6,823,092 (144) Vested/allocated during the year (2,178,556) 37 (6,823,092) 144 Amounts at 31 December 2022 1,873,777 (38) - - Year ended 31 December 2021 Opening balance 1,766,099 (23) - - Purchases during the year 2,683,469 (47) - - Vested during the year (2,629,824) 40 - - Amounts at 31 December 2021 1,819,744 (30) - - Year ended 31 December 2020 Opening balance 1,985,306 (39) - - Purchases during the year 2,242,345 (32) - - Vested during the year (2,461,552) 48 - - Amounts at 31 December 2020 1,766,099 (23) ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-824": {
"value": "Issued capital Ordinary shares are classi\ufb01ed as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-823": {
"value": "Reserved shares Reserved shares are the Group\u2019s own equity instruments, which are reacquired for later use in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). These shares are deducted from equity. No gain or loss is recognised in the income statement on the purchase, sale, issue or cancellation of the Group\u2019s own equity instruments. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTreasurySharesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-774": {
"value": "C.4 Other reserves 2022 2021 2020 US$m US$m US$m Other reserves Employee bene\ufb01ts reserve 278 232 219 Foreign currency translation reserve 796 793 793 Hedging reserve1 (586) (400) (71) Distributable pro\ufb01ts reserve2 3,541 58 462 Other reserves 2 - - 4,031 683 1,403 1. The portion of the hedging reserve relating to settled hedges is $226 million. 2. For the year ended 31 December 2022, the Group transferred $5,553 million of retained earnings to the distributable pro\ufb01ts reserve. The increase was offset by the 2022 interim dividend of $2,070 million which was paid on 6 October 2022. Nature and purpose Employee bene\ufb01ts 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 \ufb01nancial statements of foreign entities from their functional currency to the Group\u2019s presentation currency. Hedging reserve Used to record gains and losses on hedges designated as cash \ufb02ow hedges, and foreign currency basis spread arising from the designation of a \ufb01nancial instrument as a hedging instrument. Gains and losses accumulated in the cash \ufb02ow hedge reserve for qualifying assets are capitalised against the carrying amount of that asset and taken to the income statement as the asset is depreciated. Distributable pro\ufb01ts reserve Used to record distributable pro\ufb01ts generated by the Parent entity, Woodside Energy Group Ltd. Other reserves Used to record gains and losses on \ufb01nancial instruments at fair value through other comprehensive income. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-806": {
"value": "Credit risk management Credit risk is the risk that a counterparty will not meet its obligation under a \ufb01nancial instrument or customer contract, leading to a \ufb01nancial loss to the Group. Credit risk arises from the \ufb01nancial assets of the Group, which comprise trade and other receivables, loans receivables and deposits with banks and \ufb01nancial institutions. The Group manages its credit risk on trade receivables and \ufb01nancial instruments by predominantly dealing with counterparties with an investment grade credit rating. Sufficient collateral is obtained to mitigate the risk of \ufb01nancial loss when transacting with counterparties with below investment grade credit ratings. Customers who wish to trade on unsecured credit terms are subject to credit veri\ufb01cation procedures. Receivable balances are monitored on an ongoing basis. As a result, the Group\u2019s exposure to bad debts is not signi\ufb01cant. The Group\u2019s maximum credit risk is limited to the carrying amount of its \ufb01nancial assets. Customer credit risk is managed by the Treasury function subject to the Group\u2019s established policy, procedures and controls relating to customer credit risk management. Credit quality of a customer is assessed based on an extensive credit rating scorecard and individual credit limits are de\ufb01ned in accordance with this assessment. Outstanding customer receivables are regularly monitored. At 31 December 2022, the Group had nineteen customers (2021: four customers) that owed the Group more than $10 million each and accounted for approximately 79% (2021: 88%) of all trade receivables. Depending on the product, settlement terms are 8 to 30 days from the date of invoice or bill of lading unless otherwise stated in the agreed payment terms. The Group considers the probability of default upon initial recognition of the asset and whether there has been a signi\ufb01cant depreciation in credit quality on an ongoing basis. A signi\ufb01cant decrease in credit quality is de\ufb01ned 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 simpli\ufb01ed approach and are measured at an amount equal to lifetime expected loss. Under the simpli\ufb01ed 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 \ufb01nancial assets is considered to be when the counterparty fails to make contractual payments within 60 days of when they fall due. At 31 December 2022, the Group had a provision for credit losses of nil (2021: nil). Subsequent to 31 December 2022, 99% (2021: 100%) of the trade receivables balance of $1,067 million (2021: $152 million) has been received. Credit risk from balances with banks is managed by the Treasury function in accordance with the Group\u2019s policy. The Group\u2019s main funds are placed as short-term deposits with reputable \ufb01nancial institutions with strong investment grade credit ratings. At 31 December 2022 and 31 December 2021, there were no signi\ufb01cant concentrations of credit risk within the Group and \ufb01nancial instruments are spread amongst a number of \ufb01nancial institutions to minimise the risk of counterparty default. The maximum exposure to \ufb01nancial institution credit risk is represented by the sum of all cash deposits plus accrued interest, bank account balances and fair value of derivative assets. The Group\u2019s counterparty credit policy limits this exposure to commercial and investment banks, according to approved credit limits based on the counterparty\u2019s credit rating. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCreditRiskExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-775": {
"value": "D.2 Receivables 2022 2021 US$m US$m (a) Receivables (current) Trade receivables1 1,067 152 Other receivables1 381 123 Loans receivable 76 75 Lease receivables 35 18 Interest receivable 19 - 1,578 368 (b) Receivables (non-current) Other receivables 75 - Loans receivable 724 627 Lease receivables 46 26 De\ufb01ned bene\ufb01t plan asset - 33 845 686 1. Interest-free and settlement terms are usually between 14 and 30 days. Recognition and measurement Trade receivables are initially recognised at the transaction price determined under AASB 15/ IFRS 15 Revenue from Contracts with Customers. Other receivables are initially recognised at fair value. Receivables that satisfy the contractual cash \ufb02ow 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 \ufb02ow and business model tests are subsequently measured at fair value (refer to Note D.6). The Group\u2019s customers are required to pay in accordance with agreed payment terms. Depending on the product, settlement terms are 14 to 30 days from the date of invoice or bill of lading and customers regularly pay on time. There are no signi\ufb01cant overdue trade receivables as at the end of the reporting period (2021: nil). Fair value The carrying amount of trade and other receivables approximates their fair value. Foreign exchange risk The Group held $174 million of receivables at 31 December 2022 (2021: $121 million) in currencies other than US dollars (predominantly Australian dollars). Loans receivable On 9 January 2020, Woodside Energy Finance (UK) Ltd entered into a secured loan agreement with Petrosen (the Senegal National Oil Company), to provide up to $450 million for the purpose of funding Sangomar project costs. The facility has a maximum term of 12 years and semi-annual repayments of the loan are due to commence at the earlier of 12 months after RFSU or 30 June 2025. The carrying amount of the loan receivable is $408 million at 31 December 2022 (2021: $335 million), which approximates its fair value. The remaining balance of loans receivable is due from non-controlling interests. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-807": {
"value": "Recognition and measurement Trade receivables are initially recognised at the transaction price determined under AASB 15/ IFRS 15 Revenue from Contracts with Customers. Other receivables are initially recognised at fair value. Receivables that satisfy the contractual cash \ufb02ow 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 \ufb02ow and business model tests are subsequently measured at fair value (refer to Note D.6). The Group\u2019s customers are required to pay in accordance with agreed payment terms. Depending on the product, settlement terms are 14 to 30 days from the date of invoice or bill of lading and customers regularly pay on time. There are no signi\ufb01cant overdue trade receivables as at the end of the reporting period (2021: nil). Fair value The carrying amount of trade and other receivables approximates their fair value. Foreign exchange risk The Group held $174 million of receivables at 31 December 2022 (2021: $121 million) in currencies other than US dollars (predominantly Australian dollars). Loans receivable On 9 January 2020, Woodside Energy Finance (UK) Ltd entered into a secured loan agreement with Petrosen (the Senegal National Oil Company), to provide up to $450 million for the purpose of funding Sangomar project costs. The facility has a maximum term of 12 years and semi-annual repayments of the loan are due to commence at the earlier of 12 months after RFSU or 30 June 2025. The carrying amount of the loan receivable is $408 million at 31 December 2022 (2021: $335 million), which approximates its fair value. The remaining balance of loans receivable is due from non-controlling interests. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-776": {
"value": "D.3 Inventories 2022 2021 US$m US$m (a) Inventories (current) Petroleum products Goods in transit 95 35 Finished stocks 103 34 Warehouse stores and materials 480 133 678 202 (b) Inventories (non-current) Warehouse stores and materials 11 19 11 19 Recognition and measurement Inventories include hydrocarbon stocks, consumable supplies and maintenance spares. Inventories are valued at the lower of cost and net realisable value. Cost is determined on a weighted average basis and includes direct costs and an appropriate portion of \ufb01xed and variable production overheads where applicable. Inventories determined to be obsolete or damaged are written down to net realisable value, being the estimated selling price less selling costs. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInventoriesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-808": {
"value": "Recognition and measurement Inventories include hydrocarbon stocks, consumable supplies and maintenance spares. Inventories are valued at the lower of cost and net realisable value. Cost is determined on a weighted average basis and includes direct costs and an appropriate portion of \ufb01xed and variable production overheads where applicable. Inventories determined to be obsolete or damaged are written down to net realisable value, being the estimated selling price less selling costs. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-777": {
