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ABOUT THESE STATEMENTS
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 2024.
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 International Financial
Reporting Standards (IFRS) as issued by the International
Accounting Standards Board. They also include additional
disclosures required for foreign registrants by the United States
Securities and Exchange Commission (US SEC).
The Group\u2019s accounting policies are consistent with those
disclosed in the Group\u2019s 2022 Financial Statements.
Adoption of new or amended standards and interpretations
effective 1 January 2023 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 climate change.
Updated assumptions used for depreciation methodology
and asset useful lives, impairment assessments, business
combinations and restoration obligations are disclosed in
Notes B.3, B.4, B.5 and D.5 respectively; these assumptions
could change in the future. New estimates and judgements
relating to the sell-down of the Scarborough joint venture and
an embedded commodity derivative are disclosed in Notes B.8
and D.6 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, 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
2023 (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 material 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 values of its assets and
liabilities. This note describes climate-related assumptions that
underpin key areas of the \ufb01nancial statements and the potential
short-term and long-term impacts differing scenarios could have
on the \ufb01nancial results and \ufb01nancial position of Woodside.
Financial planning and assumptions
Woodside considers a range of climate and macroeconomic
scenarios to help benchmark our long-term price assumptions
and inform our decision-making to maintain a resilient \ufb01nancial
position. These scenarios are informed by a wide range of
externally published data, including Paris-aligned and non-
Paris-aligned outcomes, and are part of a broad consideration
of risks, opportunities, competitiveness and resilience. The
assumptions applied in assessing amounts within the \ufb01nancial
statements require signi\ufb01cant judgement and 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 goals as well as other goals such as energy
security and economic development. Price assumptions consider
current legislation in the locations where Woodside operates and
place some weight on scenarios in which the transition to a lower
carbon energy system is sufficiently rapid to meet 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 challenging environments.
The high degree of uncertainty around the nature, timing and
magnitude of climate-related risks, and the uncertainty as
to how the energy transition will evolve, makes it difficult to
determine the risks and their potential impacts with precision.
Woodside continues to monitor the uncertainty around
climate change risks and expects to take into account ongoing
developments into its assumptions, including assumptions
concerning commodity and carbon pricing, as considered
appropriate. 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 the Group's accounting policies and
applicable accounting standards, 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 to support the recoverable amount.
The sale of the 10% non-operating participating interest in the
Scarborough Joint Venture to LNG Japan announced in August
2023 is a clear example of an independent market valuation fully
supporting the carrying value of the multi-decade asset.
Price forecasts are adjusted for premiums and discounts based
on the nature and quality of the product. Commodity oil price
estimates 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. The
IEA\u2019s World Energy Outlook 2023 (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.
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)
2024-2027
2028-2032
2033-2036
2037-2040
NZE
52
41
34
31
APS
76
74
72
69
STEPS
84
85
84
84
Woodside
73
70
70
70
Average North Asian
LNG (RT US$/MMbtu)
2024-2027
2028-2032
2033-2036
2037-2040
NZE
8
5
5
5
APS
10
8
7
7
STEPS
11
9
9
8
Woodside
11
9
9
9
Average Carbon
(RT US$/tonne)
2024-2027
2028-2032
2033-2036
2037-2040
NZE
101
139
169
195
APS
100
133
153
169
STEPS
80
80
80
80
Woodside
80
80
80
80
1. IEA 2023. \u2018World Energy Outlook 2023\u2019. All rights reserved.
2. Based on data from IEA 2023. \u2018World Energy Outlook 2023\u2019 as modi\ufb01ed by Woodside analysis.
Woodside used interpolation techniques to estimate Brent annual price points in between
the years that the IEA disclose prices for. 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 that the IEA disclose prices for. For oil linked LNG contracts, prices are derived from the
Brent forecasts and the terms of the contracts.
3. Based on data from IEA 2023. \u2018World Energy Outlook 2023\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 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.
Refer to Note B.4 for the sensitivity analysis performed on
Woodside\u2019s commodity 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 may be addressed to varying degrees
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. 55% (2022: 54%) 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. This
includes the demand and related costs for offshore services
which can be in\ufb02uenced by renewable energy construction.
Woodside continues to monitor the uncertainty around climate
change risks to assess if additional changes to restoration
provisions should be recognised.
Long-term contracts
Climate risks may impact underlying assumptions used to
assess the forecast cash \ufb02ows of long-term contracts. These
judgemental assumptions include pricing forecast and discount
rate adjustments based on the nature of the product.
As at 31 December 2023, the Corpus Christi contract has a positive
value and therefore is not currently onerous (2022: not onerous).
This and other contractual arrangements could be impacted by
adverse market conditions arising from climate-related factors.
Given the uncertainty in climate events, Woodside continues to
review the forecast cash \ufb02ows of long-term contracts.
Deferred tax assets
The Group has determined that it is probable that sufficient
future taxable income will be available to utilise the deferred
tax assets relating to carry forward unused tax losses and
credits recognised as at 31 December 2023. 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.
The Australian Government has passed reforms to its Safeguard
Mechanism which applies to regulatory limits on greenhouse gas
emissions from Woodside\u2019s Australian facilities. Some elements
of the reform, such as the method for determining limits at
new facilities, continue to be developed. In December 2023, the
United States Environmental Protection Agency (EPA) issued a
\ufb01nal rule to establish performance standards for methane and
other emissions from existing and new oil and gas operations.
Woodside is not aware of any proposal that would materially
affect the information in these \ufb01nancial statements.
Key estimates and judgements In applying the Group\u2019s accounting policies, management regularly 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 116 Note A.5 Taxes Page 121 Note B.2 Exploration and evaluation Page 127 Note B.3 Oil and gas properties Page 128 Note B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill Page 130 Note B.5 Business combination Page 136 Note B.6 Goodwill Page 137 Note B.7 Signi\ufb01cant production and growth asset acquisitions Page 137 Note B.8 Disposal of assets Page 138 Note D.5 Provisions Page 146 Note D.6 Other \ufb01nancial assets and liabilities Page 148 Note D.7 Leases Page 151 Note E.6 Joint arrangements Page 158
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
(a) Revenue from contracts with customers
The transaction price at the date control passes for sales made
subject to provisional pricing periods in oil and condensate
contracts is determined with reference to quoted commodity prices.
Judgement is also used to determine if it is highly probable that a
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 per share is calculated by dividing the pro\ufb01t 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 per share is calculated by adjusting basic earnings 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 2023, 14,444,802 awards (2022:
13,061,376 awards and 2021: 9,023,439 awards) granted under
Woodside employee share plans are considered dilutive.
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
The Group has two separate USA Tax Consolidation Groups (USA
TCG) as at 31 December 2023.
Income tax losses and credits: Deferred tax assets (DTAs) relating to
carry forward unused tax losses and credits arising from the USA TCG
of $1,248 million (2022: $1,371 million) and $333 million (2022: $93
million) arising from countries other than Australia and the USA have
been recognised. The Group has determined that it is probable that
sufficient future taxable income will be available to utilise those losses
and credits within those countries. Refer to Note E.9(a) for details of
tax consolidated groups.
DTAs relating to carry forward unused tax losses and credits of
$232 million (2022: $250 million) from the USA TCG, $189 million
(2022: $146 million) from USA entities outside of the USA TCG
and $763 million (2022: $1,061 million) from countries other
than Australia and the USA have not been recognised as it is not
currently probable that the losses and credits will be utilised based
on current planned activities in those countries.
As a result of the FID to develop the Trion resource in 2023, the
Group has recognised deferred tax assets of $319 million.
PRRT: The recoverability of PRRT deferred tax assets is primarily
assessed with regard to future oil price assumptions impacting
forecast future taxable pro\ufb01ts. During the year ended 31 December
2023, the Group reduced the Pluto PRRT DTA by $637 million
($446 million post-tax) on the basis of future taxable pro\ufb01ts
not being available to utilise the deductible expenditure. This is
primarily driven by decreases in forecast pricing assumptions and
actual pricing realised during the year ended 31 December 2023.
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 2022: 3.2%) was used for the
purposes of augmentation.
Certain deferred tax assets on deductible temporary differences
have not been recognised on the basis that deductions from future
augmentation of the recognised deductible temporary difference
will be sufficient to offset future taxable pro\ufb01ts. $7,428 million
(2022: $6,523 million) relates to the North West Shelf Project,
$872 million (2022: $189 million) relates to remaining Pluto
quarantined exploration expenditure and $758 million (2022:
$831 million) relates to Wheatstone. A long-term bond rate of
3.2% (31 December 2022: 3.2%) was used for the purposes of
augmentation.
Had an alternative approach been used to assess recovery of
the deferred tax assets, whereby future augmentation was not
included in the assessment, additional deferred tax assets would
be recognised, with a corresponding 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 .
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 is
addressed within this Taxes note and Part B disclosed
within the Sustainability section 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.
(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. Tax
matters without a probable economic out\ufb02ow and/or presently
cannot be measured reliably are contingent liabilities and disclosed
in Note E.1 Contingent liabilities and assets .
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.
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 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.
(c) Change in depreciation methodology and asset
useful lives
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.
In assessing useful lives of certain oil and gas assets, these have
been determined with 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
have been depreciated over proved reserves (previously
proved plus probable, except for certain assets considered late
life). Upstream LNG assets have continued to be depreciated
over proved plus probable reserves. Multi-product assets are
assessed on a case-by-case basis and aligned to the most
appropriate representation of useful life.
The changes in depreciation methodology and asset useful lives
have been applied from 1 January 2023, resulting in an increase
in depreciation expense of $416 million for the year ended
31 December 2023.
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.
Upstream oil and conventional gas assets have been depreciated
using the unit of production basis over proved reserves (2022:
proved plus probable, except for certain assets considered
late life). Upstream LNG assets are depreciated over proved
plus probable reserves. Multi-product assets are assessed on
a case-by-case basis and aligned to the most appropriate
representation of useful life.
The depreciable amount for the unit of production basis excludes
future development costs necessary to bring probable reserves
into production. Downstream assets (primarily onshore plant and
equipment) are depreciated using a straight-line basis over the
lesser of useful life and the life of proved plus probable reserves.
On a straight-line basis the assets have an estimated useful life
of 5-50 years.
All other items of 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
$4,245 million as at 31 December 2023 (revised 20221:
$6,469 million). Capital expenditure commitments relate
predominantly to the Scarborough and Sangomar projects.
1. The 2022 Financial Statements disclosed capital expenditure commitments of $7,762 million
which duplicated certain amounts post-merger. This has now been revised to re\ufb02ect the
Group's share of commitments.
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
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.
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 value in use (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, is applied on a post-tax basis using an appropriate
discount rate and estimates are made about the assumptions
market participants would use when pricing the asset or CGU.
If the carrying amount of an asset or CGU, including any
allocated goodwill, exceeds its recoverable amount, the asset
or CGU is written down to its recoverable amount and an
impairment loss is recognised in the consolidated income
statement. Any impairment losses are \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
(a) CGU determination
Identi\ufb01cation of a CGU requires management judgement.
Management has determined CGUs based on the smallest group of
assets that generate signi\ufb01cant cash in\ufb02ows that are independent
from other assets or groups of assets.
(b) 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.
(c) 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 2023 and 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 2023 and 31 December 2022 Annual Reports.
\u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% (2022: 2.0%) has been
applied for US based assets and 2.5% (2022: 2.5%) for Australian
based assets.
\u2022 Foreign exchange rates \u2013 a rate of $0.75 (2022: $0.75) US$:AU$
is based on management\u2019s view of long-term exchange rates.
\u2022 Discount rates \u2013 a range of post-tax discount rates between
8.5% and 10.5% (2022: 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 (2022:
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 and therefore dependent on oil price
assumptions. LNG sold into spot markets is typically based on a
gas-hub linked price (for example the Title Transfer Facility (TTF)
or JKM) and therefore these pricing assumptions are also of
relevance in forecasting future revenues.
\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
goals 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
for the year ended 31 December 2023 were:
2024
2025
2026
2027
2028
2029
31 December 20231
82
80
76
77
79
80
31 December 20222
78
74
76
77
79
80
1. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and
prices are escalated at 2.0% onwards.
2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and
prices are escalated at 2.0% onwards.
The nominal Brent oil prices (US$/bbl) used for the year ended
31 December 2022 were:
2023
2024
2025
2026
2027
2028
31 December 20223
87
78
74
76
77
79
31 December 20214
71
68
69
70
72
73
3. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and
prices are escalated at 2.0% onwards.
4. 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
(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.
Recognition and measurement
Goodwill is initially measured at cost and is subsequently
measured at cost less any accumulated impairment losses.
For the purposes of impairment testing, goodwill acquired in
a business combination is, from the acquisition date, allocated
to each of the Group\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.
Key estimates and judgements
(a) 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
(a) 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 an
asset acquisition.
Recognition and measurement
The Group classi\ufb01es assets and liabilities as held for sale if their
carrying amounts will be recovered principally through sale
rather than through continuing use. Such assets and liabilities
classi\ufb01ed as held for sale are measured at the lower of their
carrying amount and fair value less costs to dispose. Costs to
dispose are the incremental costs directly attributable to the
sale, excluding \ufb01nance costs and income tax expense.
The criteria for held for sale classi\ufb01cation are considered met
only when the sale is highly probable, and the asset is available
for sale in its present condition. Actions required to complete
the sale should indicate that it is unlikely that signi\ufb01cant
changes to the sale will be made or that the decision to sell will
be withdrawn. Management must be committed to the sale,
expected within one year from the date of the classi\ufb01cation.
Assets are not depreciated or amortised once classi\ufb01ed as
held for sale. Assets and liabilities classi\ufb01ed as held for sale
are presented separately as current items in the statement of
\ufb01nancial position.
Assets and liabilities reclassi\ufb01ed as held for sale
In addition to the assets and liabilities reclassi\ufb01ed as held for sale
for the Scarborough Joint Venture, the Group has reclassi\ufb01ed
$3 million for the North West Shelf vessels to assets held for
sale. There are no recognised liabilities associated with the North
West Shelf vessels.
Key estimates and judgements
(a) Goodwill allocation
In accordance with AASB 136/IAS 36 Impairment of assets, if
goodwill has been allocated to a CGU and the entity disposes
of an operation within that unit, the goodwill associated with
the operation disposed shall be included in the carrying value
of the operation when determining the gain or loss on disposal
and measured on the basis of the relative values of the operation
disposed of and the portion of the CGU retained.
The Pluto-Scarborough CGU includes goodwill allocated
from the merger with BHPP in 2022. Judgement is required
to determine the amount of goodwill allocated to the 10%
participating interest in the Scarborough assets being disposed.
The Group used fair value measurements of Pluto and
Scarborough assets within the CGU as basis to allocate goodwill
between the Pluto and Scarborough assets. The goodwill
associated with the participating interest of the Scarborough
assets being disposed of was determined based on the
percentage participating interest disposed of in proportion
to the participating interest being retained.
Key estimates and judgements
(a) 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 as 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
for the year ended 31 December 2022.
The variable consideration is remeasured at each reporting
period with any changes recognised through the consolidated
income statement. As at 31 December 2023, the variable
consideration has been reassessed with no revaluation gain
or loss being recognised (2022: $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. There are no cash and cash
equivalents (2022: $12 million) 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 loss of
$16 million being recorded (2022: gain of $7 million), and a loss
of $6 million being recorded on the hedging instrument (2022:
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 used in employee share-based payment arrangements or
the Dividend Reinvestment Plan (DRP). The DRP was suspended
on 27 February 2023. These shares are deducted from equity.
No gain or loss is recognised in the 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 7 to 30 days from the date of invoice or bill of lading
and customers regularly pay on time. There are no signi\ufb01cant
overdue product-related trade receivables as at the end of the
reporting period (2022: nil).
Fair value
The carrying amount of trade and other receivables
approximates their fair value.
Foreign exchange risk
The Group held $305 million of receivables at 31 December
2023 (2022: $174 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
$435 million at 31 December 2023 (2022: $408 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,
maintenance spares and carbon credits expected to be utilised
to offset future emissions. Inventories are valued at the lower of
cost and net realisable value. Cost is determined on a weighted
average basis and includes direct costs and an appropriate
portion of \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 $534 million of payables at 31 December 2023
(2022: $657 million) in currencies other than US dollars
(predominantly Australian dollars).
Maturity pro\ufb01le of payables
The Group\u2019s payables balances at 31 December 2023 and
31 December 2022 are due for payment within 12 months.
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. It is currently the Group\u2019s assumption
that in some regulatory jurisdictions and environments, certain
infrastructures are decommissioned in-situ where it can be
demonstrated that this will deliver equal or better environmental
outcomes than full removal and that regulatory approval is obtained
where arrangements are satisfactory to the regulator. The Group
maintains technical expertise to ensure that industry learnings,
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.
For the year ended 31 December 2022, the Group applied either
the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in
assessing the cost estimate. Both approaches are supported by
AASB137/IAS 37 Provisions, Contingent Liabilities and Contingent
Assets, produce reliable estimates and are widely used in practice.
The \u2018expected outcome\u2019 approach was used for heritage Woodside
assets (assets held by the Group prior to the BHPP merger)
and those assets commonly held by both heritage entities. The
\u2019expected value\u2019 approach was used for heritage BHPP assets
(assets acquired from BHP) but excludes assets held by both
heritage entities.
For the year ended 31 December 2023, the Group has aligned to
the \u2018expected value\u2019 approach and consistently applied it across
all assets. This has not resulted in a material change to the prior
estimate. The alignment re\ufb02ects a change to the estimate and not a
policy change, therefore no retrospective restatement is required.
Expected value approach
For both onshore and offshore assets, provision has been made
taking into consideration a risked range of possible removal
outcomes, including full removal of certain assets or project-speci\ufb01c
risks (where applicable). 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 risk free country-speci\ufb01c
discount rates aligned to the estimated timing of cash out\ufb02ows. This
approach takes into consideration the possibility that full removal of
all assets may be required.
Inherent uncertainties
The basis of the restoration obligation provision for assets with
approved decommissioning plans or general directions issued by
the regulator can differ from the assumptions disclosed above.
Whilst the provisions 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
ongoing to ensure that the most accurate information is available
when detailed decommissioning plans are required to be submitted
to the relevant regulatory authorities. Actual costs and cash
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 2023.
A range of pre-tax discount rates between 3.7% and 5.0% (2022:
3.4% to 4.7%) has been applied. If the discount rates were decreased
by 0.5% then the provision would be $365 million higher. If the cost
estimates were increased by 10% then the provision would be
$718 million higher. The proportion of the non-current balance
not expected to be settled within 10 years is 55% (2022: 54%).
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.
(b) 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 2023, the Corpus Christi contract has a positive
value and therefore is not currently onerous (2022: nil onerous
contract provision). 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 2023 are set out below:
\u2022 Discount rate \u2013 a pre-tax, risk free US government bond rate
of 4.04% (2022: 4.10%) 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
information1. 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 2023 were:
2024
2025
2026
2027
2028
TTF (US$/MMBtu)
13.9
14.2
8.8
8.9
9.1
Brent (US$/bbl)
82
80
76
77
79\u00b2
HH (US$/MMBtu)
3.4
3.5
3.5
3.5
3.63
1. For committed volumes, contracted pricing has been applied.
2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are
escalated at 2.0% onwards.
3. Long-term gas prices are based on US$3.2/MMBtu (2022 real terms) from 2026 and
US$3.8/MMBtu (2022 real terms) from 2030. 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.
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 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.
Embedded commodity derivatives are classi\ufb01ed as Level 3 on
the fair value hierarchy with no market observable inputs.
Key estimates and judgements
(a) Embedded commodity derivative
The fair value of the Perdaman embedded derivative has
been estimated using a Monte Carlo simulation model. The
assessment requires management to make certain assumptions
about the model inputs, including forecast cash \ufb02ows, discount
rate, credit risk and volatility. These assumptions require
signi\ufb01cant management judgement and are subject to risk and
uncertainty. The present value of the embedded derivative was
estimated using the assumptions set out below.
\u2022 In\ufb02ation rate \u2013 2.5% has been applied.
\u2022 Discount rate \u2013 a pre-tax interest rate curve (range: 5.39%
to 7.12%).
\u2022 Domestic gas pricing \u2013 forecast sales are subject to urea
pricing. Price assumptions are based on the best market
information available at measurement date and derived from
short- and long-term views of global supply and demand,
building upon past experience of the industry and consistent
with external sources. The long-term urea price is determined
with reference to the prevailing gas hub (Title Transfer Facility
(TTF)) prices available in the market at reporting date.
The embedded derivative is most sensitive to changes in
discount rates and pricing, which may result in unrealised gains
or losses recognised in other income/expenses in the future.
The nominal impact of the effects of changes to discount rate
and long-term price assumptions are estimated as follows:
Change in assumption1
US$m
Urea sales price: increase of 10%
145
Urea sales price: decrease of 10%
(145)
Discount rate: increase of 1.5%2
(208)
Discount rate: decrease of 1.5%2
258
1. Amounts shown represent the change of the present value of the contract keeping
all other variables constant.
2. A change of 1.5% represents 150 basis points.
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 $447 million of lease liabilities at 31 December
2023 (2022: $441 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 $2,000 million (2022: $2,323 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. The Group operates in complex tax and legislative
regimes. The amounts disclosed above include estimates made
in relation to ongoing disputes with various tax and government
authorities. Assessing a value of contingent liabilities requires
a high degree of judgement. The contingent liabilities relating
to tax matters are estimated based on notices received from
authorities before interest and penalties. The possibility of
further claims related to the same matters cannot be ruled
out and the judicial processes may take extended periods to
conclude. 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 $47 million as at
31 December 2023 (2022: $199 million).
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, PBP Plus and EIS Restricted
Shares and Performance Rights is accounted for as share-based
payments to employees for services provided. The cost of equity-
settled transactions with employees is measured by reference
to the fair values of the equity instruments at the date at which
they are granted. The fair value of share-based payments is
recognised, together with the corresponding increase in equity,
over the period in which the vesting conditions are 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 relative total shareholder return Performance
Rights is calculated using the Binomial or Black-Scholes option
pricing technique combined with a Monte Carlo simulation
methodology, where relevant, using historical volatility to
estimate the volatility of the share price in the future.
Key estimates and judgements
(a) Accounting for interests in other entities
Judgement is required in assessing the level of control
obtained in a transaction to acquire an interest in another
entity. Depending upon the facts and circumstances in each
case, Woodside may obtain control, joint control or 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 material accounting policies
Australia tax consolidation
The parent and its wholly owned Australian controlled entities
have elected to enter a tax consolidation, with Woodside Energy
Group Ltd as the head entity of the tax consolidated group.
The members of the Australian tax consolidated group are
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 standards and interpretations
New and amended accounting standards adopted
A number of amended standards became applicable for
the current reporting period. The Group did not make any
signi\ufb01cant changes to its accounting policies and did not make
retrospective adjustments as a result of adopting these amended
standards. These amendments did not materially impact the
accounting policies or amounts disclosed in the year end
\ufb01nancial statements of the Group.
New standards and interpretations not yet adopted
Certain new accounting standards, amendments to accounting
standards and interpretations have been published that are
not mandatory for the 31 December 2023 reporting period and
have not been early adopted by the Group. These standards,
amendments or interpretations are not expected to have a
material impact to the Group in the current or future reporting
periods and on foreseeable future transactions with the
exception of the amendments to AASB 112/IAS 12 Income Taxes
where the impact is under assessment.
Pillar Two reforms
In December 2021, the Organisation for Economic Co-operation
and Development (OECD) published its Pillar Two model rules.
The Pillar Two model rules:
\u2022 aim to ensure that large multinational groups pay a minimum
amount of tax on income arising in each jurisdiction in which
they operate; and
\u2022 would achieve a minimum effective tax rate in each jurisdiction
of 15% from the reporting period commencing
1 January 2024.
For the year ended 31 December 2023, the Group paid
$2,916 million of income tax and PRRT and reported a global
effective income tax rate of 27.5%.
The Group\u2019s impact assessment will depend on the extent to
which the Pillar Two legislation has been enacted in the various
jurisdictions the Group operates in and when it comes into effect.
The Group will continue to monitor and assess the expected
impact of the Pillar Two reform.
", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-730": { "value": "ABOUT THESE STATEMENTS 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 2024. ", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-2": { "value": "Woodside Energy Group Ltd", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-3": { "value": "for-pro\ufb01t entity limited by shares", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-4": { "value": "Australia", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-727": { "value": "Australia", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-731": { "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 International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board. They also include additional disclosures required for foreign registrants by the United States Securities and Exchange Commission (US SEC). The Group\u2019s accounting policies are consistent with those disclosed in the Group\u2019s 2022 Financial Statements. Adoption of new or amended standards and interpretations effective 1 January 2023 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 climate change. Updated assumptions used for depreciation methodology and asset useful lives, impairment assessments, business combinations and restoration obligations are disclosed in Notes B.3, B.4, B.5 and D.5 respectively; these assumptions could change in the future. New estimates and judgements relating to the sell-down of the Scarborough joint venture and an embedded commodity derivative are disclosed in Notes B.8 and D.6 respectively. ", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-732": { "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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-764": { "value": "The functional and presentation currency of Woodside and all its material subsidiaries is the US dollar. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-733": { "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, unless otherwise stated. ", "dimensions": { "concept": "woodsideenergygroupltd:DisclosureOfRoundingOfAmounts", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-734": { "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 2023 (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 material 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. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-735": { "value": "CLIMATE CHANGE AND ENERGY TRANSITION Climate considerations Woodside has considered the impact of climate and the energy transition in assessing the carrying values of its assets and liabilities. This note describes climate-related assumptions that underpin key areas of the \ufb01nancial statements and the potential short-term and long-term impacts differing scenarios could have on the \ufb01nancial results and \ufb01nancial position of Woodside. Financial planning and assumptions Woodside considers a range of climate and macroeconomic scenarios to help benchmark our long-term price assumptions and inform our decision-making to maintain a resilient \ufb01nancial position. These scenarios are informed by a wide range of externally published data, including Paris-aligned and non- Paris-aligned outcomes, and are part of a broad consideration of risks, opportunities, competitiveness and resilience. The assumptions applied in assessing amounts within the \ufb01nancial statements require signi\ufb01cant judgement and 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 goals as well as other goals such as energy security and economic development. Price assumptions consider current legislation in the locations where Woodside operates and place some weight on scenarios in which the transition to a lower carbon energy system is sufficiently rapid to meet 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 challenging environments. The high degree of uncertainty around the nature, timing and magnitude of climate-related risks, and the uncertainty as to how the energy transition will evolve, makes it difficult to determine the risks and their potential impacts with precision. Woodside continues to monitor the uncertainty around climate change risks and expects to take into account ongoing developments into its assumptions, including assumptions concerning commodity and carbon pricing, as considered appropriate. 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 the Group's accounting policies and applicable accounting standards, 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 to support the recoverable amount. The sale of the 10% non-operating participating interest in the Scarborough Joint Venture to LNG Japan announced in August 2023 is a clear example of an independent market valuation fully supporting the carrying value of the multi-decade asset. Price forecasts are adjusted for premiums and discounts based on the nature and quality of the product. Commodity oil price estimates 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. The IEA\u2019s World Energy Outlook 2023 (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. 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$/bbl)
2024-2027
2028-2032
2033-2036
2037-2040
NZE
52
41
34
31
APS
76
74
72
69
STEPS
84
85
84
84
Woodside
73
70
70
70
Average North Asian
LNG (RT US$/MMbtu)
2024-2027
2028-2032
2033-2036
2037-2040
NZE
8
5
5
5
APS
10
8
7
7
STEPS
11
9
9
8
Woodside
11
9
9
9
Average Carbon
(RT US$/tonne)
2024-2027
2028-2032
2033-2036
2037-2040
NZE
101
139
169
195
APS
100
133
153
169
STEPS
80
80
80
80
Woodside
80
80
80
80
1. IEA 2023. \u2018World Energy Outlook 2023\u2019. All rights reserved. 2. Based on data from IEA 2023. \u2018World Energy Outlook 2023\u2019 as modi\ufb01ed by Woodside analysis. Woodside used interpolation techniques to estimate Brent annual price points in between the years that the IEA disclose prices for. 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 that the IEA disclose prices for. For oil linked LNG contracts, prices are derived from the Brent forecasts and the terms of the contracts. 3. Based on data from IEA 2023. \u2018World Energy Outlook 2023\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 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. Refer to Note B.4 for the sensitivity analysis performed on Woodside\u2019s commodity 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 may be addressed to varying degrees 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. 55% (2022: 54%) 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. This includes the demand and related costs for offshore services which can be in\ufb02uenced by renewable energy construction. Woodside continues to monitor the uncertainty around climate change risks to assess if additional changes to restoration provisions should be recognised. Long-term contracts Climate risks may impact underlying assumptions used to assess the forecast cash \ufb02ows of long-term contracts. These judgemental assumptions include pricing forecast and discount rate adjustments based on the nature of the product. As at 31 December 2023, the Corpus Christi contract has a positive value and therefore is not currently onerous (2022: not onerous). This and other contractual arrangements could be impacted by adverse market conditions arising from climate-related factors. Given the uncertainty in climate events, Woodside continues to review the forecast cash \ufb02ows of long-term contracts. Deferred tax assets The Group has determined that it is probable that sufficient future taxable income will be available to utilise the deferred tax assets relating to carry forward unused tax losses and credits recognised as at 31 December 2023. 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. The Australian Government has passed reforms to its Safeguard Mechanism which applies to regulatory limits on greenhouse gas emissions from Woodside\u2019s Australian facilities. Some elements of the reform, such as the method for determining limits at new facilities, continue to be developed. In December 2023, the United States Environmental Protection Agency (EPA) issued a \ufb01nal rule to establish performance standards for methane and other emissions from existing and new oil and gas operations. Woodside is not aware of any proposal that would materially affect the information in these \ufb01nancial statements. ", "dimensions": { "concept": "woodsideenergygroupltd:DisclosureOfClimateChangeAndEnergyTransition", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-736": { "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 3.9 - 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 115
Section A Foreign exchange risk management Page 115
Section C Capital risk management Page 140
Section C Liquidity risk management Page 140
Section C Interest rate risk management Page 140
Section D Credit risk management Page 144
KEY FINANCIAL 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 corporate and trading portfolios.
As at the reporting date, the Group held commodity hedging \ufb01nancial instruments with a net asset carrying value of $123 million
(2022: $557 million net liability) exposed to commodity price risk. An increase in relevant commodity prices of 10% would decrease the
instruments\u2019 carrying value by $172 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).
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 (refer to Note D.6). Through the use of foreign exchange forward contracts, the Group also hedged its Australian dollar
to US dollar exchange rate exposure in relation to the Australian dollar denominated tax payments which have matured.
As at the reporting date, the Group held hedging foreign currency \ufb01nancial instruments with a net asset carrying value of $8 million
(2022: net liability carrying value of $17 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% (2022: +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 2023.
KEY FINANCIAL 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 2023, the Group had a total of $7,790 million (2022: $10,239 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 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 $1,605 million (2022: $6,143 million) on cash and cash equivalents, nil (2022: $83 million) on interest-bearing liabilities (excluding transaction costs), nil (2022: $167 million) of other \ufb01nancial assets and nil (2022: $5 million) on cross-currency interest rate swaps. A reasonably possible change in the Secured Overnight Financing Rate (SOFR) (+2.0%/-2.0% (2022: USD London Interbank Offered Rate (USD LIBOR) +1.5%/-1.5%)), with all variables held constant, would not have a material impact on the Group\u2019s equity or the income statement in the current period. During the period, the Group has completed the transition of its \ufb01nancial liabilities from USD LIBOR to SOFR. The transition during the year ended 31 December 2023 did not result in a material impact to the Group. 140
KEY FINANCIAL AND CAPITAL RISKS IN THIS SECTION
Credit risk management
Credit risk is the risk that a counterparty will not meet its payment 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 \ufb01nancial security 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 assessment 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 exposure 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. The credit quality of a customer is assessed based on various credit metrics, including its credit
rating, and individual credit limits and requirements are de\ufb01ned in accordance with this assessment. Outstanding customer receivables
are regularly monitored.
At 31 December 2023, the Group had nineteen customers (2022: nineteen customers) that owed the Group more than $10 million
each and accounted for approximately 82% (2022: 79%) of product-related trade receivables. Depending on the product, standard
settlement terms are 7 to 30 days from the date of invoice or bill of lading.
The Group considers the probability of default upon initial recognition of the asset and whether there has been a 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 2023, the Group had a provision for credit losses of nil (2022: nil). Subsequent to 31 December 2023, 97% (2022: 99%)
of product-related trade receivables balance of $885 million (2022: $1,067 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
places funds from time to time as short-term deposits with reputable \ufb01nancial institutions with investment grade credit ratings.
At 31 December 2023 and 31 December 2022, 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:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-729": { "value": "
Key estimates and judgements
In applying the Group\u2019s accounting policies, management
regularly 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 116
Note A.5 Taxes Page 121
Note B.2 Exploration and evaluation Page 127
Note B.3 Oil and gas properties Page 128
Note B.4 Impairment of exploration and evaluation,
oil and gas properties and goodwill
Page 130
Note B.5 Business combination Page 136
Note B.6 Goodwill Page 137
Note B.7 Signi\ufb01cant production and growth asset
acquisitions
Page 137
Note B.8 Disposal of assets Page 138
Note D.5 Provisions Page 146
Note D.6 Other \ufb01nancial assets and liabilities Page 148
Note D.7 Leases Page 151
Note E.6 Joint arrangements Page 158
Key estimates and judgements (a) Revenue from contracts with customers The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices. Judgement is also used to determine if it is highly probable that a 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 The Group has two separate USA Tax Consolidation Groups (USA TCG) as at 31 December 2023. Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from the USA TCG of $1,248 million (2022: $1,371 million) and $333 million (2022: $93 million) arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $232 million (2022: $250 million) from the USA TCG, $189 million (2022: $146 million) from USA entities outside of the USA TCG and $763 million (2022: $1,061 million) from countries other than Australia and the USA have not been recognised as it is not currently probable that the losses and credits will be utilised based on current planned activities in those countries. As a result of the FID to develop the Trion resource in 2023, the Group has recognised deferred tax assets of $319 million. PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. During the year ended 31 December 2023, the Group reduced the Pluto PRRT DTA by $637 million ($446 million post-tax) on the basis of future taxable pro\ufb01ts not being available to utilise the deductible expenditure. This is primarily driven by decreases in forecast pricing assumptions and actual pricing realised during the year ended 31 December 2023. 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 2022: 3.2%) was used for the purposes of augmentation. Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable pro\ufb01ts. $7,428 million (2022: $6,523 million) relates to the North West Shelf Project, $872 million (2022: $189 million) relates to remaining Pluto quarantined exploration expenditure and $758 million (2022: $831 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2022: 3.2%) was used for the purposes of augmentation. Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the assessment, additional deferred tax assets would be recognised, with a corresponding 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. Tax matters without a probable economic out\ufb02ow and/or presently cannot be measured reliably are contingent liabilities and disclosed in Note E.1 Contingent liabilities and assets . 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. 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 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. (c) Change in depreciation methodology and asset useful lives 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. In assessing useful lives of certain oil and gas assets, these have been determined with 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 have been depreciated over proved reserves (previously proved plus probable, except for certain assets considered late life). Upstream LNG assets have continued to be depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life. The changes in depreciation methodology and asset useful lives have been applied from 1 January 2023, resulting in an increase in depreciation expense of $416 million for the year ended 31 December 2023. Key estimates and judgements (a) CGU determination Identi\ufb01cation of a CGU requires management judgement. Management has determined CGUs based on the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or groups of assets. (b) 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. (c) 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 2023 and 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 2023 and 31 December 2022 Annual Reports. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% (2022: 2.0%) has been applied for US based assets and 2.5% (2022: 2.5%) for Australian based assets. \u2022 Foreign exchange rates \u2013 a rate of $0.75 (2022: $0.75) US$:AU$ is based on management\u2019s view of long-term exchange rates. \u2022 Discount rates \u2013 a range of post-tax discount rates between 8.5% and 10.5% (2022: 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 (2022: 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 and therefore dependent on oil price assumptions. LNG sold into spot markets is typically based on a gas-hub linked price (for example the Title Transfer Facility (TTF) or JKM) and therefore these pricing assumptions are also of relevance in forecasting future revenues. \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 goals 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 for the year ended 31 December 2023 were:
2024
2025
2026
2027
2028
2029
31 December 20231
82
80
76
77
79
80
31 December 20222
78
74
76
77
79
80
1. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. The nominal Brent oil prices (US$/bbl) used for the year ended 31 December 2022 were:
2023
2024
2025
2026
2027
2028
31 December 20223
87
78
74
76
77
79
31 December 20214
71
68
69
70
72
73
3. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 4. 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 (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. Key estimates and judgements (a) 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 (a) 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 an asset acquisition. Key estimates and judgements (a) Goodwill allocation In accordance with AASB 136/IAS 36 Impairment of assets, if goodwill has been allocated to a CGU and the entity disposes of an operation within that unit, the goodwill associated with the operation disposed shall be included in the carrying value of the operation when determining the gain or loss on disposal and measured on the basis of the relative values of the operation disposed of and the portion of the CGU retained. The Pluto-Scarborough CGU includes goodwill allocated from the merger with BHPP in 2022. Judgement is required to determine the amount of goodwill allocated to the 10% participating interest in the Scarborough assets being disposed. The Group used fair value measurements of Pluto and Scarborough assets within the CGU as basis to allocate goodwill between the Pluto and Scarborough assets. The goodwill associated with the participating interest of the Scarborough assets being disposed of was determined based on the percentage participating interest disposed of in proportion to the participating interest being retained. Key estimates and judgements (a) 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 as 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 for the year ended 31 December 2022. The variable consideration is remeasured at each reporting period with any changes recognised through the consolidated income statement. As at 31 December 2023, the variable consideration has been reassessed with no revaluation gain or loss being recognised (2022: $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. It is currently the Group\u2019s assumption that in some regulatory jurisdictions and environments, certain infrastructures are decommissioned in-situ where it can be demonstrated that this will deliver equal or better environmental outcomes than full removal and that regulatory approval is obtained where arrangements are satisfactory to the regulator. The Group maintains technical expertise to ensure that industry learnings, 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. For the year ended 31 December 2022, the Group applied either the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in assessing the cost estimate. Both approaches are supported by AASB137/IAS 37 Provisions, Contingent Liabilities and Contingent Assets, produce reliable estimates and are widely used in practice. The \u2018expected outcome\u2019 approach was used for heritage Woodside assets (assets held by the Group prior to the BHPP merger) and those assets commonly held by both heritage entities. The \u2019expected value\u2019 approach was used for heritage BHPP assets (assets acquired from BHP) but excludes assets held by both heritage entities. For the year ended 31 December 2023, the Group has aligned to the \u2018expected value\u2019 approach and consistently applied it across all assets. This has not resulted in a material change to the prior estimate. The alignment re\ufb02ects a change to the estimate and not a policy change, therefore no retrospective restatement is required. Expected value approach For both onshore and offshore assets, provision has been made taking into consideration a risked range of possible removal outcomes, including full removal of certain assets or project-speci\ufb01c risks (where applicable). 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 risk free country-speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows. This approach takes into consideration the possibility that full removal of all assets may be required. Inherent uncertainties The basis of the restoration obligation provision for assets with approved decommissioning plans or general directions issued by the regulator can differ from the assumptions disclosed above. Whilst the provisions 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 ongoing to ensure that the most accurate information is available when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash 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 2023. A range of pre-tax discount rates between 3.7% and 5.0% (2022: 3.4% to 4.7%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $365 million higher. If the cost estimates were increased by 10% then the provision would be $718 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 55% (2022: 54%). (b) Onerous contracts The onerous contract provision assessment requires management to make certain estimates regarding the unavoidable costs and the expected economic bene\ufb01ts from the contract. These estimates require signi\ufb01cant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions. As at 31 December 2023, the Corpus Christi contract has a positive value and therefore is not currently onerous (2022: nil onerous contract provision). Changes in assumptions predominantly relating to the narrowing of the spread between the sales price and purchase price could result in the contract becoming onerous in the future. Assumptions used to determine the present value as at 31 December 2023 are set out below: \u2022 Discount rate \u2013 a pre-tax, risk free US government bond rate of 4.04% (2022: 4.10%) has been applied. \u2022 LNG pricing \u2013 forecast sales and purchase prices are subject to a number of price markers. Price assumptions are based on the best information on the market available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The forecasted sales are linked to gas hub prices (Title Transfer Facility (TTF)) at which physical sales are expected to occur and incorporate known sales pricing information1. The long-term gas sales price is estimated on the basis of the Group\u2019s Brent price forecast. The estimated purchase price is linked to US gas hub prices (Henry Hub (HH)) at which physical purchases are expected to occur. The nominal TTF, Brent oil prices and HH gas prices used at 31 December 2023 were:
2024
2025
2026
2027
2028
TTF (US$/MMBtu)
13.9
14.2
8.8
8.9
9.1
Brent (US$/bbl)
82
80
76
77
79\u00b2
HH (US$/MMBtu)
3.4
3.5
3.5
3.5
3.63
1. For committed volumes, contracted pricing has been applied. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards. 3. Long-term gas prices are based on US$3.2/MMBtu (2022 real terms) from 2026 and US$3.8/MMBtu (2022 real terms) from 2030. All long-term prices are escalated at 2.0%. Key estimates and judgements (a) Embedded commodity derivative The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast cash \ufb02ows, discount rate, credit risk and volatility. These assumptions require signi\ufb01cant management judgement and are subject to risk and uncertainty. The present value of the embedded derivative was estimated using the assumptions set out below. \u2022 In\ufb02ation rate \u2013 2.5% has been applied. \u2022 Discount rate \u2013 a pre-tax interest rate curve (range: 5.39% to 7.12%). \u2022 Domestic gas pricing \u2013 forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (Title Transfer Facility (TTF)) prices available in the market at reporting date. The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses recognised in other income/expenses in the future. The nominal impact of the effects of changes to discount rate and long-term price assumptions are estimated as follows:
Change in assumption1
US$m
Urea sales price: increase of 10%
145
Urea sales price: decrease of 10%
(145)
Discount rate: increase of 1.5%2
(208)
Discount rate: decrease of 1.5%2
258
1. Amounts shown represent the change of the present value of the contract keeping all other variables constant. 2. A change of 1.5% represents 150 basis points. 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 $2,000 million (2022: $2,323 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 (a) Accounting for interests in other entities Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity. Depending upon the facts and circumstances in each case, Woodside may obtain control, joint control or 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. ", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-765": { "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 corporate and trading portfolios. As at the reporting date, the Group held commodity hedging \ufb01nancial instruments with a net asset carrying value of $123 million (2022: $557 million net liability) exposed to commodity price risk. An increase in relevant commodity prices of 10% would decrease the instruments\u2019 carrying value by $172 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). 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 (refer to Note D.6). Through the use of foreign exchange forward contracts, the Group also hedged its Australian dollar to US dollar exchange rate exposure in relation to the Australian dollar denominated tax payments which have matured. As at the reporting date, the Group held hedging foreign currency \ufb01nancial instruments with a net asset carrying value of $8 million (2022: net liability carrying value of $17 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% (2022: +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 2023.
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 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 $1,605 million (2022: $6,143 million) on cash and cash equivalents, nil (2022: $83 million) on interest-bearing
liabilities (excluding transaction costs), nil (2022: $167 million) of other \ufb01nancial assets and nil (2022: $5 million) on cross-currency
interest rate swaps.
A reasonably possible change in the Secured Overnight Financing Rate (SOFR) (+2.0%/-2.0% (2022: USD London Interbank Offered
Rate (USD LIBOR) +1.5%/-1.5%)), with all variables held constant, would not have a material impact on the Group\u2019s equity or the
income statement in the current period.
During the period, the Group has completed the transition of its \ufb01nancial liabilities from USD LIBOR to SOFR. The transition during the
year ended 31 December 2023 did not result in a material impact to the Group.
140 ANNUAL REPORT 2023
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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.
The disclosed operating segments in 2023 remain consistent
to 2022. In the prior reporting period, the 2021 amounts were
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 purchased volumes) and optimisation
activities attributed to Marketing which generate 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.
Customer concentration
The Group has two major customers which respectively account
for 8% and 7% of the Group\u2019s external revenue. The sales are
generated by the Australia and Marketing operating segments
(2022: two major customers; 12% and 9% generated by the
Australia and Marketing operating segments and 2021: two major
customers; 8% and 6% generated by the Australia operating
segment).
Geographical information
Geographical Revenue from external
information customers Non-current assets
2023
2022
2021
2023
2022
US$m
US$m
US$m
US$m
US$m
Asia Paci\ufb01c
9,823
12,521
6,342
36,060
36,966
Americas
2,564
1,545
-
7,171
7,057
Africa
-
-
-
5,295
4,049
Europe
1,607
2,751
620
-
-
Consolidated
13,994
16,817
6,962
48,526
48,072
1 2 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,717 million (2022: $1,959 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 (a) Revenue from contracts with customers The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices. Judgement is also used to determine if it is highly probable that a 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 .
Australia
International
Marketing
Corporate/ Consolidated
Other
2023
2023
2023
2023
2023
US$m
US$m
US$m
US$m
US$m
Lique\ufb01ed natural gas
6,867
-
1,298
-
8,165
Pipeline gas
1,088
286
-
-
1,374
Crude oil and condensate
1,611
2,246
124
-
3,981
Natural gas liquids
218
32
31
-
281
Revenue from sale of hydrocarbons
9,784
2,564
1,453
-
13,801
Intersegment revenue1
(166)
(15)
181
-
-
Processing and services revenue
184
-
-
-
184
Shipping and other revenue
-
-
9
-
9
Other revenue
18
(15)
190
-
193
Operating revenue
9,802
2,549
1,643
-
13,994
Production costs
(1,173)
(389)
-
-
(1,562)
Royalties, excise and levies
(462)
(41)
-
-
(503)
Insurance
(41)
(11)
-
(8)
(60)
Inventory movement
(40)
3
-
-
(37)
Costs of production
(1,716)
(438)
-
(8)
(2,162)
Land and buildings
(62)
(5)
-
-
(67)
Transferred exploration and evaluation
(101)
(24)
-
-
(125)
Plant and equipment
(2,591)
(1,139)
-
(34)
(3,764)
Oil and gas properties depreciation and amortisation
(2,754)
(1,168)
-
(34)
(3,956)
Shipping and direct sales costs
(164)
(83)
(54)
(18)
(319)
Trading costs
(12)
-
(1,056)
-
(1,068)
Other hydrocarbon costs
(7)
-
-
-
(7)
Other cost of sales
(7)
-
-
-
(7)
Movement in onerous contract provision
-
-
-
-
-
Other cost of sales
(190)
(83)
(1,110)
(18)
(1,401)
Cost of sales
(4,660)
(1,689)
(1,110)
(60)
(7,519)
Gross pro\ufb01t
5,142
860
533
(60)
6,475
Other income
160
54
26
82
322
Exploration and evaluation expenditure4
(24)
(253)
-
(2)
(279)
Amortisation of permit acquisition
-
(4)
-
-
(4)
Write-offs
(31)
(46)
-
-
(77)
Exploration and evaluation
(55)
(303)
-
(2)
(360)
General, administrative and other costs
-
-
-
(453)
(453)
Depreciation of other plant and equipment
-
-
-
-
-
Depreciation of lease assets
(50)
(14)
(75)
(40)
(179)
Restoration movement
(125)
(22)
-
-
(147)
Other5
(51)
-
(109)
(274)
(434)
Other costs
(226)
(36)
(184)
(767)
(1,213)
Other expenses
(281)
(339)
(184)
(769)
(1,573)
Impairment losses
(534)
(1,383)
-
-
(1,917)
Impairment reversals
-
-
-
-
-
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
4,487
(808)
375
(747)
3,307
2
3
6
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 $13,985 million and sub-lease income of $9 million disclosed within shipping and other revenue.
3. Includes fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business.
4. Includes seismic and general permit activities and other exploration costs.
5. Includes losses on hedging activities, fair value losses on embedded derivatives and other expenses not associated with the ongoing operations of the business.
6. Impairment on oil and gas properties. Refer to Note B.4 for more details.
Australia
International
Marketing
Corporate/ Consolidated
Other
2022
2022
2022
2022
2022
US$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
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
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
900
-
-
-
900
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
9,415
125
848
(1,202)
9,186
2
4
9
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 $960 million in the Marketing and Corporate/Other segments and other expenses not associated
with the ongoing operations of the business.
9. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details.
Australia
International
Marketing
Corporate/ Consolidated
Other
20218
20218
20218
20218
2021
US$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
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
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
1,058
-
-
-
1,058
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
3,711
(317)
354
(255)
3,493
2
4
7
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.
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.
6. Includes net loss on hedging activities of $91 million, various costs relating to Woodside\u2019s exit from the Kitimat LNG development of $33 million and other expenses not associated with the ongoing
operations of the business.
7. Impairment reversals on oil and gas properties.
8. In the prior reporting period, the 2021 amounts were restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue.
Refer to Note A.1 for descriptions of the Group\u2019s segments and geographical regions.
Australia
International
Marketing
Corporate/ Consolidated
Other
2023
2023
2023
2023
2023
US$m
US$m
US$m
US$m
US$m
Balance as at 31 December
Asia Paci\ufb01c
568
-
-
-
568
Americas
-
76
-
-
76
Africa
-
24
-
-
24
Total exploration and evaluation
568
100
-
-
668
Balance as at 31 December
Land and buildings
669
32
-
-
701
Transferred exploration and evaluation
360
417
-
-
777
Plant and equipment
16,498
6,893
-
198
23,589
Projects in development
7,825
7,655
-
244
15,724
Total oil and gas properties
25,352
14,997
-
442
40,791
Balance as at 31 December
Land and buildings
96
89
-
245
430
Plant and equipment1
194
60
539
7
800
Total lease assets
290
149
539
252
1,230
Additions to exploration and evaluation:
Exploration
29
59
-
-
88
Evaluation
55
108
-
-
163
Restoration2
(5)
-
-
-
(5)
79
167
-
-
246
Additions to oil and gas properties:
Oil and gas properties
3,127
2,000
-
190
5,317
Capitalised borrowing costs3
188
123
-
-
311
Restoration2
779
188
-
-
967
4,094
2,311
-
190
6,595
Additions to lease assets:
Land and buildings
-
-
-
8
8
Plant and equipment
6
-
114
-
120
6
-
114
8
128
1. In 2023, certain shipping activities, previously understaken by the Corporate/Other segment, are now undertaken by the Marketing segment. As a result of this change, $539 million of lease assets are now reported within the Marketing segment as at 31 December 2023. 2. Relates to changes in restoration provision assumptions. 3. Borrowing costs capitalised were at a weighted average interest rate of 4.0%. B.1 SEGMENT PRODUCTION AND GROWTH ASSETS
Australia
International
Marketing
Corporate/ Consolidated
Other
2022
2022
2022
2022
2022
US$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 borrowing 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%.
D.1 SEGMENT ASSETS AND LIABILITIES
2023
2022
US$m
US$m
(a) Segment assets
Australia
31,602
31,240
International
17,923
18,084
Marketing1
835
182
Corporate/Other1
5,001
9,815
55,361
59,321
2023
2022
US$m
US$m
(b) Segment liabilities
Australia2
7,833
7,552
International
2,624
2,677
Marketing1
751
561
Corporate/Other
8,983
11,404
20,191
22,194
1,2
1. In 2023, certain shipping activities are now undertaken by the Marketing segment. As a
result of this change, $539 million of lease assets and $677 million of lease liabilities are now
reported within the Marketing segment as at 31 December 2023. The impact of this change
on revenue and expenses is not material.
2. 2022 comparatives have been revised to re\ufb02ect the appropriate allocation of intercompany
liabilities between Australia and Corporate/Other segments post-merger. As a result of this
change, $552 million has been reclassi\ufb01ed to the Corporate/Other segment.
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.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-823": { "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. The disclosed operating segments in 2023 remain consistent to 2022. In the prior reporting period, the 2021 amounts were 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 purchased volumes) and optimisation activities attributed to Marketing which generate 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. 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 (a) Revenue from contracts with customers The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices. Judgement is also used to determine if it is highly probable that a 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-820": { "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. The disclosed operating segments in 2023 remain consistent to 2022. In the prior reporting period, the 2021 amounts were 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 purchased volumes) and optimisation activities attributed to Marketing which generate 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. 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 (a) Revenue from contracts with customers The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices. Judgement is also used to determine if it is highly probable that a 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-809": { "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. The disclosed operating segments in 2023 remain consistent to 2022. In the prior reporting period, the 2021 amounts were 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 purchased volumes) and optimisation activities attributed to Marketing which generate 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. 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 (a) Revenue from contracts with customers The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices. Judgement is also used to determine if it is highly probable that a 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-795": { "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. The disclosed operating segments in 2023 remain consistent to 2022. In the prior reporting period, the 2021 amounts were 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 purchased volumes) and optimisation activities attributed to Marketing which generate 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. Customer concentration The Group has two major customers which respectively account for 8% and 7% of the Group\u2019s external revenue. The sales are generated by the Australia and Marketing operating segments (2022: two major customers; 12% and 9% generated by the Australia and Marketing operating segments and 2021: two major customers; 8% and 6% generated by the Australia operating segment). Geographical information
Geographical Revenue from external
information customers Non-current assets
2023
2022
2021
2023
2022
US$m
US$m
US$m
US$m
US$m
Asia Paci\ufb01c
9,823
12,521
6,342
36,060
36,966
Americas
2,564
1,545
-
7,171
7,057
Africa
-
-
-
5,295
4,049
Europe
1,607
2,751
620
-
-
Consolidated
13,994
16,817
6,962
48,526
48,072
1 2 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,717 million (2022: $1,959 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 (a) Revenue from contracts with customers The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices. Judgement is also used to determine if it is highly probable that a 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 .
Australia
International
Marketing
Corporate/ Consolidated
Other
2023
2023
2023
2023
2023
US$m
US$m
US$m
US$m
US$m
Lique\ufb01ed natural gas
6,867
-
1,298
-
8,165
Pipeline gas
1,088
286
-
-
1,374
Crude oil and condensate
1,611
2,246
124
-
3,981
Natural gas liquids
218
32
31
-
281
Revenue from sale of hydrocarbons
9,784
2,564
1,453
-
13,801
Intersegment revenue1
(166)
(15)
181
-
-
Processing and services revenue
184
-
-
-
184
Shipping and other revenue
-
-
9
-
9
Other revenue
18
(15)
190
-
193
Operating revenue
9,802
2,549
1,643
-
13,994
Production costs
(1,173)
(389)
-
-
(1,562)
Royalties, excise and levies
(462)
(41)
-
-
(503)
Insurance
(41)
(11)
-
(8)
(60)
Inventory movement
(40)
3
-
-
(37)
Costs of production
(1,716)
(438)
-
(8)
(2,162)
Land and buildings
(62)
(5)
-
-
(67)
Transferred exploration and evaluation
(101)
(24)
-
-
(125)
Plant and equipment
(2,591)
(1,139)
-
(34)
(3,764)
Oil and gas properties depreciation and amortisation
(2,754)
(1,168)
-
(34)
(3,956)
Shipping and direct sales costs
(164)
(83)
(54)
(18)
(319)
Trading costs
(12)
-
(1,056)
-
(1,068)
Other hydrocarbon costs
(7)
-
-
-
(7)
Other cost of sales
(7)
-
-
-
(7)
Movement in onerous contract provision
-
-
-
-
-
Other cost of sales
(190)
(83)
(1,110)
(18)
(1,401)
Cost of sales
(4,660)
(1,689)
(1,110)
(60)
(7,519)
Gross pro\ufb01t
5,142
860
533
(60)
6,475
Other income
160
54
26
82
322
Exploration and evaluation expenditure4
(24)
(253)
-
(2)
(279)
Amortisation of permit acquisition
-
(4)
-
-
(4)
Write-offs
(31)
(46)
-
-
(77)
Exploration and evaluation
(55)
(303)
-
(2)
(360)
General, administrative and other costs
-
-
-
(453)
(453)
Depreciation of other plant and equipment
-
-
-
-
-
Depreciation of lease assets
(50)
(14)
(75)
(40)
(179)
Restoration movement
(125)
(22)
-
-
(147)
Other5
(51)
-
(109)
(274)
(434)
Other costs
(226)
(36)
(184)
(767)
(1,213)
Other expenses
(281)
(339)
(184)
(769)
(1,573)
Impairment losses
(534)
(1,383)
-
-
(1,917)
Impairment reversals
-
-
-
-
-
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
4,487
(808)
375
(747)
3,307
2 3 6 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 $13,985 million and sub-lease income of $9 million disclosed within shipping and other revenue. 3. Includes fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business. 4. Includes seismic and general permit activities and other exploration costs. 5. Includes losses on hedging activities, fair value losses on embedded derivatives and other expenses not associated with the ongoing operations of the business. 6. Impairment on oil and gas properties. Refer to Note B.4 for more details.
Australia
International
Marketing
Corporate/ Consolidated
Other
2022
2022
2022
2022
2022
US$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
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
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
900
-
-
-
900
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
9,415
125
848
(1,202)
9,186
2 4 9 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 $960 million in the Marketing and Corporate/Other segments and other expenses not associated with the ongoing operations of the business. 9. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details.
Australia
International
Marketing
Corporate/ Consolidated
Other
20218
20218
20218
20218
2021
US$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
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
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
1,058
-
-
-
1,058
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
3,711
(317)
354
(255)
3,493
2 4 7 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. 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. 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. 8. In the prior reporting period, the 2021 amounts were restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue. ", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-766": { "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. The disclosed operating segments in 2023 remain consistent to 2022. In the prior reporting period, the 2021 amounts were 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 purchased volumes) and optimisation activities attributed to Marketing which generate 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. Customer concentration The Group has two major customers which respectively account for 8% and 7% of the Group\u2019s external revenue. The sales are generated by the Australia and Marketing operating segments (2022: two major customers; 12% and 9% generated by the Australia and Marketing operating segments and 2021: two major customers; 8% and 6% generated by the Australia operating segment). Geographical information
Geographical Revenue from external
information customers Non-current assets
2023
2022
2021
2023
2022
US$m
US$m
US$m
US$m
US$m
Asia Paci\ufb01c
9,823
12,521
6,342
36,060
36,966
Americas
2,564
1,545
-
7,171
7,057
Africa
-
-
-
5,295
4,049
Europe
1,607
2,751
620
-
-
Consolidated
13,994
16,817
6,962
48,526
48,072
1 2 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,717 million (2022: $1,959 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 (a) Revenue from contracts with customers The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices. Judgement is also used to determine if it is highly probable that a 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 .
Australia
International
Marketing
Corporate/ Consolidated
Other
2023
2023
2023
2023
2023
US$m
US$m
US$m
US$m
US$m
Lique\ufb01ed natural gas
6,867
-
1,298
-
8,165
Pipeline gas
1,088
286
-
-
1,374
Crude oil and condensate
1,611
2,246
124
-
3,981
Natural gas liquids
218
32
31
-
281
Revenue from sale of hydrocarbons
9,784
2,564
1,453
-
13,801
Intersegment revenue1
(166)
(15)
181
-
-
Processing and services revenue
184
-
-
-
184
Shipping and other revenue
-
-
9
-
9
Other revenue
18
(15)
190
-
193
Operating revenue
9,802
2,549
1,643
-
13,994
Production costs
(1,173)
(389)
-
-
(1,562)
Royalties, excise and levies
(462)
(41)
-
-
(503)
Insurance
(41)
(11)
-
(8)
(60)
Inventory movement
(40)
3
-
-
(37)
Costs of production
(1,716)
(438)
-
(8)
(2,162)
Land and buildings
(62)
(5)
-
-
(67)
Transferred exploration and evaluation
(101)
(24)
-
-
(125)
Plant and equipment
(2,591)
(1,139)
-
(34)
(3,764)
Oil and gas properties depreciation and amortisation
(2,754)
(1,168)
-
(34)
(3,956)
Shipping and direct sales costs
(164)
(83)
(54)
(18)
(319)
Trading costs
(12)
-
(1,056)
-
(1,068)
Other hydrocarbon costs
(7)
-
-
-
(7)
Other cost of sales
(7)
-
-
-
(7)
Movement in onerous contract provision
-
-
-
-
-
Other cost of sales
(190)
(83)
(1,110)
(18)
(1,401)
Cost of sales
(4,660)
(1,689)
(1,110)
(60)
(7,519)
Gross pro\ufb01t
5,142
860
533
(60)
6,475
Other income
160
54
26
82
322
Exploration and evaluation expenditure4
(24)
(253)
-
(2)
(279)
Amortisation of permit acquisition
-
(4)
-
-
(4)
Write-offs
(31)
(46)
-
-
(77)
Exploration and evaluation
(55)
(303)
-
(2)
(360)
General, administrative and other costs
-
-
-
(453)
(453)
Depreciation of other plant and equipment
-
-
-
-
-
Depreciation of lease assets
(50)
(14)
(75)
(40)
(179)
Restoration movement
(125)
(22)
-
-
(147)
Other5
(51)
-
(109)
(274)
(434)
Other costs
(226)
(36)
(184)
(767)
(1,213)
Other expenses
(281)
(339)
(184)
(769)
(1,573)
Impairment losses
(534)
(1,383)
-
-
(1,917)
Impairment reversals
-
-
-
-
-
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
4,487
(808)
375
(747)
3,307
2 3 6 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 $13,985 million and sub-lease income of $9 million disclosed within shipping and other revenue. 3. Includes fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business. 4. Includes seismic and general permit activities and other exploration costs. 5. Includes losses on hedging activities, fair value losses on embedded derivatives and other expenses not associated with the ongoing operations of the business. 6. Impairment on oil and gas properties. Refer to Note B.4 for more details.
Australia
International
Marketing
Corporate/ Consolidated
Other
2022
2022
2022
2022
2022
US$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
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
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
900
-
-
-
900
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
9,415
125
848
(1,202)
9,186
2 4 9 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 $960 million in the Marketing and Corporate/Other segments and other expenses not associated with the ongoing operations of the business. 9. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details.
Australia
International
Marketing
Corporate/ Consolidated
Other
20218
20218
20218
20218
2021
US$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
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
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
1,058
-
-
-
1,058
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
3,711
(317)
354
(255)
3,493
2 4 7 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. 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. 6. Includes net loss on hedging activities of $91 million, various costs relating to Woodside\u2019s exit from the Kitimat LNG development of $33 million and other expenses not associated with the ongoing operations of the business. 7. Impairment reversals on oil and gas properties. 8. In the prior reporting period, the 2021 amounts were restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue. ", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-811": { "value": "Customer concentration The Group has two major customers which respectively account for 8% and 7% of the Group\u2019s external revenue. The sales are generated by the Australia and Marketing operating segments (2022: two major customers; 12% and 9% generated by the Australia and Marketing operating segments and 2021: two major customers; 8% and 6% generated by the Australia operating segment). ", "dimensions": { "concept": "ifrs-full:DisclosureOfSegmentsMajorCustomersExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-810": { "value": "Geographical information
Geographical Revenue from external
information customers Non-current assets
2023
2022
2021
2023
2022
US$m
US$m
US$m
US$m
US$m
Asia Paci\ufb01c
9,823
12,521
6,342
36,060
36,966
Americas
2,564
1,545
-
7,171
7,057
Africa
-
-
-
5,295
4,049
Europe
1,607
2,751
620
-
-
Consolidated
13,994
16,817
6,962
48,526
48,072
1 2 1. Revenue is attributable to geographic location based on the location of the customers. 2. Non-current assets exclude deferred tax of $1,717 million (2022: $1,959 million) ", "dimensions": { "concept": "ifrs-full:DisclosureOfGeographicalAreasExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-821": { "value": "
Australia
International
Marketing
Corporate/ Consolidated
Other
2023
2023
2023
2023
2023
US$m
US$m
US$m
US$m
US$m
Lique\ufb01ed natural gas
6,867
-
1,298
-
8,165
Pipeline gas
1,088
286
-
-
1,374
Crude oil and condensate
1,611
2,246
124
-
3,981
Natural gas liquids
218
32
31
-
281
Revenue from sale of hydrocarbons
9,784
2,564
1,453
-
13,801
Intersegment revenue1
(166)
(15)
181
-
-
Processing and services revenue
184
-
-
-
184
Shipping and other revenue
-
-
9
-
9
Other revenue
18
(15)
190
-
193
Operating revenue
9,802
2,549
1,643
-
13,994
Production costs
(1,173)
(389)
-
-
(1,562)
Royalties, excise and levies
(462)
(41)
-
-
(503)
Insurance
(41)
(11)
-
(8)
(60)
Inventory movement
(40)
3
-
-
(37)
Costs of production
(1,716)
(438)
-
(8)
(2,162)
Land and buildings
(62)
(5)
-
-
(67)
Transferred exploration and evaluation
(101)
(24)
-
-
(125)
Plant and equipment
(2,591)
(1,139)
-
(34)
(3,764)
Oil and gas properties depreciation and amortisation
(2,754)
(1,168)
-
(34)
(3,956)
Shipping and direct sales costs
(164)
(83)
(54)
(18)
(319)
Trading costs
(12)
-
(1,056)
-
(1,068)
Other hydrocarbon costs
(7)
-
-
-
(7)
Other cost of sales
(7)
-
-
-
(7)
Movement in onerous contract provision
-
-
-
-
-
Other cost of sales
(190)
(83)
(1,110)
(18)
(1,401)
Cost of sales
(4,660)
(1,689)
(1,110)
(60)
(7,519)
Gross pro\ufb01t
5,142
860
533
(60)
6,475
Other income
160
54
26
82
322
Exploration and evaluation expenditure4
(24)
(253)
-
(2)
(279)
Amortisation of permit acquisition
-
(4)
-
-
(4)
Write-offs
(31)
(46)
-
-
(77)
Exploration and evaluation
(55)
(303)
-
(2)
(360)
General, administrative and other costs
-
-
-
(453)
(453)
Depreciation of other plant and equipment
-
-
-
-
-
Depreciation of lease assets
(50)
(14)
(75)
(40)
(179)
Restoration movement
(125)
(22)
-
-
(147)
Other5
(51)
-
(109)
(274)
(434)
Other costs
(226)
(36)
(184)
(767)
(1,213)
Other expenses
(281)
(339)
(184)
(769)
(1,573)
Impairment losses
(534)
(1,383)
-
-
(1,917)
Impairment reversals
-
-
-
-
-
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
4,487
(808)
375
(747)
3,307
2 3 6 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 $13,985 million and sub-lease income of $9 million disclosed within shipping and other revenue. 3. Includes fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business. 4. Includes seismic and general permit activities and other exploration costs. 5. Includes losses on hedging activities, fair value losses on embedded derivatives and other expenses not associated with the ongoing operations of the business. 6. Impairment on oil and gas properties. Refer to Note B.4 for more details.
Australia
International
Marketing
Corporate/ Consolidated
Other
2022
2022
2022
2022
2022
US$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
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
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
900
-
-
-
900
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
9,415
125
848
(1,202)
9,186
2 4 9 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 $960 million in the Marketing and Corporate/Other segments and other expenses not associated with the ongoing operations of the business. 9. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details.
Australia
International
Marketing
Corporate/ Consolidated
Other
20218
20218
20218
20218
2021
US$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
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
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
1,058
-
-
-
1,058
Pro\ufb01t/(loss) before tax and net \ufb01nance costs
3,711
(317)
354
(255)
3,493
2 4 7 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. 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. 6. Includes net loss on hedging activities of $91 million, various costs relating to Woodside\u2019s exit from the Kitimat LNG development of $33 million and other expenses not associated with the ongoing operations of the business. 7. Impairment reversals on oil and gas properties. 8. In the prior reporting period, the 2021 amounts were restated to re\ufb02ect the changes in operating segments and portfolio reporting for LNG revenue. ", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-767": { "value": "
A.2 FINANCE COSTS
2023
2022
2021
US$m
US$m
US$m
Interest on interest-bearing liabilities
229
212
201
Interest on lease liabilities
102
103
97
Accretion charge
238
110
29
Other \ufb01nance costs
49
36
26
Less: Finance costs capitalised
against qualifying assets
(311)
(294)
(123)
307
167
230
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-812": { "value": "A.2 FINANCE COSTS
2023
2022
2021
US$m
US$m
US$m
Interest on interest-bearing liabilities
229
212
201
Interest on lease liabilities
102
103
97
Accretion charge
238
110
29
Other \ufb01nance costs
49
36
26
Less: Finance costs capitalised
against qualifying assets
(311)
(294)
(123)
307
167
230
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-738": { "value": "
A.3 DIVIDENDS PAID AND PROPOSED
Woodside Energy Group Ltd, the parent entity, paid and
proposed dividends set out below:
2023
2022
2021
US$m
US$m
US$m
(a) Dividends paid during the \ufb01nancial
year
Prior year fully franked \ufb01nal
dividend1
2,734
1,018
115
Current year fully franked interim
dividend2
1,519
2,070
289
4,253
3,088
404
(b) Dividend declared subsequent
to the reporting period (not recorded
as a liability)
Final dividend3
1,139
2,734
1,018
(c) Other information
Franking credits available for
subsequent periods
1,813
1,406
1,744
Current year dividends per share
(US cents)
140
253
135
1. 2023: US$1.44, paid on 5 April 2023
2022: US$1.05, paid on 23 March 2022
2021: US$0.12, paid on 24 March 2021
2. 2023: US$0.80, paid on 28 September 2023
2022: US$1.09, paid on 6 October 2022
2021: US$0.30, paid on 24 September 2021
3. 2023: US$0.60, to be paid on 4 April 2024
2022: US$1.44, paid on 5 April 2023
2021: US$1.05, paid on 23 March 2022
The Dividend Reinvestment Plan (DRP) was approved by
the shareholders at the Annual General Meeting in 2003 for
activation as required to fund future growth. The DRP was
reactivated in 2019 and suspended by the Board of Directors
on 27 February 2023.
", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-739": { "value": "A.4 EARNINGS PER SHARE
2023
2022
2021
Pro\ufb01t attributable to equity
holders of the parent (US$m)
1,660
6,498
1,983
Weighted average number
of shares on issue for basic
earnings per share
1,896,498,169
1,511,257,404
962,604,811
Effect of dilution from
contingently issuable shares
14,444,802
13,061,376
9,023,439
Weighted average number of
shares on issue adjusted for
the effect of dilution
1,910,942,971
1,524,318,780
971,628,250
Basic earnings per share
(US cents)
87.5
430.0
206.0
Diluted earnings per share
(US cents)
86.9
426.3
204.1
Earnings per share is calculated by dividing the pro\ufb01t 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 per share is calculated by adjusting basic earnings 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 2023, 14,444,802 awards (2022: 13,061,376 awards and 2021: 9,023,439 awards) granted under Woodside employee share plans are considered dilutive. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-768": { "value": "Earnings per share is calculated by dividing the pro\ufb01t 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 per share is calculated by adjusting basic earnings 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 2023, 14,444,802 awards (2022: 13,061,376 awards and 2021: 9,023,439 awards) granted under Woodside employee share plans are considered dilutive. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-740": { "value": "
2023
2022
2021
US$m
US$m
US$m
(a) Tax expense comprises
Petroleum resource rent tax (PRRT)
Current tax expense
367
501
-
Deferred tax expense/(bene\ufb01t)
531
(814)
297
PRRT expense/(bene\ufb01t)
898
(313)
297
Income tax
Current year
Current tax expense
1,872
2,256
658
Deferred tax (bene\ufb01t)/expense
(1,255)
701
301
Adjustment to prior years
Current tax bene\ufb01t
14
(276)
(20)
Deferred tax expense
22
231
18
Income tax expense
653
2,912
957
Tax expense
1,551
2,599
1,254
(b) Reconciliation of income tax expense
Pro\ufb01t before tax
3,273
9,174
3,290
PRRT (expense)/bene\ufb01t
(898)
313
(297)
Pro\ufb01t before income tax
2,375
9,487
2,993
Income tax expense calculated at 30%
712
2,847
898
Effect of tax rate differentials
91
(141)
(42)
Effect of deferred tax assets not recognised
155
150
114
Effect of tax losses and credits previously
unrecognised1
(332)
-
-
Effect of goodwill impairment2
109
-
-
Reduction in deferred tax liability due to
held for sale basis3
(78)
-
-
Foreign exchange impact on tax bene\ufb01t
(58)
(44)
(18)
Adjustment to prior years
36
(45)
(2)
Integration and transaction costs non-
deductible
4
142
-
Other
14
3
7
Income tax expense
653
2,912
957
(c) Reconciliation of PRRT expense
Pro\ufb01t before tax
3,273
9,174
3,290
Non-PRRT assessable pro\ufb01t
(1,780)
(6,197)
(2,134)
PRRT projects pro\ufb01t before tax
1,493
2,977
1,156
PRRT expense calculated at 40%
598
1,191
462
Derecognition/(recognition) of Pluto general
expenditure4
611
(1,362)
-
Recognition of transferred exploration spend
(18)
-
-
Augmentation
(292)
(175)
(166)
Other
(1)
33
1
PRRT expense/(bene\ufb01t)
898
(313)
297
(d) Deferred tax income statement
reconciliation
PRRT
Production and growth assets
1,206
(710)
455
Augmentation for current year
(292)
(175)
(166)
Provisions
(372)
(12)
(29)
Other
(11)
83
37
PRRT expense/(bene\ufb01t)
531
(814)
297
Income tax
Oil and gas properties
(529)
292
674
Exploration and evaluation assets
38
14
(204)
Lease assets and liabilities
(20)
25
1
Provisions
(232)
151
(10)
PRRT assets and liabilities
(175)
236
(88)
Unused tax losses and tax credits
(221)
19
149
Assets held for sale
(86)
205
(205)
Derivatives
(21)
21
(11)
Other
13
(31)
13
Income tax deferred tax (bene\ufb01t)/expense
(1,233)
932
319
Deferred tax (bene\ufb01t)/expense
(702)
118
616
A.5 TAXES
2023
2022
2021
(e) Deferred tax other comprehensive
US$m
US$m
US$m
income reconciliation
Income tax
Derivatives
77
(64)
5
Other
Deferred income tax expense/(bene\ufb01t) via
7
(2)
5
other comprehensive income
84
(66)
10
(f) Effective income tax rate: Australian and
global operations
Effective income tax rate
Australia
30.2%
30.0%
30.6%
Global
27.5%
30.7%
32.0%
1,5
1. As a result of the FID to develop the Trion resource in 2023, the Group has recognised
deferred tax assets of $319 million.