"value": "D.4 Payables The following table shows the Group\u2019s payables balances. 2022 2021 US$m US$m Trade payables1 759 191 Other payables1 1,270 390 Interest payable2 65 58 Total payables 2,094 639 1. Interest-free and normally settled on 30 day terms. 2. Details regarding interest-bearing liabilities are contained in Note C.2. 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. Foreign exchange risk The Group held $657 million of payables at 31 December 2022 (2021: $311 million) in currencies other than US dollars (predominantly Australian dollars). Maturity pro\ufb01le of payables The Group\u2019s payables balances at 31 December 2022 and 31 December 2021 are due for payment within a year. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-810": {
"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. Foreign exchange risk The Group held $657 million of payables at 31 December 2022 (2021: $311 million) in currencies other than US dollars (predominantly Australian dollars). Maturity pro\ufb01le of payables The Group\u2019s payables balances at 31 December 2022 and 31 December 2021 are due for payment within a year. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-778": {
"value": "D.5 Provisions Restoration1 Employee bene\ufb01ts Onerous contracts 2 Other Total US$m US$m US$m US$m US$m Year ended 31 December 2022 At 1 January 2022 2,218 286 214 106 2,824 Acquisitions through business combination3 4,310 329 - 165 4,804 Change in provision (382) (98) (216) 137 (559) Unwinding of present value discount 107 - 2 1 110 Carrying amount at 31 December 2022 6,253 517 - 409 7,179 Current 575 331 - 313 1,219 Non-current 5,678 186 - 96 5,960 Net carrying amount 6,253 517 - 409 7,179 Year ended 31 December 2021 At 1 January 2021 2,134 295 349 129 2,907 Change in provision 60 (9) (140) (23) (112) Unwinding of present value discount 24 - 5 - 29 Carrying amount at 31 December 2021 2,218 286 214 106 2,824 Current 235 269 - 101 605 Non-current 1,983 17 214 5 2,219 Net carrying amount 2,218 286 214 106 2,824 1. 2022 change in provision is due to a revision of discount rates of $978 million (primarily due to an increase in risk free rates) and provisions used of $262 million, offset by changes in estimates of $858 million. Changes in estimates are due to new activities, increase in scope of removal and cost and rate escalations supported by the most recent estimates and benchmarks. 2. 2022 change in provision is due to changes in estimates of $245 million offset by provisions used of $29 million. 3. Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is obtained within 12 months from the acquisition date. Refer to Note B.5 for 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 out\ufb02ow of resources embodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Restoration The restoration provision is \ufb01rst 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 oil and gas properties 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 \ufb01nance costs. The carrying amount capitalised in oil and gas properties 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 bene\ufb01t, are expensed. Key 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. In many instances, decommissioning of assets occurs many years into the future. The Group\u2019s 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. The Group maintains technical expertise to ensure that industry learnings, scienti\ufb01c research and local and international guidelines are reviewed in assessing its restoration obligations. The restoration obligation requires judgemental assumptions regarding removal date, environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating cost, technologies used in determining the decommissioning cost, and liability-speci\ufb01c discount rates to determine the present value of these cash \ufb02ows. The Group applies either the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in assessing the cost estimate, re\ufb02ecting a difference in approach to cost estimation for heritage Woodside and heritage BHPP assets. Both approaches are supported by AASB 137/ IAS 37 Provisions, Contingent Liabilities and Contingent Assets, produce reliable estimates and are widely used in practice. Heritage Woodside assets refer to assets held by the Group prior to the BHPP merger. Heritage BHPP assets refers to assets acquired from BHP but excludes the commonly held assets by both heritage entities. Expected outcome approach This approach is used for heritage Woodside assets, and those assets commonly held by both heritage entities. The following cost assumptions are applied: \u2022 for onshore assets, provision has been made for the removal of production facilities and above ground pipelines using current restoration standards and techniques and taking into account risks and uncertainties; and \u2022 for offshore assets, provision has been made for the plug and abandonment of wells and the removal of offshore platform topsides, \ufb02oating production storage offloading (FPSO) and some subsea infrastructure. It is currently the Group\u2019s assumption that in some regulatory jurisdictions and environments, certain pipelines and infrastructure, parts of offshore platform substructures, and certain subsea infrastructure 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. Expected value approach This approach is used for heritage BHPP assets (excluding those commonly held by both heritage entities). 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. Individual site provisions are an estimate of the expected value of future cash \ufb02ows 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 country speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows. 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 re\ufb02ect the Group\u2019s best estimate based on current knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be performed near the end of their operational life and/or when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash out\ufb02ows 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 2022. A range of pre-tax discount rates between 3.4% and 4.7% (2021: 0.4% to 2.4%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $316 million higher. If the cost estimates were increased by 10% then the provision would be $627 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 54% (2021: 65%). (b) Legal case outcomes Provisions for legal cases are measured at the present value of the amount expected to settle the claim. Management is required to use judgement when assessing the likely outcome of legal cases, estimating the risked amount and whether a provision or contingent liability should be recognised. Employee bene\ufb01ts Provision is made for employee bene\ufb01ts accumulated as a result of employees rendering services up to the end of the reporting period. These bene\ufb01ts include wages, salaries, annual leave and long service leave. Liabilities in respect of employees\u2019 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 bene\ufb01ts. These liabilities are measured at the present value of the estimated future cash out\ufb02ow 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 classi\ufb01ed as short- term bene\ufb01ts and are measured at the amount due to be paid. Onerous contract provision Provision is made for loss-making contracts at the present value of the lower of the net cost of ful\ufb01lling and the cost arising from failure to ful\ufb01ll each contract. (c) Onerous contracts The onerous contract provision assessment requires management to make certain estimates regarding the unavoidable costs and the expected economic bene\ufb01ts from the contract. These estimates require signi\ufb01cant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions. As at 31 December 2022, the Corpus Christi contract is expected to return a positive value and on this basis the provision has been reversed to nil (2021: $214 million). Changes in assumptions predominantly relating to the narrowing of the spread between the sales price and purchase price could result in the contract becoming onerous in the future. Assumptions used to determine the present value as at 31 December 2022 are set out below: \u2022 Remaining contract term \u2013 18 years. \u2022 Discount rate \u2013 a pre-tax, risk free US government bond rate of 4.10% (2021: 1.855%) has been applied. \u2022 LNG pricing \u2013 forecast sales and purchase prices are subject to a number of price markers. Price assumptions are based on the best information on the market available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The forecasted sales are linked to gas hub prices (Title Transfer Facility (TTF)) at which physical sales are expected to occur and incorporate known sales pricing information . The long-term gas sales price is estimated on the basis of the Group\u2019s Brent price forecast. The estimated purchase price is linked to US gas hub prices (Henry Hub (HH)) at which physical purchases are expected to occur. The nominal TTF, Brent oil prices and HH gas prices used at 31 December 2022 were: 2023 2024 2025 2026 2027 TTF (US$/MMBtu) 47.9 36.4 22.3 8.8 9.0 Brent (US$/bbl) 87 78 74 76 77\u00b2 HH (US$/MMBtu) 6.1 4.7 4.0 4.1 4.23 1. For committed volumes, contracted pricing has been applied. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 3. Long-term gas prices are based on US$3.8/MMBtu (2022 real terms) from 2025. All long-term prices are escalated at 2.0%. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfProvisionsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-809": {
"value": "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 out\ufb02ow of resources embodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Restoration The restoration provision is \ufb01rst 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 oil and gas properties 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 \ufb01nance costs. The carrying amount capitalised in oil and gas properties 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 bene\ufb01t, are expensed. Key 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. In many instances, decommissioning of assets occurs many years into the future. The Group\u2019s 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. The Group maintains technical expertise to ensure that industry learnings, scienti\ufb01c research and local and international guidelines are reviewed in assessing its restoration obligations. The restoration obligation requires judgemental assumptions regarding removal date, environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating cost, technologies used in determining the decommissioning cost, and liability-speci\ufb01c discount rates to determine the present value of these cash \ufb02ows. The Group applies either the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in assessing the cost estimate, re\ufb02ecting a difference in approach to cost estimation for heritage Woodside and heritage BHPP assets. Both approaches are supported by AASB 137/ IAS 37 Provisions, Contingent Liabilities and Contingent Assets, produce reliable estimates and are widely used in practice. Heritage Woodside assets refer to assets held by the Group prior to the BHPP merger. Heritage BHPP assets refers to assets acquired from BHP but excludes the commonly held assets by both heritage entities. Expected outcome approach This approach is used for heritage Woodside assets, and those assets commonly held by both heritage entities. The following cost assumptions are applied: \u2022 for onshore assets, provision has been made for the removal of production facilities and above ground pipelines using current restoration standards and techniques and taking into account risks and uncertainties; and \u2022 for offshore assets, provision has been made for the plug and abandonment of wells and the removal of offshore platform topsides, \ufb02oating production storage offloading (FPSO) and some subsea infrastructure. It is currently the Group\u2019s assumption that in some regulatory jurisdictions and environments, certain pipelines and infrastructure, parts of offshore platform substructures, and certain subsea infrastructure 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. Expected value approach This approach is used for heritage BHPP assets (excluding those commonly held by both heritage entities). 