2. Tax effect of the non-deductible impairment of goodwill relating to Shenzi.
3. Recognition of the tax base associated with the expected sale of Woodside's 10% share in the
Scarborough Project. This will offset future assessable income on the completion of the sale.
4. In 2023, the $637 million decrease of the Pluto PRRT deferred tax asset is due to the
derecognition of previously recognised deductible expenditure that is now not considered
to be recoverable on the basis of future taxable pro\ufb01ts not being available to utilise the
expenditure. In 2022, the $1,362 million increase of the Pluto PRRT deferred tax asset was due
to the recognition of previously unrecognised deductible expenditure that is now expected to
be utilised to offset future taxable pro\ufb01ts.
5. The global operations effective income tax rate (ETR) is calculated as the Group\u2019s income
tax expense divided by pro\ufb01t before income tax. The Australian operations ETR is calculated
with reference to all Australian companies and excludes foreign exchange on settlement
and revaluation of income tax liabilities. The global effective income tax rate is lower in 2023
primarily as a result of the deferred tax asset recognised upon taking FID on Trion.
2023
2022
US$m
US$m
(g) Deferred tax balance sheet reconciliation
Deferred tax assets
PRRT
Production and growth assets
455
1,460
Augmentation for current year
231
113
Provisions
445
271
Other
(30)
(23)
PRRT deferred tax assets
1,101
1,821
Income tax
Oil and gas properties
(1,388)
(1,496)
Exploration and evaluation assets
60
30
Lease assets and liabilities
40
23
Unused tax losses and tax credits
1,686
1,464
Derivatives
-
23
Provisions
227
60
Other
(9)
34
Income tax deferred tax assets
616
138
Deferred tax assets
1,717
1,959
Deferred tax liabilities
PRRT
Production and growth assets
1,309
1,281
Augmentation for current year
(38)
(62)
Provisions
(995)
(743)
Other
113
137
PRRT deferred tax liabilities
389
613
Income tax
Oil and gas properties
2,939
2,857
Exploration and evaluation assets
127
67
Lease assets and liabilities
(48)
(22)
Provisions
(1,856)
(1,280)
PRRT assets and liabilities
118
347
Assets held for sale
36
-
Derivatives
(2)
(36)
Other
(76)
(89)
Income tax deferred tax liabilities
1,238
1,844
Deferred tax liabilities
1,627
2,457
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 The Group has two separate USA Tax Consolidation Groups (USA TCG) as at 31 December 2023. Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from the USA TCG of $1,248 million (2022: $1,371 million) and $333 million (2022: $93 million) arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $232 million (2022: $250 million) from the USA TCG, $189 million (2022: $146 million) from USA entities outside of the USA TCG and $763 million (2022: $1,061 million) from countries other than Australia and the USA have not been recognised as it is not currently probable that the losses and credits will be utilised based on current planned activities in those countries. As a result of the FID to develop the Trion resource in 2023, the Group has recognised deferred tax assets of $319 million. PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. During the year ended 31 December 2023, the Group reduced the Pluto PRRT DTA by $637 million ($446 million post-tax) on the basis of future taxable pro\ufb01ts not being available to utilise the deductible expenditure. This is primarily driven by decreases in forecast pricing assumptions and actual pricing realised during the year ended 31 December 2023. 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 2022: 3.2%) was used for the purposes of augmentation. Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable pro\ufb01ts. $7,428 million (2022: $6,523 million) relates to the North West Shelf Project, $872 million (2022: $189 million) relates to remaining Pluto quarantined exploration expenditure and $758 million (2022: $831 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2022: 3.2%) was used for the purposes of augmentation. Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the assessment, additional deferred tax assets would be recognised, with a corresponding 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 . 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 is addressed within this Taxes note and Part B disclosed within the Sustainability section 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. (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. Tax matters without a probable economic out\ufb02ow and/or presently cannot be measured reliably are contingent liabilities and disclosed in Note E.1 Contingent liabilities and assets ", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-769": { "value": "
2023
2022
2021
US$m
US$m
US$m
(a) Tax expense comprises
Petroleum resource rent tax (PRRT)
Current tax expense
367
501
-
Deferred tax expense/(bene\ufb01t)
531
(814)
297
PRRT expense/(bene\ufb01t)
898
(313)
297
Income tax
Current year
Current tax expense
1,872
2,256
658
Deferred tax (bene\ufb01t)/expense
(1,255)
701
301
Adjustment to prior years
Current tax bene\ufb01t
14
(276)
(20)
Deferred tax expense
22
231
18
Income tax expense
653
2,912
957
Tax expense
1,551
2,599
1,254
(b) Reconciliation of income tax expense
Pro\ufb01t before tax
3,273
9,174
3,290
PRRT (expense)/bene\ufb01t
(898)
313
(297)
Pro\ufb01t before income tax
2,375
9,487
2,993
Income tax expense calculated at 30%
712
2,847
898
Effect of tax rate differentials
91
(141)
(42)
Effect of deferred tax assets not recognised
155
150
114
Effect of tax losses and credits previously
unrecognised1
(332)
-
-
Effect of goodwill impairment2
109
-
-
Reduction in deferred tax liability due to
held for sale basis3
(78)
-
-
Foreign exchange impact on tax bene\ufb01t
(58)
(44)
(18)
Adjustment to prior years
36
(45)
(2)
Integration and transaction costs non-
deductible
4
142
-
Other
14
3
7
Income tax expense
653
2,912
957
(c) Reconciliation of PRRT expense
Pro\ufb01t before tax
3,273
9,174
3,290
Non-PRRT assessable pro\ufb01t
(1,780)
(6,197)
(2,134)
PRRT projects pro\ufb01t before tax
1,493
2,977
1,156
PRRT expense calculated at 40%
598
1,191
462
Derecognition/(recognition) of Pluto general
expenditure4
611
(1,362)
-
Recognition of transferred exploration spend
(18)
-
-
Augmentation
(292)
(175)
(166)
Other
(1)
33
1
PRRT expense/(bene\ufb01t)
898
(313)
297
(d) Deferred tax income statement
reconciliation
PRRT
Production and growth assets
1,206
(710)
455
Augmentation for current year
(292)
(175)
(166)
Provisions
(372)
(12)
(29)
Other
(11)
83
37
PRRT expense/(bene\ufb01t)
531
(814)
297
Income tax
Oil and gas properties
(529)
292
674
Exploration and evaluation assets
38
14
(204)
Lease assets and liabilities
(20)
25
1
Provisions
(232)
151
(10)
PRRT assets and liabilities
(175)
236
(88)
Unused tax losses and tax credits
(221)
19
149
Assets held for sale
(86)
205
(205)
Derivatives
(21)
21
(11)
Other
13
(31)
13
Income tax deferred tax (bene\ufb01t)/expense
(1,233)
932
319
Deferred tax (bene\ufb01t)/expense
(702)
118
616
A.5 TAXES
2023
2022
2021
(e) Deferred tax other comprehensive
US$m
US$m
US$m
income reconciliation
Income tax
Derivatives
77
(64)
5
Other
Deferred income tax expense/(bene\ufb01t) via
7
(2)
5
other comprehensive income
84
(66)
10
(f) Effective income tax rate: Australian and
global operations
Effective income tax rate
Australia
30.2%
30.0%
30.6%
Global
27.5%
30.7%
32.0%
1,5 1. As a result of the FID to develop the Trion resource in 2023, the Group has recognised deferred tax assets of $319 million. 2. Tax effect of the non-deductible impairment of goodwill relating to Shenzi. 3. Recognition of the tax base associated with the expected sale of Woodside's 10% share in the Scarborough Project. This will offset future assessable income on the completion of the sale. 4. In 2023, the $637 million decrease of the Pluto PRRT deferred tax asset is due to the derecognition of previously recognised deductible expenditure that is now not considered to be recoverable on the basis of future taxable pro\ufb01ts not being available to utilise the expenditure. In 2022, the $1,362 million increase of the Pluto PRRT deferred tax asset was due to the recognition of previously unrecognised deductible expenditure that is now expected to be utilised to offset future taxable pro\ufb01ts. 5. The global operations effective income tax rate (ETR) is calculated as the Group\u2019s income tax expense divided by pro\ufb01t before income tax. The Australian operations ETR is calculated with reference to all Australian companies and excludes foreign exchange on settlement and revaluation of income tax liabilities. The global effective income tax rate is lower in 2023 primarily as a result of the deferred tax asset recognised upon taking FID on Trion.
2023
2022
US$m
US$m
(g) Deferred tax balance sheet reconciliation
Deferred tax assets
PRRT
Production and growth assets
455
1,460
Augmentation for current year
231
113
Provisions
445
271
Other
(30)
(23)
PRRT deferred tax assets
1,101
1,821
Income tax
Oil and gas properties
(1,388)
(1,496)
Exploration and evaluation assets
60
30
Lease assets and liabilities
40
23
Unused tax losses and tax credits
1,686
1,464
Derivatives
-
23
Provisions
227
60
Other
(9)
34
Income tax deferred tax assets
616
138
Deferred tax assets
1,717
1,959
Deferred tax liabilities
PRRT
Production and growth assets
1,309
1,281
Augmentation for current year
(38)
(62)
Provisions
(995)
(743)
Other
113
137
PRRT deferred tax liabilities
389
613
Income tax
Oil and gas properties
2,939
2,857
Exploration and evaluation assets
127
67
Lease assets and liabilities
(48)
(22)
Provisions
(1,856)
(1,280)
PRRT assets and liabilities
118
347
Assets held for sale
36
-
Derivatives
(2)
(36)
Other
(76)
(89)
Income tax deferred tax liabilities
1,238
1,844
Deferred tax liabilities
1,627
2,457
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 The Group has two separate USA Tax Consolidation Groups (USA TCG) as at 31 December 2023. Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from the USA TCG of $1,248 million (2022: $1,371 million) and $333 million (2022: $93 million) arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $232 million (2022: $250 million) from the USA TCG, $189 million (2022: $146 million) from USA entities outside of the USA TCG and $763 million (2022: $1,061 million) from countries other than Australia and the USA have not been recognised as it is not currently probable that the losses and credits will be utilised based on current planned activities in those countries. As a result of the FID to develop the Trion resource in 2023, the Group has recognised deferred tax assets of $319 million. PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. During the year ended 31 December 2023, the Group reduced the Pluto PRRT DTA by $637 million ($446 million post-tax) on the basis of future taxable pro\ufb01ts not being available to utilise the deductible expenditure. This is primarily driven by decreases in forecast pricing assumptions and actual pricing realised during the year ended 31 December 2023. 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 2022: 3.2%) was used for the purposes of augmentation. Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable pro\ufb01ts. $7,428 million (2022: $6,523 million) relates to the North West Shelf Project, $872 million (2022: $189 million) relates to remaining Pluto quarantined exploration expenditure and $758 million (2022: $831 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2022: 3.2%) was used for the purposes of augmentation. Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the assessment, additional deferred tax assets would be recognised, with a corresponding 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 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 is addressed within this Taxes note and Part B disclosed within the Sustainability section 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. (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. Tax matters without a probable economic out\ufb02ow and/or presently cannot be measured reliably are contingent liabilities and disclosed in Note E.1 Contingent liabilities and assets . ", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-813": { "value": "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 is addressed within this Taxes note and Part B disclosed within the Sustainability section 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. 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 The Group has two separate USA Tax Consolidation Groups (USA TCG) as at 31 December 2023. Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from the USA TCG of $1,248 million (2022: $1,371 million) and $333 million (2022: $93 million) arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $232 million (2022: $250 million) from the USA TCG, $189 million (2022: $146 million) from USA entities outside of the USA TCG and $763 million (2022: $1,061 million) from countries other than Australia and the USA have not been recognised as it is not currently probable that the losses and credits will be utilised based on current planned activities in those countries. As a result of the FID to develop the Trion resource in 2023, the Group has recognised deferred tax assets of $319 million. PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. During the year ended 31 December 2023, the Group reduced the Pluto PRRT DTA by $637 million ($446 million post-tax) on the basis of future taxable pro\ufb01ts not being available to utilise the deductible expenditure. This is primarily driven by decreases in forecast pricing assumptions and actual pricing realised during the year ended 31 December 2023. 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 2022: 3.2%) was used for the purposes of augmentation. Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable pro\ufb01ts. $7,428 million (2022: $6,523 million) relates to the North West Shelf Project, $872 million (2022: $189 million) relates to remaining Pluto quarantined exploration expenditure and $758 million (2022: $831 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2022: 3.2%) was used for the purposes of augmentation. Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the assessment, additional deferred tax assets would be recognised, with a corresponding 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. Tax matters without a probable economic out\ufb02ow and/or presently cannot be measured reliably are contingent liabilities and disclosed in Note E.1 Contingent liabilities and assets . ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-796": { "value": "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 is addressed within this Taxes note and Part B disclosed within the Sustainability section 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. 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 The Group has two separate USA Tax Consolidation Groups (USA TCG) as at 31 December 2023. Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from the USA TCG of $1,248 million (2022: $1,371 million) and $333 million (2022: $93 million) arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a) for details of tax consolidated groups. DTAs relating to carry forward unused tax losses and credits of $232 million (2022: $250 million) from the USA TCG, $189 million (2022: $146 million) from USA entities outside of the USA TCG and $763 million (2022: $1,061 million) from countries other than Australia and the USA have not been recognised as it is not currently probable that the losses and credits will be utilised based on current planned activities in those countries. As a result of the FID to develop the Trion resource in 2023, the Group has recognised deferred tax assets of $319 million. PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable pro\ufb01ts. During the year ended 31 December 2023, the Group reduced the Pluto PRRT DTA by $637 million ($446 million post-tax) on the basis of future taxable pro\ufb01ts not being available to utilise the deductible expenditure. This is primarily driven by decreases in forecast pricing assumptions and actual pricing realised during the year ended 31 December 2023. 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 2022: 3.2%) was used for the purposes of augmentation. Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable pro\ufb01ts. $7,428 million (2022: $6,523 million) relates to the North West Shelf Project, $872 million (2022: $189 million) relates to remaining Pluto quarantined exploration expenditure and $758 million (2022: $831 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2022: 3.2%) was used for the purposes of augmentation. Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the assessment, additional deferred tax assets would be recognised, with a corresponding bene\ufb01t to tax expense. It was determined that the approach adopted provides the most meaningful information on the implications of the PRRT regime, whilst ensuring compliance with AASB 112/IAS 12 Income Taxes . (c) Uncertain tax positions The Group has tax matters, litigation and other claims, for which the timing of resolution and potential economic out\ufb02ows are uncertain. Where the Group assesses an outcome for any tax matter, litigation or other claim as more likely than not to be accepted by the relevant tax authority, the position is adopted in the reported tax balances. Because of the complexity of some of these positions, the ultimate outcome may differ from the current estimate of the position. These differences will be re\ufb02ected as increases or decreases to tax expense in the period in which new information is available. Tax matters without a probable economic out\ufb02ow and/or presently cannot be measured reliably are contingent liabilities and disclosed in Note E.1 Contingent liabilities and assets . ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-741": { "value": "B.2 EXPLORATION AND EVALUATION
Asia Paci\ufb01c
Americas
Africa
Total
US$m
US$m
US$m
US$m
Year ended 31 December 2023
Carrying amount at 1 January 2023
529
240
38
807
Additions
79
161
6
246
Amortisation of licence acquisition costs
-
(2)
(2)
(4)
Expensed1
(31)
(28)
(18)
(77)
Transferred exploration and evaluation2
(9)
(295)
-
(304)
Carrying amount at 31 December 2023
568
76
24
668
Year ended 31 December 2022
Carrying amount at 1 January 2022
546
-
68
614
Acquisitions through business combination3
-
180
-
180
Additions
19
204
17
240
Disposals
-
(10)
-
(10)
Amortisation of licence acquisition costs
-
(8)
(2)
(10)
Expensed1
-
(126)
(45)
(171)
Transferred exploration and evaluation
(36)
-
-
(36)
Carrying amount at 31 December 2022
529
240
38
807
Exploration commitments
Year ended 31 December 2023
3
1
35
39
Year ended 31 December 2022
1
1
27
29
1. $77 million (2022: $125 million) relates to costs of unsuccessful wells. 2. On 20 June 2023, the Group made a \ufb01nal investment decision to develop the Trion resource in Mexico. Related exploration and evaluation assets of $274 million were transferred to oil and gas properties. 3. Refer to Note B.5 for details of business combination. 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. ", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-770": { "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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForExplorationAndEvaluationExpenditures", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-742": { "value": "
Transferred
Land and exploration and Plant and Projects in
buildings evaluation equipment
development
Total
US$m
US$m
US$m
US$m
US$m
Year ended 31 December 2023
Carrying amount at 1 January 2023
840
481
23,057
15,541
39,919
Additions1
-
-
836
5,759
6,595
Disposals at written down value
(8)
-
(2)
-
(10)
Depreciation and amortisation
(67)
(125)
(3,764)
-
(3,956)
Impairment losses2
(64)
(20)
(1,028)
(328)
(1,440)
Completions and transfers
-
441
4,496
(4,633)
304
Transfer to assets held for sale3
-
-
(6)
(615)
(621)
Carrying amount at 31 December 2023
701
777
23,589
15,724
40,791
At 31 December 2023
Historical cost
1,745
1,979
50,272
16,443
70,439
Accumulated depreciation and impairment
(1,044)
(1,202)
(26,683)
(719)
(29,648)
Net carrying amount
701
777
23,589
15,724
40,791
Year ended 31 December 2022
Carrying amount at 1 January 2022
739
526
12,465
4,919
18,649
Acquisitions through business combinations4
64
-
11,952
7,337
19,353
Additions
-
-
(508)
4,332
3,824
Disposals at written down value
(3)
(10)
(32)
-
(45)
Depreciation and amortisation
(54)
(107)
(2,637)
-
(2,798)
Impairment reversal2
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
1. Includes $5,317 million of capital additions, $311 million of capitalised borrowing costs and $967 million following changes in restoration provision. 2. Refer to Note B.4 for details on impairment losses and impairment reversals. 3. Refer to Note B.8 for details of the sell-down of the Scarborough Joint Venture. 4. Refer to Note B.5 for details of business combination. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations. B.3 OIL AND GAS PROPERTIES 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. Upstream oil and conventional gas assets have been depreciated using the unit of production basis over proved reserves (2022: proved plus probable, except for certain assets considered late life). Upstream LNG assets are depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life. The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. Downstream assets (primarily onshore plant and equipment) are depreciated using a straight-line basis over the lesser of useful life and the life of proved plus probable reserves. On a straight-line basis the assets have an estimated useful life of 5-50 years. All other items of 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 $4,245 million as at 31 December 2023 (revised 20221: $6,469 million). Capital expenditure commitments relate predominantly to the Scarborough and Sangomar projects. 1. The 2022 Financial Statements disclosed capital expenditure commitments of $7,762 million which duplicated certain amounts post-merger. This has now been revised to re\ufb02ect the Group's share of commitments. 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. 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 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. (c) Change in depreciation methodology and asset useful lives 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. In assessing useful lives of certain oil and gas assets, these have been determined with 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 have been depreciated over proved reserves (previously proved plus probable, except for certain assets considered late life). Upstream LNG assets have continued to be depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life. The changes in depreciation methodology and asset useful lives have been applied from 1 January 2023, resulting in an increase in depreciation expense of $416 million for the year ended 31 December 2023. ", "dimensions": { "concept": "woodsideenergygroupltd:DisclosureOfOilAndGasProperties", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-797": { "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. Upstream oil and conventional gas assets have been depreciated using the unit of production basis over proved reserves (2022: proved plus probable, except for certain assets considered late life). Upstream LNG assets are depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life. The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. Downstream assets (primarily onshore plant and equipment) are depreciated using a straight-line basis over the lesser of useful life and the life of proved plus probable reserves. On a straight-line basis the assets have an estimated useful life of 5-50 years. All other items of 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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-771": { "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. Upstream oil and conventional gas assets have been depreciated using the unit of production basis over proved reserves (2022: proved plus probable, except for certain assets considered late life). Upstream LNG assets are depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life. The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. Downstream assets (primarily onshore plant and equipment) are depreciated using a straight-line basis over the lesser of useful life and the life of proved plus probable reserves. On a straight-line basis the assets have an estimated useful life of 5-50 years. All other items of 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 $4,245 million as at 31 December 2023 (revised 20221: $6,469 million). Capital expenditure commitments relate predominantly to the Scarborough and Sangomar projects. 1. The 2022 Financial Statements disclosed capital expenditure commitments of $7,762 million which duplicated certain amounts post-merger. This has now been revised to re\ufb02ect the Group's share of commitments. 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. 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 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. (c) Change in depreciation methodology and asset useful lives 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. In assessing useful lives of certain oil and gas assets, these have been determined with 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 have been depreciated over proved reserves (previously proved plus probable, except for certain assets considered late life). Upstream LNG assets have continued to be depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life. The changes in depreciation methodology and asset useful lives have been applied from 1 January 2023, resulting in an increase in depreciation expense of $416 million for the year ended 31 December 2023. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-798": { "value": "Capital commitments The Group has capital expenditure commitments contracted for, but not provided for in the \ufb01nancial statements, of $4,245 million as at 31 December 2023 (revised 20221: $6,469 million). Capital expenditure commitments relate predominantly to the Scarborough and Sangomar projects. 1. The 2022 Financial Statements disclosed capital expenditure commitments of $7,762 million which duplicated certain amounts post-merger. This has now been revised to re\ufb02ect the Group's share of commitments. ", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-799": { "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 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. 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 value in use (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, is applied on a post-tax basis using an appropriate discount rate and estimates are made about the assumptions market participants would use when pricing the asset or CGU. If the carrying amount of an asset or CGU, including any allocated goodwill, exceeds its recoverable amount, the asset or CGU is written down to its recoverable amount and an impairment loss is recognised in the consolidated income statement. Any impairment losses are \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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-772": { "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 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. 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 value in use (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, is applied on a post-tax basis using an appropriate discount rate and estimates are made about the assumptions market participants would use when pricing the asset or CGU. If the carrying amount of an asset or CGU, including any allocated goodwill, exceeds its recoverable amount, the asset or CGU is written down to its recoverable amount and an impairment loss is recognised in the consolidated income statement. Any impairment losses are \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 (a) CGU determination Identi\ufb01cation of a CGU requires management judgement. Management has determined CGUs based on the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or groups of assets. (b) 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. (c) 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 2023 and 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 2023 and 31 December 2022 Annual Reports. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% (2022: 2.0%) has been applied for US based assets and 2.5% (2022: 2.5%) for Australian based assets. \u2022 Foreign exchange rates \u2013 a rate of $0.75 (2022: $0.75) US$:AU$ is based on management\u2019s view of long-term exchange rates. \u2022 Discount rates \u2013 a range of post-tax discount rates between 8.5% and 10.5% (2022: 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 (2022: 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 and therefore dependent on oil price assumptions. LNG sold into spot markets is typically based on a gas-hub linked price (for example the Title Transfer Facility (TTF) or JKM) and therefore these pricing assumptions are also of relevance in forecasting future revenues. \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 goals 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 for the year ended 31 December 2023 were:
2024
2025
2026
2027
2028
2029
31 December 20231
82
80
76
77
79
80
31 December 20222
78
74
76
77
79
80
1. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. The nominal Brent oil prices (US$/bbl) used for the year ended 31 December 2022 were:
2023
2024
2025
2026
2027
2028
31 December 20223
87
78
74
76
77
79
31 December 20214
71
68
69
70
72
73
3. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 4. Long-term oil prices are based on US$65/bbl (2022 real terms) from 2024 and prices are escalated at 2.0% onwards. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-743": { "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 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. 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 value in use (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, is applied on a post-tax basis using an appropriate discount rate and estimates are made about the assumptions market participants would use when pricing the asset or CGU. If the carrying amount of an asset or CGU, including any allocated goodwill, exceeds its recoverable amount, the asset or CGU is written down to its recoverable amount and an impairment loss is recognised in the consolidated income statement. Any impairment losses are \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.
For the year ended 31 December 2023
Goodwill allocation
The Group performed its annual goodwill impairment test as at 31 December 2023.
The carrying amount of goodwill allocated to each CGU, or groups of CGUs and excess recoverable amounts are as follows:
Excess of recoverable amount
Segment
CGU
Goodwill carrying amount over CGU carrying amount
US$m
US$m
Australia
Pluto-Scarborough2
2,743
3,051
Australia
NWS Gas
442
784
International
Atlantis
522
338
International
Other goodwill
288
1,176
Total
3,995
1
1. Amounts are with reference to the total CGU value including goodwill.
2. A portion of the goodwill allocated to Pluto-Scarborough was transferred to assets held for sale (refer to Note B.8).
Other goodwill of $288 million (2022: $283 million) has been allocated across a number of CGUs within the International segment.
This represents less than one percent of net assets as at 31 December 2023.
Recognised impairment and impairment reversals
As at 30 June 2023, the Group assessed each AOI and CGU to determine whether an indicator of impairment or impairment reversal
existed. The Group identi\ufb01ed the following indicators of impairment on CGUs where an impairment loss has been recognised:
CGU Description Indicator of impairment
Pyrenees Oil asset consisting of a \ufb02oating production storage and offloading
(FPSO) facility off the north-west coast of Western Australia.
Reduction in future production volumes, re\ufb02ecting a lower-than-
expected outcome of drilling activities.
For CGUs where goodwill has been allocated, no impairment was recognised as the recoverable amount exceeds the carrying amount
of the CGU.
An impairment was recognised for the Pyrenees CGU (refer to Note A.1), with results as follows:
Impairment loss
Oil and gas properties
Transferred
Recoverable Land and exploration and Plant and Projects in
amount buildings evaluation equipment
development
Total
Segment
CGU
US$m
US$m
US$m
US$m
US$m
US$m
Australia
Pyrenees
159
-
-
68
-
68
Following the impairment recognised at 30 June 2023, no further impairment or impairment reversal for Pyrenees was identi\ufb01ed.
As at 31 December 2023, the Group assessed each AOI and CGU to determine whether an indicator of impairment or impairment
reversal existed. The Group identi\ufb01ed the following indicators of impairment on CGUs where an impairment loss has been recognised:
CGU Description Indicator of impairment
Shenzi
Conventional oil and gas \ufb01eld developed through a tension leg
platform (TLP) located in the US Gulf of Mexico.
Reduction in future production volumes, re\ufb02ecting lower-than-expected
performance of in\ufb01ll sidetracks and performance of the Shenzi North
development following start-up.
Wheatstone
LNG processing facility in Western Australia, comprising an offshore
production platform and two onshore LNG processing trains, a
domestic gas plant and associated infrastructure.
Updated short-term price assumptions (in particular the Japan/Korea
Marker (JKM)).
An impairment was recognised in the pro\ufb01t and loss, refer to Note A.1. The results as follows:
Impairment loss
Goodwill
Oil and gas properties
Transferred
Recoverable Land and exploration and Plant and Projects in
amount
Goodwill
buildings evaluation equipment
development
Total
Segment
CGU
US$m
US$m
US$m
US$m
US$m
US$m
US$m
International Shenzi
1,862
477
-
-
589
317
1,383
Australia
Wheatstone
2,418
-
64
20
371
11
466
For CGUs where goodwill has been allocated, with the exception of Shenzi, no impairment was recognised as the recoverable amount
exceeds the carrying amount of the CGU.
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). Reasonably possible changes to these key assumptions are set out below:
\u2022 Post-tax discount rate \u2013 plus or minus 1.0% (representing a change of 100 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 reasonably possible changes to these assumptions on recoverable amounts is detailed below.
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 2023:
Sensitivity (US$m)2
Discount rate Discount rate Commodity Commodity Production Production
CGU increase\u00b3 decrease\u00b3 price increase\u00b3
price decrease\u00b3
FX increase\u00b3
FX decrease\u00b3
increase\u00b3 decrease\u00b3
Shenzi
(67)
71
359
(359)
N/A
N/A
47
(46)
Wheatstone
(88)
94
431
(370)
(36)
87
90
(42)
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 reasonably possible changes to discount rate, commodity price, FX and production volumes assumptions.
3. The relationship between the discount rate, commodity price, FX and production and the carrying amount is non-linear in certain circumstances which may include \ufb01xed costs impacts as well as
economic cut off modelling. As such, sensitivities are unlikely to result in a symmetrical impact 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:
Commodity price Nominal discount rate
CGU
% 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
Atlantis
(5%)
N/A\u00b2
1
1. Brent price applies to Pluto-Scarborough and NWS Gas. WTI price (Brent - $3/bbl) applies to Atlantis.
2. Management considers there to be no reasonably possible change in the respective estimate which, in isolation, would result in the estimated recoverable amount being equal to the carrying amount.
A change in any of the above assumptions would have an impact on other assumptions which when considered together may offset.
This does not incorporate decisions management may take in order to mitigate the change in assumptions. Management considers
there to be no reasonably possible changes in production volumes, carbon prices or foreign exchange rates that would, in isolation,
result in the estimated recoverable amount being equal to the carrying amount. Analysis of key assumptions which could result in the
carrying value to equal the recoverable value provides a basis to assess the magnitude of a reasonably possible change to the carrying
amounts of respective CGUs.
For the year ended 31 December 2022
Goodwill allocation
The Group performed its annual goodwill impairment test as at 31 December 2022.
The carrying amount of goodwill allocated to each CGU, or groups of CGUs and excess recoverable amounts were as follows:
Excess of recoverable amount
Segment
CGU
Goodwill carrying amount1
over CGU carrying amount
US$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
2
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 $283 million (2021: nil) has been allocated across a number of CGUs within the International segment.
This represents less than one percent of net assets as at 31 December 2022.
Recognised impairment and impairment reversals
As at 31 December 2022, the Group assessed each AOI and CGU to determine whether an indicator of impairment or impairment
reversal existed. The Group identi\ufb01ed the following indicators of impairment reversals:
\u2022 Wheatstone CGU \u2013 revision in short-term and long-term LNG price assumptions and updated cost and production pro\ufb01les.
For CGUs where goodwill has been allocated, no impairment was recognised as the recoverable amount exceeds the carrying amount
of the CGU.
An impairment reversal was recognised for Wheatstone (refer to Note A.1), with results as follows:
Impairment reversal
Oil and gas properties
Transferred
Recoverable Land and exploration and Plant and
amount buildings evaluation
equipment
Total
Segment
CGU
US$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). Reasonably 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 reasonably possible changes to these assumptions on recoverable amounts is detailed below.
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
Discount rate Discount rate Brent price Brent price Production Production
CGU increase\u00b3 decrease\u00b3 increase
decrease
FX increase
FX decrease
increase\u2074 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:
Commodity price Nominal discount rate
CGU
% 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 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 (a) CGU determination Identi\ufb01cation of a CGU requires management judgement. Management has determined CGUs based on the smallest group of assets that generate signi\ufb01cant cash in\ufb02ows that are independent from other assets or groups of assets. (b) 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. (c) 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 2023 and 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 2023 and 31 December 2022 Annual Reports. \u2022 In\ufb02ation rate \u2013 an in\ufb02ation rate of 2.0% (2022: 2.0%) has been applied for US based assets and 2.5% (2022: 2.5%) for Australian based assets. \u2022 Foreign exchange rates \u2013 a rate of $0.75 (2022: $0.75) US$:AU$ is based on management\u2019s view of long-term exchange rates. \u2022 Discount rates \u2013 a range of post-tax discount rates between 8.5% and 10.5% (2022: 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 (2022: 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 and therefore dependent on oil price assumptions. LNG sold into spot markets is typically based on a gas-hub linked price (for example the Title Transfer Facility (TTF) or JKM) and therefore these pricing assumptions are also of relevance in forecasting future revenues. \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 goals 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 for the year ended 31 December 2023 were:
2024
2025
2026
2027
2028
2029
31 December 20231
82
80
76
77
79
80
31 December 20222
78
74
76
77
79
80
1. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. The nominal Brent oil prices (US$/bbl) used for the year ended 31 December 2022 were:
2023
2024
2025
2026
2027
2028
31 December 20223
87
78
74
76
77
79
31 December 20214
71
68
69
70
72
73
3. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 4. Long-term oil prices are based on US$65/bbl (2022 real terms) from 2024 and prices are escalated at 2.0% onwards. ", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-744": { "value": "
B.5 BUSINESS COMBINATION
BHP Petroleum merger
Refer to the 2022 Financial Statements for details of the BHPP
merger. Except for changes noted below, the disclosures are
consistent with Note B.5 of the 2022 Financial Statements.
On 1 June 2022, the Group acquired 100% of the issued share
capital of BHP Petroleum International Pty Ltd (subsequently
renamed Woodside Energy Global Holdings Pty Ltd), which held
BHP Group\u2019s (BHP) 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 was accounted for as a
business combination with an acquisition date of 1 June 2022.
The Group had 12 months from the acquisition date to make
adjustments to the fair value of net identi\ufb01able assets acquired
and the resultant value of goodwill. As at 1 June 2023, the Group
\ufb01nalised the purchase price allocation which has resulted in
goodwill of $4,669 million, a net increase of $55 million from
the provisional amount reported at 31 December 2022.
Details of the purchase consideration and the fair value of
goodwill, identi\ufb01able assets and liabilities of BHPP acquired
are as follows:
Fair value of net identi\ufb01able assets and goodwill arising on
acquisition date
US$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
284
Exploration and evaluation assets
180
Oil and gas properties
19,353
Lease assets
142
Payables
(1,035)
Provisions
(4,827)
Tax payable
(365)
Deferred tax liabilities
(653)
Lease liabilities
(268)
Other liabilities
(1,054)
Net identi\ufb01able assets acquired
13,941
Goodwill arising on acquisition
4,669
Purchase consideration
18,610
Purchase consideration
US$m
Shares issued, at fair value
19,265
Other reserves (share replacement awards)
18
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
Locked box payment received
683
Net cash \ufb02ow on acquisition
1,082
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. Locked box payment received For the year ended 31 December 2022, 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 initial purchase consideration was subsequently adjusted by $10 million against the locked box payment received. 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. $2,035 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 $2,634 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. 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. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-773": { "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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-774": { "value": "B.6 GOODWILL
US$m
Year ended 31 December 2023
Carrying amount at 1 January 2023
4,614
Adjustment to purchase price allocation1
55
Impairment2
(477)
Transfer to assets held for sale3
(197)
Carrying amount at 31 December 2023
3,995
At 31 December 2023
Cost
4,472
Accumulated impairment
(477)
Net carrying amount
3,995
Year ended 31 December 2022
Carrying amount at 1 January 2022
-
Acquisitions through business combinations1
4,614
Carrying amount at 31 December 2022
4,614
At 31 December 2022
Cost
4,614
Accumulated impairment
-
Net carrying amount
4,614
1. Refer to Note B.5 for details on business combination. 2. Refer to Note B.4 for details on impairment. 3. Refer to Note B.8 for details of the sell-down of the Scarborough Joint Venture. Recognition and measurement Goodwill is initially measured at cost and is subsequently measured at cost less any accumulated impairment losses. For the purposes of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group\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. Key estimates and judgements (a) 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 . ", "dimensions": { "concept": "ifrs-full:DisclosureOfGoodwillExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-745": { "value": "B.6 GOODWILL
US$m
Year ended 31 December 2023
Carrying amount at 1 January 2023
4,614
Adjustment to purchase price allocation1
55
Impairment2
(477)
Transfer to assets held for sale3
(197)
Carrying amount at 31 December 2023
3,995
At 31 December 2023
Cost
4,472
Accumulated impairment
(477)
Net carrying amount
3,995
Year ended 31 December 2022
Carrying amount at 1 January 2022
-
Acquisitions through business combinations1
4,614
Carrying amount at 31 December 2022
4,614
At 31 December 2022
Cost
4,614
Accumulated impairment
-
Net carrying amount
4,614
1. Refer to Note B.5 for details on business combination. 2. Refer to Note B.4 for details on impairment. 3. Refer to Note B.8 for details of the sell-down of the Scarborough Joint Venture. Recognition and measurement Goodwill is initially measured at cost and is subsequently measured at cost less any accumulated impairment losses. For the purposes of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group\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. Key estimates and judgements (a) 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 ", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-814": { "value": "Recognition and measurement Goodwill is initially measured at cost and is subsequently measured at cost less any accumulated impairment losses. For the purposes of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group\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. Key estimates and judgements (a) 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 . ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-800": { "value": "Recognition and measurement Goodwill is initially measured at cost and is subsequently measured at cost less any accumulated impairment losses. For the purposes of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group\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. Key estimates and judgements (a) 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 . ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-746": { "value": "B.7 SIGNIFICANT PRODUCTION AND GROWTH ASSET ACQUISITIONS 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 $55 million being reached. With \ufb01rst oil in Sangomar targeted in mid-2024, the Group has recognised the additional payments as a provision for the year ended 31 December 2023. For the years ended 31 December 2022 and 31 December 2021, the contingent payments were accounted for as contingent liabilities in accordance with the Group\u2019s accounting policies. As at 31 December 2021, Woodside held an 82% interest in the Sangomar exploitation area (2020: 68.33%) and a 90% interest in the remaining RSSD evaluation area (2020: 75%). Assets acquired and liabilities assumed The identi\ufb01able assets and liabilities acquired as at the date of the acquisition inclusive of transaction costs are:
US$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 (a) 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 an asset acquisition. ", "dimensions": { "concept": "woodsideenergygroupltd:DisclosureOfSignificantProductionAndGrowthAssetAcquisitions", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-747": { "value": "
B.8 DISPOSAL OF ASSETS
(a) Sell-down of Scarborough Joint Venture
On 8 August 2023 the Group entered into a sale and purchase
agreement with LNG Japan for the sale of a 10% non-operating
participating interest in the Scarborough Joint Venture.
As at 31 December 2023, the Group has reclassi\ufb01ed
$823 million of assets, being the carrying value of the 10%
interest in the Scarborough Joint Venture within the Australia
segment, to assets held for sale. Liabilities of $94 million have
been reclassi\ufb01ed to liabilities directly associated with assets held
for sale. No impairment of assets occurred on reclassi\ufb01cation to
held for sale.
The following assets and liabilities were reclassi\ufb01ed as held
for sale as at 31 December 2023:
US$m
Assets classi\ufb01ed as held for sale
Inventories
4
Oil and gas properties
618
Lease assets
3
Goodwill
197
Other assets
1
Total assets held for sale
823
Liabilities directly associated with assets held for sale
Payables
(26)
Deferred tax liabilities
(61)
Lease liabilities
(7)
Total liabilities directly associated with assets held for sale
(94)
The purchase price is $500 million, subject to adjustments.
The total proceeds from the sale are expected to exceed the
net carrying value of the assets and liabilities classi\ufb01ed as held
for sale as LNG Japan will reimburse the Group for its share of
expenditure for the Scarborough project from the effective date
of 1 January 2022. Delays to the \ufb01rst cargo or cost overruns in
speci\ufb01c circumstances may result in payments by Woodside to
LNG Japan of up to a maximum of $50 million. The transaction is
expected to complete in the \ufb01rst quarter of 2024.
Completion of the transaction is subject to the remaining
Western Australian Government approvals.
In addition to the above, a reduction in the deferred tax liability
due to the change to a held for sale basis resulted in a tax
bene\ufb01t of $78 million being recognised for the year ended
31 December 2023.
Recognition and measurement The Group classi\ufb01es assets and liabilities as held for sale if their carrying amounts will be recovered principally through sale rather than through continuing use. Such assets and liabilities classi\ufb01ed as held for sale are measured at the lower of their carrying amount and fair value less costs to dispose. Costs to dispose are the incremental costs directly attributable to the sale, excluding \ufb01nance costs and income tax expense. The criteria for held for sale classi\ufb01cation are considered met only when the sale is highly probable, and the asset is available for sale in its present condition. Actions required to complete the sale should indicate that it is unlikely that signi\ufb01cant changes to the sale will be made or that the decision to sell will be withdrawn. Management must be committed to the sale, expected within one year from the date of the classi\ufb01cation. Assets are not depreciated or amortised once classi\ufb01ed as held for sale. Assets and liabilities classi\ufb01ed as held for sale are presented separately as current items in the statement of \ufb01nancial position. Assets and liabilities reclassi\ufb01ed as held for sale In addition to the assets and liabilities reclassi\ufb01ed as held for sale for the Scarborough Joint Venture, the Group has reclassi\ufb01ed $3 million for the North West Shelf vessels to assets held for sale. There are no recognised liabilities associated with the North West Shelf vessels. Key estimates and judgements (a) Goodwill allocation In accordance with AASB 136/IAS 36 Impairment of assets, if goodwill has been allocated to a CGU and the entity disposes of an operation within that unit, the goodwill associated with the operation disposed shall be included in the carrying value of the operation when determining the gain or loss on disposal and measured on the basis of the relative values of the operation disposed of and the portion of the CGU retained. The Pluto-Scarborough CGU includes goodwill allocated from the merger with BHPP in 2022. Judgement is required to determine the amount of goodwill allocated to the 10% participating interest in the Scarborough assets being disposed. The Group used fair value measurements of Pluto and Scarborough assets within the CGU as basis to allocate goodwill between the Pluto and Scarborough assets. The goodwill associated with the participating interest of the Scarborough assets being disposed of was determined based on the percentage participating interest disposed of in proportion to the participating interest being retained.
(b) 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 for the
year ended 31 December 2022.
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 2023,
the variable consideration has been reassessed with no revaluation
gain or loss being recognised (2022: $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 (a) 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 as 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 for the year ended 31 December 2022. The variable consideration is remeasured at each reporting period with any changes recognised through the consolidated income statement. As at 31 December 2023, the variable consideration has been reassessed with no revaluation gain or loss being recognised (2022: $71 million revaluation gain recognised as other income). ", "dimensions": { "concept": "woodsideenergygroupltd:DisclosureOfDisposalOfAssets", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-775": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-776": { "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 2023, the Group had a total of $7,790 million (2022: $10,239 million) of available undrawn
facilities and cash at its disposal. The maturity pro\ufb01le of interest-bearing liabilities is disclosed in Note C.2, trade and other payables are
disclosed in Note D.4 and lease liabilities are disclosed in Note D.7. Financing facilities available to the Group are disclosed in Note C.2.
", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-748": { "value": "C.1 CASH AND CASH EQUIVALENTS
2023
2022
US$m
US$m
Cash and cash equivalents
Cash at bank
1,198
1,222
Term deposits
542
4,967
Restricted cash
-
12
Total cash and cash equivalents
1,740
6,201
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. There are no cash and cash equivalents (2022: $12 million) restricted by legal or contractual arrangements.
Foreign exchange risk
The following table summarises the Group\u2019s cash and cash
equivalents by currency.
2023
2022
US$m
US$m
US dollar
1,480
5,886
Australian dollar
112
182
Other
148
133
Total cash and cash equivalents
1,740
6,201
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-777": { "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. There are no cash and cash equivalents (2022: $12 million) restricted by legal or contractual arrangements.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-801": { "value": "
C.2 INTEREST-BEARING LIABILITIES AND FINANCING FACILITIES
Liquidity Bilateral Syndicated Medium Term
Facilities Facilities
Facilities
JBIC Facility
US Bonds
Notes
Total
US$m
US$m
US$m
US$m
US$m
US$m
US$m
Year ended 31 December 2023
At 1 January 2023
-
(5)
591
83
4,084
385
5,138
Repayments1
-
-
-
(83)
-
(201)
(284)
Fair value adjustment and foreign
exchange movement
-
-
-
-
-
16
16
Transaction costs capitalised and
amortised
(1)
(1)
3
-
3
-
4
Carrying amount at 31 December 2023
(1)
(6)
594
-
4,087
200
4,874
Current2
(1)
(2)
(3)
-
(3)
-
(9)
Non-current
-
(4)
597
-
4,090
200
4,883
Carrying amount at 31 December 2023
(1)
(6)
594
-
4,087
200
4,874
Undrawn balance at 31 December 2023
1,800
2,250
2,000
-
-
-
6,050
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
1. Included in cash \ufb02ows classi\ufb01ed within \ufb01nancing activities in the consolidated statement of cash \ufb02ows.
2. The balance relates to capitalised costs to be amortised within the next 12 months. This balance has been reclassi\ufb01ed to other assets (current) for presentation on the statement of \ufb01nancial position.
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 loss of $16 million being recorded (2022: gain of $7 million), and a loss of $6 million being recorded on the hedging instrument (2022: 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.
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 $4,087 million (2022: $4,084 million) and a fair value of
$3,936 million (2022: $3,852 million). The medium term notes have
a carrying amount of $200 million (2022: $385 million) and a fair
value of $188 million (2022: $372 million). Fair value is calculated
based on the present value of future principal and interest cash
\ufb02ows, discounted at the market rate of interest at the reporting date
and classi\ufb01ed as Level 1 on the fair value hierarchy. Where these cash
\ufb02ows are in a foreign currency, the present value is converted to US
dollars at the foreign exchange spot rate prevailing at the reporting
date. The Group\u2019s repayment obligations remain unchanged.
Foreign exchange risk
All interest-bearing liabilities are denominated in US dollars,
excluding the CHF175 million medium term note which was
settled in December 2023.
Maturity pro\ufb01le of interest-bearing liabilities
The table below presents the contractual undiscounted
cash \ufb02ows associated with the Group\u2019s interest-bearing
liabilities, representing principal and interest. The \ufb01gures will
not necessarily reconcile with the amounts disclosed in the
consolidated statement of \ufb01nancial position.
2023
2022
US$m
US$m
Due for payment in:
1 year or less
212
483
1-2 years
1,181
206
2-3 years
962
1,181
3-4 years
907
962
4-5 years
883
908
More than 5 years
1,534
2,416
5,679
6,156
Amounts exclude transaction costs.
Liquidity facilities
In October 2023, the Group obtained 12-month liquidity facilities
to the value of $1,800 million in aggregate. Interest rates are
based on daily SOFR plus credit adjustment spread (CAS) and
margins, \ufb01xed at the commencement of the drawdown period.
Bilateral facilities
The Group has 15 bilateral loan facilities totalling $2,250 million
(2022: 14 bilateral loan facilities totalling $2,050 million). Details
of bilateral loan facilities at the reporting date are as follows:
Number of
facilities
Term (years)
Currency
Extension option
1
5-6
US$
Evergreen
5
4-5
US$
Evergreen
4
3-4
US$
Evergreen
5
3 years or less
US$
Evergreen
Interest rates are based on SOFR plus CAS 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 year ended 31 December 2022, 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 plus CAS 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 SOFR plus CAS 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
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.
This facility was settled in July 2023. During the period, the
Group repaid $83 million on the JBIC facility.
Medium term notes
On 28 August 2015, the Group established a $3,000 million
Global Medium Term Notes Programme listed on the Singapore
Stock Exchange. One note is currently issued under this
programme as set out below:
Carrying amount Nominal
Maturity date
Currency
(million) interest rate
29 January 2027
US$
200
3.07%
The unutilised program is not considered to be an unused facility.
The CHF medium term note was settled in December 2023.