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. Individual site provisions are an estimate of the expected value of future cash \ufb02ows 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 country speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows. 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 re\ufb02ect the Group\u2019s best estimate based on current knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be performed near the end of their operational life and/or when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash out\ufb02ows 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 2022. A range of pre-tax discount rates between 3.4% and 4.7% (2021: 0.4% to 2.4%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $316 million higher. If the cost estimates were increased by 10% then the provision would be $627 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 54% (2021: 65%). (b) Legal case outcomes Provisions for legal cases are measured at the present value of the amount expected to settle the claim. Management is required to use judgement when assessing the likely outcome of legal cases, estimating the risked amount and whether a provision or contingent liability should be recognised. Employee bene\ufb01ts Provision is made for employee bene\ufb01ts accumulated as a result of employees rendering services up to the end of the reporting period. These bene\ufb01ts include wages, salaries, annual leave and long service leave. Liabilities in respect of employees\u2019 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 bene\ufb01ts. These liabilities are measured at the present value of the estimated future cash out\ufb02ow 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 classi\ufb01ed as short- term bene\ufb01ts and are measured at the amount due to be paid. Onerous contract provision Provision is made for loss-making contracts at the present value of the lower of the net cost of ful\ufb01lling and the cost arising from failure to ful\ufb01ll each contract. (c) Onerous contracts The onerous contract provision assessment requires management to make certain estimates regarding the unavoidable costs and the expected economic bene\ufb01ts from the contract. These estimates require signi\ufb01cant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions. As at 31 December 2022, the Corpus Christi contract is expected to return a positive value and on this basis the provision has been reversed to nil (2021: $214 million). Changes in assumptions predominantly relating to the narrowing of the spread between the sales price and purchase price could result in the contract becoming onerous in the future. Assumptions used to determine the present value as at 31 December 2022 are set out below: \u2022 Remaining contract term \u2013 18 years. \u2022 Discount rate \u2013 a pre-tax, risk free US government bond rate of 4.10% (2021: 1.855%) has been applied. \u2022 LNG pricing \u2013 forecast sales and purchase prices are subject to a number of price markers. Price assumptions are based on the best information on the market available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The forecasted sales are linked to gas hub prices (Title Transfer Facility (TTF)) at which physical sales are expected to occur and incorporate known sales pricing information . The long-term gas sales price is estimated on the basis of the Group\u2019s Brent price forecast. The estimated purchase price is linked to US gas hub prices (Henry Hub (HH)) at which physical purchases are expected to occur. The nominal TTF, Brent oil prices and HH gas prices used at 31 December 2022 were: 2023 2024 2025 2026 2027 TTF (US$/MMBtu) 47.9 36.4 22.3 8.8 9.0 Brent (US$/bbl) 87 78 74 76 77\u00b2 HH (US$/MMBtu) 6.1 4.7 4.0 4.1 4.23 1. For committed volumes, contracted pricing has been applied. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 3. Long-term gas prices are based on US$3.8/MMBtu (2022 real terms) from 2025. All long-term prices are escalated at 2.0%",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-825": {
"value": "Restoration The restoration provision is \ufb01rst 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 oil and gas properties 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 \ufb01nance costs. The carrying amount capitalised in oil and gas properties 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 bene\ufb01t, are expensed. Key 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. In many instances, decommissioning of assets occurs many years into the future. The Group\u2019s 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. The Group maintains technical expertise to ensure that industry learnings, scienti\ufb01c research and local and international guidelines are reviewed in assessing its restoration obligations. The restoration obligation requires judgemental assumptions regarding removal date, environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating cost, technologies used in determining the decommissioning cost, and liability-speci\ufb01c discount rates to determine the present value of these cash \ufb02ows. The Group applies either the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in assessing the cost estimate, re\ufb02ecting a difference in approach to cost estimation for heritage Woodside and heritage BHPP assets. Both approaches are supported by AASB 137/ IAS 37 Provisions, Contingent Liabilities and Contingent Assets, produce reliable estimates and are widely used in practice. Heritage Woodside assets refer to assets held by the Group prior to the BHPP merger. Heritage BHPP assets refers to assets acquired from BHP but excludes the commonly held assets by both heritage entities. Expected outcome approach This approach is used for heritage Woodside assets, and those assets commonly held by both heritage entities. The following cost assumptions are applied: \u2022 for onshore assets, provision has been made for the removal of production facilities and above ground pipelines using current restoration standards and techniques and taking into account risks and uncertainties; and \u2022 for offshore assets, provision has been made for the plug and abandonment of wells and the removal of offshore platform topsides, \ufb02oating production storage offloading (FPSO) and some subsea infrastructure. It is currently the Group\u2019s assumption that in some regulatory jurisdictions and environments, certain pipelines and infrastructure, parts of offshore platform substructures, and certain subsea infrastructure 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. Expected value approach This approach is used for heritage BHPP assets (excluding those commonly held by both heritage entities). 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. Individual site provisions are an estimate of the expected value of future cash \ufb02ows 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 country speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows. 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 re\ufb02ect the Group\u2019s best estimate based on current knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be performed near the end of their operational life and/or when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash out\ufb02ows 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 2022. A range of pre-tax discount rates between 3.4% and 4.7% (2021: 0.4% to 2.4%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $316 million higher. If the cost estimates were increased by 10% then the provision would be $627 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 54% (2021: 65%). (b) Legal case outcomes Provisions for legal cases are measured at the present value of the amount expected to settle the claim. Management is required to use judgement when assessing the likely outcome of legal cases, estimating the risked amount and whether a provision or contingent liability should be recognised. ",
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"language": "en",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-779": {
"value": "D.6 Other \ufb01nancial assets and liabilities 2022 2021 US$m US$m Other \ufb01nancial assets Financial instruments at fair value through pro\ufb01t and loss Derivative \ufb01nancial instruments designated as hedges 207 134 Other \ufb01nancial assets 22 293 Financial instruments at amortised cost Hedge collateral (including interest) 509 - Other \ufb01nancial assets 30 - Financial instruments at fair value through other comprehensive income Other \ufb01nancial assets 29 - Total other \ufb01nancial assets 797 427 Current 677 320 Non-current 120 107 Net carrying amount 797 427 Other \ufb01nancial liabilities Financial instruments at fair value through pro\ufb01t and loss Derivative \ufb01nancial instruments designated as hedges 721 563 Other \ufb01nancial liabilities - 9 Total other \ufb01nancial liabilities 721 572 Current 654 411 Non-current 67 161 Net carrying amount 721 572 Recognition and measurement Other \ufb01nancial assets and liabilities Receivables subject to provisional pricing adjustments are initially recognised at the transaction price and subsequently measured at fair value with movements recognised in the consolidated income statement. Derivative \ufb01nancial instruments Derivative \ufb01nancial 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 \ufb02ow 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 reclassi\ufb01ed to the consolidated income statement in the periods when the hedged item affects pro\ufb01t or loss. D.6 Other \ufb01nancial assets and liabilities (cont.) Derivative \ufb01nancial instruments (cont.) 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 \ufb02ows 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 LNG revenue contracts. Fair value Except for the other \ufb01nancial assets and other \ufb01nancial liabilities set out in this note, there are no material \ufb01nancial assets or \ufb01nancial liabilities carried at fair value. The fair value of commodity derivative \ufb01nancial instruments is determined based on observable quoted forward pricing and swap models and is classi\ufb01ed 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 \ufb02ows based on the terms of maturity of each contract, using market interest rates for a similar instrument at the reporting date and is classi\ufb01ed 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 classi\ufb01ed as Level 2 on the fair value hierarchy. The fair values of other \ufb01nancial assets and other \ufb01nancial liabilities are predominantly determined based on observable quoted forward pricing and are predominantly classi\ufb01ed as Level 2 on the fair value hierarchy. Foreign exchange The derivative \ufb01nancial instruments include foreign exchange forward contracts that are denominated in Australian dollars. The Group had no material other \ufb01nancial assets and liabilities denominated in currencies other than US dollars. Hedging activities During the period, the following hedging activities were undertaken: \u2022 The Group hedged a percentage of its oil-linked exposure, entering into oil swap derivatives settling in 2023 in order to achieve a minimum average sales price of $75 per barrel. \u2022 The Group entered into additional separate HH commodity swaps to hedge the purchase leg of the Corpus Christi volumes and separate TTF commodity swaps to hedge the sales leg of Corpus Christi volumes to mitigate pricing risk for 2023 to 2024. \u2022 As a result of hedging activities, approximately 49% of Corpus Christi volumes included in stock in transit for 