During the period, the Group repaid $201 million of the CHF
medium term note.
US bonds
The Group has four series of unsecured bonds issued in reliance
on Rule 144A of the US Securities Act of 1933 as set out below:
Carrying amount Nominal
Maturity date US$m 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.
", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-778": { "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 loss of $16 million being recorded (2022: gain of $7 million), and a loss of $6 million being recorded on the hedging instrument (2022: loss of $7 million). All bonds, notes and facilities are subject to various covenants and negative pledges restricting future secured borrowings, subject to a number of permitted lien exceptions. Neither the covenants nor the negative pledges have been breached at any time during the reporting period. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-815": { "value": "C.3 CONTRIBUTED EQUITY Recognition and measurement Issued capital Ordinary shares are classi\ufb01ed as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds. Reserved shares Reserved shares are the Group\u2019s own equity instruments, which are used in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity. No gain or loss is recognised in the income statement on the purchase, sale, issue or cancellation of the Group\u2019s own equity instruments. (a) Issued and fully paid shares
Number of
shares
US$m
Year ended 31 December 2023
Opening balance
1,898,749,771
29,001
Amounts as at 31 December 2023
1,898,749,771
29,001
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$14.21
(2021 interim dividend)
6,051,940
86
Amounts as at 31 December 2021
969,631,826
9,409
1. Relates to ordinary shares issued for the DRP as part of the 2021 \ufb01nal dividend. The Group purchased on-market shares for the issuance of DRP as part of the 2022 interim dividend. Refer to Note C.3(b) for details of the on-market purchases and allocation. 2. 914,768,948 new Woodside shares were issued as consideration for the BHPP merger. Refer to Note B.5 for details. All shares are a single class with equal rights to dividends, capital, distributions and voting. Woodside does not have authorised capital nor par value in relation to its issued shares. ", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-749": { "value": "C.3 CONTRIBUTED EQUITY Recognition and measurement Issued capital Ordinary shares are classi\ufb01ed as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds. Reserved shares Reserved shares are the Group\u2019s own equity instruments, which are used in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity. No gain or loss is recognised in the income statement on the purchase, sale, issue or cancellation of the Group\u2019s own equity instruments. (a) Issued and fully paid shares
Number of
shares
US$m
Year ended 31 December 2023
Opening balance
1,898,749,771
29,001
Amounts as at 31 December 2023
1,898,749,771
29,001
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$14.21
(2021 interim dividend)
6,051,940
86
Amounts as at 31 December 2021
969,631,826
9,409
1. Relates to ordinary shares issued for the DRP as part of the 2021 \ufb01nal dividend. The Group purchased on-market shares for the issuance of DRP as part of the 2022 interim dividend. Refer to Note C.3(b) for details of the on-market purchases and allocation. 2. 914,768,948 new Woodside shares were issued as consideration for the BHPP merger. Refer to Note B.5 for details. All shares are a single class with equal rights to dividends, capital, distributions and voting. Woodside does not have authorised capital nor par value in relation to its issued shares.
(b) Reserved shares
Employee share Dividend
plans reinvestment plan
Number Number
of shares
US$m
of shares
US$m
Year ended 31 December 2023
Opening balance
1,873,777
(38)
-
-
Purchases during the year
2,332,121
(57)
-
-
Vested/allocated during the year
(2,064,971)
46
-
-
Amounts at 31 December 2023
2,140,927
(49)
-
-
Year ended 31 December 2022
Opening balance
1,819,744
(30)
-
-
Purchases during the year
2,232,589
(45)
6,823,092
(144)
Vested during the year
(2,178,556)
37
(6,823,092)
144
Amounts at 31 December 2022
1,873,777
(38)
-
-
Year ended 31 December 2021
Opening balance
1,766,099
(23)
-
-
Purchases during the year
2,683,469
(47)
-
-
Vested during the year
(2,629,824)
40
-
-
Amounts at 31 December 2021
1,819,744
(30)
-
-
C.4 OTHER RESERVES
2023
2022
2021
US$m
US$m
US$m
Other reserves
Employee bene\ufb01ts reserve
290
278
232
Foreign currency translation reserve
795
796
793
Hedging reserve1
88
(586)
(400)
Distributable pro\ufb01ts reserve2
4,118
3,541
58
Other reserves
(30)
2
-
5,261
4,031
683
1. For the year ended 31 December 2023, the portion of the hedging reserve relating to settled
hedges is $80 million (2022: $226 million).
2. For the year ended 31 December 2023, the Group transferred $4,830 million (2022:
$5,553 million) of retained earnings to the distributable pro\ufb01ts reserve. The increase was
offset by the 2022 \ufb01nal and 2023 interim dividend payments of $4,253 million (2022 interim
dividend payment: $2,070 million).
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 effective portion of 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 recognised in 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:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-802": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-803": { "value": "Reserved shares Reserved shares are the Group\u2019s own equity instruments, which are used in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity. No gain or loss is recognised in the 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-816": { "value": "(b) Reserved shares Employee share Dividend plans reinvestment plan Number Number of shares US$m of shares US$m Year ended 31 December 2023 Opening balance 1,873,777 (38) - - Purchases during the year 2,332,121 (57) - - Vested/allocated during the year (2,064,971) 46 - - Amounts at 31 December 2023 2,140,927 (49) - - Year ended 31 December 2022 Opening balance 1,819,744 (30) - - Purchases during the year 2,232,589 (45) 6,823,092 (144) Vested during the year (2,178,556) 37 (6,823,092) 144 Amounts at 31 December 2022 1,873,777 (38) - - Year ended 31 December 2021 Opening balance 1,766,099 (23) - - Purchases during the year 2,683,469 (47) - - Vested during the year (2,629,824) 40 - - Amounts at 31 December 2021 1,819,744 (30) ", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-779": { "value": "C.4 OTHER RESERVES
2023
2022
2021
US$m
US$m
US$m
Other reserves
Employee bene\ufb01ts reserve
290
278
232
Foreign currency translation reserve
795
796
793
Hedging reserve1
88
(586)
(400)
Distributable pro\ufb01ts reserve2
4,118
3,541
58
Other reserves
(30)
2
-
5,261
4,031
683
1. For the year ended 31 December 2023, the portion of the hedging reserve relating to settled hedges is $80 million (2022: $226 million). 2. For the year ended 31 December 2023, the Group transferred $4,830 million (2022: $5,553 million) of retained earnings to the distributable pro\ufb01ts reserve. The increase was offset by the 2022 \ufb01nal and 2023 interim dividend payments of $4,253 million (2022 interim dividend payment: $2,070 million). 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 effective portion of 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 recognised in 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-780": { "value": "Credit risk management Credit risk is the risk that a counterparty will not meet its payment 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 \ufb01nancial security 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 assessment 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 exposure 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. The credit quality of a customer is assessed based on various credit metrics, including its credit rating, and individual credit limits and requirements are de\ufb01ned in accordance with this assessment. Outstanding customer receivables are regularly monitored. At 31 December 2023, the Group had nineteen customers (2022: nineteen customers) that owed the Group more than $10 million each and accounted for approximately 82% (2022: 79%) of product-related trade receivables. Depending on the product, standard settlement terms are 7 to 30 days from the date of invoice or bill of lading. The Group considers the probability of default upon initial recognition of the asset and whether there has been a 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 2023, the Group had a provision for credit losses of nil (2022: nil). Subsequent to 31 December 2023, 97% (2022: 99%) of product-related trade receivables balance of $885 million (2022: $1,067 million) has been received. Credit risk from balances with banks is managed by the Treasury function in accordance with the Group\u2019s policy. The Group places funds from time to time as short-term deposits with reputable \ufb01nancial institutions with investment grade credit ratings. At 31 December 2023 and 31 December 2022, there were no signi\ufb01cant concentrations of credit risk within the Group and \ufb01nancial instruments are spread amongst a number of \ufb01nancial institutions to minimise the risk of counterparty default. The maximum exposure to \ufb01nancial institution credit risk is represented by the sum of all cash deposits plus accrued interest, bank account balances and fair value of derivative assets. The Group\u2019s counterparty credit policy limits this exposure to commercial and investment banks, according to approved credit limits based on the counterparty\u2019s credit rating.", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-750": { "value": "D.2 RECEIVABLES
2023
2022
US$m
US$m
(a) Receivables (current)
Trade receivables1
963
1,067
Other receivables1
456
381
Loans receivable
73
76
Lease receivables
24
35
Interest receivable
1
19
1,517
1,578
(b) Receivables (non-current)
Other receivables
21
75
Loans receivable
771
724
Lease receivables
47
46
839
845
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 7 to 30 days from the date of invoice or bill of lading and customers regularly pay on time. There are no signi\ufb01cant overdue product-related trade receivables as at the end of the reporting period (2022: nil). Fair value The carrying amount of trade and other receivables approximates their fair value. Foreign exchange risk The Group held $305 million of receivables at 31 December 2023 (2022: $174 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 $435 million at 31 December 2023 (2022: $408 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-781": { "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 7 to 30 days from the date of invoice or bill of lading and customers regularly pay on time. There are no signi\ufb01cant overdue product-related trade receivables as at the end of the reporting period (2022: nil). Fair value The carrying amount of trade and other receivables approximates their fair value. Foreign exchange risk The Group held $305 million of receivables at 31 December 2023 (2022: $174 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 $435 million at 31 December 2023 (2022: $408 million), which approximates its fair value. The remaining balance of loans receivable is due from non-controlling interests. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-751": { "value": "D.3 INVENTORIES
2023
2022
US$m
US$m
(a) Inventories (current)
Petroleum products
Goods in transit
41
95
Finished stocks
93
103
Warehouse stores and materials
476
480
Carbon credits1
6
-
616
678
(b) Inventories (non-current)
Warehouse stores and materials
3
11
Carbon credits1
117
54
120
65
1. Inventories include carbon credits which were previously presented within other assets (non- current). The 2022 amounts have been reclassi\ufb01ed to be presented on the same basis. Recognition and measurement Inventories include hydrocarbon stocks, consumable supplies, maintenance spares and carbon credits expected to be utilised to offset future emissions. Inventories are valued at the lower of cost and net realisable value. Cost is determined on a weighted average basis and includes direct costs and an appropriate portion of \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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-782": { "value": "Recognition and measurement Inventories include hydrocarbon stocks, consumable supplies, maintenance spares and carbon credits expected to be utilised to offset future emissions. Inventories are valued at the lower of cost and net realisable value. Cost is determined on a weighted average basis and includes direct costs and an appropriate portion of \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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-752": { "value": "
D.4 PAYABLES
2023
2022
US$m
US$m
Trade and other payables1
1,655
2,029
Interest payable2
69
65
1,724
2,094
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 $534 million of payables at 31 December 2023 (2022: $657 million) in currencies other than US dollars (predominantly Australian dollars). Maturity pro\ufb01le of payables The Group\u2019s payables balances at 31 December 2023 and 31 December 2022 are due for payment within 12 months. ", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-783": { "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 $534 million of payables at 31 December 2023 (2022: $657 million) in currencies other than US dollars (predominantly Australian dollars). Maturity pro\ufb01le of payables The Group\u2019s payables balances at 31 December 2023 and 31 December 2022 are due for payment within 12 months. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-753": { "value": "D.5 PROVISIONS
Restoration Employee bene\ufb01ts Onerous contracts
Other
Total
US$m
US$m
US$m
US$m
US$m
Year ended 31 December 2023
At 1 January 2023
6,253
517
-
409
7,179
Change in provision
664
5
-
(128)
541
Unwinding of present value discount
237
-
-
-
237
Carrying amount at 31 December 2023
7,154
522
-
281
7,957
Current
1,011
351
-
144
1,506
Non-current
6,143
171
-
137
6,451
Net carrying amount
7,154
522
-
281
7,957
Year ended 31 December 2022
At 1 January 2022
2,218
286
214
106
2,824
Acquisitions through business combination2
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
1 1. 2023 change in provision is due to increase in estimates of $1,111 million and accretion of $237 million offset by provisions used of $447 million. Changes in estimates are due to new activities, revisions to cost and removal scope assumptions and rate escalations, supported by the most recent estimates and benchmarks and the alignment of the 'expected value approach' across all assets. 2. Refer to Note B.5 for details of business combination 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. It is currently the Group\u2019s assumption that in some regulatory jurisdictions and environments, certain infrastructures are decommissioned in-situ where it can be demonstrated that this will deliver equal or better environmental outcomes than full removal and that regulatory approval is obtained where arrangements are satisfactory to the regulator. The Group maintains technical expertise to ensure that industry learnings, 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. For the year ended 31 December 2022, the Group applied either the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in assessing the cost estimate. Both approaches are supported by AASB137/IAS 37 Provisions, Contingent Liabilities and Contingent Assets, produce reliable estimates and are widely used in practice. The \u2018expected outcome\u2019 approach was used for heritage Woodside assets (assets held by the Group prior to the BHPP merger) and those assets commonly held by both heritage entities. The \u2019expected value\u2019 approach was used for heritage BHPP assets (assets acquired from BHP) but excludes assets held by both heritage entities. For the year ended 31 December 2023, the Group has aligned to the \u2018expected value\u2019 approach and consistently applied it across all assets. This has not resulted in a material change to the prior estimate. The alignment re\ufb02ects a change to the estimate and not a policy change, therefore no retrospective restatement is required. Expected value approach For both onshore and offshore assets, provision has been made taking into consideration a risked range of possible removal outcomes, including full removal of certain assets or project-speci\ufb01c risks (where applicable). 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 risk free country-speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows. This approach takes into consideration the possibility that full removal of all assets may be required. Inherent uncertainties The basis of the restoration obligation provision for assets with approved decommissioning plans or general directions issued by the regulator can differ from the assumptions disclosed above. Whilst the provisions 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 ongoing to ensure that the most accurate information is available when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash 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 2023. A range of pre-tax discount rates between 3.7% and 5.0% (2022: 3.4% to 4.7%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $365 million higher. If the cost estimates were increased by 10% then the provision would be $718 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 55% (2022: 54%). 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. (b) 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 2023, the Corpus Christi contract has a positive value and therefore is not currently onerous (2022: nil onerous contract provision). 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 2023 are set out below: \u2022 Discount rate \u2013 a pre-tax, risk free US government bond rate of 4.04% (2022: 4.10%) 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 information1. 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 2023 were:
2024
2025
2026
2027
2028
TTF (US$/MMBtu)
13.9
14.2
8.8
8.9
9.1
Brent (US$/bbl)
82
80
76
77
79\u00b2
HH (US$/MMBtu)
3.4
3.5
3.5
3.5
3.63
1. For committed volumes, contracted pricing has been applied. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards. 3. Long-term gas prices are based on US$3.2/MMBtu (2022 real terms) from 2026 and US$3.8/MMBtu (2022 real terms) from 2030. All long-term prices are escalated at 2.0%. ", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-784": { "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. It is currently the Group\u2019s assumption that in some regulatory jurisdictions and environments, certain infrastructures are decommissioned in-situ where it can be demonstrated that this will deliver equal or better environmental outcomes than full removal and that regulatory approval is obtained where arrangements are satisfactory to the regulator. The Group maintains technical expertise to ensure that industry learnings, 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. For the year ended 31 December 2022, the Group applied either the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in assessing the cost estimate. Both approaches are supported by AASB137/IAS 37 Provisions, Contingent Liabilities and Contingent Assets, produce reliable estimates and are widely used in practice. The \u2018expected outcome\u2019 approach was used for heritage Woodside assets (assets held by the Group prior to the BHPP merger) and those assets commonly held by both heritage entities. The \u2019expected value\u2019 approach was used for heritage BHPP assets (assets acquired from BHP) but excludes assets held by both heritage entities. For the year ended 31 December 2023, the Group has aligned to the \u2018expected value\u2019 approach and consistently applied it across all assets. This has not resulted in a material change to the prior estimate. The alignment re\ufb02ects a change to the estimate and not a policy change, therefore no retrospective restatement is required. Expected value approach For both onshore and offshore assets, provision has been made taking into consideration a risked range of possible removal outcomes, including full removal of certain assets or project-speci\ufb01c risks (where applicable). 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 risk free country-speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows. This approach takes into consideration the possibility that full removal of all assets may be required. Inherent uncertainties The basis of the restoration obligation provision for assets with approved decommissioning plans or general directions issued by the regulator can differ from the assumptions disclosed above. Whilst the provisions 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 ongoing to ensure that the most accurate information is available when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash 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 2023. A range of pre-tax discount rates between 3.7% and 5.0% (2022: 3.4% to 4.7%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $365 million higher. If the cost estimates were increased by 10% then the provision would be $718 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 55% (2022: 54%). 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. (b) 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 2023, the Corpus Christi contract has a positive value and therefore is not currently onerous (2022: nil onerous contract provision). 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 2023 are set out below: \u2022 Discount rate \u2013 a pre-tax, risk free US government bond rate of 4.04% (2022: 4.10%) 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 information1. 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 2023 were:
2024
2025
2026
2027
2028
TTF (US$/MMBtu)
13.9
14.2
8.8
8.9
9.1
Brent (US$/bbl)
82
80
76
77
79\u00b2
HH (US$/MMBtu)
3.4
3.5
3.5
3.5
3.63
1. For committed volumes, contracted pricing has been applied. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards. 3. Long-term gas prices are based on US$3.2/MMBtu (2022 real terms) from 2026 and US$3.8/MMBtu (2022 real terms) from 2030. All long-term prices are escalated at 2.0%. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-804": { "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. It is currently the Group\u2019s assumption that in some regulatory jurisdictions and environments, certain infrastructures are decommissioned in-situ where it can be demonstrated that this will deliver equal or better environmental outcomes than full removal and that regulatory approval is obtained where arrangements are satisfactory to the regulator. The Group maintains technical expertise to ensure that industry learnings, 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. For the year ended 31 December 2022, the Group applied either the \u2018expected outcome\u2019 approach or \u2018expected value\u2019 approach in assessing the cost estimate. Both approaches are supported by AASB137/IAS 37 Provisions, Contingent Liabilities and Contingent Assets, produce reliable estimates and are widely used in practice. The \u2018expected outcome\u2019 approach was used for heritage Woodside assets (assets held by the Group prior to the BHPP merger) and those assets commonly held by both heritage entities. The \u2019expected value\u2019 approach was used for heritage BHPP assets (assets acquired from BHP) but excludes assets held by both heritage entities. For the year ended 31 December 2023, the Group has aligned to the \u2018expected value\u2019 approach and consistently applied it across all assets. This has not resulted in a material change to the prior estimate. The alignment re\ufb02ects a change to the estimate and not a policy change, therefore no retrospective restatement is required. Expected value approach For both onshore and offshore assets, provision has been made taking into consideration a risked range of possible removal outcomes, including full removal of certain assets or project-speci\ufb01c risks (where applicable). 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 risk free country-speci\ufb01c discount rates aligned to the estimated timing of cash out\ufb02ows. This approach takes into consideration the possibility that full removal of all assets may be required. Inherent uncertainties The basis of the restoration obligation provision for assets with approved decommissioning plans or general directions issued by the regulator can differ from the assumptions disclosed above. Whilst the provisions 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 ongoing to ensure that the most accurate information is available when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash 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 2023. A range of pre-tax discount rates between 3.7% and 5.0% (2022: 3.4% to 4.7%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $365 million higher. If the cost estimates were increased by 10% then the provision would be $718 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 55% (2022: 54%). ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-754": { "value": "D.6 OTHER FINANCIAL ASSETS AND LIABILITIES
2023
2022
US$m
US$m
Other \ufb01nancial assets
Financial instruments at fair value through
pro\ufb01t and loss
Derivative \ufb01nancial instruments designated
as hedges
248
207
Other \ufb01nancial assets
53
22
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
28
29
Total other \ufb01nancial assets
329
797
Current
209
677
Non-current
120
120
Net carrying amount
329
797
Other \ufb01nancial liabilities
Financial instruments at fair value through
pro\ufb01t and loss
Derivative \ufb01nancial instruments designated
as hedges
74
721
Embedded derivative
35
-
Total other \ufb01nancial liabilities
109
721
Current
67
654
Non-current
42
67
Net carrying amount
109
721
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. 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 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. Embedded commodity derivatives are classi\ufb01ed as Level 3 on the fair value hierarchy with no market observable inputs. 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 As at 31 December 2023, the Group hedged approximately 29.3 MMboe of 2024 production at an average price of approximately $75.7 per barrel. \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. \u2022 In 2022, the Group placed $506 million (excluding interest) as collateral against the oil hedge positions to reduce counterparty credit risk exposure. The collateral was returned to the Group in 2023. \u2022 Through the use of foreign exchange forward contracts, the Group also hedged its Australian dollar to US dollar exchange rate in relation to the Australian dollar denominated tax payments which have matured.
2023
2022
Oil swaps (cash \ufb02ow hedges)
Carrying amount (US$m)
(14)
(114)
Notional amount (MMbbl)1
29
18
Maturity date
2024
2023
Hedge ratio
1:1
1:1
Weighted average hedged rate (US$/MMbbl)
76
79
HH Corpus Christi commodity swaps
(cash \ufb02ow hedges)
Carrying amount (US$m)
(44)
26
Notional amount (TBtu)1
38
58
Maturity date
2024-2025
2023-2024
Hedge ratio
1:1
1:1
Weighted average hedged rate (US$/MMBtu)
4
4
TTF Corpus Christi commodity swaps
(cash \ufb02ow hedges)
Carrying amount (US$m)
181
(469)
Notional amount (TBtu)1
32
50
Maturity date
2024-2025
2023-2024
Hedge ratio
1:1
1:1
Weighted average hedged rate (US$/MMBtu)
18
16
Interest rate swap (cash \ufb02ow hedges)
Carrying amount (US$m)
43
55
Notional amount (US$m)1
600
600
Maturity date
2027
2027
Hedge ratio
1:1
1:1
Weighted average hedged rate
1.7%
1.7%
Cross currency interest rate swap
(cash \ufb02ow and fair value hedges)
Carrying amount (US$m)
-
5
Notional amount (Swiss Franc)1
-
175
Maturity date
-
2023
Hedge ratio
-
1:1
Three month
USD LIBOR
Weighted average hedged rate
-
+2.8%
FX forwards (cash \ufb02ow hedges)
Carrying amount (US$m)
8
(17)
Notional amount (AUD$m)1
1,834
1,037
Maturity date
2024-2025
2023-2025
Hedge Ratio
1:1
1:1
Weighted average hedged rate (AUD:USD)
0.68
0.68
1. The notional amounts relate to unrealised volumes of the hedge item included in the cash \ufb02ow
hedge reserve.
Hedge ineffectiveness loss of $15 million (2022: $72 million loss)
has been recognised in the pro\ufb01t and loss.
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). In 2020, the Federal Reserve
announced that the three-month and six-month LIBOR will be
phased out and eventually replaced by June 2023. The Group
had exposures to IBORs on its \ufb01nancial instruments that were
impacted as part of these market-wide initiatives.
During the period, the Group has transitioned its \ufb01nancial
liabilities from USD London Inter-Bank Offered Rate (USD
LIBOR) to SOFR. The transition of a number of the Group\u2019s
\ufb01nancial liabilities from USD LIBOR to SOFR during the year
ended 31 December 2023 did not result in a material impact to
the Group.
Embedded commodity derivative
In 2023, the Group entered into a revised long-term gas sale
and purchase contract (GSPA) with Perdaman with conditions
precedent being satis\ufb01ed during the year, where a component
of the selling price is linked to the price of urea. The contract has
been assessed to contain an embedded commodity derivative
that is required to be separated and recognised at fair value
through pro\ufb01t and loss. The carrying value of the embedded
derivative at 31 December 2023 amounted to a net liability of
$35 million (31 December 2022: nil). The derivative is remeasured
to fair value at each reporting date in accordance with the Urea
price at that date. As at 31 December 2023, the unrealised loss of
$35 million has been recognised through other expenses.
Key estimates and judgements (a) Embedded commodity derivative The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast cash \ufb02ows, discount rate, credit risk and volatility. These assumptions require signi\ufb01cant management judgement and are subject to risk and uncertainty. The present value of the embedded derivative was estimated using the assumptions set out below. \u2022 In\ufb02ation rate \u2013 2.5% has been applied. \u2022 Discount rate \u2013 a pre-tax interest rate curve (range: 5.39% to 7.12%). \u2022 Domestic gas pricing \u2013 forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (Title Transfer Facility (TTF)) prices available in the market at reporting date. The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses recognised in other income/expenses in the future. The nominal impact of the effects of changes to discount rate and long-term price assumptions are estimated as follows:
Change in assumption1
US$m
Urea sales price: increase of 10%
145
Urea sales price: decrease of 10%
(145)
Discount rate: increase of 1.5%2
(208)
Discount rate: decrease of 1.5%2
258
1. Amounts shown represent the change of the present value of the contract keeping all other variables constant. 2. A change of 1.5% represents 150 basis points. ", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-785": { "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. 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 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. Embedded commodity derivatives are classi\ufb01ed as Level 3 on the fair value hierarchy with no market observable inputs. Key estimates and judgements (a) Embedded commodity derivative The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast cash \ufb02ows, discount rate, credit risk and volatility. These assumptions require signi\ufb01cant management judgement and are subject to risk and uncertainty. The present value of the embedded derivative was estimated using the assumptions set out below. \u2022 In\ufb02ation rate \u2013 2.5% has been applied. \u2022 Discount rate \u2013 a pre-tax interest rate curve (range: 5.39% to 7.12%). \u2022 Domestic gas pricing \u2013 forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (Title Transfer Facility (TTF)) prices available in the market at reporting date. The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses recognised in other income/expenses in the future. The nominal impact of the effects of changes to discount rate and long-term price assumptions are estimated as follows:
Change in assumption1
US$m
Urea sales price: increase of 10%
145
Urea sales price: decrease of 10%
(145)
Discount rate: increase of 1.5%2
(208)
Discount rate: decrease of 1.5%2
258
1. Amounts shown represent the change of the present value of the contract keeping all other variables constant. 2. A change of 1.5% represents 150 basis points. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-822": { "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. 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 revenue contracts. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-817": { "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. 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 revenue contracts. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-805": { "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. 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 revenue contracts. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-806": { "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. Embedded commodity derivatives are classi\ufb01ed as Level 3 on the fair value hierarchy with no market observable inputs. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-807": { "value": "
Hedging activities
During the period, the following hedging activities were
undertaken:
\u2022 As at 31 December 2023, the Group hedged approximately
29.3 MMboe of 2024 production at an average price of
approximately $75.7 per barrel.
\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.
\u2022 In 2022, the Group placed $506 million (excluding interest)
as collateral against the oil hedge positions to reduce
counterparty credit risk exposure. The collateral was returned
to the Group in 2023.
\u2022 Through the use of foreign exchange forward contracts, the
Group also hedged its Australian dollar to US dollar exchange
rate in relation to the Australian dollar denominated tax
payments which have matured.
2023
2022
Oil swaps (cash \ufb02ow hedges)
Carrying amount (US$m)
(14)
(114)
Notional amount (MMbbl)1
29
18
Maturity date
2024
2023
Hedge ratio
1:1
1:1
Weighted average hedged rate (US$/MMbbl)
76
79
HH Corpus Christi commodity swaps
(cash \ufb02ow hedges)
Carrying amount (US$m)
(44)
26
Notional amount (TBtu)1
38
58
Maturity date
2024-2025
2023-2024
Hedge ratio
1:1
1:1
Weighted average hedged rate (US$/MMBtu)
4
4
TTF Corpus Christi commodity swaps
(cash \ufb02ow hedges)
Carrying amount (US$m)
181
(469)
Notional amount (TBtu)1
32
50
Maturity date
2024-2025
2023-2024
Hedge ratio
1:1
1:1
Weighted average hedged rate (US$/MMBtu)
18
16
Interest rate swap (cash \ufb02ow hedges)
Carrying amount (US$m)
43
55
Notional amount (US$m)1
600
600
Maturity date
2027
2027
Hedge ratio
1:1
1:1
Weighted average hedged rate
1.7%
1.7%
Cross currency interest rate swap
(cash \ufb02ow and fair value hedges)
Carrying amount (US$m)
-
5
Notional amount (Swiss Franc)1
-
175
Maturity date
-
2023
Hedge ratio
-
1:1
Three month
USD LIBOR
Weighted average hedged rate
-
+2.8%
FX forwards (cash \ufb02ow hedges)
Carrying amount (US$m)
8
(17)
Notional amount (AUD$m)1
1,834
1,037
Maturity date
2024-2025
2023-2025
Hedge Ratio
1:1
1:1
Weighted average hedged rate (AUD:USD)
0.68
0.68
1. The notional amounts relate to unrealised volumes of the hedge item included in the cash \ufb02ow hedge reserve. Hedge ineffectiveness loss of $15 million (2022: $72 million loss) has been recognised in the pro\ufb01t and loss. ", "dimensions": { "concept": "ifrs-full:DisclosureOfHedgeAccountingExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-755": { "value": "
D.7 LEASES
Land and Plant and
buildings
equipment
Total
US$m
US$m
US$m
Lease assets
Year ended 31 December 2023
Carrying amount at 1 January 2023
464
800
1,264
Additions
8
120
128
Transfer to assets held for sale1
-
(3)
(3)
Lease remeasurements
7
184
191
Depreciation
(49)
(301)
(350)
Carrying amount at 31 December 2023
430
800
1,230
At 31 December 2023
Historical cost and remeasurements
600
1,612
2,212
Accumulated depreciation, impairment
and disposals
(170)
(812)
(982)
Net carrying amount
430
800
1,230
Lease liabilities
Year ended 31 December 2023
At 1 January 2023
623
1,011
1,634
Additions
24
121
145
Transfer to liabilities directly associated
with assets held for sale1
-
(7)
(7)
Repayments (principal and interest)
(78)
(391)
(469)
Accretion of interest
27
75
102
Lease remeasurements
11
199
210
Carrying amount at 31 December 2023
607
1,008
1,615
Current
54
244
298
Non-current
553
764
1,317
Carrying amount at 31 December 2023
607
1,008
1,615
Lease assets
Year ended 31 December 2022
Carrying amount at 1 January 2022
377
703
1,080
Acquisitions through business
combination2
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
combination2
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
1. Refer to Note B.8 for details of the sell-down of the Scarborough Joint Venture.
2. Refer to Note B.5 for details of business combination.
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 $447 million of lease liabilities at 31 December 2023 (2022: $441 million) in currencies other than the US dollar (predominantly Australian dollars). Maturity pro\ufb01le of lease liabilities The table below presents the contractual undiscounted cash \ufb02ows associated with the Group\u2019s lease liabilities, representing principal and interest. The \ufb01gures will not necessarily reconcile with the amounts disclosed in the consolidated statement of \ufb01nancial position.
2023
2022
US$m
US$m
Due for payment in:
1 year or less
415
433
1-2 years
240
272
2-3 years
194
199
3-4 years
180
186
4-5 years
181
176
More than 5 years
1,032
966
2,242
2,232
Lease commitments The table below presents the contractual undiscounted cash \ufb02ows associated with the Group\u2019s future lease commitments for non-cancellable leases not yet commenced, representing principal and interest.
2023
2022
US$m
US$m
Due for payment:
Within one year
33
67
After one year but not more than \ufb01ve years
889
263
Later than \ufb01ve years
1,242
1,288
2,164
1,618
Payments of $121 million (2022: $162 million) for short-term leases (lease term of 12 months or less) and payments of $12 million (2022: $12 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 $575 million (2022: $525 million), with $361 million (2022: $258 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 $232 million (2022: $60 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 $2,000 million (2022: $2,323 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-786": { "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 $2,000 million (2022: $2,323 million) were not included in the measurement of lease liabilities. (c) lnterest in joint arrangements Judgement is required to determine the Group\u2019s rights and obligations for lease contracts within joint operations, to assess whether lease liabilities are recognised gross (100%) or in proportion to the Group\u2019s participating interest in the joint operation. This includes an evaluation of whether the lease arrangement contains a sublease with the joint operation. (d) Discount rates Judgement is required to determine the discount rate, where the discount rate is the Group\u2019s incremental borrowing rate if the rate implicit in the lease cannot be readily determined. The incremental borrowing rate is determined with reference to the Group\u2019s borrowing portfolio at the inception of the arrangement or the time of the modi\ufb01cation. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-787": { "value": "
Maturity pro\ufb01le of lease liabilities
The table below presents the contractual undiscounted cash
\ufb02ows associated with the Group\u2019s lease liabilities, representing
principal and interest. The \ufb01gures will not necessarily reconcile
with the amounts disclosed in the consolidated statement of
\ufb01nancial position.
2023
2022
US$m
US$m
Due for payment in:
1 year or less
415
433
1-2 years
240
272
2-3 years
194
199
3-4 years
180
186
4-5 years
181
176
More than 5 years
1,032
966
2,242
2,232
", "dimensions": { "concept": "ifrs-full:DisclosureOfMaturityAnalysisOfOperatingLeasePaymentsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-756": { "value": "E.1 CONTINGENT LIABILITIES AND ASSETS
2023
2022
US$m
US$m
Contingent liabilities at reporting date
Contingent liabilities
260
161
Guarantees
2
2
262
163
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. The Group operates in complex tax and legislative regimes. The amounts disclosed above include estimates made in relation to ongoing disputes with various tax and government authorities. Assessing a value of contingent liabilities requires a high degree of judgement. The contingent liabilities relating to tax matters are estimated based on notices received from authorities before interest and penalties. The possibility of further claims related to the same matters cannot be ruled out and the judicial processes may take extended periods to conclude. 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 $47 million as at 31 December 2023 (2022: $199 million). ", "dimensions": { "concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-790": { "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. The Group operates in complex tax and legislative regimes. The amounts disclosed above include estimates made in relation to ongoing disputes with various tax and government authorities. Assessing a value of contingent liabilities requires a high degree of judgement. The contingent liabilities relating to tax matters are estimated based on notices received from authorities before interest and penalties. The possibility of further claims related to the same matters cannot be ruled out and the judicial processes may take extended periods to conclude. 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 $47 million as at 31 December 2023 (2022: $199 million). ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-757": { "value": "E.2 EMPLOYEE BENEFITS
2023
2022
2021
US$m
US$m
US$m
Employee bene\ufb01ts
494
415
217
Share-based payments
39
26
12
De\ufb01ned contribution plan costs
53
41
26
De\ufb01ned bene\ufb01t plan expense
17
9
1
603
491
256
(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:
2023
2022
2021
US$
US$
US$
Short-term employee bene\ufb01ts1
5,245,763
5,730,340
6,626,354
Post-employment bene\ufb01ts1
215,856
155,086
88,396
Share-based payments2
3,693,072
3,114,043
5,697,529
Long-term employee bene\ufb01ts
213,562
4,300
717,223
Termination bene\ufb01ts
-
152,531
2,447,525
9,368,253
9,156,300
15,577,027
1. In the prior reporting period, the 2021 comparatives for short-term employee bene\ufb01ts and
post-employment bene\ufb01ts were 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. In the prior reporting period, the 2021 comparative for share-based payments was 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 (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 2023 and 2022, participants are entitled to
receive a Woodside share on the vesting date, three years after
the grant date. Awards made in 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 targeted 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.
Each ER entitles the participant to receive a Woodside share on
vesting date. Participants do not make any payment in respect of
the ERs 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 2022 Restricted Shares
and Performance Rights were granted on 27 February 2023
for Executives and 28 April 2023 for the CEO and have been
included in the table below. The expense estimated as at
31 December 2022 in relation to the 2022 performance year
was updated to the fair value on grant date during the period.
The 2023 Restricted Shares and Performance Rights have
not been included in the table below as they have not been
approved as at 31 December 2023. An expense related to the
2023 performance year has been estimated for the Restricted
Shares and Performance Rights, using fair value estimates based
on inputs at 31 December 2023.
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 2022 Restricted Shares were granted on 27 February 2023 and have been included in the table below. The expense estimated as at 31 December 2022 in relation to the 2022 performance year was updated to the fair value on grant date during the period. The 2023 Restricted Shares have not been included in the table below as they have not been approved as at 31 December 2023. An expense related to the 2023 performance year has been estimated for the Restricted Shares, using fair value estimates based on inputs at 31 December 2023. Recognition and measurement All compensation under WEP, SWEP, PBP Plus and EIS Restricted Shares and Performance Rights is accounted for as share-based payments to employees for services provided. The cost of equity- settled transactions with employees is measured by reference to the fair values of the equity instruments at the date at which they are granted. The fair value of share-based payments is recognised, together with the corresponding increase in equity, over the period in which the vesting conditions are 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 relative total shareholder return Performance Rights is calculated using the Binomial or Black-Scholes option pricing technique combined with a Monte Carlo simulation methodology, where relevant, using historical volatility to estimate the volatility of the share price in the future.
The number of awards and movements for all share plans are summarised as follows:
Number of performance awards
Employee plans
Executive plans
WEP
SWEP
STA
LTA
Year ended 31 December 2023
Opening balance
6,629,681
2,884,076
993,197
2,554,422
Granted during the year
3,445,234
100,811
420,429
658,969
Vested during the year
(600,271)
(1,071,291)
(286,979)
(106,430)
Forfeited during the year
(349,204)
(357,023)
(60,410)
(410,409)
Awards at 31 December 2023
9,125,440
1,556,573
1,066,237
2,696,552
US$m
US$m
US$m
US$m
Fair value of awards granted during the year
60
2
10
12
4
4
1,2,3
Number of performance awards
Employee plans
Executive plans
WEP
SWEP
STA
LTA
Year ended 31 December 2022
Opening balance
5,649,783
-
994,436
2,379,220
Granted during the year
3,017,366
3,046,963
495,800
764,171
Vested during the year
(1,498,065)
(38,146)
(450,609)
(191,736)
Forfeited during the year
(539,403)
(124,741)
(46,430)
(397,233)
Awards at 31 December 2022
6,629,681
2,884,076
993,197
2,554,422
US$m
US$m
US$m
US$m
Fair value of awards granted during the year
49
60
9
13
4
4
1,2,3
1. For the purpose of valuation, the share price on grant date for the 2023 WEP allocations was $17.54 (2022: $16.30).
2. For the purpose of valuation, the share price on grant date for the 2023 SWEP allocations was $20.78 (2022: $19.74).
3. For the purpose of valuation, the share price on grant date for Restricted Shares was $23.48 and $23.33 (2022: $19.20 and $19.27) and Performance Rights was $15.96 (2022: $13.08 and $13.71).
4. Includes awards issued under Executive Incentive Plan (EIP), EIS and PBP Plus.
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-789": { "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, PBP Plus and EIS Restricted Shares and Performance Rights is accounted for as share-based payments to employees for services provided. The cost of equity- settled transactions with employees is measured by reference to the fair values of the equity instruments at the date at which they are granted. The fair value of share-based payments is recognised, together with the corresponding increase in equity, over the period in which the vesting conditions are 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 relative total shareholder return Performance Rights is calculated using the Binomial or Black-Scholes option pricing technique combined with a Monte Carlo simulation methodology, where relevant, using historical volatility to estimate the volatility of the share price in the future. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-788": { "value": "(b) Compensation of key management personnel Key management personnel (KMP) compensation for the \ufb01nancial year was as follows:
2023
2022
2021
US$
US$
US$
Short-term employee bene\ufb01ts1
5,245,763
5,730,340
6,626,354
Post-employment bene\ufb01ts1
215,856
155,086
88,396
Share-based payments2
3,693,072
3,114,043
5,697,529
Long-term employee bene\ufb01ts
213,562
4,300
717,223
Termination bene\ufb01ts
-
152,531
2,447,525
9,368,253
9,156,300
15,577,027
1. In the prior reporting period, the 2021 comparatives for short-term employee bene\ufb01ts and post-employment bene\ufb01ts were 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. In the prior reporting period, the 2021 comparative for share-based payments was 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. ", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-818": { "value": "(c) Share plans The Group provides bene\ufb01ts to its employees (including KMP) in the form of share-based payments (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 2023 and 2022, participants are entitled to receive a Woodside share on the vesting date, three years after the grant date. Awards made in 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 targeted 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. Each ER entitles the participant to receive a Woodside share on vesting date. Participants do not make any payment in respect of the ERs 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 2022 Restricted Shares and Performance Rights were granted on 27 February 2023 for Executives and 28 April 2023 for the CEO and have been included in the table below. The expense estimated as at 31 December 2022 in relation to the 2022 performance year was updated to the fair value on grant date during the period. The 2023 Restricted Shares and Performance Rights have not been included in the table below as they have not been approved as at 31 December 2023. An expense related to the 2023 performance year has been estimated for the Restricted Shares and Performance Rights, using fair value estimates based on inputs at 31 December 2023. 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 2022 Restricted Shares were granted on 27 February 2023 and have been included in the table below. The expense estimated as at 31 December 2022 in relation to the 2022 performance year was updated to the fair value on grant date during the period. The 2023 Restricted Shares have not been included in the table below as they have not been approved as at 31 December 2023. An expense related to the 2023 performance year has been estimated for the Restricted Shares, using fair value estimates based on inputs at 31 December 2023. Recognition and measurement All compensation under WEP, SWEP, PBP Plus and EIS Restricted Shares and Performance Rights is accounted for as share-based payments to employees for services provided. The cost of equity- settled transactions with employees is measured by reference to the fair values of the equity instruments at the date at which they are granted. The fair value of share-based payments is recognised, together with the corresponding increase in equity, over the period in which the vesting conditions are 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 relative total shareholder return Performance Rights is calculated using the Binomial or Black-Scholes option pricing technique combined with a Monte Carlo simulation methodology, where relevant, using historical volatility to estimate the volatility of the share price in the future. The number of awards and movements for all share plans are summarised as follows:
Number of performance awards
Employee plans
Executive plans
WEP
SWEP
STA
LTA
Year ended 31 December 2023
Opening balance
6,629,681
2,884,076
993,197
2,554,422
Granted during the year
3,445,234
100,811
420,429
658,969
Vested during the year
(600,271)
(1,071,291)
(286,979)
(106,430)
Forfeited during the year
(349,204)
(357,023)
(60,410)
(410,409)
Awards at 31 December 2023
9,125,440
1,556,573
1,066,237
2,696,552
US$m
US$m
US$m
US$m
Fair value of awards granted during the year
60
2
10
12
4 4 1,2,3
Number of performance awards
Employee plans
Executive plans
WEP
SWEP
STA
LTA
Year ended 31 December 2022
Opening balance
5,649,783
-
994,436
2,379,220
Granted during the year
3,017,366
3,046,963
495,800
764,171
Vested during the year
(1,498,065)
(38,146)
(450,609)
(191,736)
Forfeited during the year
(539,403)
(124,741)
(46,430)
(397,233)
Awards at 31 December 2022
6,629,681
2,884,076
993,197
2,554,422
US$m
US$m
US$m
US$m
Fair value of awards granted during the year
49
60
9
13
4 4 1,2,3 1. For the purpose of valuation, the share price on grant date for the 2023 WEP allocations was $17.54 (2022: $16.30). 2. For the purpose of valuation, the share price on grant date for the 2023 SWEP allocations was $20.78 (2022: $19.74). 3. For the purpose of valuation, the share price on grant date for Restricted Shares was $23.48 and $23.33 (2022: $19.20 and $19.27) and Performance Rights was $15.96 (2022: $13.08 and $13.71). 4. Includes awards issued under Executive Incentive Plan (EIP), EIS and PBP Plus. For more detail on these share plans and Performance Rights issued to KMPs, refer to the Remuneration Report.", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-808": { "value": "Recognition and measurement All compensation under WEP, SWEP, PBP Plus and EIS Restricted Shares and Performance Rights is accounted for as share-based payments to employees for services provided. The cost of equity- settled transactions with employees is measured by reference to the fair values of the equity instruments at the date at which they are granted. The fair value of share-based payments is recognised, together with the corresponding increase in equity, over the period in which the vesting conditions are 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 relative total shareholder return Performance Rights is calculated using the Binomial or Black-Scholes option pricing technique combined with a Monte Carlo simulation methodology, where relevant, using historical volatility to estimate the volatility of the share price in the future. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSharebasedPaymentTransactionsExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-758": { "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
$71,407 thousand (2022: $60,730 thousand), sale of goods/
services of $27,142 thousand (2022: $18,527 thousand) and
dividend income of $15,296 thousand (2022: $8,294 thousand).
As at 31 December 2023, the total amounts owing to related
parties is $1,559 thousand (2022: $1,686 thousand) and amounts
owing from related parties is $1,960 thousand (2022: $2,200
thousand). 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-791": { "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 $71,407 thousand (2022: $60,730 thousand), sale of goods/ services of $27,142 thousand (2022: $18,527 thousand) and dividend income of $15,296 thousand (2022: $8,294 thousand). As at 31 December 2023, the total amounts owing to related parties is $1,559 thousand (2022: $1,686 thousand) and amounts owing from related parties is $1,960 thousand (2022: $2,200 thousand). 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-819": { "value": "
E.4 AUDITOR REMUNERATION
For the year ended 31 December 2023 and 31 December 2022, the
auditor of Woodside Energy Group Ltd is PricewaterhouseCoopers
Australia (PwC) (2021: Ernst & Young (EY)).
2023
2022
2021
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
6,510
2,878
-
Assurance services
138
129
-
Other assurance and agreed upon
procedures services
332
832
-
Tax services
-
-
-
Other services
-
41
-
Other overseas member \ufb01rms of
PricewaterhouseCoopers (Australia)
Audit of the \ufb01nancial reports of
controlled entities
1,557
1,274
-
Other assurance and agreed upon
procedures services
-
-
-
Tax services
1,081
258
-
Other services
-
-
-
9,618
5,412
-
(b) Other auditors and their related
network \ufb01rms
Ernst & Young
Audit and review of \ufb01nancial reports
-
48
1,732
Assurance services
-
611
2,687
Other assurance and agreed upon
procedures services
-
2,335
33
Tax services
-
-
129
Other services
-
-
19
-
2,994
4,600
1
1. The disclosure of auditor remuneration is not required as EY is no longer bound by auditor
independence requirements for the year ended 31 December 2023.
", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-760": { "value": "
E.5 EVENTS AFTER THE END OF THE
REPORTING PERIOD
On 23 February 2024, Woodside and JERA Scarborough Pty
Ltd (JERA) entered into a Sale and Purchase agreement for
JERA to acquire 15.1% participating interest in the Scarborough
Joint Venture. The purchase price is $740 million. JERA will
also reimburse Woodside for its share of expenditure for the
Scarborough project from the effective date of 1 January 2022.
Subject to the satisfaction of conditions precedent, the transaction
is expected to complete in the second half of 2024. The full
\ufb01nancial effect of the transaction is still being assessed. The
Scarborough Joint Venture is included in the Australia segment.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-759": { "value": "
E.6 JOINT ARRANGEMENTS
(a) Interest percentage in joint ventures
Group Interest %
Entity
Principal activity
2023
2022
North West Shelf Gas Pty Contract administration
33.33
33.33
Ltd services for venturers
for LNG sales to
Japan. Marketing and
administration services
for venturers for gas
processing.
North West Shelf Liaison Liaison for venturers in the 33.33 33.33
Company Pty Ltd sale of LNG to the Japanese
market.
China Administration Contract administration 33.33 33.33
Company Pty Ltd services for venturers for
LNG sales to China.
North West Shelf Shipping LNG vessel \ufb02eet advisor. 33.33 33.33
Service Company Pty Ltd
North West Shelf Lifting Allocating, scheduling and 33.33 33.33
Coordinator Pty Ltd administering the lifting of
LNG and pipeline gas.