2022, approximately 82% of 2023 volumes and approximately 29% of 2024 volumes have hedged pricing risk. \u2022 The Group restruck $150 million of the TTF hedges to reduce the derivative \ufb01nancial liability. \u2022 The Group restruck $92 million of the oil swap hedges to reduce the derivative \ufb01nancial liability. Further, the Group also voluntarily placed $506 million as collateral against the oil hedge positions to reduce counterparty credit risk exposure. The collateral will mature in line with hedge settlements in 2023. \u2022 Through the use of foreign exchange forward contracts, the Group hedged its Australian dollar to US dollar exchange rate in relation to a portion of the Australian dollar denominated capital expenditure expected to be incurred under the Scarborough development . D.6 Other \ufb01nancial assets and liabilities (cont.) Hedging activities (cont.) 2022 2021 Oil swaps (cash \ufb02ow hedges) Carrying amount (US$m) (114) (1) Notional amount (MMbbl) 18 30 Maturity date 2023 2022-2023 Hedge ratio 1:1 1:1 Weighted average hedged rate (US$/MMbbl) 79 74 HH Corpus Christi commodity swaps (cash \ufb02ow hedges) Carrying amount (US$m) 26 31 Notional amount (TBtu) 58 65 Maturity date 2023-2024 2022-2023 Hedge ratio 1:1 1:1 Weighted average hedged rate (US$/MMBtu) 4 3 TTF Corpus Christi commodity swaps (cash \ufb02ow hedges) Carrying amount (US$m) (469) (465) Notional amount (TBtu) 50 49 Maturity date 2023-2024 2022-2023 Hedge ratio 1:1 1:1 Weighted average hedged rate (US$/MMBtu) 16 9 TTF commodity swaps (cash \ufb02ow hedges) Carrying amount (US$m) - 4 Notional amount (TBtu) - 3 Maturity date - 2022 Hedge ratio - 1:1 Weighted average hedged rate (US$/MMBtu) - 26 Interest rate swap (cash \ufb02ow hedges) Carrying amount (US$m) 55 (17) Notional amount (US$m) 600 600 Maturity date 2027 2027 Hedge ratio 1:1 1:1 Weighted average hedged rate 1.7% 1.7% Cross currency interest rate swap (cash \ufb02ow and fair value hedges) Carrying amount (US$m) 5 9 Notional amount (Swiss Franc) 175 175 Maturity date 2023 2023 Hedge ratio 1:1 1:1 Weighted average hedged rate Three month USD LIBOR +2.8% Three month USD LIBOR +2.8% FX forwards (cash \ufb02ow hedges) Carrying amount (US$m) (17) 10 Notional amount (AUD$m) 1,037 934 Maturity date 2023-2025 2022-2025 Hedge Ratio 1:1 1:1 Weighted average hedged rate (AUD:USD) 0.68 0.71 Hedge ineffectiveness loss of $72 million (2021: $38 million loss) has been recognised in the pro\ufb01t and loss. Other \ufb01nancial assets Other \ufb01nancial assets measured at fair value include receivables subject to provisional pricing adjustments of nil (2021: $163 million) and repurchase agreements entered into for the purposes of net settlement rather than for physical delivery of nil (2021: $69 million). Interest Rate Benchmark Reform A fundamental reform of major interest rate benchmarks is being undertaken globally, including the replacement of some interbank offered rates (IBORs) with alternative nearly risk-free rates (referred to as \u2018IBOR reform\u2019). The Group has exposures to IBORs on its \ufb01nancial instruments that will be impacted as part of these market-wide initiatives. The Group's main IBOR exposure at the reporting date is USD LIBOR. In 2020, the Federal Reserve announced that the three-month and six-month LIBOR will be phased out and eventually replaced by June 2023. During the period, the Group has transitioned a number of \ufb01nancial liabilities from USD LIBOR to SOFR and is in the process of transitioning the remaining \ufb01nancial instruments to alternative benchmark rates. The Group has \ufb01nancial liabilities and \ufb01nancial assets with a total carrying value of $670 million (2021: $957 million) and $393 million (2021: $367 million) respectively, which reference USD LIBOR. The Group has the following hedging relationships which are exposed to interest rate benchmarks impacted by IBOR Reform: \u2022 Interest rate swaps to hedge the LIBOR interest rate risk associated with the $600 million syndicated facility (refer to Note C.2). The interest rate swaps are designated as cash \ufb02ow hedges, converting the variable interest into \ufb01xed interest US dollar debt, and mature in 2027. \u2022 A \ufb01xed rate 175 million Swiss Franc (CHF) denominated medium term note, which it hedges with cross-currency interest rate swaps designated in both fair value and cash \ufb02ow hedge relationships. The cross-currency interest rate swaps are referenced to LIBOR (refer to Note C.2). The transition of a number of the Group\u2019s \ufb01nancial liabilities from USD LIBOR to SOFR during the year ended 31 December 2022 did not result in a material impact to the Group. The Group\u2019s Treasury function continues to execute the transition of the remaining \ufb01nancial instruments from current benchmark rates to alternative benchmark rates. Key estimates and judgements Fair value of other \ufb01nancial assets and liabilities Estimates have been applied in the measurement of other \ufb01nancial assets and liabilities and, where required, judgement is applied in the settlement of any \ufb01nancial assets or liabilities. In the current period, this included a $3 million periodic adjustment relating to timing which increased other \ufb01nancial liabilities, re\ufb02ecting the arrangements governing Wheatstone LNG sales (2021: $56 million increase).",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-811": {
"value": "Recognition and measurement Other \ufb01nancial assets and liabilities Receivables subject to provisional pricing adjustments are initially recognised at the transaction price and subsequently measured at fair value with movements recognised in the consolidated income statement. Derivative \ufb01nancial instruments Derivative \ufb01nancial 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 \ufb02ow 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 reclassi\ufb01ed to the consolidated income statement in the periods when the hedged item affects pro\ufb01t or loss. Derivative \ufb01nancial instruments (cont.) 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 \ufb02ows 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 LNG revenue contracts. Fair value Except for the other \ufb01nancial assets and other \ufb01nancial liabilities set out in this note, there are no material \ufb01nancial assets or \ufb01nancial liabilities carried at fair value. The fair value of commodity derivative \ufb01nancial instruments is determined based on observable quoted forward pricing and swap models and is classi\ufb01ed 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 \ufb02ows based on the terms of maturity of each contract, using market interest rates for a similar instrument at the reporting date and is classi\ufb01ed 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 classi\ufb01ed as Level 2 on the fair value hierarchy. The fair values of other \ufb01nancial assets and other \ufb01nancial liabilities are predominantly determined based on observable quoted forward pricing and are predominantly classi\ufb01ed as Level 2 on the fair value hierarchy. Key estimates and judgements Fair value of other \ufb01nancial assets and liabilities Estimates have been applied in the measurement of other \ufb01nancial assets and liabilities and, where required, judgement is applied in the settlement of any \ufb01nancial assets or liabilities. In the current period, this included a $3 million periodic adjustment relating to timing which increased other \ufb01nancial liabilities, re\ufb02ecting the arrangements governing Wheatstone LNG sales (2021: $56 million increase). ",
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"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-833": {
"value": "Derivative \ufb01nancial instruments Derivative \ufb01nancial 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 \ufb02ow 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 reclassi\ufb01ed to the consolidated income statement in the periods when the hedged item affects pro\ufb01t or loss. Derivative \ufb01nancial instruments (cont.) 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 \ufb02ows 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 LNG revenue contracts. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-831": {
"value": "Derivative \ufb01nancial instruments Derivative \ufb01nancial 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 \ufb02ow 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 reclassi\ufb01ed to the consolidated income statement in the periods when the hedged item affects pro\ufb01t or loss. Derivative \ufb01nancial instruments (cont.) 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 \ufb02ows 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 LNG revenue contracts. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-826": {
"value": "Derivative \ufb01nancial instruments Derivative \ufb01nancial 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 \ufb02ow 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 reclassi\ufb01ed to the consolidated income statement in the periods when the hedged item affects pro\ufb01t or loss. Derivative \ufb01nancial instruments (cont.) 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 \ufb02ows 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 LNG revenue contracts. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-827": {
"value": "Fair value Except for the other \ufb01nancial assets and other \ufb01nancial liabilities set out in this note, there are no material \ufb01nancial assets or \ufb01nancial liabilities carried at fair value. The fair value of commodity derivative \ufb01nancial instruments is determined based on observable quoted forward pricing and swap models and is classi\ufb01ed 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 \ufb02ows based on the terms of maturity of each contract, using market interest rates for a similar instrument at the reporting date and is classi\ufb01ed 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 classi\ufb01ed as Level 2 on the fair value hierarchy. The fair values of other \ufb01nancial assets and other \ufb01nancial liabilities are predominantly determined based on observable quoted forward pricing and are predominantly classi\ufb01ed as Level 2 on the fair value hierarchy. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-828": {
"value": "Hedging activities During the period, the following hedging activities were undertaken: \u2022 The Group hedged a percentage of its oil-linked exposure, entering into oil swap derivatives settling in 2023 in order to achieve a minimum average sales price of $75 per barrel. \u2022 The Group entered into additional separate HH commodity swaps to hedge the purchase leg of the Corpus Christi volumes and separate TTF commodity swaps to hedge the sales leg of Corpus Christi volumes to mitigate pricing risk for 2023 to 2024. \u2022 As a result of hedging activities, approximately 49% of Corpus Christi volumes included in stock in transit for 2022, approximately 82% of 2023 volumes and approximately 29% of 2024 volumes have hedged pricing risk. \u2022 The Group restruck $150 million of the TTF hedges to reduce the derivative \ufb01nancial liability. \u2022 The Group restruck $92 million of the oil swap hedges to reduce the derivative \ufb01nancial liability. Further, the Group also voluntarily placed $506 million as collateral against the oil hedge positions to reduce counterparty credit risk exposure. The collateral will mature in line with hedge settlements in 2023. \u2022 Through the use of foreign exchange forward contracts, the Group hedged its Australian dollar to US dollar exchange rate in relation to a portion of the Australian dollar denominated capital expenditure expected to be incurred under the Scarborough development Hedging activities (cont.) 2022 2021 Oil swaps (cash \ufb02ow hedges) Carrying amount (US$m) (114) (1) Notional amount (MMbbl) 18 30 Maturity date 2023 2022-2023 Hedge ratio 1:1 1:1 Weighted average hedged rate (US$/MMbbl) 79 74 HH Corpus Christi commodity swaps (cash \ufb02ow hedges) Carrying amount (US$m) 26 31 Notional amount (TBtu) 58 65 Maturity date 2023-2024 2022-2023 Hedge ratio 1:1 1:1 Weighted average hedged rate (US$/MMBtu) 4 3 TTF Corpus Christi commodity swaps (cash \ufb02ow hedges) Carrying amount (US$m) (469) (465) Notional amount (TBtu) 50 49 Maturity date 2023-2024 2022-2023 Hedge ratio 1:1 1:1 Weighted average hedged rate (US$/MMBtu) 16 9 TTF commodity swaps (cash \ufb02ow hedges) Carrying amount (US$m) - 4 Notional amount (TBtu) - 3 Maturity date - 2022 Hedge ratio - 1:1 Weighted average hedged rate (US$/MMBtu) - 26 Interest rate swap (cash \ufb02ow hedges) Carrying amount (US$m) 55 (17) Notional amount (US$m) 600 600 Maturity date 2027 2027 Hedge ratio 1:1 1:1 Weighted average hedged rate 1.7% 1.7% Cross currency interest rate swap (cash \ufb02ow and fair value hedges) Carrying amount (US$m) 5 9 Notional amount (Swiss Franc) 175 175 Maturity date 2023 2023 Hedge ratio 1:1 1:1 Weighted average hedged rate Three month USD LIBOR +2.8% Three month USD LIBOR +2.8% FX forwards (cash \ufb02ow hedges) Carrying amount (US$m) (17) 10 Notional amount (AUD$m) 1,037 934 Maturity date 2023-2025 2022-2025 Hedge Ratio 1:1 1:1 Weighted average hedged rate (AUD:USD) 0.68 0.71 Hedge ineffectiveness loss of $72 million (2021: $38 million loss) has been recognised in the pro\ufb01t and loss. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfHedgeAccountingExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-780": {
"value": "D.7 Leases Land and buildings Plant and equipment 2 Total US$m US$m US$m Lease assets Year ended 31 December 2022 Carrying amount at 1 January 2022 377 703 1,080 Acquisitions through business combination1 120 22 142 Additions 4 238 242 Lease remeasurements 5 103 108 Depreciation (42) (266) (308) Carrying amount at 31 December 2022 464 800 1,264 At 31 December 2022 Historical cost and remeasurements 591 1,311 1,902 Accumulated depreciation, impairment and disposals (127) (511) (638) Net carrying amount 464 800 1,264 Lease liabilities Year ended 31 December 2022 At 1 January 2022 437 930 1,367 Acquisitions through business combination1 245 23 268 Additions 1 189 190 Repayments (principal and interest) (60) (305) (365) Accretion of interest 25 78 103 Lease remeasurements (25) 96 71 Carrying amount at 31 December 2022 623 1,011 1,634 Current 48 276 324 Non-current 575 735 1,310 Carrying amount at 31 December 2022 623 1,011 1,634 Lease assets Year ended 31 December 2021 Carrying amount at 1 January 2021 392 592 984 Additions 14 214 228 Lease remeasurements 15 16 31 Disposals at written down value (12) - (12) Depreciation (32) (119) (151) Carrying amount at 31 December 2021 377 703 1,080 At 31 December 2021 Historical cost 462 948 1,410 Accumulated depreciation and impairment (85) (245) (330) Net carrying amount 377 703 1,080 Lease liabilities Year ended 31 December 2021 At 1 January 2021 484 794 1,278 Additions 7 244 251 Repayments (principal and interest) (70) (192) (262) Accretion of interest 25 72 97 Lease remeasurements (9) 12 3 Carrying amount at 31 December 2021 437 930 1,367 Current 19 172 191 Non-current 418 758 1,176 Carrying amount at 31 December 2021 437 930 1,367 1. Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is obtained within 12 months from the acquisition date. Refer to Note B.5 for details. 2. Marine, vessels and carriers have been included within plant and equipment for the year ended 31 December 2022. The 2021 amounts have been reclassi\ufb01ed to be presented on the same basis. 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 identi\ufb01ed asset which is not substitutable and to obtain substantially all economic bene\ufb01ts 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\u2019s impairment policies. Lease liabilities are initially measured at the present value of future minimum lease payments, discounted using the Group\u2019s 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 \ufb01xed payments or index-based variable payments incorporating the Group\u2019s 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 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. Foreign exchange risk The Group held $441 million of lease liabilities at 31 December 2022 (2021: $476 million) in currencies other than the US dollar (predominantly Australian dollars). Maturity pro\ufb01le of lease liabilities The table below presents the contractual undiscounted cash \ufb02ows associated with the Group\u2019s lease liabilities, representing principal and interest. The \ufb01gures will not necessarily reconcile with the amounts disclosed in the consolidated statement of \ufb01nancial position. 2022 2021 US$m US$m Due for payment in: 1 year or less 433 283 1-2 years 272 283 2-3 years 199 191 3-4 years 186 171 4-5 years 176 161 More than 5 years 966 789 2,232 1,878 Lease commitments The table below presents the contractual undiscounted cash \ufb02ows associated with the Group's future lease commitments for non-cancellable leases not yet commenced, representing principal and interest. 2022 2021 US$m US$m Due for payment: Within one year 67 80 After one year but not more than \ufb01ve years 263 159 Later than \ufb01ve years 1,288 49 1,618 288 Payments of $162 million (2021: $68 million) for short-term leases (lease term of 12 months or less) and payments of $12 million (2021: $18 million) for leases of low value assets were expensed in the consolidated income statement. Total payments for leases in the consolidated statement of cash \ufb02ows are $525 million (2021: $330 million), with $258 million (2021: $244 million) included in \ufb01nancing activities. The Group has short-term and/or low value lease commitments for marine vessels and carriers, property, drill rigs and plant and equipment contracted for, but not provided for in the \ufb01nancial statements, of $60 million (2021: $53 million). Key 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 identi\ufb01ed asset and obtain substantially all the economic bene\ufb01ts 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 signi\ufb01cant change in circumstances occurs. On this basis, possible additional lease payments amounting to $2,323 million (2021: $1,654 million) were not included in the measurement of lease liabilities. (c) lnterest in joint arrangements Judgement is required to determine the Group\u2019s rights and obligations for lease contracts within joint operations, to assess whether lease liabilities are recognised gross (100%) or in proportion to the Group\u2019s 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\u2019s 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\u2019s borrowing portfolio at the inception of the arrangement or the time of the modi\ufb01cation.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLeasesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-812": {
"value": "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 identi\ufb01ed asset which is not substitutable and to obtain substantially all economic bene\ufb01ts 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\u2019s impairment policies. Lease liabilities are initially measured at the present value of future minimum lease payments, discounted using the Group\u2019s 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 \ufb01xed payments or index-based variable payments incorporating the Group\u2019s 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 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. Key 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 identi\ufb01ed asset and obtain substantially all the economic bene\ufb01ts 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 signi\ufb01cant change in circumstances occurs. On this basis, possible additional lease payments amounting to $2,323 million (2021: $1,654 million) were not included in the measurement of lease liabilities. (c) lnterest in joint arrangements Judgement is required to determine the Group\u2019s rights and obligations for lease contracts within joint operations, to assess whether lease liabilities are recognised gross (100%) or in proportion to the Group\u2019s participating interest in the joint operation. This includes an evaluation of whether the lease arrangement contains a sublease with the joint operation. (d) Discount rates Judgement is required to determine the discount rate, where the discount rate is the Group\u2019s incremental borrowing rate if the rate implicit in the lease cannot be readily determined. The incremental borrowing rate is determined with reference to the Group\u2019s borrowing portfolio at the inception of the arrangement or the time of the modi\ufb01cation. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-781": {
"value": "E.1 Contingent liabilities and assets 2022 2021 US$m US$m Contingent liabilities at reporting date Contingent liabilities 161 195 Guarantees 2 7 163 202 Contingent liabilities relate predominantly to possible obligations whose existence will only be con\ufb01rmed by the occurrence or non-occurrence of uncertain future events, and therefore the Group has not provided for such amounts in these \ufb01nancial statements. Additionally, there are a number of other claims and possible claims that have arisen in the course of business against entities in the Group, the outcome of which cannot be estimated at present and for which no amounts have been included in the table above. The Group has contingent assets of $199 million as at 31 December 2022 (2021: nil). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-814": {
"value": "Contingent liabilities relate predominantly to possible obligations whose existence will only be con\ufb01rmed by the occurrence or non-occurrence of uncertain future events, and therefore the Group has not provided for such amounts in these \ufb01nancial statements. Additionally, there are a number of other claims and possible claims that have arisen in the course of business against entities in the Group, the outcome of which cannot be estimated at present and for which no amounts have been included in the table above. The Group has contingent assets of $199 million as at 31 December 2022 (2021: nil). ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForContingentLiabilitiesAndContingentAssetsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-782": {
"value": "E.2 Employee bene\ufb01ts 2022 2021 2020 US$m US$m US$m Employee bene\ufb01ts 415 217 252 Share-based payments 26 12 19 De\ufb01ned contribution plan costs 41 26 27 De\ufb01ned bene\ufb01t plan expense 9 1 2 491 256 300 (a) Employee bene\ufb01ts Employee bene\ufb01ts for the reporting period are as follows: Recognition and measurement The Group\u2019s accounting policy for employee bene\ufb01ts 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 bene\ufb01ts on retirement, disability or death from the Group\u2019s retirement plans. The Group operates a number of pension schemes throughout the world. Employees entitled to de\ufb01ned contribution schemes receive \ufb01xed contributions from Group companies and the Group\u2019s legal or constructive obligation is limited to these contributions. Contributions to de\ufb01ned 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. (b) Compensation of key management personnel Key management personnel (KMP) compensation for the \ufb01nancial year was as follows: 2022 2021 2020 US$ US$ US$ Short-term employee bene\ufb01ts1 5,730,340 6,626,354 5,868,476 Post-employment bene\ufb01ts1 155,086 88,396 63,805 Share-based payments2 3,114,043 5,697,529 7,201,653 Long-term employee bene\ufb01ts 4,300 717,223 515,585 Termination bene\ufb01ts 152,531 2,447,525 390,087 9,156,300 15,577,027 14,039,606 1. The 2021 comparatives for short-term employee bene\ufb01ts and post-employment bene\ufb01ts have been restated to include the superannuation component of the 2021 EIS cash and other cash bonuses for three key management personnel, increasing the short-term employee bene\ufb01ts expense by $26,676 to $6,626,354 and the post-employee bene\ufb01ts expense by $10,881 to $88,396. 2. The 2021 comparative for share-based payments has been restated to include amortisation of the fair value of 2021 performance rights for two key management personnel, increasing the expense by $88,507 to $5,697,529. (c) Share plans The Group provides bene\ufb01ts to its employees (including KMP) in the form of share-based payments whereby employees render services for shares (equity-settled transactions). Woodside equity plan (WEP) and supplementary Woodside equity plan (SWEP) The WEP is available to all permanent employees, but since 1 January 2018 has excluded Executive Incentive Scheme (EIS) participants. The number of Equity Rights (ERs) offered to each eligible employee is determined by the Board, and based on individual performance as assessed under the performance review process. The linking of performance to an allocation allows the Group to recognise and reward eligible employees for high performance. The ERs have no further ongoing performance conditions after allocation, and do not require participants to make any payment in respect of the ERs at grant or at vesting. Each ER entitles the participant to receive a Woodside share on the vesting date three years after the grant date. For awards made in 2022, the Board amended the terms of the plan to entitle participants to receive a Woodside share on the vesting date, three years after the grant date. Awards made in 2020 and 2021 will vest under the terms of the plan at that time, which provided for 75% vesting of the ERs three years after the grant date and the remaining 25% of the ERs \ufb01ve years after the grant date. In October 2011, the Board approved the establishment of the SWEP to enable the offering of targeting retention awards of ERs for key capability. The SWEP was updated in 2022 to broaden eligibility to all employees of a subsidiary of Woodside Energy Group Ltd and ensure compliance in all jurisdictions in which Woodside operates. This facilitated the offer of replacement unvested incentives, as required under transitional arrangements for eligible heritage BHP employees transitioning from BHP Group Long-Term Incentive (LTI) plans to VAR offered under Woodside\u2019s VAR arrangements. Woodside equity plan (WEP) and supplementary Woodside equity plan (SWEP) (cont.) Each ER entitles the participant to receive a Woodside share or an American Depositary share on the vesting date either one, two, three or four years after the effective grant date, depending on the individual details of each SWEP offered. Participants do not make any payment in respect of the ERs at grant or at vesting. Executive Incentive Plans (EIP) The EIP operated as Woodside\u2019s Executive incentive framework until the end of 2017, after which the Board introduced the EIS. The EIP was used to deliver Short-Term Awards (STAs) and Long-Term Awards (LTAs) to Senior Executives. Short-Term Awards (STAs) STAs were delivered in the form of restricted shares to Executives, including all Executive KMP. There are no further performance conditions for vesting of deferred STAs. Participants are not required to make any payments in respect of STA awards at grant or at vesting. Restricted shares entitle their holders to receive dividends. Long-Term Awards (LTAs) LTAs were granted in the form of Performance Rights (PRs) to Executives, including all Executive KMP. Vesting of LTAs is subject to achievement of relative total shareholder return (RTSR) targets, with 33% measured against the ASX 50 and the remaining 67% tested against an international group of oil and gas companies. Participants are not entitled to receive dividends and are not required to make any payments in respect of LTA awards at grant or at vesting. Executive Incentive Scheme (EIS) The EIS was introduced for the 2018 performance year for all Executives including Executive KMP. The EIS is delivered in the form of a cash incentive, Restricted Shares and Performance Rights. The grant date of the Restricted Shares and Performance Rights has been determined to be subsequent to the performance year, being the date of the Board of Directors\u2019 approval. Accordingly, the 2021 Restricted Shares and Performance Rights were granted on 16 February 2022 for Executives and 19 May 2022 for the CEO and have been included in the table below. The expense estimated as at 31 December 2021 in relation to the 2021 performance year was updated to the fair value on grant date during the period. The 2022 Restricted Shares and Performance Rights have not been included in the table below as they have not been approved as at 31 December 2022. An expense related to the 2022 performance year has been estimated for the Restricted Shares and Performance Rights, using fair value estimates based on inputs at 31 December 2022. Performance Based Pay Plus (PBP Plus) PBP Plus is available to senior, permanent employees who are not Executives. Participants receive an annual award of cash and Restricted Shares based on corporate and individual performance, recognising and rewarding eligible employees for high performance. The grant date of the Restricted Shares has been determined to be subsequent to the performance year, being the date of the Board of Directors\u2019 approval. Accordingly, the 2021 Restricted Shares were granted on 16 February 2022 and have been included in the table below. The expense estimated as at 31 December 2021 in relation to the 2021 performance year was updated to the fair value on grant date during the period. The 2022 Restricted Shares have not been included in the table below as they have not been approved as at 31 December 2022. An expense related to the 2022 performance year has been estimated for the Restricted Shares, using fair value estimates based on inputs at 31 December 2022. Recognition and measurement All compensation under WEP, SWEP and Executive share plans 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 ful\ufb01lled, 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 bene\ufb01t 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 bene\ufb01t provided for the RTSR PRs 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. E.2 Employee bene\ufb01ts (cont.) The number of awards and movements for all share plans are summarised as follows: Number of performance awards Employee plans Executive plans WEP SWEP STA4 LTA4 Year ended 31 December 2022 Opening balance 5,649,783 - 994,436 2,379,220 Granted during the year1,2,3 3,017,366 3,046,963 495,800 764,171 Vested during the year (1,498,065) (38,146) (450,609) (191,736 Forfeited during the year (539,403) (124,741) (46,430) (397,233) Awards at 31 December 2022 6,629,681 2,884,076 993,197 2,554,422 US$m US$m US$m US$m Fair value of awards granted during the year 49 60 9 13 Number of performance awards Employee plans Executive plans WEP SWEP STA4 LTA4 Year ended 31 December 2021 Opening balance 5,618,603 - 975,295 2,798,305 Granted during the year1,2,3 2,507,167 - 353,412 553,849 Vested during the year (1,999,676) - (307,402) (322,746) Forfeited during the year (476,311) - (26,869) (650,188) Awards at 31 December 2021 5,649,783 - 994,436 2,379,220 US$m US$m US$m US$m Fair value of awards granted during the year 39 - 7 9 1. For the purpose of valuation, the share price on grant date for the 2022 WEP allocations was $16.30 (2021: $15.17). 2. For the purpose of valuation, the share price on grant date for the 2022 SWEP allocations was $19.74 (2021: nil). 3. For the purpose of valuation, the share price on grant date for Restricted Shares was $19.20 and $19.27 (2021: $20.18) and Performance Rights was $13.08 and $13.71 (2021: $11.66 and $14.44). 4. Includes awards issued under EIP and EIS. For more detail on these share plans and performance rights issued to KMPs, refer to the Remuneration Report. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-813": {
"value": "Recognition and measurement The Group\u2019s accounting policy for employee bene\ufb01ts 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 bene\ufb01ts on retirement, disability or death from the Group\u2019s retirement plans. The Group operates a number of pension schemes throughout the world. Employees entitled to de\ufb01ned contribution schemes receive \ufb01xed contributions from Group companies and the Group\u2019s legal or constructive obligation is limited to these contributions. Contributions to de\ufb01ned 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 and Executive share plans 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 ful\ufb01lled, 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 bene\ufb01t 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 bene\ufb01t provided for the RTSR PRs 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-815": {
"value": "E.3 Related party transactions The Group\u2019s related party transactions are predominantly with associates of the Group. During the period, the transactions with related parties include purchases of goods/services of $60.730 million, sale of goods/services of $18.527 million and dividend income of $8.294 million. As at 31 December 2022, the total amounts owing to related parties is $1.686 million and amounts owing from related parties is $2.200 million. All transactions to/from related parties are made at arm\u2019s length (normal market rates and on normal commercial terms). There were no transactions with directors during the year. Key management personnel compensation is disclosed in Note E.2(b). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTransactionsBetweenRelatedPartiesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-783": {
"value": "E.3 Related party transactions The Group\u2019s related party transactions are predominantly with associates of the Group. During the period, the transactions with related parties include purchases of goods/services of $60.730 million, sale of goods/services of $18.527 million and dividend income of $8.294 million. As at 31 December 2022, the total amounts owing to related parties is $1.686 million and amounts owing from related parties is $2.200 million. All transactions to/from related parties are made at arm\u2019s length (normal market rates and on normal commercial terms). There were no transactions with directors during the year. Key management personnel compensation is disclosed in Note E.2(b). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-784": {
"value": "E.4 Auditor remuneration For the year ended 31 December 2022, the auditor of Woodside Energy Group Ltd is PricewaterhouseCoopers Australia (PwC) (2021 and 2020: Ernst & Young (EY)). 2022 2021 2020 US$000 US$000 US$000 (a) Auditors of the Group Amounts received or due and receivable to: PricewaterhouseCoopers (Australia) Audit and review of \ufb01nancial reports 2,878 - - Assurance services 129 - - Other assurance and agreed upon procedures services 832 - - Tax services - - - Other services 41 - - Other overseas member \ufb01rms of PricewaterhouseCoopers (Australia) Audit of the \ufb01nancial reports of controlled entities 1,274 - - Other assurance and agreed upon procedures services - - - Tax services 258 - - Other services - - - 5,412 - - (b) Other auditors and their related network \ufb01rms Ernst & Young Audit and review of \ufb01nancial reports 48 1,732 1,686 Assurance services 611 2,687 - Other assurance and agreed upon procedures services 2,335 33 140 Tax services - 129 178 Other services - 19 - 2,994 4,600 2,004",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-785": {
"value": "E.5 Events after the end of the reporting period The Group has undertaken a review of the depreciation methodology and asset useful lives for oil and gas properties in accordance with its accounting policies and the accounting standards, considering the scale and diversity of the post- merger portfolio and to ensure alignment with common industry practice. In assessing useful lives of certain oil and gas assets, these have been approximated by reference to either their proved (1P) or proved plus probable (2P) reserves, which is then used in the units of production depreciation calculation. From 1 January 2023, upstream oil and conventional gas assets will be depreciated over proved reserves (previously proved plus probable, except for certain assets considered late life). Upstream LNG assets will continue to be depreciated over proved plus probable reserves. Multiproduct assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life. The indicative impact to depreciation expense in 2023 resulting from the change in estimate is expected to be an increase of approximately $600 million. This is an indicative amount and is based on current forecasts which are subject to assumptions and uncertainties. ",
"dimensions": {
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"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-786": {
"value": "E.6 Joint arrangements (a) Interest percentage in joint ventures Group Interest % Entity Principal activity 2022 2021 North West Shelf Gas Pty Ltd Contract administration services for venturers for LNG sales to Japan. Marketing and administration services for venturers for gas processing. 33.33 16.67 North West Shelf Liaison Company Pty Ltd Liaison for venturers in the sale of LNG to the Japanese market. 33.33 16.67 China Administration Company Pty Ltd Contract administration services for venturers for LNG sales to China. 33.33 16.67 North West Shelf Shipping Service Company Pty Ltd LNG vessel \ufb02eet advisor. 33.33 16.67 North West Shelf Lifting Coordinator Pty Ltd Allocating, scheduling and administering the lifting of LNG and pipeline gas. 33.33 16.67 E.6 Joint arrangement (cont.) (b) Interest percentage in joint operations Group Interest % 2022 2021 Producing and developing assets Australia North West Shelf1 25.0 - 66.7 12.5 - 50.0 Greater En\ufb01eld and Vincent 60.0 60.0 Stybarrow2 - 50.0 Balnaves 65.0 65.0 Pluto 90.0 90.0 Wheatstone 13.0 - 65.0 13.0 - 65.0 Scarborough2 - 73.5 Bass Strait1 25.0 - 50.0 - Macedon1 71.4 - Pyrenees1 40.0 - 71.4 - Griffin1 45.0 - 71.0 - Minerva1 90.0 - International Sangomar 82.0 82.0 Atlantis1 44.0 - Mad Dog1 23.9 - Shenzi1 72.0 - Trion1 60.0 - Greater Angostura1 45.0 - 68.5 - Calypso1 70.0 - Exploration and evaluation assets Oceania Browse Basin 30.6 30.6 Carnarvon Basin3 31.6 - 70.0 15.8 - 70.0 Scarborough2,3 - 50.0 Bonaparte Basin 26.7 - 35.0 26.7 - 35.0 Africa Congo4 22.5 42.5 Senegal 90.0 90.0 Egypt1 25.0 - 45.0 - Americas US Gulf of Mexico1 23.9 - 75.0 - Kitimat 50.0 50.0 Asia Republic of Korea 50.0 50.0 Myanmar5 40.0 - 45.0 40.0 - 50.0 Caribbean Barbados1 60.0 - Trinidad & Tobago1 65.0 - 70.0 - Other joint operations Angel6 20.0 - Bonaparte Basin6 21.0 - 1. Increase in interests due to the merger with BHPP on 1 June 2022. 2. No longer recognised as joint operations as the Group\u2019s interest increased to 100% due to the merger with BHPP on 1 June 2022. 3. The Carnarvon Basin and Scarborough exploration and evaluation assets which were previously presented on the same line, have been separately presented in 2022. The 2021 Group interests have been reclassi\ufb01ed to be presented on the same basis. 4. The Group\u2019s interest decreased to 22.5% upon farm-down of interest in June 2022. 5. The Group relinquished permits AD-1 and AD-8 in 2022. Formalities are pending. 6. Carbon Capture Storage titles G-10-AP and G-7-AP granted to the Group in 2022. The principal activities of the joint operations are exploration, development and production of hydrocarbons. Key estimates and judgements 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 signi\ufb01cant in\ufb02uence 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 signi\ufb01cant in\ufb02uence over the entity, which is then accounted for as an associate. 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 classi\ufb01ed 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 classi\ufb01ed as a joint operation, and as such the Group recognises its: \u2022 assets, including its share of any assets held jointly; \u2022 liabilities, including its share of any liabilities incurred jointly; \u2022 revenue from the sale of its share of the output arising from the joint operation; \u2022 share of revenue from the sale of the output by the joint operation; and \u2022 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 classi\ufb01ed 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 AASB 3/ IFRS 3 Business Combinations. Joint arrangements which are not deemed to be carrying on a business are treated as asset acquisitions.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfJointVenturesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-816": {
"value": "Key estimates and judgements 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 signi\ufb01cant in\ufb02uence 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 signi\ufb01cant in\ufb02uence over the entity, which is then accounted for as an associate. 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 classi\ufb01ed 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 classi\ufb01ed as a joint operation, and as such the Group recognises its: \u2022 assets, including its share of any assets held jointly; \u2022 liabilities, including its share of any liabilities incurred jointly; \u2022 revenue from the sale of its share of the output arising from the joint operation; \u2022 share of revenue from the sale of the output by the joint operation; and \u2022 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 classi\ufb01ed 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 AASB 3/ IFRS 3 Business Combinations. Joint arrangements which are not deemed to be carrying on a business are treated as asset acquisitions. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-787": {
"value": "E.7 Parent entity information 2022 2021 US$m US$m Woodside Energy Group Ltd: Current assets 312 456 Non-current assets 34,734 10,037 Current liabilities (1,530) (357) Non-current liabilities (481) (300) Net assets 33,035 9,836 Issued and fully paid shares 29,001 9,409 Reserved shares (38) (30) Employee bene\ufb01ts reserve 150 112 Foreign currency translation reserve 296 296 Distributable pro\ufb01ts reserve 3,541 58 Retained earnings 85 (9) Total shareholders equity 33,035 9,836 Pro\ufb01t of parent entity 6,665 18 Total comprehensive income of parent entity 6,665 18 Guarantees Woodside Energy Group Ltd and Woodside Energy Ltd (a subsidiary company) are parties to a Deed of Cross Guarantee as disclosed in Note E.8. The effect of the Deed is that Woodside Energy Group Ltd has guaranteed to pay any de\ufb01ciency in the event of winding up of the subsidiary company under certain provisions of the Corporations Act 2001. The subsidiary company has also given a similar guarantee in the event that Woodside Energy Group Ltd is wound up. Woodside Energy Group Ltd has guaranteed the discharge by a subsidiary company of its \ufb01nancial obligations under debt facilities disclosed in Note C.2. Woodside Energy Group Ltd has guaranteed certain obligations of subsidiaries to unrelated parties on behalf of their performance in contracts. No liabilities are expected to arise from these guarantees. ",
"dimensions": {
"concept": "woodsideenergygroupltd:DisclosureOfParentEntityInformation",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-788": {
"value": "E.8 Subsidiaries (a) Subsidiaries Name of entity Notes Ultimate Parent Entity Woodside Energy Group Ltd (1,2,3) Subsidiaries Company name Woodside Energy Ltd (2,3,4) Woodside Browse Pty Ltd (2,4) Woodside Burrup Pty Ltd (2,4) Burrup Facilities Company Pty Ltd (5) Burrup Train 1 Pty Ltd (5) Pluto LNG Pty Ltd (5) Woodside Burrup Train 2 A Pty Ltd (2,4) Woodside Burrup Train 2 B Pty Ltd (2,4) Woodside Energy (LNG Fuels and Power) Pty Ltd (2,4) Woodside Energy (Domestic Gas) Pty Ltd (2,4) Woodside Energy (Algeria) Pty Ltd (2,4) Woodside Energy Australia Asia Holdings Pte Ltd y (4) Woodside Energy Holdings International Pty Ltd (2,4) Name of entity Notes Woodside Energy International (Canada) Limited t (4) Woodside Energy (Canada LNG) Limited t (4) Woodside Energy (Canada PTP) Limited t (4) KM LNG Operating General Partnership t (9) KM LNG Operating Ltd t (4) Woodside Energy Holdings Pty Ltd (2,4) Woodside Energy Holdings (USA) Inc q (4) Woodside Energy (USA) Inc q (4) Gryphon Exploration Company q (4) PT Woodside Energy Indonesia (6) Woodside Energy (Cameroon) SARL n (4) Woodside Energy (Gabon) Pty Ltd (2,4) Woodside Energy (Indonesia) Pty Ltd (2,4) Woodside Energy (Indonesia II) Pty Ltd (2,4) Woodside Energy (Malaysia) Pty Ltd (2,4) Woodside Energy (Ireland) Pty Ltd (2,4) Woodside Energy (Korea) Pte Ltd y (4) Woodside Energy (Korea II) Pte Ltd y (4) Woodside Energy (Myanmar) Pte Ltd y (4) Woodside Energy (Morocco) Pty Ltd (2,4) Woodside Energy (New Zealand) Limited z (4) Woodside Energy (New Zealand 55794) Limited z (4) Woodside Energy (Peru) Pty Ltd (2,4) Woodside Energy (Senegal) Pty Ltd (2,4) Woodside Energy (Tanzania) Limited 3 (7) Woodside Energy Holdings II Pty Ltd (2,4) Woodside Power Pty Ltd (2,4) Woodside Power (Generation) Pty Ltd (2,4) Woodside Energy Holdings (South America) Pty Ltd (2,4) Woodside Energia (Brasil) Apoio Administrativo Ltda l (8) Woodside Energy Holdings (UK) Pty Ltd (2,4) Woodside Energy (UK) Limited p (4) Woodside Energy Finance (UK) Limited p (4) Woodside Energy (Congo) Limited p (4) Woodside Energy (Bulgaria) Limited p (4) Woodside Energy Holdings (Senegal) Limited p (4) Woodside Energy (Senegal) B.V. (4) Woodside Energy (France) SAS \u00a3 (4) Woodside Energy Iberia S.A. \u00ba (4) Woodside Energy (N.A.) Ltd p (4) Woodside Energy Services (Qingdao) Co Ltd (4) Woodside Energy Julimar Pty Ltd (2,4) Woodside Energy (Norway) Pty Ltd (2,4) Woodside Energy Technologies Pty Ltd (2,4,14) Woodside Technology Solutions Pty Ltd (2,4) Woodside Energy Scarborough Pty Ltd (2,4) Woodside Energy Carbon Holdings Pty Ltd (2,4) Woodside Energy Carbon (Assets) Pty Ltd (2,4) Woodside Energy Carbon (Services) Pty Ltd (2,4) Woodside Energy (Financial Advisory Services) Pty Ltd (2,4) Woodside Energy Trading Singapore Pte Ltd y (4) WelCap Insurance Pte Ltd y (4) Woodside Energy Shipping Singapore Pte Ltd y (4) Metasource Pty Ltd (2,4) Mermaid Sound Port and Marine Services Pty Ltd (2,4) Woodside Finance Limited (2,4) Woodside Petroleum (Timor Sea 19) Pty Ltd (2,4) Woodside Petroleum (Timor Sea 20) Pty Ltd (2,4) Woodside Petroleum Holdings Pty Ltd (2,4,15) Woodside Energy Global Holdings Pty Ltd (2,4) E.8 Subsidiaries (cont.) Name of entity Notes Woodside Energy Global Pty Ltd (2,4) Perdido Mexico Pipeline Holdings, S.A. de C.V. (10) Perdido Mexico Pipeline, S. de R.L. de C.V. (10) Woodside Energy Investments Pty Ltd (2,4) Woodside Energia Brasil Investimentos Ltda. l (11) Woodside Energia Brasil Explora\u00e7\u00e3o e Produ\u00e7\u00e3o Ltda. l (4) Woodside Energy (Great Britain) Limited p (4) Woodside Energy (North West Shelf) Pty Ltd (2,4) Woodside Energy (Trinidad) Holdings Ltd (4) Woodside Energy (Trinidad-3A) Ltd (4) Woodside Energy USA Operations Inc q (12) Hamilton Brothers Petroleum Corporation q (4) Hamilton Oil Company LLC q (4) Woodside Energy Boliviana Inc. q (4) Woodside Energy (North America) LLC q (4) Woodside Energy (Americas) Inc. q (4) Woodside Energy (GOM) Inc. q (4) Woodside Energy Hawaii Inc. q (4,16) Woodside Energy Resources Inc. q (4) Woodside Energy Holdings (Resources) Inc. q (4) Woodside Energy USA Services Inc. q (4) Woodside Energy Marketing Inc. q (4) Woodside Energy (Deepwater) Inc. q (4,17) Woodside Energy (Foreign Exploration Holdings) LLC q (4) Woodside Energy (Trinidad Block 3) Limited p (4) Woodside Energy (Trinidad Block 6) Limited p (4) Woodside Energy (Trinidad Block 5) Limited p (4) Woodside Energy (Trinidad Block 7) Limited p (4) Woodside Energy (Trinidad Block 14) Limited p (4) Woodside Energy (Trinidad Block 23A) Limited p (4) Woodside Energy (Trinidad Block 23B) Limited p (4) Woodside Energy (Trinidad Block 28) Limited p (4) Woodside Energy (Trinidad Block 29) Limited p (4) Woodside Energy (Bimshire) Limited p (4) Woodside Energy (South Africa 3B/4B) Limited p (4) Woodside Energy (Egypt) Limited p (4) Woodside Energy (Carlisle Bay) Limited p (4) Woodside Energy (Mexico) Limited p (4) Woodside Energ\u00eda Servicios Administrativos, S. de R.L. de C.V. (13) Woodside Energ\u00eda Servicios de M\u00e9xico, S. de R.L. de C.V. (13) Woodside Energy (Mexico Holdings) LLC q (4) Operaciones Conjuntas, S. de R.L. de C.V. (13) Woodside Energ\u00eda Holdings de M\u00e9xico, S. de R.L. de C.V. (13) Woodside Petr\u00f3leo Operaciones de M\u00e9xico, S. de R.L. de C.V. (13) Woodside Energy (Australia) Pty Ltd (2,4) Woodside Energy (International Exploration) Pty Ltd (2,4) Woodside Energy (Bass Strait) Pty Ltd (2,4) Woodside Energy (Victoria) Pty Ltd (2,4) Woodside Energy Holdings LLC q (4) Woodside Energy (Trinidad-2C) Ltd t (4) Woodside Energy (Canada) Corporation t (4) 1. Woodside Energy Group Ltd, previously Woodside Petroleum Ltd, is the ultimate holding company and the head entity within the tax consolidated group. 2. These companies were members of the Australian tax consolidated group at 31 December 2022. 3. Woodside Energy Group Ltd and Woodside Energy Ltd are parties to a Deed of Cross Guarantee. 4. All subsidiaries are wholly owned except those referred to in Notes 5 to 13. 5. Kansai Electric Power Australia Pty Ltd and Tokyo Gas Pluto Pty Ltd each hold a 5% interest in the shares of these subsidiaries. These subsidiaries are controlled. 6. PT Woodside Energy Indonesia was incorporated on 27 April 2022. As at 31 December 2022, Woodside Energy Holdings Pty Ltd held a 99% interest in the shares of PT Woodside Energy Indonesia. Woodside Energy Ltd held the remaining 1% interest. 7. As at 31 December 2022, Woodside Energy Holdings Pty Ltd held >99.99% interest in the shares of Woodside Energy (Tanzania) Limited and Woodside Energy Ltd held the remaining interest. 8. As at 31 December 2022, Woodside Energy Holdings (South America) Pty Ltd held >99.99% interest in the shares of Woodside Energia (Brasil) Apoio Administrativo Ltda and Woodside Energy Ltd held the remaining interest. 9. As at 31 December 2022, Woodside Energy International (Canada) Limited and Woodside Energy (Canada LNG) Limited were the general partners of the KM LNG Operating General Partnership holding a 99.99% and 0.01% partnership interest, respectively. 10. As at 31 December 2022, Woodside Energy Global Holdings Pty Ltd held a 99.99% interest in shares of Perdido Mexico Pipeline Holdings, S.A. de C.V. and Perdido Mexico Pipeline, S. de R.L. de C.V. Woodside Energy Investments Pty Ltd held the remaining 0.01% interest. 11. As at 31 December 2022, Woodside Energy Investments Pty Ltd held a 99.97% interest in shares of Woodside Energia Brasil Investimentos Ltda. Woodside Energy Global Holdings Pty Ltd held the remaining 0.03% interest. 12. As at 31 December 2022, Woodside Energy Global Holdings Pty Ltd held 90% voting interest and 37.67% interest in shares of Woodside Energy USA Operations Inc. Woodside Energy Holdings LLC held the remaining 10% voting interest and 62.33% interest in shares. 13. As at 31 December 2022, Woodside Energy (Mexico) Limited held a 99% interest in shares of Woodside Energ\u00eda Servicios Administrativos, S. de R.L. de C.V., Woodside Energ\u00eda Servicios de M\u00e9xico, S. de R.L. de C.V., Operaciones Conjuntas, S. de R.L. de C.V. and Woodside Petr\u00f3leo Operaciones de M\u00e9xico, S. de R.L. de C.V. and 99.99% interest in shares of Woodside Energ\u00eda Holdings de M\u00e9xico, S. de R.L. de C.V. Woodside Energy (Mexico Holdings) LLC held the remaining 0.01%-1% interest. 14. Woodside Energy Technologies Pty Ltd owns 28.50% in Blue Ocean Seismic Services Limited which is accounted for as an investment in associate. 15. Woodside Energy (North West Shelf) Pty Ltd and Woodside Petroleum Holdings Pty Ltd owns 16.67% in International Gas Transportation Company Limited respectively. This investment has been accounted for as an investment in associate. 16. Woodside Energy Hawaii Inc owns 14.96% in Iwilei District Participating Parties LLC which is accounted for as an investment in associate. 17. Woodside Energy (Deepwater) Inc owns 25% in Caesar Oil Pipeline Company LLC, 22% in Cleopatra Gas Gathering Company LLC and 10% in Marine Well Containment Company LLC. These investments are accounted for as an investment in associate. All subsidiaries were incorporated in Australia unless identi\ufb01ed with one of the following symbols: Bermuda l Brazil n Cameroon t Canada China \u00a3 France Mexico Indonesia The Netherlands R. of Trinidad and Tobago z New Zealand Saint Lucia y Singapore \u00ba Spain 3 Tanzania p United Kingdom q United States Classi\ufb01cation 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\u2019s returns. E.8 Subsidiaries (cont.) (b) Subsidiaries with material non-controlling interests The Group has two Australian subsidiaries with material non-controlling interests (NCI). Name of entity Principal place of business % held by NCI Burrup Facilities Company Pty Ltd Australia 10% Burrup Train 1 Pty Ltd Australia 10% The NCI in both subsidiaries is 10% held by the same parties (refer to Note E.8(a) footnote 5 for details). The summarised \ufb01nancial information (including consolidation adjustments but before intercompany eliminations) of subsidiaries with material NCI is as follows: 2022 2021 2020 US$m US$m US$m Burrup Facilities Company Pty Ltd Current assets 567 518 425 Non-current assets 5,047 5,038 5,224 Current liabilities (68) (71) (51) Non-current liabilities (528) (528) (571) Net assets 5,018 4,957 5,027 Accumulated balance of NCI 502 496 503 Revenue 889 858 859 Pro\ufb01t 489 328 318 Pro\ufb01t allocated to NCI 49 33 32 Dividends paid to NCI (43) (40) (32) Operating 601 633 652 Investing (45) (111) (69) Financing (556) (522) (583) Net increase/(decrease) in cash and cash equivalents - - - Burrup Train 1 Pty Ltd Current assets 429 435 372 Non-current assets 2,900 2,915 3,081 Current liabilities (119) (110) (103) Non-current liabilities (325) (345) (385) Net assets 2,885 2,895 2,965 Accumulated balance of NCI 289 290 297 Revenue 1,471 1,421 1,423 Pro\ufb01t 282 200 208 Pro\ufb01t allocated to NCI 28 20 21 Dividends paid to NCI (29) (27) (13) Operating 391 393 473 Investing (55) (4) (2) Financing (336) (389) (471) Net increase/(decrease) in cash and cash equivalents - - - (c) Deed of Cross Guarantee and Closed Group Woodside Energy Group Ltd and Woodside Energy Ltd are parties to a Deed of Cross Guarantee under which each company guarantees the debts of the other. The two entities represent a Closed Group. The consolidated income statement and consolidated statement of \ufb01nancial position of the members of the Closed Group are set out below: 2022 2021 US$m US$m Closed Group Consolidated Income Statement and Statement of Retained Earnings Pro\ufb01t before tax 6,586 1,599 Tax expense (314) (50) Pro\ufb01t after tax 6,272 1,549 Retained earnings at the beginning of the \ufb01nancial year 1,660 111 Other comprehensive income 1 - Transfer of retained earnings to distributable pro\ufb01ts reserve (5,553) - Dividends (1,018) - Retained earnings at the end of the \ufb01nancial year 1,362 1,660 Closed Group Consolidated Statement of Financial Position Current assets Cash and cash equivalents 116 160 Receivables 675 948 Inventories 56 47 Other \ufb01nancial assets 653 173 Other assets 21 22 Total current assets 1,521 1,350 Non-current assets Receivables 2,171 476 Other \ufb01nancial assets 57,844 36,432 Exploration and evaluation assets 28 31 Oil and gas properties 2,424 2,930 Deferred tax assets 421 579 Lease assets 315 319 Other assets 67 13 Total non-current assets 63,270 40,780 Total assets 64,791 42,130 Current liabilities Payables 483 186 Other \ufb01nancial liabilities 675 409 Provisions 328 320 Tax payable 1,556 357 Lease liabilities 36 23 Other liabilities 38 34 Total current liabilities 3,116 1,329 Non-current liabilities Payables 25,524 27,104 Other \ufb01nancial liabilities 68 153 Provisions 1,121 1,179 Lease liabilities 325 360 Other liabilities 11 15 Total non-current liabilities 27,049 28,811 Total liabilities 30,165 30,140 Net assets 34,626 11,990 Equity Issued and fully paid shares 29,001 9,409 Reserved shares (38) (30) Other reserves 4,301 951 Retained earnings 1,362 1,660 Total equity 34,626 11,990",
"dimensions": {
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-817": {
"value": "(b) New and amended accounting standards and interpretations issued but not yet effective A number of new standards, amendments of standards and interpretations have recently been issued but are not yet effective and have not been adopted by the Group as at the \ufb01nancial reporting date. The Group has reviewed these standards and interpretations and has determined that none of the new or amended standards will signi\ufb01cantly affect the Group\u2019s accounting policies, \ufb01nancial position or performance. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfExpectedImpactOfInitialApplicationOfNewStandardsOrInterpretations",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-789": {
"value": "(b) New and amended accounting standards and interpretations issued but not yet effective A number of new standards, amendments of standards and interpretations have recently been issued but are not yet effective and have not been adopted by the Group as at the \ufb01nancial reporting date. The Group has reviewed these standards and interpretations and has determined that none of the new or amended standards will signi\ufb01cantly affect the Group\u2019s accounting policies, \ufb01nancial position or performance. (c) New and amended accounting standards and interpretations adopted As of 1 January 2022, the Group adopted AASB 2020-3 Amendments to AASs \u2013 Annual Improvements 2018-2020 and Other Amendments including: \u2022 Amendments to AASB 3 Reference to the Conceptual Framework \u2022 Amendments to AASB 9 Fees in the \u201810 per cent\u2019 Test for Derecognition of Financial Liabilities \u2022 Amendments to AASB 137 Onerous Contracts \u2013 Costs of Ful\ufb01lling a Contract These amendments did not impact the \ufb01nancial statements of the Group. A number of other new standards are also effective from 1 January 2022 but they do not have a material effect on the Group\u2019s \ufb01nancial statements. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-818": {
"value": "(c) New and amended accounting standards and interpretations adopted As of 1 January 2022, the Group adopted AASB 2020-3 Amendments to AASs \u2013 Annual Improvements 2018-2020 and Other Amendments including: \u2022 Amendments to AASB 3 Reference to the Conceptual Framework \u2022 Amendments to AASB 9 Fees in the \u201810 per cent\u2019 Test for Derecognition of Financial Liabilities \u2022 Amendments to AASB 137 Onerous Contracts \u2013 Costs of Ful\ufb01lling a Contract These amendments did not impact the \ufb01nancial statements of the Group. A number of other new standards are also effective from 1 January 2022 but they do not have a material effect on the Group\u2019s \ufb01nancial statements. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfInitialApplicationOfStandardsOrInterpretations",
"language": "en",
"entity": "scheme:2549005ZC5RXAOO7FH41",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
}
}
}