(b) Interest percentage in joint operations
Group Interest %
2023
2022
Producing and developing assets
Australia
North West Shelf
25.0 - 66.7
25.0 - 66.7
Greater En\ufb01eld and Vincent
60.0
60.0
Balnaves
65.0
65.0
Pluto
90.0
90.0
Wheatstone
13.0 - 65.0
13.0 - 65.0
Bass Strait
25.0 - 50.0
25.0 - 50.0
Macedon
71.4
71.4
Pyrenees
40.0 - 71.4
40.0 - 71.4
Griffin
45.0 - 71.0
45.0 - 71.0
Minerva
90.0
90.0
International
Sangomar
82.0
82.0
Atlantis
44.0
44.0
Mad Dog
23.9
23.9
Shenzi
72.0
72.0
Trion
60.0
60.0
Greater Angostura
45.0 - 68.5
45.0 - 68.5
Calypso
70.0
70.0
Exploration and evaluation assets
Oceania
Browse Basin
30.6
30.6
Carnarvon Basin
31.6 - 70.0
31.6 - 70.0
Bonaparte Basin
26.7 - 35.0
26.7 - 35.0
Africa
Congo
22.5
22.5
Senegal
90.0
90.0
Egypt
25.0 - 45.0
25.0 - 45.0
Americas
US Gulf of Mexico1
23.9 - 75.0
23.9 - 75.0
Kitimat
50.0
50.0
Asia
Republic of Korea2
-
50.0
Myanmar3
45.0
40.0 - 45.0
Caribbean
Barbados
60.0
60.0
Trinidad and Tobago4
70.0
65.0 - 70.0
Other joint operations
Angel
20.0
20.0
Bonaparte Basin
21.0
21.0
1. The Group relinquished permits GC 520, GC564, AC 39, AC 127 and AC170 in 2023.
2. The Group relinquished permits 8 and 6-1N in 2023.
3. The Group relinquished permit A-6 in 2023.
4. The Group relinquished permit TTDA-5 in 2023.
The principal activities of the joint operations are exploration, development and production of hydrocarbons. Key estimates and judgements (a) Accounting for interests in other entities Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity. Depending upon the facts and circumstances in each case, Woodside may obtain control, joint control or 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-792": { "value": "Key estimates and judgements (a) Accounting for interests in other entities Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity. Depending upon the facts and circumstances in each case, Woodside may obtain control, joint control or 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-761": { "value": "
E.7 PARENT ENTITY INFORMATION
2023
2022
US$m
US$m
Woodside Energy Group Ltd:
Current assets
236
312
Non-current assets
35,151
34,734
Current liabilities
(743)
(1,530)
Non-current liabilities
(527)
(481)
Net assets
34,117
33,035
Issued and fully paid shares
29,001
29,001
Reserved shares
(49)
(38)
Employee bene\ufb01ts reserve
156
150
Foreign currency translation reserve
296
296
Distributable pro\ufb01ts reserve
4,118
3,541
Retained earnings
595
85
Total shareholders equity
34,117
33,035
Pro\ufb01t of parent entity
5,340
6,665
Total comprehensive income of parent entity
5,340
6,665
Guarantees
For the year ended 31 December 2022, Woodside Energy Group
Ltd and Woodside Energy Ltd were parties to a Deed of Cross
Guarantee. In November 2023, Revocations Deeds were entered
into with respect to the previous Deed of Cross Guarantee
(with the revocation to take effect in May 2024). In December
2023, a new Deed of Cross Guarantee (Deed) was entered into
between Woodside Energy Group Ltd, Woodside Energy Ltd,
Woodside Energy Global Holdings Pty Ltd, Woodside Burrup
Pty Ltd, Woodside Energy Julimar Pty Ltd, Woodside Energy
Scarborough Pty Ltd, Woodside Energy Holdings Pty Ltd,
Woodside Energy Global Pty Ltd, Woodside Energy (Australia)
Pty Ltd, Woodside Energy (Bass Strait) Pty Ltd and Woodside
Energy (North West Shelf) Pty Ltd as disclosed in Note E.8(c).
The effect of the Deed is that each company has guaranteed to
pay any de\ufb01ciency in the event of winding up of any of the other
companies that are party to the Deed under certain provisions of
the Corporations Act 2001.
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-762": { "value": "
E.8 SUBSIDIARIES
(a) Subsidiaries
Country of
Name of entity
incorporation19
Notes
Ultimate Parent Entity
Woodside Energy Group Ltd
Australia
(1,2,3)
Subsidiaries
Company name
Woodside Energy Ltd
Australia
(2,3,4)
Woodside Browse Pty Ltd
Australia
(2,4)
Woodside Burrup Pty Ltd
Australia
(2,3,4)
Burrup Facilities Company Pty Ltd
Australia
(5)
Burrup Train 1 Pty Ltd
Australia
(5)
Country of
Name of entity
incorporation19
Notes
Pluto LNG Pty Ltd
Australia
(5)
Woodside Burrup Train 2 A Pty Ltd
Australia
(2,4)
Woodside Burrup Train 2 B Pty Ltd
Australia
(2,4)
Woodside Energy (LNG Fuels and Power) Pty Ltd
Australia
(2,4)
Woodside Energy (Domestic Gas) Pty Ltd
Australia
(2,4)
Woodside Energy (Algeria) Pty Ltd
Australia
(2,4)
Woodside Energy Australia Asia Holdings Pte Ltd
Singapore
(4)
Woodside Energy Holdings International Pty Ltd
Australia
(2,4)
Woodside Energy International (Canada) Limited
Canada
(4)
Woodside Energy (Canada LNG) Limited
Canada
(4)
Woodside Energy (Canada PTP) Limited
Canada
(4)
KM LNG Operating General Partnership
Canada
(9)
KM LNG Operating Ltd
Canada
(4)
Woodside Energy Holdings Pty Ltd
Australia
(2,3,4)
Woodside Energy Holdings (USA) Inc
United States
(4)
Woodside Energy (USA) Inc
United States
(4)
Gryphon Exploration Company
United States
(4)
PT Woodside Energy Indonesia
Indonesia
(6)
Woodside Energy (Cameroon) SARL
Cameroon
(4)
Woodside Energy (Gabon) Pty Ltd
Australia
(2,4)
Woodside Energy (Indonesia) Pty Ltd
Australia
(2,4)
Woodside Energy (Indonesia II) Pty Ltd
Australia
(2,4)
Woodside Energy (Malaysia) Pty Ltd
Australia
(2,4)
Woodside Energy (Ireland) Pty Ltd
Australia
(2,4)
Woodside Energy (Korea) Pte Ltd
Singapore
(4)
Woodside Energy (Korea II) Pte Ltd
Singapore
(4)
Woodside Energy (Myanmar) Pte Ltd
Singapore
(4)
Woodside Energy (Morocco) Pty Ltd
Australia
(2,4)
Woodside Energy (New Zealand) Limited
New Zealand
(4)
Woodside Energy Holdings (New Zealand) Limited
New Zealand
(4)
Woodside Energy (Peru) Pty Ltd
Australia
(2,4)
Woodside Energy (Senegal) Pty Ltd
Australia
(2,4)
Woodside Energy (Tanzania) Limited
Tanzania
(7)
Woodside Energy Holdings II Pty Ltd
Australia
(2,4)
Woodside Power Pty Ltd
Australia
(2,4)
Woodside Power (Generation) Pty Ltd
Australia
(2,4)
Woodside Energy Holdings (South America) Pty Ltd
Australia
(2,4)
Woodside Energia (Brasil) Apoio Administrativo Ltda
Brazil
(8)
Woodside Energy Holdings (UK) Pty Ltd
Australia
(2,4)
Woodside Energy (UK) Limited
United Kingdom
(4)
Woodside Energy Finance (UK) Limited
United Kingdom
(4)
Woodside Energy (Congo) Limited
United Kingdom
(4)
Woodside Energy (Bulgaria) Limited
United Kingdom
(4)
Woodside Energy Holdings (Senegal) Limited
United Kingdom
(4)
Woodside Energy (Senegal) B.V.
Netherlands
(4)
Woodside Energy (France) SAS
France
(4)
Woodside Energy Iberia S.A.
Spain
(4)
Woodside Energy (N.A.) Limited
United Kingdom
(4)
Woodside Energy Services (Qingdao) Co Ltd
China
(4)
Woodside Energy Julimar Pty Ltd
Australia
(2,3,4)
Woodside Energy (Norway) Pty Ltd
Australia
(2,4)
Woodside Energy Technologies Pty Ltd
Australia
(2,4,14)
Woodside Technology Solutions Pty Ltd
Australia
(2,4)
Woodside Energy Scarborough Pty Ltd
Australia
(2,3,4)
Woodside Energy Carbon Holdings Pty Ltd
Australia
(2,4)
Woodside Energy Carbon (Assets) Pty Ltd
Australia
(2,4)
Woodside Energy Carbon (Services) Pty Ltd
Australia
(2,4)
Woodside Energy (Financial Advisory Services) Pty Ltd
Australia
(2,4)
Woodside Energy Trading Singapore Pte Ltd
Singapore
(4)
WelCap Insurance Pte Ltd
Singapore
(4)
Woodside Energy Shipping Singapore Pte Ltd
Singapore
(4)
Metasource Pty Ltd
Australia
(2,4)
Mermaid Sound Port and Marine Services Pty Ltd
Australia
(2,4)
Woodside Finance Limited
Australia
(2,4)
Woodside Petroleum (Timor Sea 19) Pty Ltd
Australia
(2,4)
Country of
Name of entity
incorporation19
Notes
Woodside Petroleum (Timor Sea 20) Pty Ltd
Australia
(2,4)
Woodside Petroleum Holdings Pty Ltd
Australia
(2,4,15)
Woodside Energy Global Holdings Pty Ltd
Australia
(2,3,4)
Woodside Energy Global Pty Ltd
Australia
(2,3,4)
Perdido Mexico Pipeline Holdings, S.A. de C.V.
Mexico
(10)
Perdido Mexico Pipeline, S. de R.L. de C.V.
Mexico
(10)
Woodside Energy Investments Pty Ltd
Australia
(2,4)
Woodside Energia Brasil Investimentos Ltda.
Brazil
(11)
Woodside Energia Brasil Explora\u00e7\u00e3o e Produ\u00e7\u00e3o Ltda.
Brazil
(11)
Woodside Energy (Great Britain) Limited
United Kingdom
(4)
Woodside Energy (North West Shelf) Pty Ltd
Australia
(2,3,4)
Woodside Energy (Trinidad) Holdings Ltd
Saint Lucia
(4)
Woodside Energy (Trinidad-3A) Ltd
R. of Trinidad
and Tobago
(4)
Woodside Energy USA Operations Inc
United States
(12)
Hamilton Brothers Petroleum Corporation
United States
(4)
Hamilton Oil Company LLC
United States
(4)
Woodside Energy Boliviana Inc.
United States
(4)
Woodside Energy (North America) LLC
United States
(4)
Woodside Energy (Americas) Inc.
United States
(4)
Woodside Energy (GOM) Inc.
United States
(4)
Woodside Energy Hawaii Inc.
United States
(4,16)
Woodside Energy Resources Inc.
United States
(4)
Woodside Energy Holdings (Resources) Inc.
United States
(4)
Woodside Energy USA Services Inc.
United States
(4)
Woodside Energy Marketing Inc.
United States
(4)
Woodside Energy (Deepwater) Inc.
United States
(4,17)
Woodside Energy (USA New Energy Holdings) LLC
United States
(4,18)
Woodside Energy (H2 Oklahoma) LLC
United States
(4,18)
Woodside Energy (Foreign Exploration Holdings) LLC
United States
(4)
Woodside Energy (Trinidad Block 3) Limited
United Kingdom
(4)
Woodside Energy (Trinidad Block 5) Limited
United Kingdom
(4)
Woodside Energy (Trinidad Block 6) Limited
United Kingdom
(4)
Woodside Energy (Trinidad Block 7) Limited
United Kingdom
(4)
Woodside Energy (Trinidad Block 14) Limited
United Kingdom
(4)
Woodside Energy (Trinidad Block 23A) Limited
United Kingdom
(4)
Woodside Energy (Trinidad Block 23B) Limited
United Kingdom
(4)
Woodside Energy (Trinidad Block 28) Limited
United Kingdom
(4)
Woodside Energy (Trinidad Block 29) Limited
United Kingdom
(4)
Woodside Energy (Bimshire) Limited
United Kingdom
(4)
Woodside Energy (South Africa 3B/4B) Limited
United Kingdom
(4)
Woodside Energy (Egypt) Limited
United Kingdom
(4)
Woodside Energy (Carlisle Bay) Limited
United Kingdom
(4)
Woodside Energy (Mexico) Limited
United Kingdom
(4)
Woodside Energ\u00eda Servicios Administrativos, S. de R.L. de C.V.
Mexico
(13)
Woodside Energ\u00eda Servicios de M\u00e9xico, S. de R.L. de C.V.
Mexico
(13)
Woodside Energy (Mexico Holdings) LLC
United States
(4)
Operaciones Conjuntas, S. de R.L. de C.V.
Mexico
(13)
Woodside Energ\u00eda Holdings de M\u00e9xico, S. de R.L. de C.V.
Mexico
(13)
Woodside Petr\u00f3leo Operaciones de M\u00e9xico, S. de R.L. de C.V.
Mexico
(13)
Woodside Energy (Australia) Pty Ltd
Australia
(2,3,4)
Woodside Energy (International Exploration) Pty Ltd
Australia
(2,4)
Woodside Energy (Bass Strait) Pty Ltd
Australia
(2,3,4)
Woodside Energy (Victoria) Pty Ltd
Australia
(2,4)
Woodside Energy Holdings LLC
United States
(2,4,19)
Woodside Energy (Trinidad-2C) Ltd
Canada
(4)
Woodside Energy (Canada) Corporation
Canada
(4)
1. Woodside Energy Group 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
2023.
3. For the year ended 31 December 2022, Woodside Energy Group Ltd and Woodside Energy
Ltd were parties to a Deed of Cross Guarantee. In November 2023, Revocations Deeds were
entered into with respect to the previous Deed of Cross Guarantee (with the revocation to
take effect in May 2024). In December 2023, a new Deed of Cross Guarantee was entered
into between Woodside Energy Group Ltd, Woodside Energy Ltd, Woodside Energy Global
Holdings Pty Ltd, Woodside Burrup Pty Ltd, Woodside Energy Julimar Pty Ltd, Woodside
Energy Scarborough Pty Ltd, Woodside Energy Holdings Pty Ltd, Woodside Energy Global
Pty Ltd, Woodside Energy (Australia) Pty Ltd, Woodside Energy (Bass Strait) Pty Ltd and
Woodside Energy (North West Shelf) Pty Ltd.
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. As at 31 December 2023, 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 2023, 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 2023, 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 2023, 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 2023, 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 2023, 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. As at 31 December 2023, Woodside Energia Brasil
Investimentos Ltda. held >99.99% interest in shares of Woodside Energia Brasil Explora\u00e7\u00e3o e
Produ\u00e7\u00e3o Ltda. Woodside Energy Global Holdings Pty Ltd held the remaining interest.
12. As at 31 December 2023, 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 2023, 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. As at 31 December 2023, Woodside Energy Technologies Pty Ltd held 28.5% of the shares in
Blue Ocean Seismic Services Limited which is accounted for as an investment in associate.
15. As at 31 December 2023, Woodside Energy (North West Shelf) Pty Ltd and Woodside
Petroleum Holdings Pty Ltd each held 16.67% of the shares in International Gas Transportation
Company Limited. This investment has been accounted for as an investment in associate.
16. As at 31 December 2023, Woodside Energy Hawaii Inc held 14.96% of the shares in Iwilei
District Participating Parties LLC which is accounted for as an investment in associate.
17. As at 31 December 2023, Woodside Energy (Deepwater) Inc held 25% of the shares in Caesar
Oil Pipeline Company LLC, 22% of the shares in Cleopatra Gas Gathering Company LLC and
10% of the shares in Marine Well Containment Company LLC. These are accounted for as
investments in associates.
18. Woodside Energy (USA New Energy Holdings) LLC and Woodside Energy (H2 Oklahoma) LLC
were incorporated on 1 August 2023.
19. All subsidiaries are tax residents in their place of incorporation.
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.
(b) Subsidiaries with material non-controlling interests The Group has two Australian subsidiaries with material non-controlling interests (NCI).
Principal place % held
Name of entity of business 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: 2023 2022 2021 US$m US$m US$m Burrup Facilities Company Pty Ltd Current assets 513 567 518 Non-current assets 5,020 5,047 5,038 Current liabilities (58) (68) (71) Non-current liabilities (568) (528) (528) Net assets 4,907 5,018 4,957 Accumulated balance of NCI 491 502 496 Revenue 839 889 858 Pro\ufb01t 400 489 328 Pro\ufb01t allocated to NCI 40 49 33 Dividends paid to NCI (51) (43) (40) Operating 570 601 633 Investing (58) (45) (111) Financing (512) (556) (522) Net increase/(decrease) in cash and cash equivalents - - - Burrup Train 1 Pty Ltd Current assets 453 429 435 Non-current assets 2,806 2,900 2,915 Current liabilities (121) (119) (110) Non-current liabilities (341) (325) (345) Net assets 2,797 2,885 2,895 Accumulated balance of NCI 280 289 290 Revenue 1,393 1,471 1,421 Pro\ufb01t 222 282 200 Pro\ufb01t allocated to NCI 22 28 20 Dividends paid to NCI (31) (29) (27) Operating 321 391 393 Investing (80) (55) (4) Financing (241) (336) (389) Net increase/(decrease) in cash and cash equivalents - -
(c) Deed of Cross Guarantee and Closed Group
For the year ended 31 December 2022, Woodside Energy Group
Ltd and Woodside Energy Ltd were parties to a Deed of Cross
Guarantee and represented a Closed Group. In November 2023,
this Deed of Cross Guarantee was revoked (with the revocation
to take effect in May 2024) and replaced by a new Deed of Cross
Guarantee entered into by the following entities under which
each company guarantees the debts of the other:
\u2022 Woodside Energy Group Ltd
\u2022 Woodside Energy Ltd
\u2022 Woodside Energy Global Holdings Pty Ltd
\u2022 Woodside Burrup Pty Ltd
\u2022 Woodside Energy Julimar Pty Ltd
\u2022 Woodside Energy Scarborough Pty Ltd
\u2022 Woodside Energy Holdings Pty Ltd
\u2022 Woodside Energy Global Pty Ltd
\u2022 Woodside Energy (Australia) Pty Ltd
\u2022 Woodside Energy (Bass Strait) Pty Ltd
\u2022 Woodside Energy (North West Shelf) Pty Ltd
These entities represent a Closed Group for the purposes of the
Instrument for the year ended 31 December 2023.
For the year ended 31 December 2023, the above entities with
the exception of Woodside Energy Group Ltd, Woodside Energy
Ltd and Woodside Energy Global Holdings Pty Ltd, have relied
on the relief from the Corporations Act 2001 requirements for the
preparation, audit and publication of accounts, pursuant to ASIC
Corporations (Wholly-owned Companies) Instrument 2016/785
and the Deed of Cross Guarantee.
The consolidated income statement and consolidated statement
of \ufb01nancial position of the members of the Closed Group for the
year ended 31 December 2023 are set out below:
2023
US$m
Closed Group Consolidated Income Statement
and Statement of Retained Earnings
Pro\ufb01t before tax
3,915
Tax expense
(1,390)
Pro\ufb01t after tax
2,525
Retained earnings at the beginning of the \ufb01nancial year
2,177
Transfer of retained earnings to distributable pro\ufb01ts reserve
(4,830)
Retained earnings at the end of the \ufb01nancial year
(128)
Closed Group Consolidated Statement of Financial Position
Current assets
Cash and cash equivalents
375
Receivables
3,325
Inventories
308
Other \ufb01nancial assets
186
Assets held for sale
826
Tax receivable
57
Other assets
12
Total current assets
5,089
Non-current assets
Receivables
283
Other \ufb01nancial assets
30,122
Exploration and evaluation assets
63
Oil and gas properties
18,382
Deferred tax assets
1,037
Lease assets
488
Goodwill
3,185
Other assets
161
Total non-current assets
53,721
Total assets
58,810
Current liabilities
Payables
2,687
Other \ufb01nancial liabilities
94
Liabilities directly associated with assets held for sale
94
Provisions
1,237
Tax payable
893
Lease liabilities
108
Other liabilities
169
Total current liabilities
5,282
Non-current liabilities
Payables
12,977
Deferred tax liabilities
395
Other \ufb01nancial liabilities
42
Provisions
4,454
Lease liabilities
559
Other liabilities
648
Total non-current liabilities
19,075
Total liabilities
24,357
Net assets
34,453
Equity
Issued and fully paid shares
29,001
Reserved shares
(49)
Other reserves
5,629
Retained earnings
(128)
Total equity 34,453
For the year ended 31 December 2023, results for Woodside
Energy Group Ltd and Woodside Energy Ltd (which comprised
the Closed Group under the previous Deed of Cross Guarantee
that is currently in the process of being revoked) have been
included within the new Closed Group as they are parties to the
new Deed of Cross Guarantee. The consolidated income statement
and consolidated statement of \ufb01nancial position of the members
of the Closed Group under the previous Deed of Cross Guarantee
for the year ended 31 December 2022 are set out below:
2022
US$m
Closed Group Consolidated Income Statement
and Statement of Retained Earnings
Pro\ufb01t before tax
6,586
Tax expense
(314)
Pro\ufb01t after tax
6,272
Retained earnings at the beginning of the \ufb01nancial year
1,660
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
Closed Group Consolidated Statement of Financial Position
Current assets
Cash and cash equivalents
116
Receivables
675
Inventories
56
Other \ufb01nancial assets
653
Other assets
21
Total current assets
1,521
Non-current assets
Receivables
2,171
Other \ufb01nancial assets
57,844
Exploration and evaluation assets
28
Oil and gas properties
2,424
Deferred tax assets
421
Lease assets
315
Other assets
67
Total non-current assets
63,270
Total assets
64,791
Current liabilities
Payables
483
Other \ufb01nancial liabilities
675
Provisions
328
Tax payable
1,556
Lease liabilities
36
Other liabilities
38
Total current liabilities 3,116
Non-current liabilities
Payables
25,524
Other \ufb01nancial liabilities
68
Provisions
1,121
Lease liabilities
325
Other liabilities
11
Total non-current liabilities
27,049
Total liabilities 30,165
Net assets
34,626
Equity
Issued and fully paid shares
29,001
Reserved shares
(38)
Other reserves
4,301
Retained earnings
1,362
Total equity
34,626
", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-763": { "value": "(b) New standards and interpretations New and amended accounting standards adopted A number of amended standards became applicable for the current reporting period. The Group did not make any signi\ufb01cant changes to its accounting policies and did not make retrospective adjustments as a result of adopting these amended standards. These amendments did not materially impact the accounting policies or amounts disclosed in the year end \ufb01nancial statements of the Group. New standards and interpretations not yet adopted Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for the 31 December 2023 reporting period and have not been early adopted by the Group. These standards, amendments or interpretations are not expected to have a material impact to the Group in the current or future reporting periods and on foreseeable future transactions with the exception of the amendments to AASB 112/IAS 12 Income Taxes where the impact is under assessment. Pillar Two reforms In December 2021, the Organisation for Economic Co-operation and Development (OECD) published its Pillar Two model rules. The Pillar Two model rules: \u2022 aim to ensure that large multinational groups pay a minimum amount of tax on income arising in each jurisdiction in which they operate; and \u2022 would achieve a minimum effective tax rate in each jurisdiction of 15% from the reporting period commencing 1 January 2024. For the year ended 31 December 2023, the Group paid $2,916 million of income tax and PRRT and reported a global effective income tax rate of 27.5%. The Group\u2019s impact assessment will depend on the extent to which the Pillar Two legislation has been enacted in the various jurisdictions the Group operates in and when it comes into effect. The Group will continue to monitor and assess the expected impact of the Pillar Two reform.", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-793": { "value": "New and amended accounting standards adopted A number of amended standards became applicable for the current reporting period. The Group did not make any signi\ufb01cant changes to its accounting policies and did not make retrospective adjustments as a result of adopting these amended standards. These amendments did not materially impact the accounting policies or amounts disclosed in the year end \ufb01nancial statements of the Group. ", "dimensions": { "concept": "ifrs-full:DescriptionOfInitialApplicationOfStandardsOrInterpretations", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-794": { "value": "New standards and interpretations not yet adopted Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for the 31 December 2023 reporting period and have not been early adopted by the Group. These standards, amendments or interpretations are not expected to have a material impact to the Group in the current or future reporting periods and on foreseeable future transactions with the exception of the amendments to AASB 112/IAS 12 Income Taxes where the impact is under assessment. ", "dimensions": { "concept": "ifrs-full:DescriptionOfExpectedImpactOfInitialApplicationOfNewStandardsOrInterpretations", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-5": { "value": "Following the approval of Woodside shareholders at Woodside\u2019s Annual General Meeting on 19 May 2022, Woodside changed its name from \u2018Woodside Petroleum Ltd.\u2019 to \u2018Woodside Energy Group Ltd\u2019 effective 20 May 2022.", "dimensions": { "concept": "ifrs-full:ExplanationOfChangeInNameOfReportingEntityOrOtherMeansOfIdentificationFromEndOfPrecedingReportingPeriod", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-6": { "value": "Mia Yellagonga, 11 Mount Street, Perth, Western Australia 6000, Australia, telephone +61 8 9348 4000", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:2549005ZC5RXAOO7FH41", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } } } }