Woodside Energy (WDS) details 2025 reserves, production and risk outlook
Filing Impact
Filing Sentiment
Form Type
20-F
Woodside Energy Group Ltd filed its annual Form 20‑F for the year ended 31 December 2025, outlining its global oil and gas operations, risk framework and reserves position. The company reported proved reserves of 1,882.1 MMboe, after producing 211.4 MMboe in 2025, including fuel used in operations.
Proved undeveloped reserves were 1,238.5 MMboe, with about 88% scheduled for development within five years of initial disclosure, and significant projects in Australia, the Gulf of Mexico, Senegal, Mexico and Trinidad and Tobago. Woodside details capitalised oil and gas assets of over $79.7 billion before depreciation and explains its use of non‑IFRS measures like EBITDA and free cash flow.
The filing devotes substantial space to risk factors, covering health and safety, environmental and climate transition risks, operational and joint‑venture risks, growth project execution (including Louisiana LNG and new energy), social licence, people and culture, financial management, market volatility, and cybersecurity. It also provides SEC‑compliant reserve reconciliations, capital and development spending by region, and governance around reserves estimation.
Positive
- None.
Negative
- None.
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 20-F
(Mark One)
REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31 , 2025
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR
SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Date of event requiring this shell company report____________
Commission File No.: 001-41404
(Exact name of Registrant as specified in its charter)
N/A
(Translation of Registrant’s name into English)
(Jurisdiction of incorporation or organization)
Woodside Energy Group Ltd
(Address of principal executive offices)
Woodside Energy Group Ltd
|Mia Yellagonga , 11 Mount Street
Tel: +61 8 9348 4000
+61 477 397 961
E-mail: investor@woodside.com
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
__________________________
Securities registered or to be registered pursuant to Section 12(b) of the Act.
Title of each class | Trading symbol | Name of each exchange on which registered | ||
* Not for trading , but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
(Title of Class)
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
(Title of Class)
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
Ordinary Shares: 1,901,100,143
__________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes o No
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934. o Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12
months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§
232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). x Yes o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large
accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
x | Accelerated filer | o | Non-accelerated filer | o | Emerging growth company |
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected
not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the
Exchange Act. o
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting
Standards Codification after April 5, 2012.
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Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal
control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 762(b)) by the registered public accounting firm that prepared
or issued its audit report. x
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the
filing reflect the correction of an error to previously issued financial statements. o
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received
by any of the registrant’s executive officers during the relevant recovery period pursuant to§240.10D-1(b). o
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP o | by the International Accounting Standards Board x | Other o |
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to
follow.
o Item 17 o Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No
(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. o Yes o No
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TABLE OF CONTENTS
INTRODUCTION | 3 | ||
FORWARD-LOOKING STATEMENTS, INDUSTRY AND MARKET DATA AND CLIMATE STRATEGY AND EMISSIONS DATA | 4-5 | ||
USE AND RECONCILIATION OF NON-IFRS FINANCIAL MEASURES | 6 | ||
PART I | 7 | ||
ITEM 1. | IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS | 7 | |
A. | Directors and Senior Management | 7 | |
B. | Advisers | 7 | |
C. | Auditors | 7 | |
ITEM 2. | OFFER STATISTICS AND EXPECTED TIMETABLE | 7 | |
A. | Offer Statistics | 7 | |
B. | Method and Expected Timetable | 7 | |
ITEM 3. | KEY INFORMATION | 7 | |
A. | [Reserved] | 7 | |
B. | Capitalization and Indebtedness | 7 | |
C. | Reason for the Offer and Use of Proceeds | 7 | |
D. | Risk Factors | 7 | |
ITEM 4. | INFORMATION ON THE COMPANY | 15 | |
A. | History and Development of the Company | 15 | |
B. | Business Overview | 16 | |
C. | Organizational Structure | 29 | |
D. | Property, Plant and Equipment | 29 | |
ITEM 4A. | UNRESOLVED STAFF COMMENTS | 29 | |
ITEM 5. | OPERATING AND FINANCIAL REVIEW AND PROSPECTS | 29 | |
A. | Operating Results | 29 | |
B. | Liquidity and capital resources | 35 | |
C. | Research and development, Patents and Licences, etc. | 35 | |
D. | Trend information | 35 | |
E. | Critical Accounting Estimates | 36 | |
ITEM 6. | DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES | 36 | |
A. | Directors and Senior Management | 36 | |
B. | Compensation | 36 | |
C. | Board Practices | 36 | |
D. | Employees | 36 | |
E. | Share Ownership | 36 | |
F. | Disclosure of a registrant’s action to recover erroneously awarded compensation. | 36 | |
ITEM 7. | MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS | 36 | |
A. | Major shareholders | 36 | |
B. | Related Party Transactions | 36 | |
C. | Interests of Experts and Counsel | 36 | |
ITEM 8. | FINANCIAL INFORMATION | 36 | |
A. | Consolidated Statements and Other Financial Information | 37 | |
B. | Significant Changes | 37 | |
ITEM 9. | THE OFFER AND LISTING | 37 | |
A. | Offer and Listing Details | 37 | |
B. | Plan of Distribution | 37 | |
C. | Markets | 37 | |
D. | Selling Shareholders | 37 | |
E. | Dilution | 37 | |
F. | Expenses of the Issue | 37 | |
ITEM 10. | ADDITIONAL INFORMATION | 37 | |
A. | Share Capital | 37 | |
B. | Memorandum and Articles of Association | 37 | |
C. | Material Contracts | 37 | |
D. | Exchange controls | 37 | |
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E. | Taxation | 38 | |
F. | Dividends and Paying Agents | 41 | |
G. | Statement by Experts | 41 | |
H. | Documents on Display | 41 | |
I. | Subsidiary Information | 41 | |
J. | Annual Report to Security Holders. | 41 | |
ITEM 11. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 41 | |
ITEM 12. | DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES | 41 | |
A. | Debt Securities | 41 | |
B. | Warrants and Rights | 42 | |
C. | Other Securities | 42 | |
D. | American Depositary Shares | 42 | |
PART II | |||
ITEM 13. | DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES | 43 | |
ITEM 14. | MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS | 43 | |
ITEM 15. | CONTROLS AND PROCEDURES | 43 | |
ITEM 16. | [RESERVED] | 43 | |
ITEM 16A. | AUDIT COMMITTEE FINANCIAL EXPERT | 43 | |
ITEM 16B. | CODE OF ETHICS | 43 | |
ITEM 16C. | PRINCIPAL ACCOUNTANT FEES AND SERVICES | 44 | |
ITEM 16D. | EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES | 44 | |
ITEM 16E. | PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS | 44 | |
ITEM 16F. | CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT | 44 | |
ITEM 16G. | CORPORATE GOVERNANCE | 44 | |
ITEM 16H. | MINE SAFETY DISCLOSURE | 44 | |
ITEM 16I. | DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS | 44 | |
ITEM 16J. | INSIDER TRADING POLICIES | 44 | |
ITEM 16K. | CYBERSECURITY DISCLOSURE. | 44 | |
PART III | |||
ITEM 17. | FINANCIAL STATEMENTS | 46 | |
ITEM 18. | FINANCIAL STATEMENTS | 46 | |
ITEM 19. | EXHIBITS | ||
CONSOLIDATED FINANCIAL STATEMENTS | F-1 | ||
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INTRODUCTION
Unless otherwise indicated, all references herein to “we”, “our”, the “company”, the “group” or “Woodside” are references to Woodside
Energy Group Ltd and its consolidated subsidiaries.
This document is our annual report on Form 20-F for the year ended 31 December 2025 (“2025 Form 20-F”). Reference is made to our
2025 Annual Report, portions of which are attached hereto as Exhibit 15.2 (the “2025 Annual Report”). Only (i) the information
included in this 2025 Form 20-F, (ii) the information in the 2025 Annual Report that is incorporated by reference in this 2025 Form 20-F
(excluding any information that is identified as intentionally omitted in Exhibit 15.2 hereto and any page references incorporated in the
incorporated material unless specifically noted otherwise), and (iii) the other exhibits to this 2025 Form 20-F shall be deemed to be filed
with the Securities and Exchange Commission (“SEC”) for any purpose, including incorporation by reference into the Registration
Statement on Form F-3 filed on 29 February 2024 (File No. 333-277499), Form S-8 filed on 1 March 2024 (File No. 333-277568), Form
S-8 filed on 1 September 2023 (File No. 333-274296), Form S-8 filed on 28 February 2023 (File No. 333-270076), Form S-8 filed on 15
September 2022 (File No. 333-267432) and Form S-8 filed on 15 June 2022 (File No. 333-265606) and any other documents filed by us
pursuant to the Securities Act of 1933, as amended, which purport to incorporate by reference the 2025 Form 20-F. The full 2025 Annual
Report, inclusive of our sustainability report and other information omitted from, or otherwise not incorporated by reference into, this
2025 Form 20-F, has been furnished to the SEC on a Report on Form 6-K.
Unless otherwise indicated, references to major headings include all information under such major headings, including subheadings,
unless such reference is a reference to a subheading, in which case such reference includes only the information contained under such
subheading. Any other information shall not be deemed to be so incorporated by reference.
In addition to the information set out below, the information set forth under the heading “Glossary, units of measure and conversion
factors” in Section 6.7 on pages 290-296 of the 2025 Annual Report is incorporated herein by reference.
The 2025 Form 20-F contains references to our website (https://www.woodside.com). Information on our website or any other website
referenced in the 2025 Form 20-F is not incorporated into this document and should not be considered part of this document. All
references to websites in this 2025 Form 20-F are intended to be inactive textual references for information only and any information
contained in or accessible through any such website does not form a part of this 2025 Form 20-F.
The SEC maintains an Internet website that contains reports and other information regarding issuers that file electronically with the SEC.
Our filings with the SEC are available to the public through the SEC’s website at http://www.sec.gov.
In this report, references to a year are to the calendar and financial year ended 31 December 2025 unless otherwise stated. All references
to dollars, cents or $ in this report are references to US currency and are stated in Woodside share, unless otherwise stated.
Unless otherwise stated, all Woodside results set out in this 2025 Form 20-F include the performance of the interests acquired as part of
the merger with BHP’s petroleum business from 1 June 2022.
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FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements. These statements may relate to Woodside’s business, goals targets, aspirations, plans,
expectations, market conditions, results of operations and financial condition, including, but not limited to, statements regarding the
timing, completion and outcomes of transactions, construction costs and capital expenditures, supply and demand for Woodside’s
products, development, completion and execution of Woodside’s projects, the expected benefits, cash flows and rates of return or other
future results of investments, strategies and transactions, the payment of future dividends and the amount thereof, future results of
projects, operating activities and new energy products, expectations and plans for renewables production capacity and investments in,
and development of, renewables projects, expectations and guidance with respect to production, production costs and other costs, capital
expenditure, abandonment expenditure, exploration expenditure and gas hub exposure, trends in commodity prices and currency
exchange rates, adoption and implementation of new technologies and expectations regarding the achievement of Woodside’s Scope 1
and 2 greenhouse gas emissions targets and Scope 3 investment and emissions abatement targets (in each case on a net equity or gross
equity basis as specified) and other climate and sustainability goals. All statements, other than statements of historical or present facts,
are forward-looking statements and generally may be identified by the use of forward-looking words such as ‘aim’, ‘anticipate’, ‘aspire’,
‘believe’, ‘enable’, ‘estimate’, ‘expect’, ‘forecast’, ‘foresee’, ‘guidance’, ‘intend’, ‘likely’, ‘may’, ‘objective’, ‘outlook’, ‘pathway’
‘plan’, ‘position’, ‘potential’, ‘project’, ‘schedule’, ‘seek’, ‘should’, ‘strategy’, ‘strive’, ‘target’, ‘will’, and other similar words or
expressions. Forward-looking statements in this report are not guidance, forecasts, guarantees or predictions of future events or
performance, but are in the nature of future expectations that are based on management’s current expectations.
Those statements and any assumptions on which they are based are subject to change without notice and are subject to inherent known
and unknown risks, uncertainties, contingencies and other factors, many of which are beyond the control of Woodside, its related bodies
corporate and their respective officers, directors, employees, advisers or representatives.
Important factors that could cause actual results to differ materially from those in the forward-looking statements and the assumptions on
which they are based include, but are not limited to, fluctuations in commodity prices, actual demand for Woodside products, currency
fluctuations, geotechnical factors, drilling and production results, gas commercialisation, development progress, operating results,
engineering estimates, reserve and resource estimates, loss of market, industry competition, pace of technology developments,
sustainability and environmental risks, climate related transition and physical risks, safety and personnel risks, changes in accounting
standards, economic and financial markets conditions in various countries and regions the actions of third parties, project delay or
advancement, regulatory approvals, political risks and the impact of armed conflict and political instability (such as the ongoing conflicts
in Ukraine and in the Middle East) on economic activity and oil and gas supply and demand, cost estimates, legislative, fiscal and
regulatory developments, including those related to the imposition of tariffs and other trade restrictions, and the effect of future
regulatory or legislative actions on Woodside or the industries in which it operates, including potential changes to tax laws, the impact of
general economic conditions, inflationary conditions, prevailing exchange rates and interest rates and conditions in financial markets,
and risks associated with acquisitions, mergers and joint ventures, including difficulties integrating or separating businesses, uncertainty
associated with financial projections, restructuring, increased costs and adverse tax consequences, and uncertainties and liabilities
associated with acquired and divested properties and businesses.
A more detailed summary of the key risks relating to Woodside and its business can be found in Item 3.D. Risk Factors. You should
review and have regard to these risks when considering the information contained in this report. If any of the assumptions on which a
forward-looking statement is based were to change or be found to be incorrect, this would likely cause outcomes to differ from the
statements made in this report.
Investors are strongly cautioned not to place undue reliance on any forward-looking statements. Actual results or performance may vary
materially from those expressed in, or implied by, any forward-looking statements. None of Woodside nor any of its related bodies
corporate, nor any of their respective officers, directors, employees, advisers or representatives, nor any person named in this report or
involved in the preparation of the information in this report, makes any representation, assurance, guarantee or warranty (either express
or implied) as to the accuracy or likelihood of fulfilment of any forward-looking statement, or any outcomes, events or results expressed
or implied in any forward-looking statement in this report. All forward-looking statements contained in this report reflect Woodside’s
views held as at the date of this report and, except as required by applicable law, neither Woodside, its related bodies corporate, nor any
of their respective officers, directors, employees, advisers or representatives nor any person named in this report or involved in the
preparation of the information in this report intends to, undertakes to, or assumes any obligation to, provide any additional information or
update or revise any of these statements after the date of this report, either to make them conform to actual results or as a result of new
information, future events or results, changes in Woodside’s expectations or otherwise.
Past performance (including historical financial and operational information) is given for illustrative purposes only. It is not necessarily a
reliable indicator of future performance, including future security prices.
INDUSTRY AND MARKET DATA
This report contains industry, market and competitive position data that are based on industry publications, third-party studies, and
Woodside’s internal estimates and research. These industry publications and third-party studies generally state that the information they
contain has been obtained from sources believed to be reliable, although they do not guarantee the accuracy or completeness of such
information. While Woodside believes that each of these publications and third-party studies is reliable and has been prepared by a
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reputable source, Woodside has not independently verified the market and industry data obtained from these third-party sources and
cannot guarantee the accuracy or completeness of such data. There may be differences in the way third parties calculate or report
greenhouse gas emissions compared to Woodside, which means third party data may not be comparable to Woodside’s data.
Accordingly, undue reliance should not be placed on any of the industry, market and competitive position data contained in this report.
Forecasts and other forward-looking information obtained from these sources are subject to the same qualifications and uncertainties as
the other forward-looking statements contained in this report and may differ among third-party sources. These forecasts and forward-
looking information are subject to uncertainty and risk due to a variety of factors, including those described in the sections captioned
“Risk Factors” and “Forward-Looking Statements” elsewhere in this report. These and other factors could cause results to differ
materially from those expressed in Woodside’s forecasts or estimates or those of independent third parties. While Woodside believes its
internal research is reliable and its selection of industry publications and third-party studies and the description of its market and industry
are appropriate, neither such research nor these descriptions have been verified by any independent source.
CLIMATE STRATEGY AND
EMISSIONS DATA
All greenhouse gas emissions data in, or incorporated by reference into, this report are estimates, due to the inherent uncertainty and
limitations in measuring or quantifying greenhouse gas emissions. Methodologies for measuring or quantifying greenhouse gas
emissions may evolve as market practices continue to develop and data quality and quantity continue to improve.
Woodside “greenhouse gas” or “emissions” information reported are Scope 1 greenhouse gas emissions, Scope 2 greenhouse gas
emissions, and/or Scope 3 greenhouse gas emissions, each on a net equity or gross equity basis as specified.
Actual performance against Woodside’s targets (including items that are described as a target) and aspirations or goals may be affected
by various risks associated with the Woodside business, the uncertainty as to how the global energy transition to a lower carbon
economy will evolve, and physical risks associated with climate change, many of which are beyond Woodside’s control.
The glossary and footnotes included, or incorporated by reference, into this 2025 Form 20-F provide further clarification of “lower
carbon” where applicable. Woodside uses the term “lower-carbon services” to describe technologies, such as carbon capture utilization
and storage, or “CCUS”, or offsets, that may be capable of reducing the net greenhouse gas emissions of our customers.
Additionally, the developments of environmental and climate change-related issues discussed in this report or the information
incorporated by reference herein are based on various frameworks and the interests of various stakeholders that are subject to evolve
independently of our will. Moreover, materiality, as used in the context of climate and sustainability-related disclosures, may differ from
the materiality standards applied by other reporting regimes, including as defined for SEC reporting purposes. Our disclosures on such
issues, including climate-related disclosures that are identified as material for purposes of sustainability in this report, may include
information that is not necessarily “material” under US securities laws for SEC reporting purposes or under applicable securities law.
Scope 3 targets are subject to commercial arrangements, commercial feasibility, regulatory and joint venture approvals, and third party
activities (which may or may not proceed). Individual investment decisions are subject to Woodside’s investment targets. Such targets
are not guidance. Scope 3 targets potentially include both organic and inorganic investment.
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USE AND RECONCILIATION OF NON-
IFRS FINANCIAL MEASURES
Woodside’s financial statements are prepared in accordance with the Australian Accounting Standards and other authoritative
pronouncements of the Australian Accounting Standards Board (AASB) and comply with the International Financial Reporting
Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
Certain parts of this report contain financial measures that are not defined in, and have not been prepared in accordance with, IFRS and
are not recognised measures of financial performance or liquidity under IFRS. In addition to the financial information contained in this
report presented in accordance with IFRS, certain “non-GAAP financial measures” (as defined in Item 10(e) of Regulation S-K under the
US Securities Act of 1933, as amended) have been included in this report. These measures include: EBIT, EBITDA, EBITDA excluding
impairment, Gearing, Underlying NPAT, Net debt, Free cash flow, Operating cash flow, Cash margin, Capital expenditure, Exploration
expenditure, Net tangible assets, and Net tangible asset per ordinary security.
For further details and a reconciliation of these measures to the most directly comparable IFRS measure presented in Woodside’s
financial statements, refer to the information set forth under the heading “Alternative performance measures” in Section 6.6 on pages
284-289 of the 2025 Annual Report is incorporated herein by reference. These non-IFRS financial measures are defined in under the
heading “Glossary, units of measure and conversion factors” in Section 6.7 on pages 290-296 of the 2025 Annual Report.
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PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
A.Directors and Senior Management
Not applicable.
B.Advisers
Not applicable.
C.Auditors
Not applicable.
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
A.Offer statistics
Not applicable.
B.Method and Expected Timetable
Not applicable.
ITEM 3. KEY INFORMATION
A.[Reserved]
B.Capitalization and Indebtedness
Not applicable.
C.Reason for the Offer and Use of Proceeds
Not applicable.
D.Risk Factors
Woodside recognises that taking risk is necessary for our business and that effective risk management is vital to meeting our
objectives. We are committed to managing risks in a proactive, informed and effective manner as a source of competitive
advantage.
Our approach is intended to support risk-informed decision making and enable us to pursue the right opportunities while taking
into account potential adverse impacts. The objective of our risk management framework is to foster a positive, risk-aware culture
by integrating risk management and governance activities into our ways of working. Our risk process delivers a consolidated view
of risks across the company to understand our full risk exposure and prioritise risk management and governance.
Woodside’s Risk Appetite Statement is a key element of our risk framework. It sets out the Board’s appetite to take risk in pursuit
of our strategic objectives. It provides guidance to the executive and senior management on the type and amount of risk that is
acceptable when making decisions, consistent with other company policies.
Woodside’s risk management process is designed to identify, assess and control risks across the organisation. Company-wide risk
management activities occur throughout the year and are reported to the Audit & Risk Committee and Executive Leadership Team
twice annually, in addition to deep dives on particular risk areas that occur throughout the year.
We categorise risks in three different ways:
1. Strategic risks
These are risks that could materially affect our ability to achieve our mid- and long-term strategic objectives. Woodside’s
disciplined approach to risk management is designed to support the delivery of our strategy. Management and the Board consider
a range of risks and opportunities that have the potential to deliver or erode value for our organisation over medium- and longer-
term horizons. Our governance process is designed to factor these risks into our strategic decision-making. We regularly review
our portfolio and adapt to changing conditions and emerging risks to seek to maintain our resilience and competitiveness.
Examples of strategic risks include acquisitions and divestments, and the competitiveness of our portfolio mix under a range
of scenarios.
2. Emerging risks
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These risks capture external threats or factors that have a high degree of uncertainty, are not readily controlled by Woodside
and may be unpredictable or rapidly changing. They have the potential to materially affect the achievement of our
strategic objectives.
We monitor the external environment to seek to identify emerging risks. Our risk management framework has been designed to
allow us to respond to new evolving threats.
Examples of emerging risks include a shifting geopolitical landscape or rapid technological change.
3. Current risks
These quantifiable risks could affect Woodside’s ability to deliver our objectives and require appropriate control and management.
If these risks were to materialise, they could have potential impacts across health and safety, environment, community and culture,
reputation and brand, legal and compliance, and financial performance. These impacts may lead to a decline in shareholder value,
loss of market share and reductions in asset values. They could also lead to operational delays or stoppages, loss of revenue,
increased costs, constraints on our ability to execute and complete transactions or reduced capacity to fund capital projects.
Furthermore, impacts may cause delayed or suspended regulatory approvals, expose the company to legal liabilities and adversely
affect Woodside’s reputation, social licence to operate and delivery of our strategy.
Examples of current risks include operational integrity risks such as loss of process containment, structural integrity failure or loss
of license to operate.
Woodside maintains a comprehensive risk register, designed to enable management of risks and prioritisation of mitigation
actions. Regular reporting to the executive leadership and the Audit & Risk Committee supports effective governance.
Woodside’s risk management process
Our risk management process, informed by the International Standard ISO31000, is designed to provide a consistent and
integrated approach to identifying, assessing, managing, and reporting risks that have the potential to affect the achievement of
Woodside’s objectives.
The Audit & Risk Committee plays a crucial role in enabling the Board to meet its oversight responsibility in relation to
Woodside’s risk management. The Sustainability Committee also focuses on sustainability-related risk management.
For more information on Woodside’s risk management process, refer to our Risk Management Policy, available on our website at
woodside.com.
Overview of our Risk Factors
HEALTH & SAFETY
Our business is subject to risks related to safety or major hazard events associated with our activities or facilities.
These may include unanticipated or unforeseeable adverse events that affect our ability to respond, manage and recover
from such events.
How is this factor relevant to Woodside?
At Woodside, we believe that our ability to operate safely is critical to our competitiveness. Failure to continue to do so could
result in potential impacts on our people and operations, as well as reputational damage with customers, employees, commercial
partners and other stakeholders, and sustained production interruptions leading to an inability to meet production forecasts.
Examples of how this factor may affect Woodside
•A loss of containment event or other operational incident on or related to our property or operations could occur, which
could have significant impacts including to human health and safety, from personal health, safety and wellbeing through
to fatalities. This could result in financial, legal and reputational impacts.
•Natural disasters and severe weather events, such as cyclones, floods, freezes and heatwaves, droughts, earthquakes or
other acts of nature, social unrest, pandemic diseases, and criminal actions by external parties could result in injuries, loss
of life, disruption of our operations or the loss or suspension of permits or other approvals. Coastal operations may be
particularly susceptible to severe weather event impacts.
•Woodside’s operations are subject to numerous laws and regulations relating to public and occupational health and safety.
The requirements of these laws and regulations are becoming increasingly complex, stringent and expensive to implement
and comply with.
ENVIRONMENT
Risks associated with major environmental incidents in connection with our activities or facilities including potential incidents
that could result in significant loss of hydrocarbon. We are also subject to risks associated with biodiversity and failure to deliver
emission reductions in a timely manner, consistent with regulatory and stakeholder expectations.
How is this factor relevant to Woodside?
Woodside’s operations are subject to environmental impacts or risks that can arise as a result of the nature of our operations.
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Examples of how this factor may impact Woodside
•An incident may result in a significant loss of hydrocarbon to the environment including when caused by factors that are
beyond Woodside’s direct control. These factors include natural disasters, severe weather events, such as cyclones,
floods, freezes and heatwaves, droughts, earthquakes or other acts of nature, pandemics, loss of well control, fires,
explosions, pipeline ruptures, chemical releases, hydrocarbon releases including maritime releases, releases into navigable
waters and groundwater contamination, material or mechanical failure, power outages, industrial accidents, physical or
cyber attacks, abnormally pressured or structured formations and other events that cause operations to cease or be
curtailed. This may negatively affect Woodside’s businesses and the communities in which we operate.
•Woodside’s operations are subject to numerous laws and regulations relating to environmental protection. The
requirements of these laws and regulations are becoming increasingly complex, stringent and expensive to implement.
Costs of compliance with these laws and regulations are significant and can be unpredictable.
•Applicable laws and regulations may obligate Woodside to adjust our various operational practices, plans or strategies,
which in turn could cause uncertainty and delay, materially adversely affect our business, financial condition or results of
operations. We may also be required to maintain financial assurance through bonds or insurance.
•Third-party insurance may not provide adequate coverage or Woodside may be self-insured with respect to the related
losses.
CLIMATE
The global response to climate change is changing the way the world produces and consumes energy. Responses to climate
change may create a systemic risk to the global economy and present multiple risks to Woodside, including, a decline in the
demand or pricing of our products, or commercial risk from our lower carbon products and services. Legislative and regulatory
programs to reduce emissions have been introduced, or are pending, in response to political, social and industry attention on
climate change. Climate change may also create physical risks, such as increased frequency and severity of storms, wildfires,
floods and other climatic events, as well as chronic shifts in temperature and precipitation patterns.
How is this factor relevant to Woodside?
Woodside’s risks associated with climate change and the transition to a lower-carbon economy include possible impacts to
demand (and pricing) for oil, gas and their substitutes, as well as to reputation. Differing global responses to climate change,
driven by divergent regulatory and political positions create uncertainty and make long-term planning and investment decisions
increasingly challenging for the energy industry.
Legislative and regulatory programs to reduce emissions present strategic and financial threats to Woodside including increased
compliance costs within our operations, potential approval delays, asset impairment of high-emission assets, and reputational risk
through investor and shareholder activism.
An increase in nature, frequency and magnitude of physical risks may result in production interruptions leading to an inability to
meet production forecasts.
Examples of how this factor may affect Woodside
•Climate change is expected to lead to an increase in the frequency and severity of extreme weather events with the
potential to impact assets, suppliers, customers or communities.
•Some of Woodside’s stakeholders hold differing opinions about how to address climate change and the energy transition.
This may impact Woodside’s reputation.
•Groups and individuals who are opposed to Woodside’s activities may initiate proceedings or file challenges against
Woodside.
•Countries may pursue policies that lead to lower levels of gas demand over time compared to the external scenarios that
inform Woodside’s analysis.
•Woodside’s producing facilities are subject to environmental regulatory limits including for Scope 1 & 2 greenhouse gas
emissions, which vary across regions and have the potential to increase.
PRODUCTION AND OPERATIONS
We manage a range of risks within our operations, including commercial risks relating to third-party relationships such as joint
venture participants, contract counterparties and our supply chain. Woodside is subject to extensive governmental oversight and
regulation in the jurisdictions in which we operate, and such regulations may change in ways that adversely affect our business,
results of operations and financial condition. In addition, we are required to comply with securities regulations in Australia, the
United States and elsewhere.
We manage the estimation of proved oil and gas reserves by using judgement and the application of complex rules.
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How is this factor relevant to Woodside?
Our operating assets are subject to a range of risks associated with process safety incidents, breaches of cybersecurity, extreme
weather events and supply chain disruptions, potentially impacting our production, operations, financial performance and
reputation. Joint ventures may limit our control over, and our ability to effectively manage risks associated with our major
projects. For projects where we are not the operator, we may be unable to directly control the behaviour, performance and cost of
operations.
Our operations are subject to operating and capital expenditures to comply with various national and local laws, regulations and
approvals. More stringent standards for greenhouse gas emissions could lead to operational restrictions, increased compliance
costs and changes in product pricing and demand. Woodside faces closure and decommissioning risks that require proactive
management to safeguard financial stability and reputation. Key challenges include escalating abandonment costs, regulatory
compliance obligations, health, safety and environmental hazards, and potential reputational impacts if closure activities are
poorly executed. These risks are compounded by operational complexities and supply chain constraints, which have the potential
to result in schedule delays and cost overruns.
Examples of how this factor may affect Woodside
•A loss of containment event or other operational incident on or related to our property or operations could occur, which
could have significant impacts including to human health and safety, from personal health, safety and wellbeing through
to fatalities. This could result in financial, legal and reputational impacts.
•Our JVP may have the ability to exercise veto rights to block certain key decisions or actions that we believe are in our or
the joint venture’s best interests or approve those matters without our support.
•Our JVP and contractual counterparties may not be able to meet their financial or other obligations and their actions could
result in legal liability and financial loss for Woodside.
•Government policy objectives in the countries in which we do business, now or in the future, could take the form of
increased governmental regulations relating to environment, biodiversity, climate, taxation, lease retention, contracts and
other commercial matters.
•Supply chain disruptions such as extended lead times for critical spares or imposition of trade sanctions or export controls
on key suppliers, may cause outages at our operations, increased costs or delays on our projects.
•A failure to comply with applicable laws, regulations and approvals may result in action, including fines and sanctions
being taken against Woodside that could result in cost increases, schedule delays or stoppages or production and operation
impacts. Actual or alleged violations of the securities laws that we are subject to could result in private or governmental
litigation, civil penalties, regulatory action and shareholder class actions.
•The geographical locations for our operations may present challenges and risks. For example, certain activities undertaken
in deep waters are more difficult and costly than in shallower waters and require significant time between the discovery
and the time that Woodside can market its production.
•JVP or contractual counterparties may be primarily responsible for the adequacy of the human or technical competencies
and capabilities that they bring to bear on the joint project, which may not be adequate.
•Actual or alleged violations of the securities laws that we are subject to could result in private or governmental litigation,
civil penalties, regulatory action and shareholder class actions.
•The suspension, revocation, failure to renew or alteration of, or challenges to, the terms of the licences, permits,
government contracts or approvals required for our operations.
GROWTH
Growth risks associated with delivery of both major and complex multi-year execution project activities and transactions
(including acquisitions and divestments) across multiple locations around the world, including a reliance on third parties for
materials, products and services.
How is this factor relevant to Woodside?
Oil and gas
Woodside’s strategy is to continue to identify growth opportunities, organic and inorganic, and commercialise them. Woodside
competes with a wide range of companies as we seek to continue to expand Woodside’s current operations and deliver
shareholder value.
Woodside manages relationships with industry partners, including when we enter joint ventures with organisations that may also
be competing oil and gas suppliers.
The development of our current and planned capital projects involves numerous challenges and uncertainties that have the
potential to impact profitability or, in extreme cases, result in a total loss of investment. Key risks include uncertain geology,
drilling at significant depths, the existence and availability of necessary technology and engineering resources. Additional
1. Woodside’s Scope 3 investment target is to invest US$5 billion in new energy products and lower-carbon services by 2030. Woodside’s Scope 3
emissions abatement target is to take FID on new energy products and lower-carbon services by 2030, with a total abatement of capacity of 5 Mtpa CO2-e.
The acquisition of the Beaumont New Ammonia Project has delivered material progress towards our Scope 3 investment and abatement targets.
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challenges encompass supply chain constraints; availability of skilled labour, transport infrastructure limitations; licence
expirations, project delays – including delays in securing permits – potential cost overruns, and exposure to technical, fiscal,
regulatory, political and other conditions.
The development of Louisiana LNG depends on several key factors, including market conditions for natural gas and LNG,
transportation logistics, availability of equipment and skilled personnel, project costs, environmental and legal considerations, and
regulatory requirements. While our Foreign-Trade Zone status provides benefits that mitigate tariff impacts, changes in trade
policies continue to evolve and may impact costs.
The project's performance is subject to market uncertainties, particularly regarding the ability to supply LNG competitively from
North America to overseas markets, especially Europe and Asia. Fluctuations in supply, demand, and pricing could affect the
financial outcomes for Louisiana LNG and our business.
Our future oil and gas production depends on continued access to new reserves through exploration, negotiations with
governments and other owners of proven reserves, acquisitions, and the development and application of new technologies.
New energy
We have set targets for our new energy products and lower-carbon services. There is uncertainty around the pace of required
technological innovation and the reliability of technologies that will be needed to transition to a lower-carbon economy. New
energy products and lower carbon services, such as hydrogen or ammonia, face uncertain demand forecasts, may be more difficult
to commercialise than expected or may not be able to be commercialised safely or as efficiently as expected at scale. Woodside
may also face unforeseen obstacles in the commercialisation of a future carbon capture business and in the implementation of
other lower-carbon services and emission reduction efforts.1
Examples of how this factor may affect Woodside
•An unbalanced portfolio of oil and gas and new energy, that may not meet the market’s needs.
•Limited or reduced market share resulting in a loss of shareholder value and a failure to deliver expected returns.
•Project schedule delays or cost increases due to labour or material shortages, geopolitical conflicts, regulatory approvals
or other unanticipated events.
•Failure to identify, execute or implement strategic transactions, including acquisitions and divestments, or to achieve the
full benefits of those transactions.
•The scale and complexity of projects such as Louisiana LNG will require substantial capital and operating investment.
Higher capital demands, prolonged weakness in oil and gas prices, or reduced cash flow could negatively impact our
financial position and growth prospects. In such cases, we may need additional debt financing, which could be costly or
unavailable, face potential credit rating downgrades, divest assets, or miss strategic opportunities.
•The development of acquired assets may lead to significant capital and operating expenses being incurred. This may result
in a requirement to incur additional debt, and we may not be able to obtain financing in the future on acceptable terms.
•Woodside relies on third-party suppliers and partners for materials, products, and services. This dependency introduces
risks beyond Woodside’s direct control. For example, the successful production of lower-carbon ammonia at Beaumont
New Ammonia is contingent on ExxonMobil’s CCS facility becoming operational. Similarly, the supply for the Louisiana
LNG project will be sourced from external providers. Any failure by these third parties to deliver on time, at required
quality standards, or at competitive prices – or any inability to secure alternative sources – could materially impact project
timelines, costs, and overall success.
•Credit rating agencies could downgrade our credit ratings below currently expected levels, particularly if Woodside is
unable to undertake a material sell-down of its interest in LALNG HoldCo in the near term.
•Woodside may be unable to compete with other larger companies in the industry with greater resources at their disposal.
•Louisiana LNG has not yet secured purchase agreements for most of its expected production volumes. Failure to finalise
contracts or sell an adequate portion of the ultimate expected volumes, could significantly impact the project’s prospects
and financial performance.
SOCIAL LICENCE
Social licence risks are associated with actual or perceived deviation from social or business expectations of ethical behaviour
(including breaches of laws or regulations) and social responsibility (including community contribution and impacts on the
environment, climate, biodiversity, human rights or cultural heritage), particularly as these expectations evolve and as Woodside
expands its operations around the world.
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How is this factor relevant to Woodside?
Communities, Indigenous Peoples including Traditional Owners and Custodians, government authorities, investors and other
groups form significant relationships with our organisation on the basis that Woodside will meet our stakeholders’ expectations.
Woodside operates across multiple jurisdictions with varying levels of political, legal, and fiscal stability. Certain regions present
heightened operational and business risks that could materially impact our reputation, activities and financial performance.
Examples of how this factor may affect Woodside
•Lost or limited stakeholder support for our current business and future opportunities, resulting in refusal or delay in
approvals, permits or authorisations and potential cost overruns.
•New or amended laws and regulations, or new or different applications or interpretations of existing laws and regulations.
•Risks from the violation or perceived violation of certain laws and regulations, which may result in class action lawsuits,
litigation and activism, allegations of legal compliance failures and greenwashing.
•Reductions in the availability of, or less favourable terms for, financing and other forms of capital.
•We process personal data throughout our operations, and any failure to protect it or use it lawfully and ethically could
result in significant harm to individuals and expose the company to reputational and regulatory risk.
•Third-party risks that are outside of our control could negatively affect our reputation and licence to operate, including
reputational damage to the oil and gas industry at large.
PEOPLE AND CULTURE
These risks are associated with the ability to attract, retain, develop and motivate employees to succeed and safeguard both current
and future performance and growth.
How is this factor relevant to Woodside?
People are key to the success of Woodside. We must build and maintain a capable workforce if we are to achieve our objectives.
An effective operating model with a balanced organisational structure is important to allow us to conduct our operations and
pursue new opportunities. For Woodside to remain an employer of choice, our culture must support our current employees and
attract the best new candidates.
The conduct of Woodside, our employees and our third-party partners could result in actual or alleged breaches of laws,
regulations and approvals, including fraud, corruption, anti-competitive behaviour, money laundering, breaching trade or financial
sanctions, market manipulation, privacy breaches, ethical misconduct and wider organisational cultural failings.
Examples of how this factor may affect Woodside
•During periods of high demand for skilled resources, Woodside may be unable to fill critical roles at acceptable costs or at
all, leading to operational impacts.
•A limited ability to operate due to our people leaving critical roles.
•An inability to pursue innovation opportunities due to a skills shortage.
•Loss of key personnel or expert knowledge.
•Actual or alleged misconduct, including fraud and corruption.
•An inability to reach timely agreements with employees including where representation by third parties may result in
industrial action.
FINANCIAL MANAGEMENT
Woodside is exposed to treasury risks, including liquidity, interest rate, foreign exchange, and credit risk. Our financial position is
influenced by global macroeconomic conditions and market and commodity volatility, which also affect the valuation of assets
and liabilities.
How is this factor relevant to Woodside?
Woodside must be financially well positioned in order to pursue our strategic objectives and remain resilient during times of
economic challenge. Several factors can affect our position.
Capital management
For Woodside to operate sustainably we must make risk informed decisions related to allocation of capital. We seek to apply a
disciplined and balanced approach to capital management through the commodity price cycle.
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From time to time, Woodside has relied on access to capital markets for funding. Our ability to obtain additional financing or
refinancing will be subject to a number of factors, including general economic and market conditions such as rising interest rates,
inflation or unstable or illiquid market conditions.
Commodity price risk
Commodity price fluctuations can materially influence Woodside’s revenue, cash flow, and asset valuations, requiring disciplined
capital allocation and proactive risk management to maintain financial resilience through the price cycle.
Foreign exchange risk:
Woodside is exposed to foreign currency risk from future commitments, financial assets and financial liabilities that are not
denominated in US dollars. See section A in Notes to the financial Statements in “Item 18. Financial Statements” in this 2025
Form 20-F for further information.
Interest rate risk:
This is the risk that Woodside’s financial position will fluctuate due to changes in market interest rates. Woodside’s risk relates
primarily to financial instruments with floating interest rates including long-term debt obligations, cash and short-term deposits.
See section C in Notes to the financial Statements in “Item 18. Financial Statements” in this 2025 Form 20-F for further
information.
Credit risk:
Woodside is exposed to credit risk, where counterparties may fail to meet payment or performance obligations under contractual
arrangements. Such defaults, while infrequent, could result in financial losses and impact our operations.
If any of these risks materialise, they could significantly impact Woodside’s earnings, cash flows, and overall financial position.
Examples of how this factor may impact Woodside
•Reduced ability to fund our strategy, including our projects, may limit growth and execution.
•Operating across multiple jurisdictions exposes us to varying economic and political conditions, creating global market
volatility risks.
•Restriction of debt market access or reliance on bonds and commercial paper for funding could impact our liquidity and
operations.
•Interest rate fluctuations or any deterioration in credit rating could increase borrowing costs.
•Some financial institutions are limiting exposure to fossil fuel projects, potentially affecting funding availability.
•Sustained price declines or heightened volatility could constrain funding capacity and covenant headroom, reinforcing the
need for robust liquidity management, stress testing and prudent decision making.
•We are exposed to foreign exchange risk from currency fluctuations and exchange controls associated with our
international operations. While we apply hedging strategies, these measures do not fully eliminate the risk or perform as
expected.
•Counterparty defaults on payment or performance obligations could result in financial losses.
•Impairments of assets, goodwill or other intangible assets, or a significant increase in capital and operational expenditure
as a result of acquisitions or investing in projects, could have a significant negative effect on our reported net income and
our ability to pay dividends in one or more accounting periods if the level of impairment were to exceed profits available
for distribution.
COMMERCIAL AND MARKET
Woodside is exposed to commercial and market risks primarily driven by the global energy transition, fluid market dynamics,
commodity price volatility, geopolitical tensions and trade tariffs and restrictions increasing supply chain costs and complexity.
Commercial and market risks are associated with the ability to capture value whether markets are stable or volatile. Generally,
Woodside does not have control over the factors that affect market development and prices.
How is this factor relevant to Woodside?
Woodside’s revenues are primarily derived from the sale of oil and gas. The prices Woodside receives for these products are
variable and are affected by global economic factors beyond Woodside’s control.
Uncertainty in macroeconomic conditions, tariffs, the energy transition, and geopolitical tensions can create strategic and financial
challenges for Woodside. Volatile commodity prices and inflationary pressures can erode margins and disrupt capital planning,
while tariffs and trade restrictions increase supply chain costs and complexity. The pace and direction of the energy transition
introduces regulatory and market uncertainty, potentially impacting demand for hydrocarbons and accelerating the need for
portfolio diversification. Collectively, these factors can materially affect Woodside’s earnings, cash flows, and investment
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decisions, requiring robust scenario planning, disciplined capital allocation, and proactive risk management designed to safeguard
long-term shareholder value.
We seek to forecast changes in the economic factors to enable us to maintain a strong market position during challenging
economic times. See “Item 11. Quantitative and qualitative disclosures about market risk” of this 2025 Form 20-F.
Examples of how this factor may impact Woodside
•Sustained decline or significant volatility in energy prices, such as the volatility experienced in recent years, may decrease
the viability or attractiveness of projects or may increase the challenges associated with future revenue and delivery of our
strategy.
•An imbalance in supply and demand, a slowdown in global GDP growth or economic activity in the markets in which we
or our customers operate can affect commodity price cycles. Our ability to forecast market conditions determines whether
we are affected positively or negatively. For instance, a significant increase in supply to the LNG market in the near to
medium term could result in prolonged depressed prices.
•Geopolitical tensions, including conflicts and sanctions, may disrupt trade flows resulting in the introduction or increase
in trade tariffs. This has the potential to complicate supply chains for critical equipment, escalate operational and project
costs and reduce competitiveness.
•Woodside may become a less attractive JVP, reducing our ability to execute projects with partners or increasing the cost
to do so.
•Shareholder returns are reduced due to lower commodity prices.
•Woodside’s acquisition activities carry the risk that anticipated benefits may not be fully realised due to factors such as
less-than-expected reserves, reduced production or changed circumstances, such as price decline or an inability to capture
market optimisation opportunities; bear unexpected integration costs or experience other integration difficulties;
experience share price declines based on the market’s evaluation of the activity; or be subject to liabilities that are greater
than anticipated. Similar risks may apply to Woodside’s development activities and potential divestments.
•If we inaccurately forecast the global demand for our LNG products, we may face difficulties obtaining longer-term sales
contracts with desirable commercial terms.
•If counterparties to our derivative instruments are unable to fulfil their obligations, a larger percentage of our future oil
and gas production could be subject to price changes.
DIGITAL AND CYBERSECURITY
These risks are associated with adopting and implementing new technologies, while safeguarding our digital information and
landscape (including from cyber threats) across our value chain.
How is this factor relevant to Woodside?
Woodside relies significantly on information and operational technology systems for its core operations. As a result, we are
heavily reliant on secure, affordable and resilient IT services provided both in-house and by third parties. Woodside must protect
the confidentiality, integrity and availability of digital information and operational technologies. Woodside’s technology systems,
including artificial intelligence and machine learning, may be targeted by an internal or external malicious act or our systems may
be disrupted unintentionally. Additionally, the cost of implementing and maintaining effective technology systems may be higher
than anticipated. While our technology controls are designed to protect against all causes of disruption, we cannot be certain that
they will protect our systems in all cases.
Examples of how this factor may impact Woodside
•Cybersecurity risks are increasing due to more sophisticated attacks, rapid technology changes, geopolitical tensions, and
evolving regulations across the markets in which we operate. Woodside has faced, and expects to continue facing,
cybersecurity threats such as ransomware, denial-of-service, hacktivism, and nation-state attacks targeting critical energy
infrastructure. In addition, non-malicious IT incidents have occurred and may happen again, potentially impacting
operations and data security. In the event of a cyber attack, Woodside’s confidential or sensitive information may be made
public or held for ransom.
•Our operations may be disrupted if unauthorised access to our process control systems, or the systems of vendors on
which we rely, occurs.
•Rapid advancements in digital technologies, including AI and quantum computing, are ongoing. If we do not effectively
harness these technologies, our business operations may become less efficient, and our product offerings could lose their
competitive edge, ultimately hindering our ability to execute our strategy.
•Misuse of AI (e.g., biased algorithms misreporting) could damage Woodside’s credibility with investors, regulators,
communities and other stakeholders.
•As AI adoption grows, Woodside faces compliance with evolving rules around data governance, reporting, and safety
standards. Misalignment could delay projects or attract non-compliance penalties.
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•Litigation and governmental investigations may arise from the occurrence of a cyber attack.
•There may be potential adverse impacts on our reputation, the safety and privacy of our employees and the communities
in which we operate.
ITEM 4. INFORMATION ON THE COMPANY
A.History and Development of the Company
Woodside was registered under Australian corporate law in 1971 and listed on the Australian Securities Exchange (the ASX) on
18 November 1971. Woodside’s shares are currently listed on the ASX under the ticker symbol ‘WDS’ and its American
Depositary Shares (ADS) are listed on the NYSE under the symbol ‘WDS’. Following the approval of Woodside shareholders at
Woodside’s Annual General Meeting on 19 May 2022, Woodside changed its name from ‘Woodside Petroleum Ltd.’ to
‘Woodside Energy Group Ltd’ effective 20 May 2022. Woodside’s registered office is Mia Yellagonga, 11 Mount Street, Perth,
Western Australia 6000, Australia, telephone +61 8 9348 4000.
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 1: Overview from pages 4-11
•Section 2.3: Financial overview from pages 17-18
•Section 2.5: Business model and value chain from pages 22-23
•Section 3: Our Business from pages 24-39
•Documents on display in Section 6.4: Shareholder statistics on page 274.
See Three-Year Financial Analysis in “Item 5.A Operating Results” of this 2025 Form 20-F.
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B.Business Overview
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 1: Overview from pages 4-11
•Section 2: Strategy and Financial Performance from pages 12-23
•Section 3: Our Business from pages 24-39
•Section 6.3: Additional disclosures from pages 257-271.
See Three-Year Financial Analysis in “Item 5.A Operating Results” of this 2025 Form 20-F.
Applicable laws and regulations
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Government regulations in Section 6.3: Additional disclosures from pages 263-271
•Material limitations in Section 6.3: Additional disclosures on page 271
•Summary of material legal proceedings in Section 6.3: Additional disclosures on page 271.
Disclosures regarding oil and gas operations
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Drilling and other exploratory and development activities in Section 6.3: Additional disclosures on page 257
•Present development activities continuing as of 31 December 2025 in Section 6.3: Additional disclosures on page
257
•Oil and gas properties, wells, operations and acreage in Section 6.3: Additional disclosures on pages 258
•Delivery commitments in Section 6.3: Additional disclosures on page 258
•Production in Section 6.3: Additional disclosures on page 259.
RESERVES STATEMENT
About the Reserves Statement
This Reserves Statement presents Woodside’s proved oil and gas reserves, as of 31 December 2025, in accordance with the
regulations of the United States Securities and Exchange Commission (SEC).1
Unless stated otherwise, the following apply to this Reserves Statement: The effective date for reserves estimates is
31 December 2025. Estimates have been prepared in accordance with the reserves definitions of Rules 4-10(a) of SEC
Regulations S-X and are calculated using SEC-compliant economic assumptions and pricing. Production is reported for the
period from 1 January 2025 to 31 December 2025. Reserves and production stated are Woodside’s net share and inclusive of
fuel consumed in operations. See “Methodology” below.
All numbers are internal estimates produced by Woodside. Estimates of reserves should be regarded only as estimates that
may change over time as additional information and production history becomes available. See “Forward-Looking
Statements”.
2025 proved reserves
Woodside produced a total of 211.4 MMboe in 2025, including 197.7 MMboe produced for sale and 13.7 MMboe of
production consumed as fuel in operations.2 At 31 December 2025, Woodside’s proved (1P) reserves were
1,882.1 MMboe (Table 1, 2).
As a result of the divestment of the Greater Angostura assets in Trinidad and Tobago, Woodside’s proved developed reserves
decreased by 16.3 MMboe (shown as acquisitions and divestments in Table 2).
In 2025, excluding divestments and production, Woodside's proved reserves increased by 134.1 MMboe (shown as extensions
and discoveries, revisions of previous estimates, and improved recovery in Table 2). Key drivers for these changes included:
•production driven technical updates at Greater Pluto in Australia contributed to proved reserves increases of 25.6 MMboe
(included as revisions of previous estimates in Table 2)
•field performance, technical updates and the final investment decision on Greater Western Flank 4 (GWF4) at North
West Shelf in Australia contributed to proved reserves increases of 34.6 MMboe.3 Of these changes, the final investment
decision on GWF4 resulted in proved reserves increases of 16.4 MMboe (included as extensions and discoveries, and
revisions of previous estimates in Table 2)
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•field performance, technical updates and the final investment decision on Turrum Phase 3 at Bass Strait in Australia
resulted in proved reserves increases of 17.4 MMboe (included as extensions and discoveries, and revisions of previous
estimates in Table 2)
•field performance and technical updates at several Exmouth fields in Australia contributed to proved reserves increases of
12.2 MMboe
•field performance and technical updates at Sangomar in Senegal contributed to proved reserves increases of
27.9 MMboe. Of these changes, reservoir performance supported the booking of water injection volumes in the S400
reservoirs at Sangomar, resulting in proved reserves increases of 7.7 MMboe (included as improved recovery in Table 2)
•final investment decision on a water injection expansion project at Atlantis in the United States resulted in proved
reserves increases of 7.6 MMboe (included as improved recovery in Table 2). In addition, field performance and
technical updates across several Gulf of America fields in the United States contributed to additional proved reserves
increases of 9.1 MMboe.
The transfers of undeveloped to developed reserves associated with successful start-up of development wells in Australia and
in the United States are discussed in the 2025 proved undeveloped reserves section of this Reserves Statement.
Table 1: Woodside’s proved reserves4,5,6 overview (net Woodside share, as at 31 December 2025)
Natural gas7 Bcf10 | NGLs8 MMbbl11 | Oil & condensate MMbbl | Total9 MMboe12 | Fuel included in total MMboe | ||||||
Proved13 developed14 and undeveloped15 | 7,637.1 | 18.0 | 524.3 | 1,882.1 | 170.3 | |||||
Proved developed | 1,740.7 | 15.3 | 322.9 | 643.6 | 52.3 | |||||
Proved undeveloped | 5,896.4 | 2.7 | 201.4 | 1,238.5 | 118.0 |
Small differences are due to rounding
2024 proved reserves
Woodside produced a total of 206.3 MMboe in 2024, including 192.7 MMboe produced for sale and 13.6 MMboe of
production consumed as fuel in operations.2 At 31 December 2024, Woodside’s remaining proved (1P) reserves were
1,975.7 MMboe (Table 2).
As a result of completion of the sale of 10.0% and 15.1% non-operating participating interest in the Scarborough Joint Venture
in Australia, Woodside’s proved undeveloped reserves decreased by 323.0 MMboe (shown as acquisitions and divestments in
Table 2, 3).
In 2024, revisions of previous estimates and extensions resulted in proved reserves increases of 54.9 MMboe. Key drivers for
these changes included:
•post start-up field performance at Sangomar in Senegal contributed to a proved reserves increase of 16.2 MMboe
•performance based revisions, technical updates and the final investment decision on a development opportunity in North
West Shelf in Australia contributed to a proved reserves increase of 13.4 MMboe3
•performance and technical updates at Bass Strait and multiple Exmouth fields in Australia contributed to a proved
reserves increase of 20.5 MMboe
•final investment decision on Xena-3 in Greater Pluto in Australia resulted in extensions of proved reserves of 7.1 MMboe
•initial field performance and technical updates at Mad Dog Phase 2 in the United States contributed to a proved reserves
decrease of 8.1 MMboe
The transfers of undeveloped to developed reserves associated with successful start-up of Sangomar, start-up of development
wells in the United States and start-up of two compression projects in Australia are discussed in the 2024 proved undeveloped
reserves section of this Reserves Statement.
2023 proved reserves
Woodside produced a total of 201.0 MMboe in 2023, including 186.1 MMboe produced for sale and 15.0 MMboe of
production consumed as fuel in operations.2 At 31 December 2023, Woodside’s remaining proved reserves were
2,450.1 MMboe (Table 2).
The first-time booking of reserves at Trion in Mexico and Mad Dog Southwest in the United States increased proved reserves
by 204.1 MMboe (shown as extensions and discoveries in Table 2), of which:
•final investment decision and regulatory approval of the field development plan at Trion in August 2023 increased proved
reserves by 194.8 MMboe16; and
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•approval of the Mad Dog Southwest Extension project increased proved reserves by 9.3 MMboe.
Revisions of previous estimates in 2023 resulted in a net increase of 61.8 MMboe for proved reserves. Key drivers for these
revisions included:
•asset optimisation, including injector to producer conversions, and field performance at Angostura and Ruby in Trinidad
and Tobago contributed to a proved reserves increase of 13.0 MMboe
•improved overall field performance and technical updates in North West Shelf increased proved reserves by 49.7 MMboe
•performance based revisions at Shenzi decreased proved reserves by 13.4 MMboe.
The transfers of undeveloped reserves to developed reserves are discussed in the 2023 proved undeveloped reserves section of
this Reserves Statement.
Methodology
Reserves estimates have not been adjusted for risk. Proved reserves are estimated and reported on a net interest basis,
excluding royalties owned by others, in accordance with the SEC regulations, and have been determined in accordance with
SEC Rule 4-10(a) of Regulation S-X. As defined by the SEC, proved reserves are those quantities of crude oil, condensate,
natural gas, and natural gas liquids that, by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible from a given date forward from known reservoirs and under existing economic
conditions, operating methods, operating contracts, and government regulations. Unless evidence indicates that renewal of
existing operating contracts is reasonably certain, estimates of economically producible reserves reflect only the period before
the contracts expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain
that it will commence within a reasonable time.
Proved reserves are estimated by reference to available well and reservoir information, including but not limited to well logs,
well test data, core data, production and pressure data, geologic data, seismic data and, in some cases, similar data from
analogous, producing reservoirs. A wide range of engineering and geoscience methods, including performance analysis,
numerical simulation, well analogues and geologic studies, have been used to develop high confidence in estimated quantities.
Governance and assurance
Woodside has several processes designed to provide assurance for reserves reporting, including its Reserves and Resources
Policy and Standards, reserves estimation guidance, annual staff training, and minimum experience levels. In addition,
Woodside has a dedicated and independent Corporate Reserves Team (CRT) that provides oversight and assurance of the
reserves assessments and reporting processes. Reserves are estimated by staff in teams directly responsible for development
and production activities. These individuals are trained in the fundamentals of reserves reporting and are approved by the CRT
on an annual basis. Reserves estimates are reviewed annually by the CRT to ensure technical quality, adherence to
Woodside’s Reserves and Resources Policy and Standards and compliance with SEC reporting requirements. All reserves are
reviewed and approved by Woodside’s Qualified Petroleum Reserves Evaluator and approved by senior management and
Woodside’s Board prior to public reporting.
Qualified Petroleum Reserves Evaluator statement
The estimates of petroleum reserves are based on and fairly represent information and supporting documentation prepared by,
or under the supervision of Mr. Benjamin Ziker, Woodside’s Vice President Reserves and Subsurface, who is a full-time
employee of the company and a member of the Society of Petroleum Engineers. The Reserves Statement as a whole has been
approved by Mr. Ziker. Mr. Ziker’s qualifications include a Bachelor of Science (Chemical Engineering) from Rice University
(Houston, Texas, USA), and 27 years of relevant experience.
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Table 2: Proved developed and undeveloped reserves reconciliation (net Woodside share, three years ending
31 December 2025)
Australia | International17 | Total | ||||||||||
Natural gas | NGLs | Oil & condensate | Total | Natural gas | NGLs | Oil & condensate | Total | Natural gas | NGLs | Oil & condensate | Total | |
Bcf | MMbbl | MMbbl | MMboe | Bcf | MMbbl | MMbbl | MMboe | Bcf | MMbbl | MMbbl | MMboe | |
Reserves as at 31 December 2022 | 10,455.8 | 17.3 | 79.7 | 1,931.4 | 327.8 | 9.0 | 387.3 | 453.8 | 10,783.6 | 26.3 | 467.0 | 2,385.2 |
Acquisitions and divestments18 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 |
Extensions and discoveries19 | 0.0 | 0.0 | 0.0 | 0.0 | 177.9 | 0.4 | 172.5 | 204.1 | 177.9 | 0.4 | 172.5 | 204.1 |
Revisions of previous estimates20 | 308.6 | 2.2 | 15.4 | 71.8 | 35.6 | (0.6) | (15.6) | (9.9) | 344.3 | 1.6 | (0.2) | 61.8 |
Production | (738.4) | (5.9) | (22.7) | (158.1) | (70.6) | (1.4) | (29.2) | (43.0) | (809.0) | (7.3) | (51.8) | (201.0) |
Reserves as at 31 December 2023 | 10,026.1 | 13.6 | 72.5 | 1,845.1 | 470.7 | 7.4 | 515.0 | 605.0 | 10,496.9 | 21.0 | 587.5 | 2,450.1 |
Acquisitions and divestments | (1,841.3) | 0.0 | 0.0 | (323.0) | 0.0 | 0.0 | 0.0 | 0.0 | (1,841.3) | 0.0 | 0.0 | (323.0) |
Extensions and discoveries | 37.7 | 0.0 | 0.5 | 7.1 | 0.0 | 0.0 | 0.0 | 0.0 | 37.7 | 0.0 | 0.5 | 7.1 |
Revisions of previous estimates | 108.6 | 4.3 | 11.1 | 34.4 | 25.8 | 0.2 | 8.6 | 13.4 | 134.4 | 4.5 | 19.8 | 47.9 |
Production | (714.2) | (5.1) | (20.7) | (151.1) | (63.5) | (1.6) | (42.5) | (55.2) | (777.8) | (6.7) | (63.2) | (206.3) |
Reserves as at 31 December 2024 | 7,616.9 | 12.8 | 63.4 | 1,412.5 | 433.0 | 6.0 | 481.2 | 563.2 | 8,049.9 | 18.9 | 544.6 | 1,975.7 |
Acquisitions and divestments | 0.0 | 0.0 | 0.0 | 0.0 | (91.9) | 0.0 | (0.2) | (16.3) | (91.9) | 0.0 | (0.2) | (16.3) |
Extensions and discoveries | 75.6 | 1.1 | 3.4 | 17.7 | 0.0 | 0.0 | 0.0 | 0.0 | 75.6 | 1.1 | 3.4 | 17.7 |
Revisions of previous estimates | 341.9 | 3.0 | 9.1 | 72.1 | (13.4) | 0.2 | 31.1 | 29.0 | 328.5 | 3.3 | 40.2 | 101.1 |
Improved recovery21 | 0.0 | 0.0 | 0.0 | 0.0 | 3.7 | 0.5 | 14.3 | 15.4 | 3.7 | 0.5 | 14.3 | 15.4 |
Production | (684.1) | (4.1) | (18.7) | (142.8) | (44.5) | (1.6) | (59.1) | (68.5) | (728.6) | (5.7) | (77.8) | (211.4) |
Reserves as at 31 December 202522 | 7,350.2 | 12.8 | 57.1 | 1,359.5 | 286.9 | 5.1 | 467.2 | 522.7 | 7,637.1 | 18.0 | 524.3 | 1,882.1 |
Fuel included in 31 December 2025 reserves | 843.4 | 0.8 | 0.0 | 148.8 | 122.6 | 0.0 | 0.0 | 21.5 | 966.0 | 0.8 | 0.0 | 170.3 |
Proved developed and undeveloped reserves | ||||||||||||
Proved developed reserves | ||||||||||||
as at 31 December 2022 | 2,722.6 | 16.7 | 73.3 | 567.6 | 202.5 | 5.9 | 161.0 | 202.4 | 2,925.1 | 22.5 | 234.3 | 770.0 |
as at 31 December 2023 | 2,361.3 | 12.6 | 67.9 | 494.8 | 220.8 | 6.1 | 198.0 | 242.8 | 2,582.1 | 18.7 | 266.0 | 737.7 |
as at 31 December 2024 | 1,748.5 | 12.4 | 58.4 | 377.6 | 246.5 | 5.0 | 281.0 | 329.2 | 1,995.0 | 17.4 | 339.4 | 706.8 |
as at 31 December 2025 | 1,641.6 | 11.2 | 51.0 | 350.2 | 99.0 | 4.1 | 272.0 | 293.4 | 1,740.7 | 15.3 | 322.9 | 643.6 |
Proved undeveloped reserves | ||||||||||||
as at 31 December 2022 | 7,733.2 | 0.7 | 6.4 | 1,363.8 | 125.2 | 3.1 | 226.3 | 251.4 | 7,858.5 | 3.8 | 232.8 | 1,615.2 |
as at 31 December 2023 | 7,664.9 | 1.0 | 4.6 | 1,350.3 | 249.9 | 1.3 | 317.0 | 362.2 | 7,914.7 | 2.3 | 321.6 | 1,712.5 |
as at 31 December 2024 | 5,868.4 | 0.4 | 5.0 | 1,034.9 | 186.5 | 1.1 | 200.2 | 234.0 | 6,054.9 | 1.5 | 205.2 | 1,268.9 |
as at 31 December 2025 | 5,708.5 | 1.6 | 6.2 | 1,009.3 | 187.9 | 1.1 | 195.2 | 229.2 | 5,896.4 | 2.7 | 201.4 | 1,238.5 |
Small differences are due to rounding
2025 proved undeveloped reserves
At 31 December 2025, Woodside’s remaining proved undeveloped reserves were 1,238.5 MMboe, representing a decrease of
30.4 MMboe from the 1,268.9 MMboe as at 31 December 2024 (Table 3).
In 2025, 67.2 MMboe of proved undeveloped reserves were transferred to proved developed reserves with the start-up of
development wells at Greater Pluto (47.3 MMboe), Bass Strait (4.1 MMboe), North West Shelf (1.2 MMboe), and Mad Dog
and Atlantis (14.6 MMboe).
Technical updates, performance based revisions and development plan changes in Australia and the United States resulted in
revisions of previous estimates, contributing to a 11.5 MMboe increase in proved undeveloped reserves. The final investment
decision on Greater Western Flank 4 (North West Shelf) and Turrum Phase 3 (Bass Strait) in Australia resulted in proved
undeveloped reserves increases of 22.5 MMboe (included as revisions of previous estimates, and extensions and discoveries in
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Table 3). In addition, the final investment decision on a water injection expansion project in the Atlantis field resulted in
improved recovery additions to proved undeveloped reserves of 7.6 MMboe.
Only undeveloped reserves in Julimar-Brunello and Greater Pluto have remained undeveloped for longer than five years from
the dates they were initially reported and are expected to be developed in a phased manner to meet long-term contractual
commitments. Both projects are being progressed, demonstrating an intent to proceed with development3.
As of 31 December 2025, approximately 88% of Woodside’s proved undeveloped reserves are scheduled to be developed
within five years of initial disclosure. The remaining proved undeveloped reserves (approximately 12%) are associated with
large and complex capital investment projects, which are scheduled to be developed beyond five years from initial disclosure
primarily due to facility ullage constraints and scheduled offshore drilling campaigns. Woodside is committed to these projects
and continues to actively progress the development of these volumes.
In 2025, Woodside incurred approximately US$3.2 billion progressing the transfer of proved undeveloped reserves to proved
developed reserves. These expenditures were primarily associated with field development activities at Scarborough and Trion,
with additional capital associated with field developments that achieved, or are expected to achieve, development status upon
completion.
2024 proved undeveloped reserves
At 31 December 2024, Woodside’s remaining proved undeveloped reserves were 1,268.9 MMboe, representing a decrease of
443.6 MMboe from the 1,712.5 MMboe as at 31 December 2023 (Table 3).
Following completion of the sales of 10.0% and 15.1% non-operating participating interest in the Scarborough Joint Venture
in March 2024 and October 2024, respectively, Woodside’s proved undeveloped reserves decreased by 323.0 MMboe.
In 2024, 132.6 MMboe of proved undeveloped reserves were transferred to proved developed reserves with start-up of
development wells in Sangomar (94.5 MMboe), Mad Dog and Atlantis (24.0 MMboe), and compression projects at Bass Strait
(9.3 MMboe) and Macedon (4.9 MMboe).
Revisions of previous estimates resulted in proved undeveloped reserves increases of 5.0 MMboe. Technical updates at
Greater Pluto resulted in proved undeveloped reserves increases of 20.7 MMboe, primarily due to production acceleration and
onshore facility limits. Initial field performance and technical updates at Mad Dog and strong base performance at Julimar-
Brunello in Australia contributed to proved undeveloped reserves decreases of 12.4 MMboe and 7.4 MMboe, respectively.
The final investment decision and approval of multiple development opportunities in the United States and Australia, and
minor development plan changes in the United States, resulted in proved undeveloped reserves increases of 5.2 MMboe.
The final investment decision on a single well development in Greater Pluto (Xena-3) resulted in extensions of proved
undeveloped reserves of 7.1 MMboe.
Only undeveloped reserves in Julimar-Brunello have remained undeveloped for longer than five years from the dates they
were initially reported and are expected to be developed in a phased manner to meet long-term contractual commitments. The
project is included in the company business plan, demonstrating the intent to proceed with the development.
As of 31 December 2024, approximately 88% of Woodside’s proved undeveloped reserves are scheduled to be developed
within five years of initial disclosure. The remaining proved undeveloped reserves (approximately 12%) are associated with
large and complex capital investment projects, which are scheduled to be developed beyond five years from initial disclosure
primarily due to facility ullage constraints and scheduled offshore drilling campaigns. Woodside is committed to these projects
and continues to actively progress the development of these volumes.
During 2024, Woodside incurred approximately US$4.0 billion progressing the transfer of proved undeveloped reserves for
projects where development status was achieved in 2024 or is expected to be achieved when development is completed in the
future.
2023 proved undeveloped reserves
At 31 December 2023, Woodside’s remaining proved undeveloped reserves were 1,712.5 MMboe, representing an increase of
97.2 MMboe from the 1,615.2 MMboe as at 31 December 2022 (Table 3).
Extensions and discoveries increased proved undeveloped reserves by 204.1 MMboe following the final investment decision
and regulatory approval of the field development plan at Trion, and approval of the Mad Dog Southwest Extension project.
In 2023, 87.7 MMboe of proved undeveloped reserves were transferred to proved developed reserves with start-up of
development wells in Mad Dog Phase 2 (56.0 MMboe), Shenzi North (10.5 MMboe), Atlantis (8.7 MMboe), and Pyrenees
(1.1 MMboe), and completion of offshore Pluto water handling (11.3 MMboe). Technical studies and performance resulted in
a 3.4 MMboe decrease to proved undeveloped reserves. The effect of commodity prices relative to 2022 resulted in a
15.8 MMboe reduction to proved undeveloped reserves at Sangomar.
Only undeveloped reserves in Julimar-Brunello have remained undeveloped for longer than five years from the dates they
were initially reported and are expected to be developed in a phased manner to meet long-term contractual commitments. The
project is included in the company business plan, demonstrating the intent to proceed with the development.
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As of 31 December 2023, approximately 89% of Woodside’s proved undeveloped reserves are scheduled to be developed
within five years of initial disclosure. The remaining proved undeveloped reserves (approximately 11%) are associated with
large and complex capital investment projects, which are scheduled to be developed beyond five years from initial disclosure
primarily due to facility ullage constraints and scheduled offshore drilling campaigns. Woodside is committed to these projects
and continues to actively progress the development of these volumes.
During 2023, Woodside incurred approximately US$4.7 billion progressing the transfer of proved undeveloped reserves for
projects where development status was achieved in 2023 or is expected to be achieved when development is completed in the
future.
Table 3: Proved undeveloped reserves reconciliation (net Woodside share, three years ending 31 December 2025)
MMboe | 2025 | 2024 | 2023 | ||
Proved undeveloped opening balance | 1,268.9 | 1,712.5 | 1,615.2 | ||
Extensions and discoveries | 17.7 | 7.1 | 204.1 | ||
Transfers to proved developed reserves | (67.2) | (132.6) | (87.7) | ||
Revisions of previous estimates | 11.5 | 5.0 | (19.2) | ||
Performance, technical studies, development plan changes, and other | 11.5 | 5.0 | (3.4) | ||
Price | 0.0 | 0.0 | (15.8) | ||
Improved recovery | 7.6 | 0.0 | 0.0 | ||
Acquisitions and divestments | 0.0 | (323.0) | 0.0 | ||
Proved undeveloped closing balance | 1,238.5 | 1,268.9 | 1,712.5 | ||
Small differences are due to rounding | |||||
Notes to the Reserves Statement
1.Woodside is an Australian company listed on the Australian Securities Exchange and the New York Stock Exchange.
Woodside reports its proved reserves in accordance with SEC regulations. These guidelines are also compliant with
2018 Society of Petroleum Engineers/World Petroleum Council/American Association of Petroleum Geologists/Society
of Petroleum Evaluation Engineers Petroleum Resources Management System (SPE-PRMS).
2.‘Production’ is the volume of natural gas, natural gas liquids (NGLs), condensate and oil produced during the period
from 1 January to 31 December of the reporting year, and converted to ‘MMboe’ for the specific purpose of reserves
reconciliation. The production volume figures in this Reserves Statement differ from the production volume figures
reported in Woodside’s annual and quarterly reports, because the production volume figures reported in this Reserves
Statement include all fuel consumed in operations but exclude 1.1 MMboe (2023), 1.2 MMboe (2024), and 1.2 MMboe
(2025) of volumes from feed gas purchased from Pluto non-operating participants and processed via the Pluto-KGP
Interconnector. Other small differences are due to rounding.
3.In this Reserves Statement, Woodside’s interests, including those in the North West Shelf Project Area and Julimar-
Brunello, represent interests at the end of the reporting period. On 19 December 2024 Woodside issued an
announcement entitled “Woodside Simplifies Portfolio and Unlocks Long-Term Value”, describing an asset swap with
Chevron. The transaction would, if completed, result in changes to Woodside’s interests in the North West Shelf
Project Area and Julimar-Brunello. Completion of the transaction is subject to customary conditions precedent,
including Australian Competition and Consumer Commission and Foreign Investment Review Board clearances and
other applicable State and Federal and regulatory approvals, relevant third-party consents and pre-emption rights of the
continuing joint venture participants. The transaction is also subject to the completion of Julimar Phase 3 Project
execution and handover which is expected in 2026, and the completion of certain ongoing abandonment activities.
4.For offshore oil projects, the reference point is defined as the outlet of the floating production storage and offloading
facility (FPSO) or platform, while for the onshore gas projects the reference point is defined as the outlet of the
downstream (onshore) gas processing facility.
5.‘Reserves’ are estimated quantities of petroleum that have been demonstrated to be producible from known
accumulations in which the company has a material interest from a given date forward, at commercial rates, under
presently anticipated production methods, operating conditions, prices, and costs. Woodside reports reserves inclusive
of all fuel consumed in operations. Proved reserves are estimated and reported in accordance with SEC regulations
which are also compliant with SPE-PRMS guidelines. SEC-compliant proved reserves estimates use a more restrictive,
rules-based approach and are generally lower than estimates prepared solely in accordance with SPE-PRMS guidelines
due to, among other things, the requirement to use commodity prices based on the average of first of month prices
during the 12-month period in the reporting company’s fiscal year.
6.All proved reserves estimates have been estimated using deterministic methods and reported on a net interest basis in
accordance with the SEC regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-
X. Unless otherwise stated, all petroleum estimates reported at the company or region level are aggregated by
arithmetic summation by category. The aggregated proved reserves may be a conservative estimate due to the portfolio
effects of arithmetic summation.
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7.‘Natural gas’ is defined as the gas product associated with liquefied natural gas (LNG) and pipeline gas. Liquid
volumes of crude oil, condensate and NGLs are reported separately.
8.‘Natural gas liquids’ or ‘NGLs’ is defined as the product associated with liquified petroleum gas (LPG) and consists of
propane, butane, and ethane - individually or as a mixture.
9.‘Total’ includes fuel consumed in operations.
10.‘Bcf’ means billions (109) of cubic feet of gas at standard oilfield conditions of 14.696 psi (101.325 kPa) and
60 degrees Fahrenheit (15.56 degrees Celsius).
11.‘MMbbl’ means millions (106) of barrels of NGLs, oil and condensate at standard oilfield conditions of 14.696 psi
(101.325 kPa) and 60 degrees Fahrenheit (15.56 degrees Celsius).
12.‘MMboe’ means millions (106) of barrels of oil equivalent. Natural Gas volumes are converted to oil equivalent
volumes via a constant conversion factor, which for Woodside is 5.7 Bcf of dry gas per 1 MMboe. Volumes of NGLs,
oil and condensate are converted from MMbbl to MMboe on a 1:1 ratio.
13.‘Proved reserves’ are those quantities of crude oil, condensate, natural gas and NGLs that, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible from a given date
forward from known reservoirs and under existing economic conditions, operating methods, operating contracts, and
government regulations. Proved reserves are estimated and reported on a net interest basis in accordance with the SEC
regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X.
14.‘Developed reserves’ are those reserves that are producible through currently existing completions and installed
facilities for treatment, compression, transportation and delivery, using existing operating methods and standards.
15.‘Undeveloped reserves’ are those reserves for which wells and facilities have not been installed or executed but are
expected to be recovered through future significant investments.
16.The estimation of material additions to proved reserves was developed through the utilization of available well and
reservoir information. This included, but not limited to, well logs, well test data, core data and analyses, seismic data,
pressure data, PVT data, and geologic data. This information formed the basis for a range of engineering and
geoscience analyses, including numerical simulation, uncertainty studies, analogue benchmarking, and geologic and
petrophysical studies.
17.‘International’ consists of Trinidad and Tobago, Senegal, Mexico, and the United States, none of which individually
accounts for 15% or more of Woodside’s total proved reserves as of 31 December 2025. The United States accounts for
the largest percentage of proved reserves within the ‘International’ segment. In reporting years 2023, 2024, and 2025,
the United States accounted for 291.6 MMboe (12%), 249.7 MMboe (13%), and 232.9 MMboe (12%) of Woodside’s
total proved reserves, respectively.
18.‘Acquisitions and divestments’ are revisions that represent changes (either upward or downward) in previous estimates
of reserves which result from either purchase or sale of interests and/or execution of contracts conveying entitlement.
19.‘Extensions and discoveries’ represent additions to reserves that result from increased areal extensions of previously
discovered fields demonstrated to exist subsequent to the original discovery and/or discovery of reserves in new fields
or new reservoirs in old fields.
20.‘Revisions of previous estimates’ are changes (either upward or downward) in previous estimates of reserves, resulting
from new information normally obtained from development drilling and production history, or resulting from a change
in economic factors.
21.'Improved recovery' refers to the incremental petroleum volumes obtained beyond primary recovery mechanisms,
typically through methods such as water flooding, secondary, or tertiary recovery processes.
22.Scarborough proved undeveloped reserves as at 31 December 2025 are 5,494.7 Bcf (964.0 MMboe). Development
activities are underway. In this Reserves Statement, Scarborough estimates are based on 74.9% interest in the
Scarborough Joint Venture.
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Supplementary oil and gas information pursuant to FASB Topic 932
The following information is reported pursuant to Financial Accounting Standards Board (FASB) Accounting Standard
Codification ‘Extractive Activities-Oil and Gas’ (Topic 932) and SEC requirements set out in Subpart 1200 of Regulation S-
K.
Reserves
Proved oil and gas reserves information is included above under the heading “Reserves Statement”.
Capitalised Costs Relating To Oil And Gas Production Activities
The following table shows the aggregate capitalised costs related to oil and gas exploration and production activities, and the
related accumulated depreciation, depletion, amortisation and valuation provisions.
Australia | International | Total | |||
US$m | US$m | US$m | |||
2025 | |||||
Unproved properties | 1,370 | 1,009 | 2,379 | ||
Proved properties1 | 56,226 | 21,108 | 77,334 | ||
Total costs | 57,596 | 22,117 | 79,713 | ||
Less: Accumulated depreciation, depletion, amortisation and valuation provisions | (31,432) | (8,153) | (39,585) | ||
Net capitalised costs | 26,164 | 13,964 | 40,128 | ||
2024 | |||||
Unproved properties | 1,358 | 895 | 2,253 | ||
Proved properties1 | 54,189 | 20,032 | 74,221 | ||
Total costs | 55,547 | 20,927 | 76,474 | ||
Less: Accumulated depreciation, depletion, amortisation and valuation provisions | (30,244) | (5,936) | (36,180) | ||
Net capitalised costs | 25,303 | 14,991 | 40,294 | ||
2023 | |||||
Unproved properties | 1,193 | 1,109 | 2,302 | ||
Proved properties1 | 52,563 | 18,039 | 70,602 | ||
Total costs | 53,756 | 19,148 | 72,904 | ||
Less: Accumulated depreciation, depletion, amortisation and valuation provisions | (27,548) | (3,994) | (31,542) | ||
Net capitalised costs | 26,208 | 15,154 | 41,362 |
1.Proved properties include the fair value ascribed to future phases of certain projects acquired through business combinations.
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Costs Incurred Relating To Oil And Gas Property Acquisition, Exploration And Development Activities
The following table shows the costs incurred related to oil and gas property acquisition, exploration and development
activities (expensed and capitalised). Amounts shown include interest capitalised.
Australia | International | Total | |||
US$m | US$m | US$m | |||
2025 | |||||
Exploration1 | 51 | 212 | 263 | ||
Development2 | 2,562 | 1,475 | 4,037 | ||
Total Costs3 | 2,613 | 1,687 | 4,300 | ||
2024 | |||||
Exploration1 | 61 | 358 | 419 | ||
Development | 3,072 | 1,714 | 4,786 | ||
Total Costs3 | 3,133 | 2,072 | 5,205 | ||
2023 | |||||
Exploration1 | 103 | 420 | 523 | ||
Development | 3,315 | 2,124 | 5,439 | ||
Total Costs3 | 3,418 | 2,544 | 5,962 |
1.Represents gross exploration expenditure, including capitalised exploration expenditure, geological and geophysical expenditure and
development evaluation costs charged to income as incurred.
2.Total development costs includes $3,552 million of expenditure and $485 million of capitalised interest in 2025.
3.Total costs include $4,121 million (2024: $4,885 million, 2023: $5,683 million) capitalised during the year.
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Results Of Operations From Oil And Gas Production Activities
Australia | International | Total | |||
US$m | US$m | US$m | |||
2025 | |||||
Oil and gas revenue | 7,188 | 4,069 | 11,257 | ||
Production costs | (1,115) | (637) | (1,752) | ||
Exploration expenses | (34) | (149) | (183) | ||
Depreciation, depletion, amortisation and valuation provision1 | (2,438) | (2,591) | (5,029) | ||
Production taxes2 | (200) | (24) | (224) | ||
Accretion expense3 | (214) | (66) | (280) | ||
Income taxes | (1,043) | (278) | (1,321) | ||
Royalty-related taxes4 | (358) | - | (358) | ||
Results of oil and gas producing activities5 | 1,786 | 324 | 2,110 | ||
2024 | |||||
Oil and gas revenue | 8,276 | 3,412 | 11,688 | ||
Production costs | (1,147) | (579) | (1,726) | ||
Exploration expenses | (47) | (282) | (329) | ||
Depreciation, depletion, amortisation and valuation provision1 | (2,679) | (1,857) | (4,536) | ||
Production taxes2 | (287) | (29) | (316) | ||
Accretion expense3 | (223) | (66) | (289) | ||
Income taxes | (1,140) | (249) | (1,389) | ||
Royalty-related taxes4 | (91) | - | (91) | ||
Results of oil and gas producing activities5 | 2,662 | 350 | 3,012 | ||
2023 | |||||
Oil and gas revenue | 9,699 | 2,564 | 12,263 | ||
Production costs | (1,396) | (402) | (1,798) | ||
Exploration expenses | (55) | (299) | (354) | ||
Depreciation, depletion, amortisation and valuation provision1 | (3,288) | (2,555) | (5,843) | ||
Production taxes2 | (363) | (29) | (392) | ||
Accretion expense3 | (179) | (58) | (237) | ||
Income taxes | (1,449) | — | (1,449) | ||
Royalty-related taxes4 | (367) | - | (367) | ||
Results of oil and gas producing activities5 | 2,602 | (779) | 1,823 |
1.Includes valuation provision recognition of nil (2024: a valuation provision recognition of nil; 2023: a valuation provision recognition
of $1,917 million).
2.Includes royalties and excise duty.
3.Represents the unwinding of the discount on the closure and rehabilitation provision.
4.Includes petroleum resource rent tax and petroleum revenue tax where applicable. Excludes deferred tax (benefit)/expense of
$(9) million (2024: $(487) million; 2023: $531 million).
5.This table reflects the results of our oil and gas activities as reported in note A.1 ‘Segment revenue and expenses’ in "Item 18.
Financial Statements". Other income, other expenses, general and administrative costs and amounts relating to the marketing and
corporate segments within the note are excluded.
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Standardised Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves (Standardised
Measure)
The following tables set out the standardised measure of discounted future net cash flows, and changes therein, related to the
Group’s estimated proved reserves as presented in the Reserves Statement, and should be read in conjunction with that
disclosure. See “Item 4: Information on the Company” of this 2025 Form 20-F.
The analysis is prepared in compliance with FASB Oil and Gas Disclosure requirements, applying certain prescribed
assumptions under Topic 932 including the use of unweighted average first-day-of-the-month prices for the previous 12-
months, year-end cost factors, currently enacted tax rates and an annual discount factor of 10% to year-end quantities of net
proved reserves.
Certain key assumptions prescribed under Topic 932 are arbitrary in nature and may not prove to be accurate. The reserve
estimates on which the standardised measure is based are subject to revision as further technical information becomes
available or economic conditions change.
Discounted future net cash flows like those shown below are not intended to represent estimates of fair value. An estimate of
fair value would also take into account, among other things, the expected recovery of reserves in excess of proved reserves,
anticipated future changes in commodity prices, exchange rates, development and production costs as well as alternative
discount factors representing the time value of money and adjustments for risk inherent in producing oil and gas.
Woodside Standardised Measure Year Ended 31 December
Australia | International | Total | |||
US$m | US$m | US$m | |||
2025 | |||||
Future cash inflows | 61,468 | 31,289 | 92,757 | ||
Future production costs | (23,922) | (10,048) | (33,970) | ||
Future development costs1 | (8,956) | (5,753) | (14,709) | ||
Future income taxes | (9,080) | (2,781) | (11,861) | ||
Future net cash flows | 19,510 | 12,707 | 32,217 | ||
Discount at 10% per annum | (6,927) | (5,026) | (11,953) | ||
Standardised measure | 12,583 | 7,681 | 20,264 | ||
2024 | |||||
Future cash inflows | 67,576 | 37,800 | 105,376 | ||
Future production costs | (24,198) | (11,150) | (35,348) | ||
Future development costs1 | (9,350) | (6,766) | (16,116) | ||
Future income taxes | (11,631) | (4,776) | (16,407) | ||
Future net cash flows | 22,397 | 15,108 | 37,505 | ||
Discount at 10% per annum | (8,157) | (6,493) | (14,650) | ||
Standardised measure | 14,240 | 8,615 | 22,855 | ||
2023 | |||||
Future cash inflows | 114,168 | 41,307 | 155,475 | ||
Future production costs | (31,945) | (11,344) | (43,289) | ||
Future development costs1 | (10,758) | (8,216) | (18,974) | ||
Future income taxes | (27,527) | (5,375) | (32,902) | ||
Future net cash flows | 43,938 | 16,372 | 60,310 | ||
Discount at 10% per annum | (20,024) | (8,133) | (28,157) | ||
Standardised measure | 23,914 | 8,239 | 32,153 |
1. Future development costs include decommissioning.
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Changes in standardised measure are presented in the following table:
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Changes in the standardised measure | |||||
Standardised measure at the beginning of the year | 22,855 | 32,153 | 54,143 | ||
Revisions: | |||||
Prices, net of production costs | (4,995) | (12,139) | (41,132) | ||
Changes in future development costs | (2,208) | (2,695) | (2,288) | ||
Revisions of reserves quantity estimates | 3,502 | 1,848 | 3,156 | ||
Accretion of discount | 2,876 | 4,496 | 8,039 | ||
Changes in production timing and other | 347 | 662 | (707) | ||
Sales of oil and gas, net of production costs | (9,362) | (9,963) | (10,500) | ||
Sales of reserves-in-place | (107) | (3,492) | — | ||
Previously estimated development costs incurred | 4,368 | 5,061 | 5,276 | ||
Extensions, discoveries, and improved recoveries, net of future costs | 495 | 160 | 1,174 | ||
Changes in future income taxes | 2,493 | 6,764 | 14,992 | ||
Standardised measure at the end of the year | 20,264 | 22,855 | 32,153 |
Changes in reserves quantities are shown in the Reserves Statement in “Item 4. Information on the Company” of this 2025 Form 20-F.
Accounting For Suspended Exploratory Well Costs
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:
•where the expenditure relates to an exploration discovery for which the assessment of the existence or otherwise of
economically recoverable hydrocarbons is not yet complete; or
•where the expenditure is expected to be recouped through successful exploitation of the area of interest, or alternatively,
by its sale.
The costs of acquiring interests in new exploration and evaluation licences are capitalised. The costs of drilling exploration
wells are initially capitalised pending the results of the well. Costs are expensed where the well does not result in the
successful discovery of economically recoverable hydrocarbons and the recognition of an area of interest. Subsequent to the
recognition of an area of interest, all further evaluation costs relating to that area of interest are capitalised.
Upon approval for the commercial development of an area of interest, accumulated expenditure for the area of interest is
transferred to property, plant and equipment.
In the consolidated statement of cash flows, those cash flows associated with capitalised exploration and evaluation
expenditure, including unsuccessful wells, are classified as cash flows used in investing activities.
The following table provides the changes to the capitalised exploratory well costs that were pending the determination of
proved reserves for the three years ended 31 December 2025, 31 December 2024 and 31 December 2023.
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Movement in capitalised exploratory well costs1 | |||||
At the beginning of the year | 721 | 668 | 807 | ||
Additions to the capitalised exploratory well costs pending the determination of proved reserves | 80 | 90 | 169 | ||
Capitalised exploratory well costs expensed2 | (5) | (8) | (4) | ||
Capitalised exploratory well costs reclassified to wells, equipment and facilities based on the determination of proved reserves | (6) | (29) | (304) | ||
At the end of the year | 790 | 721 | 668 |
1.Suspended exploratory well costs represent capitalised exploration, evaluation and permit acquisition costs.
2.Includes amortisation of licence acquisition costs.
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The following table provides an ageing of capitalised exploratory well costs, based on the date the drilling was completed, and
the number of projects for which exploratory well costs has been capitalised for a period greater than one year since the
completion of drilling.
Exploration activity typically involves drilling multiple wells, over a number of years, to fully evaluate and appraise a project.
The term “project” as used in this disclosure refers primarily to individual wells and associated exploratory activities.
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Ageing of capitalised exploratory well costs | |||||
Exploratory well costs capitalised for a period of one year or less | 35 | 97 | 71 | ||
Exploratory well costs capitalised for a period greater than one year | 755 | 624 | 597 | ||
At the end of the year | 790 | 721 | 668 |
2025 | 2024 | 2023 | |||
Number of projects that have been capitalised for a period greater than one year | 7 | 7 | 12 |
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C.Organizational Structure
See “Item 18. Financial Statements” of this 2025 Form 20-F.
Exhibit 8.1 to this 2025 Form 20-F is incorporated herein by reference.
D.Property, Plant and Equipment
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 1.5: Global portfolio from pages 10-11
•Section 3: Our Business from pages 24-39
•Section 6.5: Asset facts from pages 281-283
See “Item 18. Financial Statements” of this 2025 Form 20-F.
ITEM 4A. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
The financial statements of Woodside have been prepared in accordance with the requirements of the International Financial Reporting
Standards (IFRS) as issued by the International Accounting Standards Board. See “Item 18. Financial Statements” of this 2025 Form 20-
F. See also “Use and reconciliation of Non-IFRS Financial Measures” for further information concerning non-IFRS financial measures
presented in this 2025 Form 20-F.
A.Operating Results
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 1: Overview from pages 4-11
•Section 2: Strategy and Financial Performance from pages 12-23
•Section 3: Our Business from pages 24-39
•Quantitative and qualitative disclosures about market risk in Section 6.3: Additional disclosures from pages 260-262
•Government regulations in Section 6.3: Additional disclosures from pages 263-271
•Material limitations in Section 6.3: Additional disclosures on page 271.
See “Item 18. Financial Statements” of this 2025 Form 20-F.
THREE-YEAR FINANCIAL ANALYSIS
Three-year Pricing Overview
Woodside’s results from operations are significantly influenced by global energy market conditions. In 2023, gas prices were
above historic averages, reflecting the lingering effects of years of underinvestment and the supply shock caused by Russia’s
invasion of Ukraine, though they began to decline following milder weather and elevated stock levels across Europe. In 2024,
despite ongoing geopolitical tensions, energy prices were range‑bound. Supported by OPEC+ market management, dated Brent
averaged $80/bbl, while LNG prices eased from earlier peaks as countries prioritised energy security and maintained storage
levels. In 2025, global energy markets stabilised amid moderate economic growth. Volatility in the oil price eased over 2025, with
increased supply from OPEC+ partially offset by Chinese stockpiling throughout the year and global geopolitical risks. Global gas
markets remained balanced in 2025, with higher imports into Europe to meet peak energy demand, especially during winter, offset
by lower imports into Asia due to Chinese demand.
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Seasonality
Woodside’s revenue is exposed to commodity price fluctuations through the sale of hydrocarbons. Commodity pricing can
be affected by seasonal energy demand movements in different markets.
Financial results | 2025 | 2024 | 2023 | ||
US$m | US$m | US$m | |||
Operating revenue | 12,984 | 13,179 | 13,994 | ||
Cost of sales | (8,448) | (7,501) | (7,519) | ||
Gross profit | 4,536 | 5,678 | 6,475 | ||
Other income | 948 | 624 | 322 | ||
Other expenses | (1,452) | (1,788) | (1,573) | ||
Net other expenses | (504) | (1,164) | (1,251) | ||
Impairment losses | (143) | – | (1,917) | ||
Impairment reversals | – | – | – | ||
Profit before tax and net finance costs | 3,889 | 4,514 | 3,307 | ||
Net finance costs | (40) | (145) | (34) | ||
Total tax expense | (1,112) | (723) | (1,551) | ||
Profit after tax | 2,737 | 3,646 | 1,722 | ||
Attributable to equity holders of the parent | 2,718 | 3,573 | 1,660 | ||
Attributable to non-controlling interests | 19 | 73 | 62 | ||
Profit for the period | 2,737 | 3,646 | 1,722 |
Woodside’s profit after tax attributable to equity holders of the parent decreased to $2,718 million in 2025 from $3,573 million in
2024 and increased compared to $1,660 million in 2023
Operating revenue decreased by $195 million, or 1%, to $12,984 million from 2024 to 2025. The decrease was primarily due to
lower average Brent, WTI and JCC price markers, natural field decline at NWS and divestment of Greater Angostura assets offset
by a full year of Sangomar operations and more third-party trades. Operating revenue decreased by $815 million, or 6%, from
2023 to 2024. The decrease was primarily due to lower average Brent, WTI, TTF, and JKM price markers, natural field decline at
Bass Strait and NWS, Trinidad planned turnaround and reduced third-party trades offset by the start of production at Sangomar.
Cost of sales increased by $947 million, or 13%, to $8,448 million from 2024 to 2025, primarily due to a full year of Sangomar
operations and more third-party trades offset by lower NWS depreciation due to natural field decline and lower royalties, excise
and levies driven by lower prices. Cost of sales decreased by $18 million, or nil per cent movement, from 2023 to 2024, primarily
due to fewer external LNG trades and lower royalties, excise and levies driven by lower prices offset by cost of sales associated
with Sangomar’s first production.
Net other expenses decreased by $660 million, or 57%, to $504 million from 2024 to 2025, primarily due to a fair value gain on
remeasurement of the Perdaman embedded derivative, gain on hedging activities and profit on sale of Greater Angostura assets
offset by increased restoration provision estimates at closed sites. Net other expenses decreased by $87 million, or 7%, from 2023
to 2024, primarily due to a fair value reduction on remeasurement of the Perdaman embedded derivative and increased restoration
provision estimates at closed sites offset by lower losses on hedging activities and profit on the sell-down of non-operating
interests in Scarborough to LNG Japan and JERA.
In 2025, an impairment loss totalling $143 million was recognised on the H2OK Project, compared to no impairment losses in
2024. An impairment loss totalling $1,917 million was recognised on the Shenzi, Wheatstone and Pyrenees assets in 2023. For
more information on impairment refer to Note B.4 Impairment of exploration and evaluation, property, plant and equipment and
goodwill in Section"Item 17. Financial Statements".
Net finance costs decreased by $105 million, or 72%, to $40 million from 2024 to 2025, primarily due to interest capitalised on
the Louisiana LNG and Scarborough projects. Net finance costs increased by $111 million, or 326%, from 2023 to 2024,
primarily due to reduced average cash in term deposits and higher debt drawdown.
Total tax expense comprises income tax and petroleum resource rent tax (PRRT). Income tax expense decreased by $51 million,
or6%, to $763 million from 2024 to 2025, primarily due to lower taxable profit and recognition of a deferred tax asset (DTA) on
Louisiana LNG final investment decision (FID) offset by the recognition of a DTA on Sangomar first production and the tax base
associated with the Scarborough sell-down to JERA in 2024. PRRT expense increased by $440 million, or 484%, to $349 million
from 2024 to 2025, primarily due to the PRRT DTA recognised at Pluto in 2024. Income tax expense increased by $161 million,
or 25%, from 2023 to 2024, driven by higher taxable profit. PRRT expense decreased by $989 million, or 110%, from 2023 to
2024, primarily due to the movement in a Pluto PRRT DTA which was derecognised in 2023 and reinstated in 2024 due to an
increase in forecast assessable income due to higher prices.
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Volumes, realised prices and operating revenues by product
The following describes movements in Woodside’s operating revenues including a discussion of production volumes, sales
volumes and realised prices for the years ended 31 December 2025, 2024 and 2023.
Units | 2025 | 2024 | 2023 | |||||
Production volumes1 | ||||||||
LNG | Bcf | 450.9 | 487.3 | 505.0 | ||||
Pipeline gas | Bcf | 206.1 | 219.6 | 226.3 | ||||
Crude oil and condensate | MMbbl | 77.9 | 63.2 | 51.8 | ||||
NGLs | MMbbl | 5.7 | 6.6 | 7.1 | ||||
Total production2 | MMboe | 198.8 | 193.9 | 187.2 | ||||
Sales volumes3,4 | ||||||||
LNG5 | Bcf | 533.1 | 550.2 | 592.7 | ||||
Pipeline gas | Bcf | 203.3 | 215.5 | 225.7 | ||||
Crude oil and condensate | MMbbl | 77.3 | 63.2 | 50.3 | ||||
NGLs | MMbbl | 5.7 | 6.4 | 7.1 | ||||
Total sales volumes2,5 | MMboe | 212.2 | 204.0 | 201.1 | ||||
Units | 2025 | 2024 | 2023 | |||||
Average realised prices4 | ||||||||
LNG5 | $/Mcf | 11.2 | 11.6 | 13.8 | ||||
Pipeline gas | $/Mcf | 6.5 | 6.3 | 6.1 | ||||
Crude oil and condensate | $/bbl | 68.0 | 77.2 | 79.0 | ||||
NGLs | $/bbl | 42.2 | 48.0 | 39.5 | ||||
Volume - weighted average5 | $/boe | 60.2 | 63.4 | 68.6 | ||||
Operating revenue3,4 | ||||||||
LNG | $m | 5,960 | 6,401 | 8,165 | ||||
Pipeline gas | $m | 1,324 | 1,349 | 1,374 | ||||
Crude oil and condensate | $m | 5,257 | 4,887 | 3,981 | ||||
NGLs | $m | 241 | 306 | 281 | ||||
Other revenue | $m | 202 | 236 | 193 | ||||
Operating revenue | $m | 12,984 | 13,179 | 13,994 | ||||
1.Production volumes for 2025, 2024 and 2023 include 1.2 MMboe, 1.2 MMboe and 1.1 MMboe, respectively, of production from feed gas
purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.
2.LNG and Pipeline gas volumes are converted to oil equivalent volumes via a constant conversion factor, which for Woodside is 5.7 billion
cubic feet (bcf) of gas per 1 million barrel of oil equivalent (MMboe). Volumes of NGLs, oil and condensate are converted from MMbbl to
MMboe on a 1:1 ratio.
3.Sales volumes for 2025, 2024 and 2023 include 18.3 MMboe, 12.3 MMboe and 15.6 MMboe, respectively, of purchased volumes sourced
from third parties. These third-party volumes are primarily LNG cargoes purchased from Corpus Christi LNG through a long-term offtake
agreement and from the spot market. Sales volumes also include feed gas purchased from Pluto non-operating participants processed through
the Pluto-KGP Interconnector.
4.Sales volumes differ from production volumes primarily due to the timing of liftings and the exclusion of third-party purchased volumes.
Average realised prices and operating revenue include third-party purchased volumes.
5.Sales volumes exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales. The 2024 and 2023 comparatives
for sales volume and average realised price have been restated to be presented on the same basis.
LNG
Revenue from the sale of LNG decreased by $441 million, or 7%, to $5,960 million from 2024 to 2025, primarily due to decreases
in Brent and JCC price markers and lower volumes due to NWS natural field decline offset by more third-party trades.
Revenue from the sale of LNG decreased by $1,764 million, or 22%, from 2023 to 2024, primarily due to decreases in Brent, JCC
JKM and TTF price markers and lower volumes due to NWS natural field decline.
Pipeline gas
Revenue from the sale of pipeline gas decreased by $25 million, or 2%, to $1,324 million from 2024 to 2025, primarily due to
divestment of Greater Angostura assets offset by higher Australian demand.
Revenue from the sale of pipeline gas decreased by $25 million, or 2%, from 2023 to 2024, primarily due to Bass Strait natural
field decline, planned turnaround and lower prices at Trinidad.
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Crude oil and condensate
Revenue from the sale of crude oil and condensate increased by $370 million, or 8%, to $5,257 million from 2024 to 2025,
primarily due to a full year of Sangomar operations offset by a decrease in Brent and WTI price markers.
Revenue from the sale of crude oil and condensate increased by $906 million, or 23%, from 2023 to 2024, primarily due to
Sangomar first production.
NGLs
Revenue from the sale of NGLs decreased by $65 million, or 21%, to $241 million from 2024 to 2025, due to lower prices and
traded volumes via third party purchases.
Revenue from the sale of NGLs increased by $25 million, or 9%, from 2023 to 2024, due to higher traded volumes via third
party purchases.
Other revenue
Other revenue comprises of processing and services tariff revenue received from non-controlling interests and plant processing
fees.
Performance by segment
Woodside has identified its operating segments based on the internal reports that are reviewed and used by the Chief Executive
Officer to assess performance and allocate resources within the business. For more information on our reportable segments, please
refer to Note A.1 Segment revenue and expenses in “Item 18. Financial Statements” of this 2025 Form 20-F.
As the Group continues to invest in new energy and integrate these activities across its operations, changes have been made to the
way financial information is presented. New energy projects that have reached a final investment decision (FID) are now reported
within either the Australia or International segments, depending on their geographical location.
The Group’s disclosed operating segments have been updated to reflect this change, and the comparative information for 2024 and
2023 has been restated to ensure consistency of presentation.
The performance of operating segments is evaluated based on profit before tax and net finance costs, and is measured in
accordance with Woodside’s accounting policies. Financing requirements, including cash and debt balances, finance income,
finance costs and taxes for Woodside and its subsidiaries are managed at a Group level.
Australia
Detailed below is the financial and operating information for our Australian operations comparing 2025, 2024 and 2023.
Key metric | Units | 2025 | 2024 | 2023 | ||||
Operating revenue | $m | 7,501 | 8,541 | 9,802 | ||||
Profit before tax and net finance costs | $m | 3,118 | 4,614 | 4,487 | ||||
Total production | MMboe | 131.5 | 139.5 | 145.1 | ||||
Average realised prices | ||||||||
LNG1 | $/Mcf | 10.6 | 11.0 | 13.5 | ||||
Pipeline gas | $/Mcf | 6.9 | 7.1 | 6.8 | ||||
Crude oil and condensate | $/bbl | 69.4 | 78.7 | 80.0 | ||||
Natural gas liquids | $/bbl | 47.3 | 51.2 | 39.1 |
1.Sales volumes exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales. The 2024 and 2023 comparatives
for sales volume and average realised price have been restated to be presented on the same basis.
Financial results
Operating revenue decreased by $1,040 million, or 12%, to $7,501 million from 2024 to 2025, primarily due to lower Brent and
JCC price markers and NWS natural field decline. The section entitled “Three-year pricing overview” has more information.
Profit before tax and net finance costs decreased by $1,496 million, or 32%, to $3,118 million from 2024 to 2025, primarily due to
lower operating revenue, profit from the sale of non-operating interests in the Scarborough Project in 2024 and restoration
provision updates.
Operating revenue decreased by $1,261 million, from 2023 to 2024 primarily due to lower LNG realised prices and natural field
decline of Bass Strait and NWS, partially offset by higher realised prices for pipeline gas and NGL, planned turnaround activities
in 2023 and higher Wheatstone mitigation cargoes
Profit before tax and net finance costs increased by $127 million, or 3%, from 2023 to 2024 primarily due to pre-tax impairments
incurred in 2023 and profit from the sale of non-operating interest in the Scarborough Project, partially offset by lower prices.
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Production
Production volumes for the Australia segment decreased by 8.0 MMboe, or 6%, to 131.5 MMboe from 2024 to 2025, primarily
due to natural field decline and impact of tropical weather at NWS.
Production volumes for the Australia segment decreased by 5.6 MMboe, or 4%, from 2023 to 2024, primarily due to natural field
decline at Bass Strait and NWS partially offset by absence of Pluto planned turnaround activities.
International
Financial and operating information for our international operations comparing 2025, 2024 and 2023 is detailed below.
Key metric | Units | 2025 | 2024 | 2023 | ||||
Operating revenue | $m | 4,069 | 3,405 | 2,549 | ||||
Profit/(loss) before tax and net finance costs | $m | 836 | 601 | (808) | ||||
Total production | MMboe | 67.3 | 54.4 | 42.1 | ||||
Average realised prices | ||||||||
Pipeline gas | $/Mcf | 4.5 | 4.0 | 4.3 | ||||
Crude oil and condensate | $/bbl | 66.9 | 75.3 | 76.8 | ||||
Natural gas liquids | $/bbl | 21.4 | 24.8 | 21.1 |
Financial results
Operating revenue increased by $664 million, or 20%, to $4,069 million from 2024 to 2025, primarily due to a full year
of Sangomar operations offset by lower WTI prices.
Profit before tax and net finance costs increased by $235 million, or 39%, to $836 million primarily due to a full year of
Sangomar operations, gain on sale of Greater Angostura assets and exploration write offs in 2024.
Operating revenue increased by $856 million, or 34%, from 2023 to 2024, primarily due to the start of production at Sangomar
partially offset by planned turnaround and timing of crude lifts at Trinidad.
Profit before tax and net finance costs increased by $1,409 million, or 174%, from 2023 to 2024, primarily due to the absence of
pre-tax impairment of the Shenzi asset of $1,383 million.
Production
Production volumes for the International segment increased by 12.9 MMboe, or 24%, to 67.3 MMboe from 2024 to 2025,
primarily due to a full year of Sangomar operations offset by divestment of Greater Angostura assets.
Production volumes for the International segment increased by 12.3 MMboe, or 29%, from 2023 to 2024, primarily due to the
start of production at Sangomar.
Marketing
Financial and operating information for our marketing operations comparing 2025, 2024 and 2023 is detailed below.
Key metric | Units | 2025 | 2024 | 2023 | |||
Operating revenue | $m | 1,414 | 1,233 | 1,643 | |||
Profit before tax and net finance costs | $m | 308 | 427 | 375 | |||
Average realised prices | |||||||
LNG | $/Mcf | 12.9 | 12.1 | 13.4 | |||
Liquids | $/boe | 57.9 | 61.5 | 78.9 |
Financial results
Operating revenue increased by $181 million, or 15%, to $1,414 million from 2024 to 2025, primarily due to more third‑party
trades.
Profit before tax and net finance costs decreased by $119 million, or 28%, to $308 million from 2024 to 2025, primarily due to
hedge losses and lower average realised price offset by more third-party trades.
Operating revenue decreased by $410 million, or 25%, from 2023 to 2024, primarily due to lower average realised price and fewer
third-party trades.
Profit before tax and net finance costs increased by $52 million, or 14%, from 2023 to 2024, primarily due to higher volumes
marketed and hedge gains partially offset by lower average realised price.
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Corporate items
Financial information for our Corporate items comparing 2025, 2024 and 2023 is detailed below.
Key metric | Units | 2025 | 2024 | 2023 | |||
Loss before tax and net finance costs | $m | (373) | (1,128) | (747) |
Loss before tax and net finance costs decreased by $755 million, or 67%, to $373 million from 2024 to 2025, primarily due to a
fair value gain on remeasurement of the Perdaman embedded derivative and a gain on hedging activities.
Loss before tax and net finance costs increased by $381 million, or 51%, from 2023 to 2024, primarily due to a fair value
reduction on remeasurement of the Perdaman embedded derivative.
CAPITAL AND EXPLORATION EXPENDITURE
Woodside’s capital expenditures vary from year to year depending on the projects that it is undertaking, their stage
of development and Woodside’s participating share in these projects and contractual arrangements with project participants.
Woodside’s exploration expenditures vary from year to year depending on its strategic priorities and the exploration projects
which it undertakes.
For more information, refer to notes B.1 Segment production and growth assets, B.2 Exploration and evaluation and B.3 Property,
plant and equipment in “Item 18. Financial Statements” of this 2025 Form 20-F.
Capital and exploration expenditure is an alternative performance measure (APM) which is a non-IFRS measure that is unaudited.
Woodside believes this non-IFRS measure provides useful performance information, however it should not be considered as an
indication of, or as a substitute for, statutory measures as an indicator of actual operating performance (such as net profit after tax
or net cash from operating activities) or any other measure of financial performance or position presented in accordance with
IFRS. For more information on non-IFRS measures, including reconciliations to Woodside’s Financial Statements, refer to
Alternative performance measures.
Capital and exploration expenditure geographical split1,2
Units | 2025 | 2024 | 2023 | ||||
Australia | $m | 2,328 | 3,284 | 3,503 | |||
International3,4 | $m | 2,577 | 2,349 | 2,570 | |||
Total | $m | 4,905 | 5,633 | 6,073 |
1.Includes capital additions on other corporate spend.
2.Capital and exploration expenditure definition has been updated to adjust for evaluation expenditure. The 2024 and 2023 comparatives have
been restated to be presented on the same basis.
3.Net of capital contributions from non-controlling interests for the development of Louisiana LNG.
4.Capital and exploration expenditure incurred in all other locations excluding Australia.
Australian capital and exploration expenditure decreased by $956 million, or 29%, to $2,328 million from 2024 to 2025, primarily
due to the lower upstream equity share in 2025 and milestones achieved in 2024 for the Scarborough project, offset by drilling
activity at Wheatstone JDP3.
Australian capital and exploration expenditure decreased by $219 million, or 6%, from 2023 to 2024, primarily due to the sell
down of non-operating interests in Scarborough partially offset by continued investment in Pluto Train 2 asset.
International capital and exploration expenditure increased by $228 million, or 10%, to $2,577 million from 2024 to 2025,
primarily due to investment in Louisiana LNG, net of capital contributions from non-controlling interests, as well as the continued
investment in Atlantis, Trion and Argos offset by completion of the Sangomar project in 2024.
International capital and exploration expenditure decreased by $221 million, or 9%, from 2023 to 2024, primarily due to
completion of the Sangomar project in 2024 and Argos Phase 2 in 2023, completion of Shenzi North in 2023 and less drilling
activity at Atlantis partially offset by continued investment into the Trion asset.
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CASH FLOW ANALYSIS
The following section describes movements in Woodside’s cash flows for the years ending 31 December 2025, 2024 and 2023.
2025 | 2024 | 2023 | |||
$m | $m | $m | |||
Net cash from operating activities | 7,192 | 5,847 | 6,145 | ||
Net cash used in investing activities | (7,911) | (5,747) | (5,585) | ||
Net cash from/(used in) financing activities | 2,491 | 2,101 | (5,000) | ||
Net increase/(decrease) in cash held | 1,772 | 2,201 | (4,440) |
Net cash from operating activities
Net cash from operating activities increased by $1,345 million, or 23%, to $7,192 million from 2024, primarily due to lower
income tax and PRRT paid driven by lower realised prices and Australian production volumes, and timing of payments.
Net cash from operating activities decreased by $298 million, or 5%, from 2023 to 2024, primarily due to higher payments
for restoration ($358 million) and return of collateral on Brent hedges in 2023 ($506 million), offset by lower settled hedge
payments ($311 million) and lower income tax paid largely due to a balancing income tax payment in 2023 for record 2022
profits ($361 million).
Net cash used in investing activities
Net cash used in investing activities increased by $2,164 million, or 38%, to $7,911 million from 2024 to 2025, primarily due to
capital spend on the Louisiana LNG project ($3,658 million), Scarborough sell-downs in 2024 and additional debt draw down
offset by the acquisitions of Beaumont New Ammonia and Louisiana LNG in 2024.
Net cash used in investing activities increased by $162 million, or 3%, from 2023 to 2024, primarily due to the acquisition
of Beaumont New Ammonia ($1,896 million) and Louisiana LNG ($1,042 million) offset in part by the Scarborough sell-downs
to LNG Japan and JERA Scarborough Pty Ltd ($2,285 million).
Net cash from/(used in) financing activities
Net cash from financing activities increased $390 million, or 19%, to $2,491 million from 2024 to 2025, primarily due to cash
contributions from Stonepeak and Williams for the Louisiana LNG sell-downs ($2,862 million), lower dividend paid to
shareholders ($437 million) offset by repayment bilaterial facilities ($1,900 million) and bonds ($1,000 million).
Net cash from financing activities increased $7,101, or 142%, from 2023 to 2024, primarily due to lower final prior year dividend
paid to shareholders ($1,804 million) due to the record 2022 net profit after tax, issue of two series of unsecured bonds ($2,000
million), drawdown of syndicated term loan facilities ($1,650 million), drawdown of JBIC Facility ($1,000 million) and
drawdown of bilateral facilities ($500 million).
B.Liquidity and capital resources
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 2.2: Capital management from pages 14-16
•Section 2.3: Financial overview from pages 17-18
•Exchange controls in Section 6.4: Shareholder statistics on pages 276
See Three-Year Financial Analysis in “Item 5.A Operating Results” of this 2025 Form 20-F.
See notes B.3, C. and D.7 in “Item 18. Financial Statements” of this 2025 Form 20-F.
C.Research and development, Patents and Licences, etc.
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 3: Our Business from pages 24-39
•Research and development in Section 4.2: Directors’ report on page 143.
D.Trend information
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 2.3: Financial overview from pages 17-18.
See Three-Year Financial Analysis in “Item 5.A Operating Results” and “Item 18. Financial Statements” of this 2025 Form 20-F.
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E.Critical Accounting Estimates
Not Applicable.
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A.Directors and Senior Management
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 4.1.2: Board of directors from pages 119-127
•Section 4.1.3: Board Committees from pages 128-129
•Section 4.1.4: Executive Leadership Team from pages 130-131.
B.Compensation
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 4.3: Remuneration Report from pages 146-175.
See Note E.2 in “Item 18. Financial Statements” of this 2025 Form 20-F.
C.Board Practices
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 4.1: Corporate Governance Statement from pages 116-141.
D.Employees
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Employees in Section 6.3: Additional disclosures on page 260.
E.Share Ownership
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 4.3: Remuneration Report from pages 146-175.
See Note E.2 in “Item 18. Financial Statements” of this 2025 Form 20-F.
F.Disclosure of a registrant’s action to recover erroneously awarded compensation
Not applicable.
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
A.Major shareholders
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 6.4: Shareholder statistics from pages 272-273.
B.Related Party Transactions
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 4.3: Remuneration Report from pages 146-175.
See Note E.3 in “Item 18. Financial Statements” of this 2025 Form 20-F.
C.Interests of Experts and Counsel
Not applicable.
ITEM 8. FINANCIAL INFORMATION
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A.Consolidated Statements and Other Financial Information
The information set forth under the following heading of the 2025 Annual Report is incorporated herein by reference:
•Capital management in Section 2.2: Capital management on page 14-16
•Summary of material legal proceedings in Section 6.3: Additional disclosures on page 271
•Dividend payments in Section 6.4: Shareholder statistics on page 274.
See “Item 18. Financial Statements” of this 2025 Form 20-F.
B.Significant Changes
See Note E.5 in “Item 18. Financial Statements” of this 2025 Form 20-F.
ITEM 9. THE OFFER AND LISTING
A.Offer and Listing Details
The information set forth under the following heading of the 2025 Annual Report is incorporated herein by reference:
•Section 6.4: Shareholder statistics from pages 272-273.
Exhibit 2.1 to this 2025 Form 20-F is incorporated herein by reference.
B.Plan of Distribution
Not applicable.
C.Markets
The information set forth under the following heading of the 2025 Annual Report is incorporated herein by reference:
•Section 6.4: Shareholder statistics from pages 272-273.
D.Selling Shareholders
Not applicable.
E.Dilution
Not applicable.
F.Expenses of the Issue
Not applicable.
ITEM 10. ADDITIONAL INFORMATION
A.Share Capital
Not applicable.
B.Memorandum and Articles of Association
Exhibit 2.1 to this 2025 Form 20-F is incorporated herein by reference.
C.Material Contracts
Exhibit 4.1 to this 2025 Form 20-F is incorporated herein by reference.
D.Exchange controls
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Exchange Controls in Section 6.4: Shareholder statistics on page 276.
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E.
Taxation
This section describes the material United States and Australian Federal income tax consequences to a US holder (as defined
below) of owning shares or ADSs. It applies to you only if you acquire your shares or ADSs and you hold your shares or ADSs as
capital assets for tax purposes. This discussion addresses only United States and Australian Federal income taxation and does not
discuss all of the tax consequences that may be relevant to you in light of your individual circumstances, including foreign, state
or local tax consequences, estate and gift tax consequences, and tax consequences arising under the Medicare contribution tax on
net investment income or the alternative minimum tax. This section does not apply to you if you are a member of a special class of
holders subject to special rules, including:
•a dealer in securities,
•a trader in securities that elects to use a mark-to-market method of accounting for securities holdings,
•a tax-exempt organisation,
•a life insurance company,
•a person that actually or constructively owns 10% or more of the combined voting power of our voting stock or of the
total value of our stock,
•a person that holds shares or ADSs as part of a straddle or a hedging or conversion transaction,
•a person that purchases or sells shares or ADSs as part of a wash sale for tax purposes, or
•a person whose functional currency is not the US dollar.
This section is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations,
published rulings and court decisions, all as currently in effect, as well as on the Convention Between the United States of
America and Australia (the “Treaty”). These authorities are subject to change, possibly on a retroactive basis. In addition, this
section is based in part upon the representations of the Depositary and the assumption that each obligation in the deposit
agreement will be performed in accordance with its terms.
You are a US holder if you are a beneficial owner of shares or ADSs and you are, for United States Federal income tax purposes:
•a citizen or resident of the United States,
•a domestic corporation,
•an estate whose income is subject to United States Federal income tax regardless of its source, or
•a trust if a United States court can exercise primary supervision over the trust’s administration and one or more United
States persons are authorised to control all substantial decisions of the trust.
If an entity or arrangement that is treated as a partnership for United States Federal income tax purposes holds the shares or ADSs,
the United States Federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment
of the partnership. A partner in a partnership holding the shares or ADSs should consult its tax advisor with regard to the United
States Federal income tax treatment of an investment in the shares or ADSs.
You should consult your own tax advisor regarding the United States Federal, state and local and Australian Federal tax
consequences of owning and disposing of shares and ADSs in your particular circumstances. In particular, you should confirm
whether you qualify for the benefits of the Treaty and the consequences of failing to do so.
In general, and taking into account the earlier assumptions, for United States Federal income tax purposes, if you hold ADRs
evidencing ADSs, you will be treated as the owner of the shares represented by those ADRs.
Exchanges of shares for ADRs, and ADRs for shares, generally will not be subject to United States Federal income tax.
Material United States Federal income tax consequences
The tax treatment of your shares or ADSs will depend in part on whether or not we are classified as a passive foreign investment
company, or PFIC, for United States Federal income tax purposes. Except as discussed below under “PFIC Classification”, this
discussion assumes that we are not classified as a PFIC for United States Federal income tax purposes.
Taxation of distributions
Under the United States Federal income tax laws, the gross amount of any distribution we pay out of our current or accumulated
earnings and profits (as determined for United States Federal income tax purposes), other than certain pro-rata distributions of our
shares, will be treated as a dividend that is subject to United States Federal income taxation. If you are a non-corporate US holder,
dividends that constitute qualified dividend income will be taxable to you at the preferential rates applicable to long-term capital
gains provided that you hold the shares or ADSs for more than 60 days during the 121-day period beginning 60 days before the
ex-dividend date and meet other holding period requirements.
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Dividends we pay with respect to the shares or ADSs generally will be qualified dividend income provided that, in the year that
you receive the dividend, we are eligible for the benefits of the Treaty. We believe that we are currently eligible for the benefits of
the Treaty, and we therefore expect that dividends on the shares and ADS will be qualified dividend income, but there can be no
assurance that we will continue to be eligible for the benefits of the Treaty.
You must include any Australian tax withheld from the dividend payment in this gross amount even though you do not in fact
receive it. The dividend is taxable to you when you, in the case of shares, or the Depositary, in the case of ADSs, receive the
dividend, actually or constructively. The dividend will not be eligible for the dividends-received deduction generally allowed to
United States corporations in respect of dividends received from other United States corporations. The amount of the dividend
distribution that you must include in your income will be the US dollar value of the Australian dollar payments made, determined
at the spot Australian dollar/US dollar rate on the date the dividend is distributed, regardless of whether the payment is in fact
converted into US dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the
date the dividend is distributed to the date you convert the payment into US dollars will be treated as ordinary income or loss and
will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or
loss from sources within the United States for foreign tax credit limitation purposes. Distributions in excess of current and
accumulated earnings and profits, as determined for United States Federal income tax purposes, will be treated as a non‑taxable
return of capital to the extent of your basis in the shares or ADSs and thereafter as capital gain. However, we do not expect to
calculate earnings and profits in accordance with United States Federal income tax principles. Accordingly, you should expect to
generally treat distributions we make as dividends.
Subject to certain limitations, the Australian tax withheld in accordance with the Treaty and paid over to Australia will generally
be creditable against your United States Federal income tax liability. To the extent a reduction or refund of the tax withheld is
available to you under Australian law or under the Treaty, the amount of tax withheld that could have been reduced or that is
refundable will not be eligible for credit against your United States Federal income tax liability.
Dividends will generally be income from sources outside the United States and will generally be “passive” income for purposes of
computing the foreign tax credit allowable to you.
Taxation of capital gains
If you are a US holder and you sell or otherwise dispose of your shares or ADSs, you will recognise capital gain or loss for United
States Federal income tax purposes equal to the difference between the US dollar value of the amount that you realise and your
tax basis, determined in US dollars, in your shares or ADSs. Your tax basis would generally equal the cost of your shares or
ADSs, or if you received the shares or ADSs pursuant to a taxable distribution, the fair market value of the shares or ADSs at the
time of such distribution, reduced by any distributions on the shares or ADSs that were treated as a return of capital for
United States Federal income tax purposes. Capital gain of a non‑corporate US holder is generally taxed at preferential rates
where the property is held for more than one year. The gain or loss will generally be income or loss from sources within the
United States for foreign tax credit limitation purposes. Your ability to deduct capital losses is subject to limitations.
Passive foreign investment company classification
We believe that we should not be currently classified as a PFIC for United States Federal income tax purposes and we do not
expect to become a PFIC in the foreseeable future. However, this conclusion is a factual determination that is made annually and
thus may be subject to change. It is therefore possible that we could become a PFIC in a future taxable year.
In general, we will be a PFIC in a taxable year if:
•at least 75% of our gross income for the taxable year is passive income; or
•at least 50% of the value, determined on the basis of a quarterly average, of our assets in such taxable year is
attributable to assets that produce or are held for the production of passive income.
If we were to be treated as a PFIC and you are a US holder, gain realised on the sale or other disposition of your shares or ADSs
would in general not be treated as capital gain. Instead, you would generally be treated as if you had realised such gain and certain
“excess distributions” ratably over your holding period for the shares or ADSs and would be taxed at the highest tax rate in effect
for each previous year to which the gain was allocated in which we were a PFIC with respect to you, together with an interest
charge in respect of the tax attributable to each such year. With certain exceptions, your shares or ADSs will be treated as stock in
a PFIC if we were a PFIC at any time during your holding period in your shares or ADSs. Dividends that you receive from us will
not be eligible for the special tax rates applicable to qualified dividend income if we are a PFIC or are treated as a PFIC with
respect to you either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates
applicable to ordinary income. If you own shares or ADSs during any year that we are a PFIC with respect to you, you may be
required to file Internal Revenue Service (‘IRS’) Form 8621.
Material Australian tax considerations
This section is based on the Income Tax Assessment Act 1936(Cth) and the Income Tax Assessment Act 1997 (Cth), as amended,
its legislative history, existing and proposed regulations, published rulings and court decisions, all as currently in effect, as well as
on the Convention Between the United States of America and Australia (the “Treaty”). These authorities are subject to change,
possibly on a retroactive basis.
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Dividends (including other distributions treated as dividends for Australian tax purposes) paid by Woodside to a US holder that
is not an Australian resident for Australian tax purposes will generally not be subject to Australian withholding tax if they are
fully franked (broadly, where a dividend is franked, tax paid by Woodside is imputed to the shareholders).
Dividends paid to such US holders, which are not fully franked, will generally be subject to Australian withholding tax not
exceeding 15% only to the extent (if any) that the dividend is neither:
•franked; nor
•declared by Woodside to be conduit foreign income. (Broadly, this means that the relevant part of the dividend is
declared to have been paid out of foreign source amounts received by Woodside that are not subject to tax in Australia,
such as dividends remitted to Australia by foreign subsidiaries).
The Australian withholding tax outcome described above applies to US holders who are eligible for benefits under the Tax
Convention between Australia and the US as to the Avoidance of Double Taxation (the Australian Tax Treaty). Otherwise, the
rate of Australian withholding tax may be 30%.
In contrast, dividends (including other distributions treated as dividends for Australian tax purposes) paid by Woodside to a US
holder may instead be taxed by assessment in Australia if the US holder:
•is an Australian resident for Australian tax purposes (although tax will generally not exceed 15% where the US holder is
eligible for benefits under the Australian Tax Treaty as a treaty resident of the US and any franking credits may be
creditable against their Australian income tax liability); or
•carries on business in Australia through a permanent establishment as defined in the Australian Tax Treaty, or performs
personal services from a fixed base in Australia, and the shareholding in respect of which the dividend is paid is
effectively connected with that permanent establishment or fixed base, (however, in such a case any franking credits
may be creditable against the Australian income tax liability).
The treatment of dividends outlined above may be modified where the shareholding in Woodside is held through a trust, limited
partnership, limited liability company, pension fund, sovereign wealth fund or other investment vehicle. Affected US holders
should seek their own advice in relation to such arrangements.
Material Australian tax considerations –
disposals of Shares or ADSs
Gains made by US holders on the sale of shares or ADSs will generally not be taxed in Australia.
However, the precise Australian tax treatment of gains made by US holders on the sale of shares or ADSs generally depends on
whether or not the gain is an Australian sourced gain of an income nature for Australian income tax purposes. Where the gain is of
an income nature, a US holder will generally only be liable to Australian income tax on an assessment basis (whether or not they
are also an Australian resident for Australian tax purposes) if:
•they are not eligible for benefits under the Australian Tax Treaty and the gain is sourced in Australia for Australian tax
purposes; or
•they are eligible for benefits under the Australian Tax Treaty, but the gain constitutes any of the following (in which
case the gain will be deemed to have an Australian source):
◦business profits of an enterprise attributable to a permanent establishment situated in Australia through which the
enterprise carries on business in Australia; or
◦income or gains from the alienation of property that form part of the business property of a permanent
establishment of an enterprise that the US holder has in Australia or pertain to a fixed base available to the US
holder in Australia for the purpose of performing independent personal services; or
◦income derived from the disposition of shares in a company, the assets of which consist wholly or principally of
real property (which includes rights to exploit or to explore for nature resources) situated in Australia, whether such
assets are held directly or indirectly through one or more interposed entities.
Where the gain is not taxed as Australian sourced income, the US holder will generally only be liable to Australian capital gains
tax on an assessment basis if they acquired (or are deemed to have acquired) their shares or ADSs after 19 September 1985 and
one or more of the following applies:
•the US holder is an Australian resident for Australian tax purposes; or
•the shares or ADSs have been used by the US holder in carrying on a business through permanent establishment in
Australia; or
•the shares or ADSs constitute an “indirect Australian real properly interest” for Australian CGT purposes – this will
generally be the case if the US holder (either alone or together with associates) directly or indirectly owns or owned
10% or more of the issued share capital of Woodside at the time of disposal or throughout a 12-month period during the
two years prior to the time of disposal and, at the time of the disposal, the sum of market values of Woodside’s assets
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(held directly or through interposed entities) that are not taxable Australian real property at that time (which, for these
purposes includes mining, quarrying or prospecting rights in respect of minerals, petroleum or quarry materials situated
in Australia); or
•the US holder is an individual who is not eligible for benefits under the Australian Tax Treaty as a treaty resident of the
US and elected on becoming a non-resident of Australia to continue to have the shares or ADSs subject to Australian
capital gains tax.
In certain circumstances, if the shares or ADSs constitute an “indirect Australian real property interest” for Australian CGT
purposes, the purchaser may be required to withhold under the non-resident CGT withholding regime an amount equal to 15% of
the purchase price in situations including where the acquisition is undertaken by way of an off-market transfer.
The comments above on the sale of shares or ADSs do not apply:
•to temporary residents of Australia who should seek advice that is specific to their circumstances; or
•if the Investment Management Regime (IMR) applies to the US holder, which exempts from the Australian income tax
and capital gains tax gains made on disposal by certain categories of non-resident funds – called IMR entities – of
(relevantly) portfolio interests in Australian public companies (subject to a number of conditions). The IMR exemptions
broadly apply to widely held IMR entities in relation to their direct investments and indirect investments made through
an independent Australian fund manager. The exemptions apply to gains made by IMR entities that are treated as
companies for Australian tax purposes as well as gains made by non-resident investors in IMR entities that are treated
as trusts and partnerships for Australian tax purposes.
THE FOREGOING DISCUSSION IS NOT TAX ADVICE OR A COMPREHENSIVE DISCUSSION OF ALL US AND
AUSTRALIAN FEDERAL INCOME TAX CONSEQUENCES TO US HOLDERS OF SHARES OR AMERICAN
DEPOSITORY SHARES. SUCH HOLDERS SHOULD CONSULT WITH, AND RELY SOLELY UPON, THEIR OWN TAX
ADVISERS TO DETERMINE THE SPECIFIC TAX CONSEQUENCES TO THEM OF THE OWNERSHIP AND
DISPOSITION OF SHARES OR AMERICAN DEPOSITORY SHARES, INCLUDING THE EFFECT OF ANY US FEDERAL,
STATE, LOCAL, NON-US, OR OTHER TAX LAWS.
F.Dividends and Paying Agents
Not applicable.
G.Statement by Experts
Not applicable.
H.Documents on Display
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Documents on display in Section 6.4: Shareholder statistics on page 274.
I.Subsidiary Information
See Note E.8 in “Item 18. Financial Statements” of this 2025 Form 20-F.
Exhibit 8.1 to this 2025 Form 20-F is incorporated herein by reference.
J.Annual Report to Security Holders.
Not applicable.
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Quantitative and qualitative disclosures about market risk in Section 6.3: Additional disclosures from pages 260-262.
See Notes A and C in “Item 18. Financial Statements” of this 2025 Form 20-F.
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
A.Debt Securities
Not applicable.
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B.Warrants and Rights
Not applicable.
C.Other Securities
Not applicable.
D.American Depositary Shares
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•American Depositary Receipts in Section 6.4: Shareholder statistics on page 275
•Fees Payable by the Depositary to the Issuer in Section 6.4: Shareholder statistics on page 275.
Exhibit 2.1 to this 2025 Form 20-F is incorporated herein by reference.
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PART II
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
Not applicable.
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE
OF PROCEEDS
Not applicable.
ITEM 15. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Woodside’s management, with the participation of its CEO and CFO, have evaluated, as required by Rule 13a-15(b) under the US
Securities Exchange Act of 1934 (Exchange Act), the effectiveness of Woodside’s disclosure controls and procedures (as defined in
Exchange Act Rule 13a-15(e)) as at 31 December 2025. Based on that evaluation, the CEO and CFO have concluded that Woodside's
disclosure controls and procedures were effective, as at 31 December 2025. In designing and evaluating our disclosure controls and
procedures, our management, with the participation of the CEO and CFO, recognised that any controls and procedures, no matter how
well designed and operated, can only provide reasonable assurance that the desired control objectives will be achieved, and that the
management must necessarily exercise judgment when evaluating possible controls and procedures. Because of the limitations inherent
in all control systems, no evaluation of controls can provide absolute assurance that all control issues and any instances of fraud in the
company have been detected.
Management’s Annual Report On Internal Control Over Financial Reporting
The management of Woodside is responsible for establishing and maintaining adequate internal control over financial reporting (as
defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act).
Under the supervision and with the participation of management, including our CEO and CFO, the effectiveness of Woodside’s internal
controls over financial reporting was evaluated based on the framework and criteria established in Internal Controls – Integrated
Framework (2013), issued by the Committee of the Sponsoring Organizations of the Treadway Commission. Based on this evaluation,
management concluded that internal control over financial reporting was effective as at 31 December 2025.
Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when
determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of
changes in conditions, or the degree of compliance with the policies or procedures may deteriorate.
Attestation report of the registered public accounting firm
The effectiveness of internal control over financial reporting as of 31 December 2025 has been audited by PricewaterhouseCoopers, an
independent registered accounting firm as stated in their report that appears herein.
Changes in internal control over financial reporting
There were no changes in our internal control over financial reporting during FY2025 that materially affected or were reasonably likely
to materially affect our internal control over financial reporting.
ITEM 16. [RESERVED]
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT
Woodside’s Board has determined that Angela Minas, who currently serves as a member of the Audit & Risk Committee, meets the audit
committee financial expert requirements under SEC Rules. The Board has also determined that she is independent under applicable
NYSE Listing Rules.
ITEM 16B. CODE OF ETHICS
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 4.1.5: Promoting responsible and ethical behaviour from pages 132-133.
Exhibit 11.1 to this 2025 Form 20-F is incorporated herein by reference.
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ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•External Audit and Reporting in Section 4.1.6: Risk management and internal control from pages 134-135.
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
See “Item 16G. Corporate Governance” of this 2025 Form 20-F.
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED
PURCHASERS
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 6.4: Shareholder statistics from pages 272-275.
ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT
Not applicable.
ITEM 16G. CORPORATE GOVERNANCE
The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference:
•Section 4.1: Corporate Governance Statement from pages 116-141.
ITEM 16H. MINE SAFETY DISCLOSURE
Not applicable.
ITEM 16I. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT
INSPECTIONS
Not applicable.
ITEM 16J. INSIDER TRADING POLICIES
Woodside’s Securities Dealing Policy governs the purchase, sale and other dealings of Woodside’s securities by Directors, senior
management and employees, and seeks to promote compliance with applicable insider trading laws , rules and regulations.
Woodside’s Securities Dealing Policy applies to all Directors, employees, contractors, consultants and advisers. It prohibits
Directors and employees from dealing in Woodside’s securities when they are in possession of price-sensitive information that is
not generally available to the market. It also prohibits dealings by Directors and certain restricted employees during ‘black-out’
periods, such as during the period between the end of the financial half and full-year and the day following the announcement of
the results.
The Securities Dealing Policy also sets out our approach to transactions which limit the economic risk of participating in equity-
based remuneration schemes.
Exhibit 11.2 to this 2025 Form 20-F is incorporated herein by reference.
ITEM 16K. CYBERSECURITY DISCLOSURE
Our Cyber Resilience Process and risk management
processes.
and Technology Cybersecurity Framework.
Woodside’s Cyber Resilience Process consists of various Group‑wide policies, procedures and guidelines concerning
cybersecurity matters. These documents, published within the Woodside Management System (WMS), have these aims:
1.to design, build and maintain Woodside’s Information Technology (IT), Operational Technology (OT) and Industrial
Internet of Things systems with the right cybersecurity controls to support confidentiality, integrity and availability.
2.to monitor and strengthen Woodside’s cybersecurity posture while preventing, detecting, analysing and responding to
cybersecurity incidents.
3.to embed a cybersafe culture across Woodside and foster industry collaboration.
45
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4.to enable compliance with all applicable legislation.
The Cyber Resilience Process involves five key activities: identify, protect, detect, respond and recover.
In addition to the Cyber Resilience Process, the Data, Information and Systems Management process documented within the
WMS, includes the Woodside Information Technology Systems – Conditions of Use Procedure. This procedure sets out
Woodside’s mandatory conditions applicable to the use of Woodside’s IT, OT and digital systems.
Woodside manages cybersecurity risks utilising the same Woodside risk management process as described in SectionItem 3.D
Our Cyber Resilience Process assurance
Woodside’s cybersecurity team engages third-party vendors as part of our Cyber Resilience Process to perform a variety of
technical assessments such as penetration testing. As part of these assessments, the third parties test our internal and external
defences, and help us with identifying weaknesses and vulnerabilities within our environment. These assessment findings are risk
ranked and prioritised for remediation. Woodside’s internal audit team conducts audits on cybersecurity on a biennial basis. The
internal audit function engages external expertise to conduct the audits. The most recent cybersecurity audit concluded in 2025.
Third-party cybersecurity risk management
Woodside identifies and manages risks from cybersecurity threats associated with third parties accessing , storing and processing
Woodside data. This is done through upfront cybersecurity assessment processes that leverage independently verified security
programs including ISO 27001 certification and SOC 2 Type II compliance, and through contractual terms and conditions.
Woodside manages risk of third-party access to Woodside systems through onboarding and induction processes for personnel
including mandatory training. Third-party personnel accessing Woodside systems are subject to the same cyber security controls
as Woodside staff. This includes the requirement to complete annual cybersecurity training and additional role-based training if
applicable. Higher risk scenarios such as direct network connectivity from third-party networks are not permitted.
Material impact from cybersecurity risks, threats or previous cybersecurity incidents
Cybersecurity threats have the potential to materially affect Woodside’s business strategy, results of operations and financial
conditions. This risk is described in Item 3.D Risk Factors.
not aware of any cybersecurity incidents or threats that have materially affected or are reasonably likely to materially affect our
business strategy, results of operations or financial conditions.
Cybersecurity governance and internal control
The Audit & Risk Committee aims to hold at least five regular meetings a year at which cybersecurity risks and the Group’s
management of such risks are reviewed as part of those meetings.
with subject matter expertise provided as part of our Cyber Resilience Process.
The cybersecurity function is led by Woodside’s VP Digital and a group of competent and experienced cybersecurity
professionals. Our VP Digital has over a decade of industry experience and as held multiple technology and business facing roles.
The Cyber Resilience Process includes the monitoring, prevention, detection, mitigation and remediation of cybersecurity risks
and incidents.
through formal risk registers, briefing papers, internal audit reports, periodic reporting in person at Audit & Risk Committee
meetings or as required through Woodside’s crisis and emergency management process.
46
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PART III
ITEM 17. FINANCIAL STATEMENTS
The Company has responded to Item 18 in lieu of this item.
ITEM 18. FINANCIAL STATEMENTS
The audited consolidated financial statements as required under Item 18 are attached hereto starting on page F-1 of this 2025
Form 20-F. The audit report of PricewaterhouseCoopers, an independent registered accounting firm, is included herein following
the audited Consolidated Financial Statements. See “Item 4.B Business Overview” in this 2025 Form 20-F for Supplementary oil
and gas (unaudited) information pursuant to FASB 932.
F-1
Table of Contents
Financial Statements
Contents
Financial Statements | F-4 | |||
Consolidated income statement | F-4 | |||
Consolidated statement of comprehensive income | F-5 | |||
Consolidated statement of financial position | F-6 | |||
Consolidated statement of cash flows | F-7 | |||
Consolidated statement of changes in equity | F-8 | |||
Notes to the financial statements | F-9 | |||
About these statements | F-9 | |||
Climate change and energy transition | F-10 | |||
A. | Earnings for the period | F-13 | ||
A.1 | Segment revenue and expenses | F-14 | ||
A.2 | Finance costs | F-18 | ||
A.3 | Dividends paid and proposed | F-18 | ||
A.4 | Earnings per share | F-18 | ||
A.5 | Taxes | F-19 | ||
B. | Production and growth assets | F-24 | ||
B.1 | Segment production and growth assets | F-25 | ||
B.2 | Exploration and evaluation | F-27 | ||
B.3 | Property, plant and equipment | F-28 | ||
B.4 | Impairment of exploration and evaluation, property, plant and equipment and goodwill | F-30 | ||
B.5 | Business combination | F-34 | ||
B.6 | Intangible assets | F-36 | ||
B.7 | Significant production and growth asset acquisitions | F-37 | ||
B.8 | Disposal and sell-down of assets | F-38 | ||
B.9 | Transactions with equity holders of the Group | F-38 | ||
C. | Debt and capital | F-40 | ||
C.1 | Cash and cash equivalents | F-41 | ||
C.2 | Interest-bearing liabilities and financing facilities | F-41 | ||
C.3 | Contributed equity | F-43 | ||
C.4 | Other reserves | F-44 | ||
D. | Other assets and liabilities | F-46 | ||
D.1 | Segment assets and liabilities | F-47 | ||
D.2 | Receivables | F-47 | ||
D.3 | Inventories | F-48 | ||
D.4 | Payables | F-49 | ||
D.5 | Provisions | F-49 | ||
D.6 | Other financial assets and liabilities | F-51 | ||
D.7 | Leases | F-55 | ||
E. | Other items | F-58 | ||
E.1 | Contingent liabilities and assets | F-58 | ||
F-2
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E.2 | Employee benefits | F-58 | ||
E.3 | Related party transactions | F-61 | ||
E.4 | Auditor remuneration | F-61 | ||
E.5 | Events after the end of the reporting period | F-61 | ||
E.6 | Joint arrangements | F-61 | ||
E.7 | Parent entity information | F-63 | ||
E.8 | Subsidiaries | F-63 | ||
E.9 | Other accounting policies | F-69 | ||
Consolidated entity disclosure statement | F-71 | |||
Directors’ declaration | F-72 | |||
Report of Independent Registered Public Accounting Firm (PricewaterhouseCoopers, Australia, Auditor Firm ID: | F-73 | |||
F-3
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Significant Changes In The Current Reporting Period
The financial performance and position of the Group were affected by the following events and transactions during the reporting period:
•On 28 March 2025, the Group and Perenco Energies International Limited (Perenco) entered into an agreement for Perenco to acquire
the Greater Angostura assets in Trinidad and Tobago. The divestment includes Woodside’s 45% interest in the Angostura field and
68.46% interest in the Ruby field. The transaction completed on 11 July 2025, with an effective date of 1 January 2025. As a result,
the Group recognised a pre-tax gain on sale of $161 million (refer to Note B.8).
•On 7 April 2025, the Group and Stonepeak Wallaby I Acquiror LP (Stonepeak) entered into an agreement for Stonepeak to acquire a
40% interest in Louisiana LNG Infrastructure LLC, a subsidiary within the Group. The transaction completed on 25 June 2025 with
the Group continuing to retain control of Louisiana LNG Infrastructure LLC. Total proceeds of $1,876 million was received from
Stonepeak on transaction completion date(refer to Note B.9).
•On 29 April 2025, the Group approved a final investment decision (FID) to develop the Louisiana LNG Project. Upon FID, the Group
recognised a deferred tax asset of $182 million (refer to Note A.5).
•In March and April 2025, the Group repaid, renewed and drew down on various debt facilities. In May 2025, the Group issued
unsecured SEC-registered bonds amounting to $3,500 million (refer to Note C.2).
•As at 30 June 2025, an impairment indicator was identified on the H2OK Project following the Group’s decision to exit the Project.
As a result, the Group recognised an impairment loss before tax of $143 million (refer to Note B.4).
•On 23 October 2025, the Group and Williams Partners Operating LLC (Williams) completed an agreement for Williams to acquire an
80% interest in Driftwood Pipeline LLC and a 10% interest in Louisiana LNG LLC for total proceeds of $370 million (refer to Note
B.9).
•During the year, the Group recognised a pre-tax restoration expense of $340 million primarily due to updated closure cost estimates
and economic assumptions for Minerva, Stybarrow and Griffin (refer to Note A.1).
F-4
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Financial Statements
Consolidated income statement
for the year ended 31 December 2025
2025 | 2024 | 2023 | |||||
Notes | US$m | US$m | US$m | ||||
Operating revenue | A.1 | ||||||
Cost of sales | A.1 | ( | ( | ( | |||
Gross profit | |||||||
Other income | A.1 | ||||||
Other expenses | A.1 | ( | ( | ( | |||
Impairment losses | A.1 | ( | ( | ||||
Profit before tax and net finance costs | |||||||
Finance income | |||||||
Finance costs | A.2 | ( | ( | ( | |||
Profit before tax | |||||||
Petroleum resource rent tax (PRRT) (expense)/benefit | A.5 | ( | ( | ||||
Income tax expense | A.5 | ( | ( | ( | |||
Profit after tax | |||||||
Profit attributable to: | |||||||
Equity holders of the parent | |||||||
Non-controlling interest | E.8 | ||||||
Profit for the period | |||||||
Basic earnings per share attributable to equity holders of the parent (US cents) | A.4 | ||||||
Diluted earnings per share attributable to equity holders of the parent (US cents) | A.4 |
The accompanying notes form part of the Financial Statements.
F-5
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Consolidated statement of comprehensive income
for the year ended 31 December 2025
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Profit for the period | |||||
Other comprehensive income/(loss) | |||||
Items that may be reclassified to the income statement in subsequent periods: | |||||
Gains/(losses) on cash flow hedges | ( | ||||
(Gains)/losses on cash flow hedges reclassified to the income statement | ( | ||||
Tax recognised within other comprehensive income | ( | ( | ( | ||
Exchange fluctuations on translation of foreign operations taken to equity | ( | ||||
Items that will not be reclassified to the income statement in subsequent periods: | |||||
Remeasurement gain/(loss) on defined benefit plan | ( | ||||
Net loss on financial instruments at fair value through other comprehensive income | ( | ( | ( | ||
Other comprehensive income/(loss) for the period, net of tax | ( | ||||
Total comprehensive income for the period | |||||
Total comprehensive income attributable to: | |||||
Equity holders of the parent | |||||
Non-controlling interest | |||||
Total comprehensive income for the period |
The accompanying notes form part of the Financial Statements.
F-6
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Consolidated statement of financial position
as at 31 December 2025
2025 | 2024 | ||||
Notes | US$m | US$m | |||
Current assets | |||||
Cash and cash equivalents | C.1 | ||||
Receivables | D.2 | ||||
Inventories | D.3 | ||||
Other financial assets | D.6 | ||||
Tax receivable | |||||
Other assets | |||||
Total current assets | |||||
Non-current assets | |||||
Receivables | D.2 | ||||
Inventories | D.3 | ||||
Other financial assets | D.6 | ||||
Exploration and evaluation assets | B.2 | ||||
Property, plant and equipment | B.3 | ||||
Deferred tax assets | A.5 | ||||
Lease assets | D.7 | ||||
Investments accounted for using the equity method | |||||
Intangible assets | B.6 | ||||
Other assets | |||||
Total non-current assets | |||||
Total assets | |||||
Current liabilities | |||||
Payables | D.4 | ||||
Interest-bearing liabilities | C.2 | ||||
Other financial liabilities | D.6 | ||||
Provisions | D.5 | ||||
Tax payable | |||||
Lease liabilities | D.7 | ||||
Other liabilities | |||||
Total current liabilities | |||||
Non-current liabilities | |||||
Interest-bearing liabilities | C.2 | ||||
Deferred tax liabilities | A.5 | ||||
Other financial liabilities | D.6 | ||||
Provisions | D.5 | ||||
Tax payable | |||||
Lease liabilities | D.7 | ||||
Other liabilities | |||||
Total non-current liabilities | |||||
Total liabilities | |||||
Net assets | |||||
Equity | |||||
Issued and fully paid shares | C.3 | ||||
Shares reserved for employee share plans | C.3 | ( | ( | ||
Other reserves | C.4 | ||||
Retained earnings | |||||
Equity attributable to equity holders of the parent | |||||
Non-controlling interest | E.8 | ||||
Total equity |
The accompanying notes form part of the Financial Statements.
F-7
Table of Contents
Consolidated statement of cash flows
for the year ended 31 December 2025
2025 | 2024 | 2023 | |||||
Notes | US$m | US$m | US$m | ||||
Cash flows from/(used in) operating activities" | |||||||
Profit after tax for the period | |||||||
Adjustments for: | |||||||
Non-cash items | |||||||
Depreciation and amortisation | |||||||
Depreciation of lease assets | |||||||
Change in fair value of derivative financial instruments | ( | ||||||
Net finance costs | |||||||
Tax expense | |||||||
Exploration and evaluation written off | |||||||
Impairment loss | B.4 | ||||||
Restoration movement | |||||||
Gain on disposal of property, plant and equipment | ( | ( | |||||
Other | ( | ( | ( | ||||
Changes in assets and liabilities | |||||||
Decrease/(increase) in trade and other receivables | ( | ||||||
Increase in inventories | ( | ( | ( | ||||
(Decrease)/increase in provisions | ( | ( | |||||
Increase/(decrease) in other assets and liabilities | ( | ( | |||||
(Decrease)/increase in trade and other payables | ( | ( | |||||
Cash generated from operations | |||||||
Interest received | |||||||
Other dividends received | |||||||
Borrowing costs relating to operating activities | ( | ( | ( | ||||
Income tax and PRRT paid | ( | ( | ( | ||||
Payments for restoration | ( | ( | ( | ||||
Receipts for hedge collateral | |||||||
Other | ( | ( | |||||
Net cash from operating activities | |||||||
Cash flows from/(used in) investing activities | |||||||
Payments for capital and exploration expenditure | ( | ( | ( | ||||
Cash paid on business combination, net of cash acquired | B.5 | ( | |||||
Payments for asset acquisition, net of cash acquired | B.7 | ( | |||||
Reimbursements received from external parties for capital expenditure | |||||||
Borrowing costs relating to investing activities | ( | ( | ( | ||||
Deposits/proceeds received from disposal of non-current assets | |||||||
Dividends from/(contributions to) associates | ( | ||||||
Net cash used in investing activities | ( | ( | ( | ||||
Cash flows from/(used in) financing activities | |||||||
Proceeds from borrowings | C.2 | ||||||
Repayment of borrowings | C.2 | ( | ( | ( | |||
Purchases of shares relating to employee share plans | ( | ||||||
Borrowing costs relating to financing activities | ( | ( | |||||
Repayment of the principal portion of lease liabilities | ( | ( | ( | ||||
Borrowing costs relating to lease liabilities | ( | ( | |||||
Contributions from/(distributions to) non-controlling interests1 | ( | ( | |||||
Dividends paid | ( | ( | ( | ||||
Net cash from/(used in) financing activities | ( | ||||||
Net increase/(decrease) in cash held | ( | ||||||
Cash and cash equivalents at the beginning of the period | |||||||
Effects of exchange rate changes | ( | ( | |||||
Cash and cash equivalents at the end of the period | C.1 |
Note B.9 for details.
The accompanying notes form part of the Financial Statements.
F-8
Table of Contents
Consolidated statement of changes in equity
for the year ended 31 December 2025
Issued and fully paid shares | Reserved shares | Employee benefits reserve | Non- controllin g interest reserve | Foreign currency translation reserve | Hedging reserve | Distributable profits reserve | Other reserve | Retained earnings | Equity holders of the parent | Non- controlling interest | Total equity | ||||||||||||
Notes | C.3 | C.3 | C.4 | C.4 | C.4 | C.4 | C.4 | C.4 | E.8 | ||||||||||||||
US$m | US$m | US$m | US$m | US$m | US$m | US$m | US$m | US$m | US$m | US$m | US$m | ||||||||||||
At 1 January 2025 | ( | ( | |||||||||||||||||||||
Profit for the period | - | - | - | - | - | - | - | - | |||||||||||||||
Other comprehensive income/(loss) | - | - | - | - | - | - | ( | - | |||||||||||||||
Total comprehensive income/(loss) for the period | - | - | - | - | - | - | ( | ||||||||||||||||
Transfers | - | - | - | - | - | - | - | ( | - | ||||||||||||||
Transactions with non-controlling interests1 | - | - | - | ( | - | - | - | - | - | ( | |||||||||||||
Shares issued | - | - | - | - | - | - | - | - | - | ||||||||||||||
Employee share plan purchases | - | ( | - | - | - | - | - | - | - | ( | - | ( | |||||||||||
Employee share plan redemptions | - | ( | - | - | - | - | - | - | - | ||||||||||||||
Share-based payments (net of tax) | - | - | - | - | - | - | - | - | - | ||||||||||||||
Dividends paid | - | - | - | - | - | - | ( | - | - | ( | ( | ( | |||||||||||
At 31 December 2025 | ( | ( | ( | ||||||||||||||||||||
At 1 January 2024 | ( | - | ( | ||||||||||||||||||||
Profit for the period | - | - | - | - | - | - | - | - | |||||||||||||||
Other comprehensive loss | - | - | - | - | - | ( | - | ( | ( | ( | - | ( | |||||||||||
Total comprehensive (loss)/income for the period | - | - | - | - | - | ( | - | ( | |||||||||||||||
Transfers | - | - | - | - | - | - | - | ( | - | ||||||||||||||
Employee share plan purchases | - | ( | - | - | - | - | - | - | - | ( | - | ( | |||||||||||
Employee share plan redemptions | - | ( | - | - | - | - | - | - | - | ||||||||||||||
Share-based payments (net of tax) | - | - | - | - | - | - | - | - | - | ||||||||||||||
Dividends paid | - | - | - | - | - | - | ( | - | - | ( | ( | ( | |||||||||||
At 31 December 2024 | ( | ( | |||||||||||||||||||||
At 1 January 2023 | ( | - | ( | ||||||||||||||||||||
Profit for the period | - | - | - | - | - | - | - | - | |||||||||||||||
Other comprehensive (loss)/income | - | - | - | - | ( | - | ( | - | |||||||||||||||
Total comprehensive (loss)/income for the period | - | - | - | - | ( | - | ( | ||||||||||||||||
Transfers | - | - | - | - | - | - | - | ( | - | ||||||||||||||
Employee share plan purchases | - | ( | - | - | - | - | - | - | - | ( | - | ( | |||||||||||
Employee share plan redemptions | - | ( | - | - | - | - | - | - | - | ||||||||||||||
Share-based payments (net of tax) | - | - | - | - | - | - | - | - | - | ||||||||||||||
Dividends paid | - | - | - | - | - | - | ( | - | - | ( | ( | ( | |||||||||||
At 31 December 2023 | ( | ( |
sell-down of Louisiana LNG Infrastructure LLC to Stonepeak and the sell-down of Louisiana LNG LLC to Williams.
The accompanying notes form part of the Financial Statements.
F-9
Table of Contents
Notes to the financial statements
for the year ended 31 December 2025
Woodside Energy Group Ltd and its controlled entities (Woodside or the Group) is a for-profit entity limited by shares, incorporated and
domiciled in Australia. Its shares are publicly traded on the Australian Securities Exchange (ASX) and on the New York Stock Exchange
(NYSE) (in the form of Woodside American Depositary Shares).
The financial statements were authorised for issue in accordance with a resolution of the Directors on 24 February 2026.
The financial statements are general purpose financial statements, which have been prepared in accordance with the requirements of the
International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board. They also include
additional disclosures required for foreign registrants by the United States Securities and Exchange Commission (US SEC).
The Group’s accounting policies are materially consistent with those disclosed in the Group’s 2024 Financial Statements. Adoption of
new or amended standards and interpretations effective 1 January 2025 did not result in any significant changes to the Group’s
accounting policies. Refer to Note E.9 for more details.
Estimates have been revised, where required, to reflect current market conditions including the impact of climate change. Updated
assumptions used for impairment assessments, restoration provisions and embedded commodity derivatives are disclosed in Notes B.4,
D.5 and D.6 respectively; these assumptions could change in the future. New estimates and judgements relating to transactions with
equity holders of the Group are disclosed in Note B.9.
The accounting functional and presentation currency of Woodside and all its material subsidiaries is the US dollar.
Transactions in foreign currencies are initially recorded in the functional currency of the transacting entity at the exchange rates ruling at
the date of transaction. Monetary assets and liabilities denominated in foreign currencies at the reporting date are translated at the rates of
exchange ruling at that date. Exchange differences in the consolidated financial statements are taken to the consolidated income
statement.
Rounding of amounts
The financial statements are rounded to the nearest million dollars, except where otherwise indicated.
The financial statements have been prepared on a historical cost basis, except for derivative financial instruments and certain other
financial assets and financial liabilities, which have been measured at fair value or amortised cost adjusted for changes in fair value
attributable to the risks that are being hedged in effective hedge relationships. Where not carried at fair value, if the carrying value of
financial assets and financial liabilities does not approximate their fair value, the fair value has been included in the notes to the financial
statements.
Subsidiaries are fully consolidated from the date on which control is obtained by the Group and cease to be consolidated from the date at
which the Group ceases to have control.
The financial statements comprise the financial position and results of the Group as at and for the year ended 31 December 2025 (refer to
Note E.8).
The material subsidiaries of the Group apply the same reporting period and accounting policies as the parent company in their financial
statements. All intercompany balances and transactions, including unrealised profits and losses arising from intra-group transactions,
have been eliminated in full.
Non-controlling interests are allocated their share of the net profit after tax in the consolidated income statement and their share of other
comprehensive income net of tax in the consolidated statement of comprehensive income, and are presented within equity in the
consolidated statement of financial position, separately from parent shareholders’ equity.
The consolidated financial statements provide comparative information in respect of the previous periods. Where required,
a reclassification of items in the financial statements of the previous periods has been made in accordance with the classification of items
in the financial statements of the current period.
F-10
Table of Contents
Notes to the financial statements
for the year ended 31 December 2025
Climate considerations
Woodside has considered the impact of climate and the energy transition across its global portfolio in assessing the carrying values of its
assets and liabilities. This note describes the assumptions underpinning key areas of the financial statements and the potential short-term
and long-term impacts of differing climate-related scenarios on the financial performance, position and cash flow of Woodside for the
year ended 31 December 2025.
Financial planning and assumptions
Woodside considers a range of climate and macroeconomic scenarios to help benchmark our long-term price assumptions and inform our
decision making to maintain a resilient financial position. These scenarios are informed by a wide range of externally published data and
are part of a broad consideration of risks, opportunities, competitiveness and resilience. The assumptions applied in assessing amounts
within the financial statements require significant judgement and are in each case calculated in accordance with the requirements of
the applicable accounting standards.
Our long-term price assumptions reflect management’s current “best estimate” scenario in which global governments pursue
decarbonisation goals as well as other goals such as energy security and economic development. Price assumptions consider current
legislation in the locations where Woodside operates and place some weight on scenarios in which the transition to a lower carbon
energy system is sufficiently rapid to meet global climate goals, as well as scenarios in which the transition is not, or may not be,
sufficiently rapid. They also place some weight on a range of other assumptions which can drive prices (e.g. inflation) and which are not
related to the global climate goals.
Woodside’s oil and gas facilities are subject to physical risks such as metocean conditions and are located in regions that experience
tropical cyclones, hurricanes and high ambient temperatures. Woodside has significant experience designing and operating facilities
located in harsh environments.
The high degree of uncertainty around the nature, timing and magnitude of climate-related risks, and the uncertainty as to how the energy
transition will evolve, makes it difficult to determine the potential impacts of the risks with precision.
Woodside continues to monitor the uncertainty around climate change risks and expects to take into account ongoing developments into
its assumptions, including assumptions concerning commodity and carbon pricing, as considered appropriate. Investment cases include a
carbon price assumption which takes into consideration uncertainty around the impact of climate change. Commodity pricing
assumptions are key value drivers with greater significance to assets and liabilities than carbon pricing.
In accordance with the Group's accounting policies and applicable accounting standards, elements of Woodside’s financial statements are
based on reasonable and supportable assumptions that represent management’s current best estimate of the range of economic conditions
that may exist in the foreseeable future.
The estimation of recoverable amounts for impairment testing includes estimating what an independent market participant would pay to
acquire the asset as at the reporting date. Market participants will be guided by their own views on future economic and technical
conditions and therefore Woodside considers a range of data sources in determining a future price forecast, including industry and
market benchmarks along with asset sales transaction data to support the recoverable amount.
The completion of the sale of the 10 % and 15.1 % non-operating participating interest in the Scarborough Joint Venture to LNG Japan
and JERA respectively in 2024, is a clear example of an independent market valuation fully supporting the carrying value of the multi-
decade asset.
Price forecasts are adjusted for premiums and discounts based on the nature and quality of the product. Commodity oil price estimates
consider macroeconomic factors such as population growth and have regard to potential climate pathways along with other factors such
as industry investment and cost trends. There remains significant uncertainty around how society will respond to the climate challenge.
The energy transition is expected to bring volatility and there is uncertainty as to how commodity prices will develop.
details.
Oil and gas properties, included within property, plant and equipment, are depreciated using the unit of production basis over either
proved or proved plus probable reserves. The energy transition may result in changes to the expected useful life of oil and gas properties
and economically recoverable reserves and resources thereby accelerating depreciation charges or resulting in an impairment. New
energy assets under development still require significant capital spend. The Group will review depreciation methodology and useful life
of new energy assets as they are brought into use.
F-11
Table of Contents
Notes to the financial statements
for the year ended 31 December 2025
Woodside utilises certified carbon credits to offset equity Scope 1 and 2 emissions that are above our targets in a given year and to meet
our regulatory requirements, after design out and operate out measures have been taken. The Group’s portfolio of carbon credits enables
our base business to manage the price risk associated with regulations and our corporate net equity Scope 1 and 2 emissions targets.
As at 31 December 2025, the Group recognised $274 million (2024: $202 million) of carbon credits within inventory.
The energy transition may result in restoration activities occurring earlier than expected. 56 % (2024: 53 %) of the Group’s non-current
restoration liabilities are expected to be settled more than 10 years in the future.
Restoration cost estimates require judgemental assumptions regarding removal date, environmental legislation and regulations and the
extent of restoration activities required. These cost estimates may change in the future, as a result of increased regulatory scrutiny and the
energy transition. This includes the demand and related costs for offshore services which can be influenced by renewable energy
construction. Woodside continues to monitor the uncertainty around climate change risks to assess if additional changes to restoration
provisions should be recognised. Refer to Note D.5 for further details.
Climate risks may impact underlying assumptions used to assess the forecast cash flows of long-term contracts. These judgemental
assumptions include pricing forecast and discount rate adjustments based on the nature of the product.
Contractual arrangements, including the Corpus Christi contract, could be impacted by adverse market conditions arising from climate-
The Group has determined that it is probable that sufficient future taxable income will be available to utilise the deferred tax assets
relating to carry forward unused tax losses and credits recognised as at 31 December 2025. The recoverability of deferred tax assets is
F-12
Table of Contents
Notes to the financial statements
for the year ended 31 December 2025
Financial and capital risk management | ||||
The Board of Directors has overall responsibility for the establishment and oversight of the Group’s risk management framework, including review and approval of the Group’s risk management strategy, policy and key risk parameters. The Board of Directors and the Audit and Risk Committee have oversight of the Group’s internal control system and risk management process, including oversight of the internal audit function. The Group’s management of financial and capital risks is aimed at ensuring that available capital, funding and cash flows are sufficient to: •meet the Group’s financial commitments as and when they fall due; •maintain the capacity to fund its committed project developments; •pay a reasonable dividend; and •maintain a long-term credit rating of not less than investment grade. The Group monitors and tests its forecast financial 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. Group Treasury policy does not permit speculative trading in financial derivatives. Refer to Item 3.D for more information on the Group’s objectives, policies and processes for managing financial risk. The below risks arise in the normal course of the Group’s business. Risk information can be found in the following sections: | ||||
Section A | Commodity price risk management | Page F-13 | ||
Section A | Foreign exchange risk management | Page F-13 | ||
Section C | Capital risk management | Page F-40 | ||
Section C | Liquidity risk management | Page F-40 | ||
Section C | Interest rate risk management | Page F-40 | ||
Section D | Credit risk management | Page F-46 | ||
Significant estimates and judgements | ||||
In applying the Group’s 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. Significant judgements, estimates and assumptions made by management in the preparation of these financial statements are found in the following notes: | ||||
Note A.1 | Segment revenue and expenses | Page F-14 | ||
Note A.5 | Taxes | Page F-19 | ||
Note B.2 | Exploration and evaluation | Page F-27 | ||
Note B.3 | Property, plant and equipment | Page F-28 | ||
Note B.4 | Impairment of exploration and evaluation, property, plant and equipment and goodwill | Page F-30 | ||
Note B.5 | Business combination | Page F-34 | ||
Note B.6 | Intangible assets | Page F-36 | ||
Note B.7 | Significant production and growth asset acquisitions | Page F-37 | ||
Note B.9 | Transactions with equity holders of the Group | Page F-38 | ||
Note D.5 | Provisions | Page F-49 | ||
Note D.6 | Other financial assets and liabilities | Page F-51 | ||
Note D.7 | Leases | Page F-55 | ||
Note E.6 | Joint arrangements | Page F-61 | ||
F-13
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
IN THIS SECTION
This section addresses financial performance of the Group for the reporting period including, where applicable, the accounting policies
applied and the significant estimates and judgements made. This section also includes the tax position of the Group for and at the end of
the reporting period.
A. | Earnings for the period | |
A.1 | Segment revenue and expenses | Page F-14 |
A.2 | Finance costs | Page F-18 |
A.3 | Dividends paid and proposed | Page F-18 |
A.4 | Earnings per share | Page F-18 |
A.5 | Taxes | Page F-19 |
Key financial and capital risks in this section
The Group’s revenue is exposed to commodity price fluctuations through the sale of hydrocarbons. Commodity price risks are measured
by monitoring and stress testing the Group’s forecast financial position to sustained periods of low commodity prices. This analysis is
regularly performed on the Group’s portfolio and as required for discrete projects and transactions.
The Group’s management of commodity price risk includes the use of commodity derivatives to hedge its exposure (refer to Note D.6).
The hedged exposure includes oil-linked revenue related to produced volumes and revenues derived from trading operations. Commodity
derivatives are used to manage the Group’s price risk within its corporate and trading portfolios.
As at the reporting date, the Group held commodity hedging financial instruments with a net asset carrying value of $176 million (2024:
$27 million) exposed to commodity price risk. An increase in relevant commodity prices of 10 % would decrease the instruments’
carrying value by $77 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 arises from future commitments, financial assets and financial liabilities that are not denominated in US dollars.
The majority of the Group’s revenue is denominated in US dollars. The Group is exposed to foreign currency risk arising from operating
and capital expenditure incurred in currencies other than US dollars, particularly Australian dollars.
The Group’s management of foreign exchange risk relating to capital expenditure includes the use of forward exchange contract
derivatives to hedge its exposure (refer to Note D.6).
The Group entered into foreign exchange forward contracts to fix 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 managed its Australian dollar
to US dollar exchange rate exposure in relation to the Australian dollar denominated dividend payments.
As at the reporting date, the Group held hedging foreign currency financial instruments with a net asset carrying value of $19 million
(2024: net liability carrying value of $45 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’s
financial position.
A reasonably possible change in the exchange rate of the US dollar to the Australian dollar (+7.0 %/-7.0 % (2024: +10.0 %/-10.0 %)), with
all other variables held constant, would not have a material impact on the Group’s equity or the income statement. Refer to Notes C.1,
C.2, D.2, D.4 and D.7 for details of the denominations of cash and cash equivalents, interest-bearing liabilities, receivables, payables and
lease liabilities held at 31 December 2025.
F-14
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
A.1 Segment revenue and expenses
Operating segment information
The Group’s operating segments have been determined based on the internal reports reviewed by the Chief Executive Officer, who is the
Chief Operating Decision Maker. These reports are used to assess performance and allocate resources within the business.
As the Group continues to invest in new energy and integrate these activities across its operations, changes have been made to the way
financial information is presented. New energy projects that have reached a final investment decision (FID) are now reported within
either the Australia or International segments, depending on their geographical location.
The Group’s disclosed operating segments have been updated to reflect this change, and the comparative information for 2024 and 2023
has been restated to ensure consistency of presentation. The Group’s reportable operating segments are as follows:
Australia: Exploration, evaluation, development, production and sale of liquefied natural gas (LNG), pipeline gas, crude oil, condensate and natural gas liquids, as well as the development, production and sale of new energy products from Australian assets that have achieved FID. | International: Exploration, evaluation, development, production and sale of LNG, pipeline gas, crude oil, condensate and natural gas liquids, and the development, production and sale of new energy products from assets located outside Australia that have achieved FID. | Marketing: Marketing, shipping and trading of the Group’s oil and gas portfolio (including purchased volumes) and optimisation activities that generate incremental value. | Corporate: Comprises new energy projects that have not yet reached FID and corporate items that are not allocated to operating segments. Corporate items include revenues, expenses, assets and liabilities that are not considered part of the core operations of any segment. | ||||||||
Customer concentration
The Group has two major customers which each respectively account for 8 % and 7 % of the Group’s external revenue. The sales are
generated by the Australia and Marketing operating segments (2024: two major customers; 7 % and 6 % generated by the Australia and
Marketing operating segments and 2023: two major customers; 8 % and 7 % generated by the Australia and Marketing operating
segments).
Geographical information
Geographical information | Revenue from external customers1 | ||||
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Asia Pacific | |||||
Americas | |||||
Europe | |||||
Other | |||||
Consolidated | |||||
1.Revenue is attributable to geographic location based on the location of the customers.
Recognition and measurement
Revenue is recognised when or as the Group transfers control of products or provides services to a customer at the amount to which the
Group expects to be entitled. If the consideration includes a variable component, the Group estimates the amount of the expected
consideration receivable. Variable consideration is estimated throughout the contract and is recognised to the extent that it is highly
probable a significant reversal will not occur.
•Revenue from sale of hydrocarbons – Revenue from the sale of hydrocarbons is recognised at a point in time when control of the
product is transferred to the customer. Revenue from take or pay contracts is recorded as unearned revenue until the product has been
drawn by the customer (transfer of control), at which time it is recognised in earnings.
•Other operating revenue – Revenue earned from LNG processing and other services is recognised over time as the services are rendered.
•Royalties, excise and levies – Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on
the basis of the Group’s entitlement to physical production.
•Depreciation and amortisation - Refer to Note B.3.
•Impairment and impairment reversals - Refer to Note B.4.
•Leases - Refer to Note D.7.
F-15
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
Significant estimates and judgements
The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is
determined with reference to quoted commodity prices.
Judgement is also used to determine if it is highly probable that a significant reversal will not occur in relation to revenue recognised
during open pricing periods in LNG contracts. The Group estimates variable consideration based on available information from contract
negotiations and market indicators.
Australia | International | Marketing | Corporate | Consolidated | |
2025 | 2025 | 2025 | 2025 | 2025 | |
US$m | US$m | US$m | US$m | US$m | |
Liquified natural gas | |||||
Pipeline gas | |||||
Crude oil and condensate | |||||
Natural gas liquids | |||||
Revenue from sale of hydrocarbons | |||||
Intersegment revenue1 | ( | ||||
Processing and services revenue | |||||
Shipping and other revenue | |||||
Other revenue | |||||
Operating revenue2 | |||||
Production costs | ( | ( | ( | ||
Royalties, excise and levies | ( | ( | ( | ||
Insurance | ( | ( | ( | ( | |
Inventory movement | ( | ||||
Costs of production | ( | ( | ( | ( | |
Property, plant and equipment depreciation | ( | ( | ( | ( | |
Shipping and direct sales costs | ( | ( | ( | ( | |
Trading costs3 | ( | ( | ( | ||
Other hydrocarbon costs | ( | ( | |||
Other | ( | ( | ( | ||
Other cost of sales | ( | ( | ( | ( | |
Cost of sales | ( | ( | ( | ( | ( |
Gross profit/(loss) | ( | ||||
Other income4 | |||||
Exploration and evaluation expenditure5 | ( | ( | ( | ||
Amortisation of permit acquisitions | ( | ( | |||
Write-offs | ( | ( | |||
Exploration and evaluation | ( | ( | ( | ||
General, administration and other costs | ( | ( | ( | ( | ( |
Amortisation of intangible assets | ( | ( | |||
Depreciation of lease assets | ( | ( | ( | ( | ( |
Restoration movement6 | ( | ( | |||
Other7 | ( | ( | ( | ( | ( |
Other costs | ( | ( | ( | ( | ( |
Other expenses | ( | ( | ( | ( | ( |
Impairment losses | ( | ( | |||
Profit/(loss) before tax and net finance costs | ( |
1.Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment’s 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 $12,959 million and sub-lease income of $25 million disclosed within shipping
and other revenue.
3.In 2025 traded LNG and condensate purchased from Australia operations Joint Venture Partners have been presented in the Australia segment with
the corresponding trading revenue presented in the Australia segment, whereas in 2024 this was presented in the Marketing segment.
4.Includes a $137 million unrealised fair value gain on embedded derivatives, $204 million of net gains on hedging activities, fees and recoveries and
other income not associated with the ongoing operations of the business. The International segment includes $161 million from the gain on the sale of
the Greater Angostura assets to Perenco.
5.Includes seismic and general permit activities and other exploration costs. Exploration and evaluation expenditure includes $17 million of evaluation
expenditure.
6.Includes updated closure cost estimates and economic assumptions at closed sites.
7.Includes items not associated with the ongoing operations of the business including foreign exchange losses.
F-16
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
For the year ended 31 December 2024
Australia | International | Marketing | Corporate | Consolidated | |
2024 | 2024 | 2024 | 2024 | 2024 | |
US$m | US$m | US$m | US$m | US$m | |
Liquified natural gas | |||||
Pipeline gas | |||||
Crude oil and condensate | |||||
Natural gas liquids | |||||
Revenue from sale of hydrocarbons | |||||
Intersegment revenue1 | ( | ( | |||
Processing and services revenue | |||||
Shipping and other revenue | |||||
Other revenue | ( | ||||
Operating revenue2 | |||||
Production costs | ( | ( | ( | ||
Royalties, excise and levies | ( | ( | ( | ||
Insurance | ( | ( | ( | ||
Inventory movement | |||||
Costs of production | ( | ( | ( | ||
Property, plant and equipment depreciation | ( | ( | ( | ( | |
Shipping and direct sales costs | ( | ( | ( | ( | |
Trading costs | ( | ( | ( | ||
Other hydrocarbon costs | ( | ( | |||
Other | ( | ( | ( | ( | |
Other cost of sales | ( | ( | ( | ( | ( |
Cost of sales | ( | ( | ( | ( | ( |
Gross profit/(loss) | ( | ||||
Other income3 | ( | ||||
Exploration and evaluation expenditure4 | ( | ( | ( | ||
Amortisation of permit acquisitions | ( | ( | |||
Write-offs | ( | ( | ( | ||
Exploration and evaluation | ( | ( | ( | ||
General, administration and other costs | ( | ( | |||
Amortisation of intangible assets | ( | ( | |||
Depreciation of lease assets | ( | ( | ( | ( | ( |
Restoration movement | ( | ( | ( | ||
Other5 | ( | ( | ( | ( | |
Other costs | ( | ( | ( | ( | ( |
Other expenses | ( | ( | ( | ( | ( |
Impairment losses | |||||
Profit/(loss) before tax and net finance costs | ( |
1.Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment’s 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 $13,163 million and sub-lease income of $16 million disclosed within shipping
and other revenue.
3.Includes fees and recoveries and other income not associated with the ongoing operations of the business. The Australia segment includes $209
million from the gain on the sell-down of Scarborough to LNG Japan and JERA.
4.Includes seismic and general permit activities and other exploration costs. Exploration and evaluation expenditure includes $15 million of evaluation
expenditure.
5.Includes gains and losses on hedging activities, a $314 million fair value loss on embedded derivatives and other expenses not associated with the
ongoing operations of the business.
F-17
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
For the year ended 31 December 2023
Australia | International | Marketing | Corporate | Consolidated | |
2023 | 2023 | 2023 | 2023 | 2023 | |
US$m | US$m | US$m | US$m | US$m | |
Liquified natural gas | |||||
Pipeline gas | |||||
Crude oil and condensate | |||||
Natural gas liquids | |||||
Revenue from sale of hydrocarbons | |||||
Intersegment revenue1 | ( | ( | |||
Processing and services revenue | |||||
Shipping and other revenue | |||||
Other revenue | ( | ||||
Operating revenue2 | |||||
Production costs | ( | ( | ( | ||
Royalties, excise and levies | ( | ( | ( | ||
Insurance | ( | ( | ( | ( | |
Inventory movement | ( | ( | |||
Costs of production | ( | ( | ( | ( | |
Property, plant and equipment depreciation | ( | ( | ( | ( | |
Shipping and direct sales costs | ( | ( | ( | ( | ( |
Trading costs | ( | ( | ( | ||
Other hydrocarbon costs | ( | ( | |||
Other | ( | ( | |||
Other cost of sales | ( | ( | ( | ( | ( |
Cost of sales | ( | ( | ( | ( | ( |
Gross profit/(loss) | ( | ||||
Other income3 | |||||
Exploration and evaluation expenditure4 | ( | ( | ( | ( | |
Amortisation of permit acquisitions | ( | ( | |||
Write-offs | ( | ( | ( | ||
Exploration and evaluation | ( | ( | ( | ( | |
General, administration and other costs | ( | ( | |||
Amortisation of intangible assets | ( | ( | |||
Depreciation of lease assets | ( | ( | ( | ( | ( |
Restoration movement | ( | ( | ( | ||
Other5 | ( | ( | ( | ( | |
Other costs | ( | ( | ( | ( | ( |
Other expenses | ( | ( | ( | ( | ( |
Impairment losses | ( | ( | ( | ||
Profit/(loss) before tax and net finance costs | ( | ( |
1.Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment’s 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. Exploration and evaluation expenditure includes $30 million of evaluation
expenditure.
5.Includes losses on hedging activities, a $35 million fair value loss on embedded derivatives and other expenses not associated with the ongoing
F-18
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
A.2 Finance costs
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Interest on interest-bearing liabilities | |||||
Interest on lease liabilities | |||||
Accretion charge | |||||
Other finance costs | |||||
Less: Finance costs capitalised against qualifying assets | ( | ( | ( | ||
Total finance costs |
A.3 Dividends paid and proposed
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
(a) Dividends paid during the financial year | |||||
Prior year fully franked final dividend1 | |||||
Current year fully franked interim dividend2 | |||||
(b) Dividend declared subsequent to the reporting period (not recorded as a liability) | |||||
Current year fully franked final dividend3 | |||||
(c) Other information | |||||
Current year dividends per share (US cents) |
1.2025: US$0.53 , paid on 2 April 2025
2024: US$0.60 , paid on 4 April 2024
2023: US$1.44 , paid on 5 April 2023
2.2025: US$0.53 , paid on 24 September 2025
2024: US$0.69 , paid on 3 October 2024
2023: US$0.80 , paid on28 September 2023
3.2025: US$0.59 to be paid on 27 March 2026
2024: US$0.53 paid on 2 April 2025
2023: US$0.60 paid on 4 April 2024
The Dividend Reinvestment Plan (DRP) was approved by the shareholders at the Annual General Meeting in 2003 for activation as
required to fund future growth. The DRP was reactivated in 2019 and suspended by the Board of Directors on 27 February 2023.
A.4 Earnings per share
2025 | 2024 | 2023 | |||
Profit attributable to equity holders of the parent (US$m) | |||||
Weighted average number of shares on issue for basic earnings per share | |||||
Effect of dilution from contingently issuable shares | |||||
Weighted average number of shares on issue adjusted for the effect of dilution | |||||
Basic earnings per share (US cents) | |||||
Diluted earnings per share (US cents) |
Earnings per share is calculated by dividing the profit 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.
There have been no significant transactions involving ordinary shares between the reporting date and the date of completion of these
financial statements.
F-19
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
A.5 Taxes
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
(a) Tax expense comprises | |||||
Petroleum resource rent tax (PRRT) | |||||
Current tax expense | |||||
Deferred tax (benefit)/expense | ( | ( | |||
PRRT expense/(benefit) | ( | ||||
Income tax | |||||
Current year | |||||
Current tax expense | |||||
Deferred tax benefit | ( | ( | ( | ||
Adjustment to prior years | |||||
Current tax (benefit)/expense | ( | ( | |||
Deferred tax (benefit)/expense | ( | ||||
Income tax expense | |||||
Tax expense |
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
(b) Reconciliation of income tax expense | |||||
Profit before tax | |||||
PRRT (expense)/benefit | ( | ( | |||
Profit before income tax | |||||
Income tax expense calculated at 30% | |||||
Effect of tax rate differentials | ( | ||||
Effect of deferred tax assets not recognised | |||||
Effect of tax benefits previously unrecognised | ( | ( | ( | ||
Effect of goodwill impairment | |||||
Reduction in deferred tax liability due to held for sale basis | ( | ( | |||
Foreign exchange impact on tax (benefit)/expense | ( | ( | |||
Adjustment to prior years | ( | ( | |||
Integration and transaction costs non-deductible | |||||
Other | ( | ||||
Income tax expense1 |
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
(c) Reconciliation of PRRT expense | |||||
Profit before tax | |||||
Non-PRRT assessable profit | ( | ( | ( | ||
PPRT projects profit before tax | |||||
PRRT expense calculated at 40% | |||||
(Recognition)/derecognition of Pluto exploration expenditure2 | ( | ||||
Recognition of transferred exploration spend | ( | ||||
Augmentation | ( | ( | ( | ||
Other | ( | ( | ( | ||
PRRT expense/(benefit) | ( |
F-20
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
(d) Deferred tax income statement reconciliation | |||||
PRRT | |||||
Production and growth assets | ( | ||||
Augmentation for current year | ( | ( | ( | ||
Provisions | ( | ( | |||
Other | ( | ( | |||
PRRT (benefit)/expense | ( | ( | |||
Income tax | |||||
Property, plant and equipment | ( | ( | ( | ||
Exploration and evaluation assets | |||||
Lease assets and liabilities | ( | ( | |||
Provisions | ( | ( | |||
PRRT assets and liabilities | ( | ( | |||
Unused tax losses and tax credits | ( | ( | |||
Assets held for sale | ( | ( | |||
Intangible assets | |||||
Derivatives | ( | ( | |||
Investments | |||||
Other | ( | ||||
Income tax deferred tax benefit | ( | ( | ( | ||
Deferred tax benefit | ( | ( | ( |
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
(e) Deferred tax other comprehensive income reconciliation | |||||
Income tax | |||||
Derivatives | |||||
Other | ( | ||||
Deferred income tax expense via other comprehensive income |
by profit before income tax. The underlying EITR is 26.8 % when excluding the recognition of a $182 million deferred tax asset as a result of the
Louisiana LNG FID and the $113 million post-tax H2OK impairment loss. The Australian operations EITR of 29.5 % (2024: 26.9 %, 2023:30.2 %) is
2.In 2025, no additional Pluto PRRT deferred tax asset was recognised. In 2024, the $502 million increase of the Pluto PRRT deferred tax asset is due to
the recognition of previously unrecognised deductible expenditure that is now considered to be recoverable on the basis of future taxable profits being
F-21
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
2025 | 2024 | ||
US$m | US$m | ||
(f) Deferred tax balance sheet reconciliation | |||
Deferred tax assets | |||
PRRT | |||
Production and growth assets | |||
Augmentation for current year | |||
Provisions | |||
Other | ( | ||
PRRT deferred tax assets | |||
Income tax | |||
Property, plant and equipment | ( | ( | |
Exploration and evaluation assets | |||
Lease assets and liabilities | |||
Unused tax losses and tax credits | |||
Derivatives | ( | ||
Provisions | |||
Investments | ( | ||
Other | |||
Income tax deferred tax assets | |||
Deferred tax assets | |||
Deferred tax liabilities | |||
PRRT | |||
Production and growth assets | |||
Augmentation for current year | ( | ||
Provisions | ( | ( | |
Other | |||
PRRT deferred tax liabilities | |||
Income tax | |||
Property, plant and equipment | |||
Exploration and evaluation assets | |||
Lease assets and liabilities | ( | ( | |
Provisions | ( | ( | |
PRRT assets and liabilities | |||
Assets held for sale | |||
Intangible assets | |||
Derivatives | ( | ( | |
Other | ( | ( | |
Income tax deferred tax liabilities | |||
Deferred tax liabilities |
Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. Deferred
tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset is
realised. The tax rates and laws used to determine the amount are based on those that have been enacted or substantively enacted by the
end of the reporting period. Income taxes relating to items recognised directly in equity are recognised in equity.
Current taxes
Current tax expense is the expected tax payable on the taxable income for the current year and any adjustment to tax paid in respect of
previous years.
F-22
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
Deferred taxes
Deferred tax expense represents movements in the temporary differences between the carrying amount of an asset or liability in the
consolidated statement of financial position and its tax base.
With the exception of those noted below, deferred tax liabilities are recognised for all taxable temporary differences.
Deferred tax assets are recognised for deductible temporary differences, unused tax losses and tax credits only if it is probable that
sufficient future taxable income will be available to utilise those temporary differences and losses.
Deferred tax is not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business
combination) of assets and liabilities in a transaction that affects neither accounting profit nor the taxable profit.
In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable profits when
assessing the extent to which a deferred tax asset can be recognised in the consolidated statement of financial position.
Offsetting deferred tax balances
Deferred tax assets and liabilities are offset only if there is a legally enforceable right to offset current tax assets and liabilities and when
they relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities that the
Group intends to settle its current tax assets and liabilities on a net basis. Refer to Notes E.8 and E.9 for detail on the tax consolidated
groups.
Pillar Two legislation
In December 2021, the Organisation for Economic Co-operation and Development (OECD) published its Pillar Two legislation rules.
The Pillar Two legislation rules aim to ensure that large multinational groups pay a minimum of 15 % tax for each jurisdiction in which
they operate. Pillar Two legislation has been enacted or substantively enacted in a number of jurisdictions in which the Group operates
with effect from 1 January 2024. The Group applies the exception to recognising and disclosing information about deferred tax assets
and liabilities related to Pillar Two income taxes.
The Group has undertaken a Pillar Two analysis for the year ended 31 December 2025 and is expected to have met relevant safe
harbours for all jurisdictions in which it operates except for Singapore. The amount of Singapore Pillar Two tax expense is not material.
(a) Income tax classification
Judgement is required when determining whether a particular tax is an income tax or another type of tax. PRRT is considered,
for accounting purposes, to be an income tax. Accounting for deferred tax is applied to income taxes as described above, but is not
applied to other types of taxes, e.g. North West Shelf royalties, excise and levies which are recognised in cost of sales in the
income statement.
(b) Deferred tax asset recognition
Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from USA
TCG 1 of $1,227 million (2024: $1,274 million), USA TCG 2 of $200 million (2024:nil ) and $396 million (2024: $410 million)
arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable
that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a)
for details of tax consolidated groups.
Unrecognised DTAs relating to carry forward unused tax losses and credits of $320 million (2024: $366 million) from the USA TCG 1,
$150 million (2024: $343 million) from USA TCG 2 and $663 million (2024: $715 million) from countries other than Australia and the
USA. These DTAs have not been recognised as it is not currently probable that the losses and credits will be utilised based on
current planned activities in those countries.
On 29 April 2025, the Group approved an FID to develop the Louisiana LNG Project. Upon FID, the Group recognised a DTA of
$182 million. In the prior year, subsequent to achieving first oil on the Sangomar project in June 2024, the Group recognised a net DTA
of $342 million.
PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting
forecast future taxable profits. During the year ended 31 December 2025, the Group did not recognise any additional Pluto PRRT DTA
as a result of recoverability assessments performed.
F-23
Table of Contents
Notes to the financial statements A. Earnings for the period
for the year ended 31 December 2025
In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable profits are
risk‑adjusted where appropriate by a market premium risk rate to reflect uncertainty inherent in long-term forecasts. A long-term bond
rate of 4.3 % (31 December 2024: 3.2 %) was used for the purposes of augmentation.
Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future
augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable profits. $7,728 million (2024:
$7,490 million) relates to the North West Shelf Project, $779 million (2024: $601 million) relates to remaining Pluto deductible balances
and $776 million (2024: $795 million) relates to Wheatstone. A long-term bond rate of 4.3 % (31 December 2024: 3.2 %) was used for the
purposes of augmentation.
Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the
assessment, additional deferred tax assets would be recognised, with a corresponding benefit to tax expense. It was determined that the
approach adopted provides the most meaningful information on the implications of the PRRT regime, whilst ensuring compliance with
IAS 12 Income Taxes.
(c) Uncertain tax positions
The Group has tax matters, litigation and other claims, for which the timing of resolution and potential economic outflows are uncertain.
Where the Group assesses an outcome for any tax matter, litigation or other claim as more likely than not to be accepted by the relevant
tax authority, the position is adopted in the reported tax balances.
Because of the complexity of some of these positions, the ultimate outcome may differ from the current estimate of the position.
These differences will be reflected as increases or decreases to tax expense in the period in which new information is available. Tax
matters without a probable economic outflow and/or presently cannot be measured reliably are contingent liabilities and disclosed in
Note E.1 Contingent liabilities and assets.
F-24
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
IN THIS SECTION
This section addresses the strategic growth (exploration and evaluation), core producing, development and new energy (property, plant
and equipment) assets position of the Group at the end of the reporting period including, where applicable, the accounting policies and
significant estimates and judgements applied. This section also includes the impairment position of the Group at the end of the reporting
period.
B. | Production and growth assets | |
B.1 | Segment production and growth assets | Page F-25 |
B.2 | Exploration and evaluation | Page F-27 |
B.3 | Property, plant and equipment | Page F-28 |
B.4 | Impairment of exploration and evaluation, property, plant and equipment and goodwill | Page F-30 |
B.5 | Business combination | Page F-34 |
B.6 | Intangible assets | Page F-36 |
B.7 | Significant production and growth asset acquisitions | Page F-37 |
B.8 | Disposal and sell-down of assets | Page F-38 |
B.9 | Transactions with equity holders of the Group | Page F-38 |
F-25
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
B.1 Segment production and growth assets
Australia | International | Marketing | Corporate | Consolidated | |||||
2025 | 2025 | 2025 | 2025 | 2025 | |||||
US$m | US$m | US$m | US$m | US$m | |||||
Balance as at 31 December | |||||||||
Asia Pacific | |||||||||
Americas | |||||||||
Africa | |||||||||
Total exploration and evaluation | |||||||||
Balance as at 31 December | |||||||||
Land and buildings | |||||||||
Oil and gas properties | |||||||||
Projects in development | |||||||||
Other plant and equipment | |||||||||
Total property, plant and equipment | |||||||||
Balance as at 31 December | |||||||||
Goodwill | |||||||||
Contract assets | |||||||||
Software | |||||||||
Total intangible assets | |||||||||
Balance as at 31 December | |||||||||
Land and buildings | |||||||||
Oil and gas properties | |||||||||
Other plant and equipment | |||||||||
Total lease assets | |||||||||
Additions to exploration and evaluation: | |||||||||
Exploration | |||||||||
Evaluation | |||||||||
Additions to property, plant and equipment: | |||||||||
Property, plant and equipment | |||||||||
Capitalised borrowings costs1 | |||||||||
Restoration2 | ( | ||||||||
Additions to intangible assets: | |||||||||
Adjustment to purchase price allocation3 | |||||||||
Software | |||||||||
Additions to lease assets | |||||||||
Land and buildings | |||||||||
Other plant and equipment | |||||||||
1.Borrowing costs capitalised were at a weighted average interest rate of 5.0 %.
2.Relates to changes in restoration provision assumptions.
3.Refer to Note B.5 for details on business combination.
Refer to Note A.1 for descriptions of the Group’s segments and geographical regions.
F-26
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
As at 31 December 2024
Australia | International | Marketing | Corporate | Consolidated | |||||
2024 | 20241 | 2024 | 20241 | 2024 | |||||
US$m | US$m | US$m | US$m | US$m | |||||
Balance as at 31 December | |||||||||
Asia Pacific | |||||||||
Americas | |||||||||
Africa | |||||||||
Total exploration and evaluation | |||||||||
Balance as at 31 December | |||||||||
Land and buildings | |||||||||
Oil and gas properties | |||||||||
Projects in development | |||||||||
Other plant and equipment | |||||||||
Total property, plant and equipment | |||||||||
Balance as at 31 December | |||||||||
Goodwill | |||||||||
Contract assets | |||||||||
Software | |||||||||
Total intangible assets | |||||||||
Balance as at 31 December | |||||||||
Land and buildings | |||||||||
Oil and gas properties | |||||||||
Other plant and equipment | |||||||||
Total lease assets | |||||||||
Additions to exploration and evaluation: | |||||||||
Exploration | |||||||||
Evaluation | |||||||||
Additions to property, plant and equipment: | |||||||||
Acquisitions through business combinations and asset acquisitions2 | |||||||||
Property, plant and equipment | |||||||||
Capitalised borrowings costs3 | |||||||||
Restoration4 | ( | ( | ( | ||||||
Additions to intangible assets: | |||||||||
Acquisitions through business combination and asset acquisitions2 | |||||||||
Contract assets | |||||||||
Software | |||||||||
Additions to lease assets | |||||||||
Acquisitions through business combinations and asset acquisitions2 | |||||||||
Land and buildings | |||||||||
Other plant and equipment | |||||||||
1.The 2024 amounts have been restated to reflect the changes in operating segments. $1,115 916
million of the total intangible assets have been reclassified from the corporate to international segment. $1,115
plant and equipment and $941
‘Operating segment information’ in Note A.1 for details.
2.Refer to Note B.5 for details on business combination and Note B.7 for details on asset acquisitions.
3.Borrowing costs capitalised were at a weighted average interest rate of 4.4 %.
4.Relates to changes in restoration provision assumptions.
F-27
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
B.2 Exploration and evaluation
Asia Pacific | Americas | Africa | Total | ||||
US$m | US$m | US$m | US$m | ||||
Year ended 31 December 2025 | |||||||
Carrying amount at 1 January 2025 | |||||||
Additions | |||||||
Amortisation of licence acquisition costs | ( | ( | |||||
Expensed | ( | ( | |||||
Transferred exploration and evaluation | ( | ( | |||||
Carrying amount at 31 December 2025 | |||||||
Year ended 31 December 2024 | |||||||
Carrying amount at 1 January 2024 | |||||||
Additions | |||||||
Amortisation of licence acquisition costs | ( | ( | |||||
Expensed | ( | ( | ( | ||||
Transferred exploration and evaluation | ( | ( | ( | ||||
Carrying amount at 31 December 2024 | |||||||
Exploration commitments | |||||||
Year ended 31 December 2025 | |||||||
Year ended 31 December 2024 |
Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method.
Areas of interest (AOI) are based on a geographical area for which the rights of tenure are current. All exploration and evaluation
expenditure, including general permit activity, geological and geophysical costs and new venture activity costs, is expensed as incurred
except for the following:
•where the expenditure relates to an exploration discovery for which the assessment of the existence or otherwise of economically
recoverable hydrocarbons is not yet complete; or
•where the expenditure is expected to be recouped through successful exploitation of the area of interest, or alternatively, by its sale.
The costs of acquiring interests in new exploration and evaluation licences are capitalised. The costs of drilling exploration wells are
initially capitalised pending the results of the well.
Costs are expensed where the well does not result in the successful discovery of economically recoverable hydrocarbons and the
recognition of an area of interest.
Subsequent to the recognition of an area of interest, all further evaluation costs relating to that area of interest are capitalised. Upon
approval for the commercial development of an area of interest, accumulated expenditure for the area of interest is transferred to projects
in development within property, plant and equipment.
In the consolidated statement of cash flows, those cash flows associated with capitalised exploration and evaluation expenditure,
including unsuccessful wells, are classified as cash flows used in investing activities.
Exploration commitments
The Group has exploration expenditure obligations which are contracted for, but not provided for in the financial statements. These
Refer to Note B.4 for details on impairment, including any write‑offs.
(a) Area of interest
Typically, an AOI is defined by the Group as an individual geographical area whereby the presence of hydrocarbons is considered
favourable or proved to exist. The Group has established criteria to recognise and maintain an AOI.
F-28
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
(b) Transfer to projects in development
Development activities commence after project sanctioning by the appropriate level of management. Judgement is applied by
B.3 Property, plant and equipment
Land and buildings | Oil and gas properties | Projects in development1 | Other plant and equipment | Total | |||||
US$m | US$m | US$m | US$m | US$m | |||||
Year ended 31 December 2025 | |||||||||
Carrying amount at 1 January 2025 | |||||||||
Adjustment to purchase price allocation2 | ( | ( | ( | ||||||
Additions3 | |||||||||
Disposals at written down value4 | ( | ( | ( | ( | ( | ||||
Impairment loss5 | ( | ( | |||||||
Completions and transfers | ( | ||||||||
Depreciation | ( | ( | ( | ( | |||||
Carrying amount at 31 December 2025 | |||||||||
At 31 December 2025 | |||||||||
Historical cost | |||||||||
Accumulated depreciation and impairment | ( | ( | ( | ( | ( | ||||
Net carrying amount | |||||||||
Year ended 31 December 2024 | |||||||||
Carrying amount at 1 January 2024 | |||||||||
Acquisitions through business combinations and asset acquisitions2 | |||||||||
Additions | ( | ||||||||
Disposals at written down value | ( | ( | ( | ( | |||||
Completions and transfers6 | ( | ||||||||
Depreciation | ( | ( | ( | ( | |||||
Carrying amount at 31 December 2024 | |||||||||
At 31 December 2024 | |||||||||
Historical cost | |||||||||
Accumulated depreciation and impairment | ( | ( | ( | ( | ( | ||||
Net carrying amount |
1.Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.
2.Refer to Note B.5 for details of business combination and Note B.7 for details of asset acquisitions.
3.Includes $7,345 million of capital additions, $733 million of capitalised borrowing costs, $534 million relating to reimbursed capital expenditure from
OCI N.V. and $713 million relating to changes in restoration provision assumptions. Included within capital additions is $3,658 million relating to the
Louisiana LNG project.
4.Refer to Note B.8 for details on disposal of assets and Note B.9 for details on transactions with equity holders of the Group.
5.Refer to Note B.4 for details on impairment.
6.Upon first oil in June 2024, the carrying value of the Sangomar project has been transferred from projects in development to oil and gas properties.
Property, plant and equipment are stated at cost less accumulated depreciation and impairment charges.
Projects in development include the construction of oil and gas assets and new energy assets:
•Projects in development for oil and gas assets include the costs to acquire, construct, install or complete production and infrastructure
facilities such as pipelines and platforms, capitalised borrowing costs, transferred exploration and evaluation assets, development
wells and the estimated cost of dismantling and restoration.
•Projects in development for new energy assets include the costs to acquire, construct, install or complete infrastructure facilities,
capitalised borrowing costs and the estimated cost of dismantling and restoration.
F-29
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
Borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset are capitalised as part of
the cost of that project when it is probable that they will result in future economic benefits and the costs can be measured reliably. The
interest rate used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the
Group’s outstanding borrowings during the period.
When commercial operation commences, the accumulated costs in projects in development will be transferred to oil and gas properties
or new energy assets.
Subsequent capital costs, including major maintenance, are included in the asset’s carrying amount only when it is probable that future
Property, plant and equipment are depreciated to their estimated residual values at rates based on their expected useful lives.
Upstream oil and conventional gas assets are depreciated using the unit of production basis over proved reserves. Upstream LNG assets
are depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most
appropriate representation of useful life.
The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into
production. Downstream assets (primarily onshore plant and equipment) are depreciated using a straight-line basis over the lesser of
useful life and the life of proved plus probable reserves. On a straight-line basis the assets have an estimated useful life of 5 -50 years.
All other items of property, plant and equipment are depreciated using the straight-line method over their useful life. They are
depreciated as follows:
•Buildings – 24 –40 years;
•Other plant and equipment – 5 –40 years; and
•Land is not depreciated.
Refer to Note B.4 for details on impairment.
Capital commitments
The Group has capital commitments contracted for, but not provided for in the financial statements, of $11,957 million as at
31 December 2025 (2024: $3,841 million). Capital commitments relate predominantly to the Louisiana LNG, Trion and Scarborough
projects (2024: Trion, Scarborough and Louisiana LNG projects). Capital commitments, totalling $9,986 million are shared between the
Group, Stonepeak and Williams based on their respective interests in Louisiana LNG. Stonepeak will pay for its share of Louisiana
LNG’s capital expenditure up to a cap of $5,700 million some of which has already been utilised. Refer to Note B.9 for details of the
sell-down of Louisiana LNG Infrastructure LLC to Stonepeak.
In addition to the above, the Group also has capital commitments of $165 million (2024: $6 million) relating to its associates and joint
ventures.
(a) Reserves
The estimation of reserves requires significant management judgement and interpretation of complex geological and geophysical models
in order to make an assessment of the size, shape, depth and quality of reservoirs, and their anticipated recoveries. Estimates of oil and
natural gas reserves are used to calculate depreciation and amortisation charges for the Group’s oil and gas properties. Judgement is used
in determining the economic reserve base applied to each asset. Estimates are reviewed at least annually or when there are changes in the
economic circumstances impacting specific assets or asset groups. These changes may impact depreciation, asset carrying values,
restoration provisions and deferred tax balances. If reserves estimates are revised downwards, earnings could be affected by higher
depreciation expense or an immediate write-down of the asset’s carrying value.
(b) Depreciation
Judgement is required to determine when assets are available for use to commence depreciation. Depreciation generally commences on
first production.
F-30
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
B.4 Impairment of exploration and evaluation, property, plant and equipment and goodwill
Impairment testing
The recoverability of the carrying amount of exploration and evaluation assets is dependent on successful development and commercial
exploitation, or alternatively sale of the respective AOI.
Each AOI is reviewed half-yearly to determine whether economic quantities of hydrocarbons have been found, or whether further
exploration and evaluation work is underway or planned to support continued carry forward of capitalised costs. Where a potential
impairment is indicated for an AOI, an assessment is performed using a fair value less costs to dispose (FVLCD) method to determine its
recoverable amount. Upon approval for commercial development, exploration and evaluation assets are assessed for impairment before
they are transferred to property, plant and equipment.
Impairment calculations
If the carrying amount of an AOI exceeds its recoverable amount, the AOI is written down to its recoverable amount and an impairment
loss is recognised in the consolidated income statement.
Property, plant and equipment
Impairment testing
The carrying amounts of property, plant and equipment are assessed half-yearly to determine whether there is an indicator of impairment
or impairment reversal for those assets which have previously been impaired. Indicators of impairment and impairment reversals include
changes in reserves for oil and gas assets, expected future sales prices, or costs.
Property, plant and equipment are assessed for impairment indicators and impairments on a cash-generating unit (CGU) basis. CGUs are
determined as offshore and onshore facilities, infrastructure and associated oil and/or gas fields and new energy assets.
If there is an indicator of impairment or impairment reversal for a CGU, its recoverable amount is calculated and compared with the
CGU’s carrying value (refer to impairment calculations below).
Goodwill
For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the
Group’s cash-generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or
liabilities of the acquiree are assigned to those units. Goodwill is tested for impairment at least annually and more frequently if events or
changes in circumstances indicate that it might be impaired. Impairment of goodwill is determined by assessing the recoverable amount
of each CGU to which the goodwill relates and comparing it with its carrying value, which includes deferred taxes (refer to impairment
calculations below and Note B.5).
When part of an operation is disposed of, any goodwill associated with the disposed operation is included in the carrying amount of the
operation in determining the gain or loss on disposal.
Goodwill and property, plant and equipment impairment calculations
The recoverable amount of an asset or CGU is determined as the higher of its value in use (VIU) and FVLCD.
VIU is determined by estimating future cash flows after taking into account the risks specific to the asset and discounting to present
value using an appropriate discount rate.
FVLCD is the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the
effects of factors that may be specific to the Group. In determining FVLCD, recent market transactions are considered. If no such
transactions can be identified, an appropriate valuation model, such as discounted cash flow techniques, is applied on a post-tax basis
using an appropriate discount rate and estimates are made about the assumptions market participants would use when pricing the asset or
CGU.
If the carrying amount of an asset or CGU, including any allocated goodwill, exceeds its recoverable amount, the asset or CGU is written
down to its recoverable amount and an impairment loss is recognised in the consolidated income statement. Any impairment losses are
first allocated to reduce the carrying amount of any goodwill allocated, with the remaining impairment losses allocated to the relevant
assets.
If the recoverable amount of an asset or CGU exceeds its carrying amount, and that asset or CGU has previously been impaired, the
impairment is reversed. The carrying amount of the asset or CGU is increased to its recoverable amount, but only to the extent that the
carrying amount does not exceed the value that would have been determined, net of depreciation, if no impairment had been recognised.
Impairments of goodwill are not reversed.
F-31
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
For the year ended 31 December 2025
Goodwill allocation
The Group performed its annual goodwill impairment test as at 31 December 2025.
Segment | CGU | Goodwill carrying amount | Excess of recoverable amount over CGU carrying amount1 | |||
US$m | US$m | |||||
Australia | Pluto-Scarborough | |||||
Australia | NWS Gas | |||||
International | Atlantis | |||||
International | Beaumont New Ammonia | |||||
International | Mad Dog | |||||
International | Mad Dog Phase 2 | |||||
Total | ||||||
1.Amounts are with reference to the total CGU value including goodwill.
Impairment and impairment reversals
As at 30 June 2025, an impairment indicator was identified on the H2OK Project following the Group’s decision to exit the project.
Based on management’s judgement, the estimated recoverable value of the project’s inventory and property, plant and equipment are
expected to be less than the carrying value. The estimated recoverable amount was based on third party valuation reports. As a result, an
impairment loss before tax of $143 million was recognised in the Corporate segment of Note A.1 for the half-year ended 30 June 2025.
No other impairment or impairment reversal was recognised in the current year.
Recoverable amounts have been determined using the FVLCD method using discounted cash flow projections, classified as Level 3
on the fair value hierarchy. The carrying amount of each CGU includes all assets allocated to the respective CGU. Refer to significant
estimates and judgements for further details.
Sensitivity analysis for CGUs with goodwill
Recoverable amount valuations are sensitive to changes in certain significant accounting estimates and judgements (refer to significant
estimates and judgements for further details). Reasonably possible changes to these key assumptions are set out below:
•Post-tax discount rate – plus or minus 1 100
•Commodity pricing – plus or minus 10
The valuations of CGUs with goodwill are most sensitive to changes in forecast 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:
Decrease in commodity price1 | Increase in post-tax discount rate | |||
CGU | % change | (absolute terms) | ||
Atlantis | ( | |||
Beaumont New Ammonia | ( | N/A2 | ||
Mad Dog | < | > |
1.WTI price, which applies to Atlantis and Mad Dog, has a $5 to $6 /bbl differential from Brent. Ammonia prices apply to Beaumont New Ammonia.
2.Management considers there to be no reasonably possible change in the respective estimate which, in isolation, would result in the estimated
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 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.
F-32
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
For the year ended 31 December 2024
Goodwill allocation
The acquisition of OCI Ammonia Holding B.V. and its Beaumont New Ammonia Project was completed on 30 September 2024 and
accounted for as a business combination (refer to Note B.5). The purchase consideration represents the fair value of assets and liabilities
acquired and goodwill arose from the business combination totalling $169 million.
The Group performed its annual goodwill impairment test as at 31 December 2024. The carrying amount of goodwill allocated to each
CGU, or groups of CGUs, and excess recoverable amounts were as follows:
Segment | CGU | Goodwill carrying amount | Excess of recoverable amount over CGU carrying amount1 | |||
US$m | US$m | |||||
Australia | Pluto-Scarborough2 | |||||
Australia | NWS Gas | |||||
International | Atlantis | |||||
International | Beaumont New Ammonia3 | |||||
International | Other goodwill | |||||
Total |
1.Amounts are with reference to the total CGU value including goodwill.
2.A portion of the goodwill allocated to Pluto-Scarborough was disposed of due to the sell-down to LNG Japan and JERA.
Other goodwill of $288 million (2023: $283 million) has been allocated across a number of CGUs within the International segment.
This represents less than 1 % of net assets as at 31 December 2024.
Impairment and impairment reversals
No impairment or impairment reversal was recognised for the year ended 31 December 2024.
Recoverable amounts have been determined using the FVLCD method using discounted cash flow projections, classified as Level 3
on the fair value hierarchy. The carrying amount of each CGU includes all assets allocated to the respective CGU. Refer to significant
estimates and judgements for further details.
Sensitivity analysis for CGUs with goodwill
Recoverable amount valuations are sensitive to changes in certain significant accounting estimates and judgements (refer to significant
estimates and judgements for further details). Reasonably possible changes to these key assumptions are set out below:
•Post-tax discount rate – plus or minus 1 100
•Commodity pricing – plus or minus 10
•Production volumes – plus or minus 4
The valuations of CGUs with goodwill are most sensitive to changes in forecast 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:
Decrease in commodity price1 | Increase in post-tax discount rate | |||
CGU | % change | (absolute terms) | ||
Atlantis | ( |
1.Brent price applies to Pluto-Scarborough and NWS Gas. WTI price (Brent – $4 /bbl) applies to Atlantis.
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 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.
F-33
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
(a) CGU determination
Identification of a CGU requires management judgement. Management has determined CGUs based on the smallest group of assets that
generate significant cash inflows that are independent from other assets or groups of assets.
(b) Allocation of goodwill
Judgement is required in the allocation of goodwill arising from business combinations to the Group’s CGUs that are expected to benefit
from the synergies of the business combination.
(c) Recoverable amount calculation key assumptions
In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash flows when determining
the FVLCD. FVLCD methodology uses assumptions reflecting market participant's current expectations of such future cash flows (to
determine a value that a willing seller and a willing buyer would accept in a market transaction). These estimates require significant
management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can also affect the
assumptions used and the rates used to discount future cash flow estimates.
The basis for each estimate used to determine recoverable amounts as at 31 December 2025 and 31 December 2024 is set out below:
•Resource estimates – 2P reserves and a portion of 2C resources (where applicable) for oil and gas properties. The reserves are
as disclosed in the Reserves and Resources Statement in the 31 December 2025 and 31 December 2024 Annual Reports.
•Inflation rate – long-term inflation rate of 2.0 % (2024: 2.0 %) has been applied for US based assets and 2.5 % (2024: 2.3 %)
for Australian based assets.
•Foreign exchange rates – a rate of $0.70 (2024: $0.75 ) US$:AU$ is based on management’s view of long-term exchange rates.
•Discount rates – a post-tax discount rate of between 8.5 % and 10.5 % (2024: 8.5 % and 9.5 %) for CGUs has been applied.
The discount rate reflects an assessment of the risks specific to the asset.
•Carbon pricing – a long-term price of US$80 /tonne (2024 real terms) of emissions (2024: US$80 /tonne (2024 real terms))
is based on management’s assumptions on carbon cost pricing and incorporates an evaluation of climate risk. This is applicable
to Australian emissions that exceed facility-specific baselines in accordance with Australian regulations, as well as global emissions
that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks
and will revise carbon pricing assumptions accordingly. Refer to the Climate change and energy transition section within the basis
of preparation for further information.
•LNG price – the majority of LNG sales contracts are linked to an oil price marker and therefore dependent on oil price assumptions.
LNG sold into spot markets is typically based on a gas-hub linked price (for example the Title Transfer Facility (TTF) or JKM) and
therefore these pricing assumptions are also of relevance in forecasting future revenues.
•Brent oil prices – derived from long-term views of global supply and demand, building upon past experience of the industry and
consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product.
Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost
trends. Woodside’s pricing assumptions reflect a ‘best estimate’ scenario in which global governments pursue decarbonisation goals
as well as other goals such as energy security and economic development. Further information on climate change risk is provided in
the Climate change and energy transition section within the basis of preparation. The nominal Brent oil prices (US$/bbl) used for
the year ended 31 December 2025 were:
2026 | 2027 | 2028 | 2029 | 2030 | 2031 | |||||||
31 December 20251 | ||||||||||||
31 December 20242 |
1.Long-term oil prices are based on US$75 /bbl (2024 real terms) from 2028 and prices are escalated at 2.0 % onwards.
2.Long-term oil prices are based on US$78 /bbl (2024 real terms) from 2027 and prices are escalated at 2.0 % onwards.
The nominal Brent oil prices (US$/bbl) used for the year ended 31 December 2024 were:
2025 | 2026 | 2027 | 2028 | 2029 | 2030 | |||||||
31 December 20243 | ||||||||||||
31 December 20234 |
3.Long-term oil prices are based on US$78 /bbl (2024 real terms) from 2027 and prices are escalated at 2.0 % onwards.
4.Long-term oil prices are based on US$70 /bbl (2022 real terms) from 2026 and prices are escalated at 2.0 % onwards.
•Ammonia prices – derived from the long-term views of global supply and demand referenced to Woodside’s underlying global gas
price assumption and expectation of lower-carbon price adjustment, building upon past experience of the industry and consistent
with external sources. The long-term Ammonia prices applied range from $492 /tonne escalating to a $567 /tonne long‑term price
from 2034. Prices are real terms 2024 and escalated at 2.0 %.
F-34
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
B.5 Business combination
Acquisition of OCI Clean Ammonia Holding B.V (OCI)
On 5 August 2024, Woodside entered into a binding agreement to acquire 100 % of OCI and its Beaumont New Ammonia Project for an
all-cash consideration of $2,350 million. The project is under construction and is subject to cost, schedule and performance guarantees
from OCI N.V.
The transaction completed on 30 September 2024 and was accounted for as a business combination. The Group’s net profit after tax for
the year ended 31 December 2024 incorporated OCI’s results from acquisition date. The all-cash consideration of $2,350 million is
inclusive of capital expenditure through completion of phase 1 of the project, with 80 % paid and the remaining 20 % to be paid at project
completion subject to cost, schedule and performance guarantees. The acquisition has positioned the Group to be an early mover in the
growing lower carbon ammonia market.
The initial accounting for the acquisition of OCI was provisionally disclosed at 31 December 2024. The Group had a maximum of
indefinite life intangible assets. Management completed this exercise within the first half of the year and the table below now reflects the
final fair value of the acquired assets and liabilities and the resulting value of goodwill arising from the business combination.
The finalised purchase price allocation based on updated information has resulted in goodwill of $255 million, a net increase of
$86 million from the amount reported at 31 December 2024.
Fair value of net identifiable assets and goodwill acquired, on acquisition date | US$m |
Cash and cash equivalents | |
Receivables | |
Property, plant and equipment | |
Intangible assets | |
Other assets | |
Payables | ( |
Deferred tax liabilities | ( |
Provisions | ( |
Fair value of net identifiable assets acquired | |
Goodwill arising on acquisition | |
Total purchase consideration1 |
1.Total purchase consideration includes $20 million of working capital adjustment.
Purchase consideration | US$m |
Cash payment | |
Contingent consideration2 | |
Total purchase consideration |
2.Contingent consideration relating to the remaining 20 % of the consideration to be paid to OCI N.V. at project completion.
Analysis of cash flows on acquisition | US$m |
Cash payment | ( |
Cash and cash equivalents acquired | |
Net cash flow on acquisition | ( |
Acquisition-related costs of $2 million were included as an expense in general, administration and other costs in the consolidated income
statement for the year ended 31 December 2024.
F-35
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
Revenue and contribution to the Group
The acquired business contributed a loss before tax of $8 million to the Group from the acquisition date to 31 December 2024. If the
acquisition had occurred on 1 January 2024, consolidated profit before tax would have been lower by $21 million. The acquired business
did not recognise any operating revenue prior to or after the acquisition date.
Receivables
The fair value of receivables included $715 million of expected reimbursements from OCI N.V. for forecast capital expenditure. The full
reimbursement was received by 31 December 2025.
Intangible assets
$796 million of intangible assets were recognised on acquisition as a result of identified contract assets. Refer to Note B.6 Intangible
assets for details.
Goodwill
The goodwill of $255 million arises from the net deferred tax liability recognised on acquisition as a consequence of asset tax bases
received being lower than the fair value of the assets acquired. The goodwill is not deductible for tax purposes.
Business combination accounting
The Group accounts for business combinations using the acquisition method when the acquired set of activities and assets meets the
definition of a business and control is transferred to the Group.
In determining whether a particular set of activities and assets is a business, the Group assesses whether the set of assets and activities
acquired includes, at a minimum, an input and substantive process and whether the acquired set has the ability to produce outputs.
The consideration transferred in the acquisition is generally measured at fair value, as are the identifiable net assets acquired.
Transaction costs are expensed as incurred, except if related to the issue of debt or equity securities.
Contingent consideration is measured at fair value at the date of acquisition and subsequent changes in the fair value of the contingent
consideration are recognised in profit or loss.
(a) Nature of acquisition
Judgement is required to determine if the acquisition is a business combination due to the stage of completion of the project and the
timing of transfer of employees.
The project is under construction, with agreements in place to complete construction and transfer a fully operational asset together with a
workforce to the Group. The agreements were in place at acquisition date and provide Woodside with control over the future economic
benefits of the project, and the necessary inputs and processes to create outputs, meeting the definition of a business combination.
(b) Fair value determination for net assets acquired
Judgement is required to determine the fair value of assets acquired and liabilities assumed in a business combination, which can have a
material impact on resultant goodwill. This includes the use of a cash flow model to estimate the expected future cash flows and the
discount rate used.
On acquisition date, the reproduction cost method was used to fair value the property, plant and equipment in its construction phase. The
reproduction cost method calculates the cost to construct an equivalent asset with the same specifications.
(c) Contingent consideration
Judgement is required to determine the fair value of the contingent consideration which includes consideration on the construction
F-36
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
B.6 Intangible assets
Goodwill | Contract Assets | Software | Total | ||||
US$m | US$m | US$m | US$m | ||||
Year ended 31 December 2025 | |||||||
Carrying amount at 1 January 2025 | |||||||
Adjustment to purchase price allocation1 | |||||||
Additions | |||||||
Amortisation | - | ( | ( | ( | |||
Carrying amount at 31 December 2025 | |||||||
At 31 December 2025 | |||||||
Cost | |||||||
Accumulated amortisation and impairment | ( | ( | ( | ( | |||
Net carrying amount | |||||||
Year ended 31 December 2024 | |||||||
Carrying amount at 1 January 2024 | |||||||
Acquisitions through business combinations and asset acquisitions1 | |||||||
Additions | |||||||
Amortisation | - | ( | ( | ( | |||
Goodwill disposed | ( | ( | |||||
Carrying amount at 31 December 2024 | |||||||
At 31 December 2024 | |||||||
Cost | |||||||
Accumulated amortisation and impairment | ( | ( | ( | ( | |||
Net carrying amount |
Goodwill is initially measured at cost and is subsequently measured at cost less any accumulated impairment losses. For the purposes of
impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s CGUs or
groups of CGUs no larger than an operating segment that are expected to benefit from the combination, irrespective of whether other
assets or liabilities of the acquiree are assigned to those units.
Where goodwill has been allocated to a CGU and part of the operation within that unit is disposed of, the goodwill associated with the
disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal.
Goodwill is not amortised but will be assessed at least annually for impairment and more frequently if events or changes in
circumstances indicate that it might be impaired.
The contract assets were acquired as part of a business combination and represent the difference in contract pricing and market prices,
adjusted for time value of money. The contracts are recognised at fair value at the acquisition date and are subsequently amortised over
Software is recognised at historical cost less accumulated amortisation and impairment. All software costs are amortised over the useful
life of 5 –15 years on a straight-line basis.
(a) Goodwill allocation
Judgement is required in the allocation of goodwill to the Group’s CGUs that are expected to benefit from the synergies of the business
combination. Refer to Note B.4 for the details of the goodwill allocation.
(b) Contract assets
In determining the fair value of the contract assets as part of a business combination, estimates are made regarding the pricing
assumptions and discount rate. These estimates require management judgement and changes in economic conditions can impact the fair
value assessment of the contracts.
F-37
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
B.7 Significant production and growth asset acquisitions
(a) Operatorship of Bass Strait assets
On 29 July 2025, the Group agreed with ExxonMobil Australia (ExxonMobil) to assume operatorship of the Bass Strait production
assets, the Longford Gas Plant, the Long Island Point gas liquids processing facility and associated pipeline infrastructure.
The parties’ equity interests in the joint venture assets and existing decommissioning plans and provisions remain unchanged. The
transaction is subject to customary conditions precedent, including obtaining regulatory approvals, and is expected to complete in 2026.
There has been no financial impact to the 31 December 2025 results
As part of the transaction, Woodside will acquire ExxonMobil’s employing entity for the Bass Strait employees, which includes the
related employee assets and liabilities for consideration of $1 . The employee expenses will continue to be funded by Bass Strait joint
venture partners based on their equity interests. The acquisition of the employing entity is expected to be treated as a business
combination, with the financial impact to be determined at completion.
(b) Sale and purchase agreements with Chevron
On 19 December 2024, the Group entered into sale and purchase agreements with Chevron Australia Pty Ltd (Chevron) to acquire
Chevron’s 16.7 % interest in the North West Shelf (NWS) Project and the NWS Oil Project and 20.0 % interest in the Angel Carbon
Capture and Storage (CCS) Project, and to transfer the Group’s 13.0 % non-operated interest in the Wheatstone Project and 65.0 %
operated interest in the Julimar-Brunello Project.
Completion of the transaction is subject to the completion of Julimar Phase 3 Project execution and handover and other customary
conditions precedent.
As part of the transaction, Chevron will make a cash payment to Woodside of up to $400 million which comprises a cash payment of
$300 million at completion, and additional contingent payments of up to $100 million in aggregate.
As at 31 December 2025, the Group has received $100 million of advance payment from Chevron. The advance payment is refundable to
Chevron if the transaction fails to complete.
The transaction is expected to complete in 2026, with an effective date of 1 January 2024. There has been no financial impact to the 31
December 2025 results. At completion, there will be customary adjustments for net working capital and interim period cash flows.
(c) Acquisition of Tellurian Inc.
On 22 July 2024, the Group entered into a definitive agreement to acquire all the issued and outstanding common stock of Tellurian Inc.
(subsequently renamed Woodside Energy (LA) Holdings Inc.), including its owned and operated Louisiana LNG development
opportunity for a cash payment for shares of $876 million. As part of the agreement, the Group provided a loan facility of $230 million
to Tellurian Inc. to ensure site activity maintained momentum prior to the completion of the transaction. At acquisition date, $146
million had been drawn down.
The transaction was completed on 8 October 2024 and accounted for as an asset acquisition.
Assets acquired and liabilities assumed
US$m | |
Cash and cash equivalents | |
Receivables | |
Other financial assets | |
Property, plant and equipment | |
Intangible assets | |
Lease assets | |
Other assets | |
Payables | ( |
Other financial liabilities | ( |
Provisions | ( |
Tax payable | ( |
Lease liabilities | ( |
Interest-bearing liabilities | ( |
Net assets acquired |
F-38
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
Acquisition cost | US$m |
Cash paid for shares | |
Loan facility | |
Payments for employee awards | |
Transaction costs | |
Total purchase consideration |
Analysis of cash flows on acquisition | US$m |
Cash payment | ( |
Cash and cash equivalents acquired | |
Net cash flow on acquisition | ( |
Purchase consideration, including capitalised transaction cost, has been allocated against identifiable assets and liabilities acquired on the
following basis:
•Assets and liabilities initially measured at an amount other than cost, are measured by the Group at the amounts specified in the
applicable accounting standards. Assets and liabilities in this category include financial assets and financial liabilities recognised
initially at fair value, lease assets and liabilities measured in accordance with the accounting standard for leases, and employee
benefit liabilities measured in accordance with the accounting standard for employee benefits.
•The residual transaction price is allocated to the remaining identifiable assets and liabilities based on their relative fair values at the
date of the acquisition.
(a) Nature of acquisition
Judgement is required to determine if the transaction is the acquisition of an asset or a business combination.
The Louisiana LNG Project is in its preliminary phase with significant construction milestones and costs to be incurred prior to the
facility being operational and the acquired assets and liabilities did not meet the criteria for a business combination due to the absence of
a substantive process and organised workforce required to convert inputs to outputs.
(b) Employee compensation program
As part of the acquisition, the Group has assumed the obligation of Tellurian’s compensation programs to its employees. Judgement is
required to determine the measurement of the employee provision on acquisition as certain conditions in the compensation programs are
linked to future milestones of the Louisiana LNG Project. This includes determining the likelihood and timing of the milestones.
B.8 Disposal and sell-down of assets
(a) Disposal of Greater Angostura assets to Perenco Energies International Limited
On 28 March 2025, the Group entered into an agreement with Perenco Energies International Limited (Perenco) for the sale of the
Greater Angostura assets in Trinidad and Tobago for $259 million, which is made up of a base purchase price of $206 million plus
completion adjustments for working capital and interest. The divestment includes Woodside’s 45 % interest in the Angostura field and
The transaction completed on 11 July 2025. For the year ended 31 December 2025, the Group recognised a pre-tax gain on sale of $161
million in other income. The Group no longer holds any interest in the Angostura and Ruby fields.
B.9 Transactions with equity holders of the Group
(a) Disposal and sell-down of assets to Williams
On 23 October 2025, the Group entered into an agreement with Williams Louisiana LNG LLC (Williams) for the sale of an 80 % interest
in Driftwood Pipeline LLC and a 10 % interest in Louisiana LNG LLC for total proceeds of $370 million, comprising a base purchase
price of $250 million and reimbursement of capital expenditure incurred by the Group since the effective date of 1 January 2025. Prior to
the transaction, both entities were wholly owned subsidiaries of the Group.
Driftwood Pipeline LLC develops, constructs and operates natural gas pipelines associated with the Louisiana LNG Project.
Following completion, control of Driftwood Pipeline LLC transferred to Williams. The Group recognised a gain on sale of $16 million
F-39
Table of Contents
Notes to the financial statements B. Production and growth assets
for the year ended 31 December 2025
in other income and derecognised the entity’s assets and liabilities from the consolidated statement of financial position. The retained
Louisiana LNG LLC will manage the sale of future LNG offtake. Following the sell-down, the Group retains control, and Williams holds
a 10 % non-controlling interest. On completion, $36 million was recognised in other reserves representing the surplus of proceeds
received over the non-controlling interest recognised.
The proceeds of $370 million received from Williams are allocated between deposits/proceeds received from disposal of non-current
assets and contributions from non-controlling interests in the consolidated statement of cash flows as at 31 December 2025.
(b) Sell-down of Louisiana LNG Infrastructure LLC to Stonepeak Wallaby I Acquiror LP
On 7 April 2025, the Group and Stonepeak Wallaby I Acquiror LP (Stonepeak) entered into an agreement for Stonepeak to acquire a
effective date of 1 January 2025. Stonepeak will provide up to $5,700 million towards the expected capital spend for the foundation
development of Louisiana LNG on an accelerated basis, contributing 75 % of the expected project capital expenditure in both 2025 and
2026. As at 31 December 2025, total payment of $2,594 million was received.
Under the agreement, the Group still controls Louisiana LNG Infrastructure LLC, while Stonepeak now holds a non-controlling interest.
Stonepeak’s non-controlling interest percentage is based on the proportion of total contributions to date and will fluctuate during the
construction phase. The non-controlling interest percentage is expected to revert to 40 % when the project starts generating revenue.
The proceeds of $1,876 million received from Stonepeak on transaction completion are included in contributions from non‑controlling
interests in the consolidated statement of cash flows as at 31 December 2025. On transaction completion date, $2,146 million has been
recognised as non-controlling interest, and $278 million has been recognised in other reserves for the difference in proceeds received and
the non-controlling interest recognised.
(a) Control
Under IFRS 10 Consolidated Financial Statements, consolidation is required when an investor controls an investee. If a parent loses
control of a subsidiary, the parent is required to derecognise the assets and liabilities of the former subsidiary at their carrying amounts at
the date when control is lost. Judgement is required to determine if the Group continues to control Louisiana LNG Infrastructure LLC
after the sell-down.
It has been determined that the Group continues to control and consolidate Louisiana LNG Infrastructure LLC as it has the power
to direct the relevant activities and decisions requiring majority approval through its roles as operator, construction manager,
and majority interest holder.
(b) Classification of non-controlling interest as equity or liability
Judgement is required to determine if the classification of the non‑controlling interest is either equity or liability based on the Group’s
contractual obligation to deliver cash or another financial asset. Louisiana LNG Infrastructure LLC and Louisiana LNG LLC are not
required to distribute dividends unless Woodside Energy Group Ltd declares dividends. As the Group can indefinitely defer payment of
the Louisiana LNG Infrastructure LLC dividend and Louisiana LNG LLC dividend based on the terms in the agreement, the
non‑controlling interest in Louisiana LNG Infrastructure LLC and Louisiana LNG LLC is classified as equity in the Group’s
consolidated financial statements. While the terms grant the Group discretion to avoid distributing dividends from Louisiana LNG
Infrastructure LLC and Louisiana LNG LLC, the exercise of this discretion may increase the non-controlling interest’s entitlement to
F-40
Table of Contents
Notes to the financial statements C. Debt and capital
for the year ended 31 December 2025
In this section
This section addresses cash, debt and the capital position of the Group at the end of the reporting period including, where applicable, the
accounting policies applied and the significant estimates and judgements made.
C. | Debt and capital | ||
C.1 | Cash and cash equivalents | Page F-41 | |
C.2 | Interest-bearing liabilities and financing facilities | Page F-41 | |
C.3 | Contributed equity | Page F-43 | |
C.4 | Other reserves | Page F-44 |
Key financial and capital risks in this section
Group Treasury is responsible for the Group's capital management including cash, debt and equity. Capital management is undertaken to
ensure that a secure, cost-effective and flexible supply of funds is available to meet the Group’s operating and capital expenditure
requirements. A stable capital base is maintained from which the Group can pursue its growth aspirations, whilst maintaining a flexible
capital structure that allows access to a range of debt and equity markets to both draw upon and repay capital.
The Dividend Reinvestment Plan (DRP) was approved by shareholders at the Annual General Meeting in 2003 for activation as required
to fund future growth. The DRP was reactivated in 2019 and suspended by the Board of Directors on 27 February 2023.
A range of financial metrics are monitored, including gearing and cash flow leverage, and Treasury policy breaches and exceptions.
Liquidity risk arises from the financial liabilities of the Group and the Group’s subsequent ability to meet its obligations to repay
financial liabilities as and when they fall due. The liquidity position of the Group is managed to ensure sufficient liquid funds are
available to meet its financial commitments in a timely and cost-effective manner.
The Group’s liquidity is continually reviewed, including cash flow forecasts to determine the forecast liquidity position and maintain
appropriate liquidity levels. The Group’s primary sources of liquidity are cash and cash equivalents, net cash from operating activities,
unused borrowing capacity under its bilateral facilities and syndicated facilities, issuances of debt or equity securities and other potential
sources of liquidity, such as sales of assets or equity interests in assets. At 31 December 2025, the Group had a total of $9,262 million
(2024: $6,723 million) of available undrawn facilities and cash at its disposal. The maturity profile of interest-bearing liabilities is
disclosed in Note C.2, trade and other payables are disclosed in Note D.4 and lease liabilities are disclosed in Note D.7. Financing
facilities available to the Group are disclosed in Note C.2. Capital commitments contracted for, but not provided for in the financial
statements, are disclosed in Note B.3.
Interest rate risk is the risk that the Group’s financial position will fluctuate due to changes in market interest rates.
The Group’s exposure to the risk of changes in market interest rates relates primarily to financial instruments with floating interest rates
including long-term debt obligations, cash and short-term deposits. The Group manages its interest rate risk by maintaining an
appropriate mix of fixed and floating rate debt. To manage the ratio of fixed rate debt to floating rate debt, the Group may enter into
interest rate swaps. The Group holds interest rate swaps to hedge the interest rate risk associated with the $600 million syndicated
facility. Refer to Notes C.2 and D.6 for further details.
At the reporting date, the Group was exposed to various benchmark interest rates that were not designated in cash flow hedges, primarily
through $5,712 million (2024: $3,923 million) on cash and cash equivalents and $2,650 million (2024: $3,150 million) on interest-
bearing liabilities (excluding transaction costs).
A reasonably possible change in the Secured Overnight Financing Rate (SOFR) (+2.0 %/-2.0 % (2024: +2.0 %/-2.0 %)), with all variables
held constant, would not have a material impact (2024: no material impact) on the Group’s equity or the income statement in the
current period.
F-41
Table of Contents
Notes to the financial statements C. Debt and capital
for the year ended 31 December 2025
C.1 Cash and cash equivalents
2025 | 2024 | ||
US$m | US$m | ||
Cash and cash equivalents | |||
Cash at bank | |||
Term deposits | |||
Total cash and cash equivalents |
Cash and cash equivalents in the consolidated statement of financial position comprise cash at bank and short-term deposits with an
original maturity of three months or less. Cash and cash equivalents are stated at face value in the consolidated statement of financial
position. There are no cash and cash equivalents (2024: nil ) restricted by legal or contractual arrangements.
Foreign exchange risk
2025 | 2024 | ||
US$m | US$m | ||
US dollar | |||
Australian dollar | |||
Other | |||
Total cash and cash equivalents |
C.2 Interest-bearing liabilities and financing facilities
Liquidity facilities | Bilateral facilities | Syndicated facilities | JBIC facility | US bonds | Medium term notes | Other | Total | ||||||||
US$m | US$m | US$m | US$m | US$m | US$m | US$m | US$m | ||||||||
Year ended 31 December 2025 | |||||||||||||||
At 1 January 2025 | |||||||||||||||
Drawdowns1 | |||||||||||||||
Repayments1 | ( | ( | ( | ||||||||||||
Transaction costs capitalised and amortised | ( | ( | ( | ||||||||||||
Carrying amount at 31 December 2025 | ( | ||||||||||||||
Current | ( | ( | |||||||||||||
Non-current | ( | ||||||||||||||
Carrying amount at 31 December 2025 | ( | ||||||||||||||
Undrawn balance at 31 December 2025 | |||||||||||||||
Year ended 31 December 2024 | |||||||||||||||
At 1 January 2024 | ( | ( | |||||||||||||
Debt acquired through asset acquisitions2 | |||||||||||||||
Drawdowns1 | |||||||||||||||
Repayments1,2 | ( | ( | |||||||||||||
Transaction costs capitalised and amortised | ( | ( | ( | ||||||||||||
Carrying amount at 31 December 2024 | |||||||||||||||
Current | ( | ( | |||||||||||||
Non-current | |||||||||||||||
Carrying amount at 31 December 2024 | |||||||||||||||
Undrawn balance at 31 December 2024 |
1.Included in cash flows classified within financing activities in the consolidated statement of cash flows.
2.Refer to Note B.7 for details on asset acquisitions. The debt acquired through asset acquisitions was repaid during the year.
F-42
Table of Contents
Notes to the financial statements C. Debt and capital
for the year ended 31 December 2025
All borrowings are initially recognised at fair value less transaction costs. Borrowings are subsequently carried at amortised cost.
Any difference between the proceeds received and the redemption amount is recognised in the income statement over the period of the
borrowings using the effective interest method.
Borrowings designated as a hedged item are measured at amortised cost adjusted to record changes in the fair value of risks that are
being hedged in fair value hedges.
All bonds, notes and facilities are subject to various covenants and negative pledges restricting future secured borrowings, subject to a
number of permitted lien exceptions. Neither the covenants nor the negative pledges have been breached at any time during the reporting
period.
Fair value
The carrying amount of interest-bearing liabilities approximates their fair value, with the exception of the Group’s unsecured bonds and
the medium term notes. The unsecured bonds have a carrying amount of $8,535 million (2024: $6,069 million) and a fair value of $8,665
million (2024: $5,879 million). The medium term notes have a carrying amount of $200 million (2024: $200 million) and a fair value of
$197 million (2024: $191 million). Fair value is calculated based on the present value of future principal and interest cash flows,
discounted at the market rate of interest at the reporting date and classified as Level 1 on the fair value hierarchy. Where these cash flows
are in a foreign currency, the present value is converted to US dollars at the foreign exchange spot rate prevailing at the reporting date.
The Group’s repayment obligations remain unchanged.
Foreign exchange risk
All interest-bearing liabilities are denominated in US dollars.
Maturity profile of interest-bearing liabilities
principal and interest. The figures will not necessarily reconcile with the amounts disclosed in the consolidated statement of financial
position.
2025 | 2024 | ||
US$m | US$m | ||
Due for payment in: | |||
1 year or less | |||
1-2 years | |||
2-3 years | |||
3-4 years | |||
4-5 years | |||
More than 5 years | |||
Amounts exclude transaction costs.
Liquidity facilities
In March 2025, the Group entered into two 12 -month liquidity facilities of $1,500
plus margin, fixed at the commencement of the drawdown period. These facilities were cancelled upon receiving the cash from the
unsecured bonds in May 2025.
Bilateral facilities
The Group has 15 undrawn bilateral loan facilities totalling $2,350 million (2024: 13 bilateral loan facilities totalling $2,100 million).
Number of facilities | Term (years) | Currency | Extension option | |||
US$ | Evergreen | |||||
US$ | Evergreen | |||||
US$ | Evergreen | |||||
US$ | Evergreen |
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Notes to the financial statements C. Debt and capital
for the year ended 31 December 2025
Interest rates are based on SOFR plus margins are fixed 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’s agreement.
In March 2025, the Group executed two bilateral facilities amounting to $250 million.
In March and April 2025, the Group drew down on eight bilateral facilities amounting to $1,400 million. In June 2025, the Group repaid
$1,900 million of bilateral facilities, inclusive of $500 million which was drawn in January 2024.
Syndicated facility
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. The facility was fully drawn in 2020.
On 20 June 2024, the Group entered into a $450 million syndicated term loan facility with a tenor of 10 years. Interest is based on daily
SOFR plus CAS and margin. The facility was fully drawn in June 2024.
On 19 September 2024, the Group entered into a $1,200 million syndicated term loan facility with a tenor of 7 years. Interest is based on
daily SOFR and margin. The facility was fully drawn in September 2024.
On 27 June 2025, Woodside refinanced existing undrawn $1,200 million syndicated facilities, $600 million expiring on 27 June 2028
and $600 million expiring on 27 June 2030. Interest rates are based on SOFR plus CAS and margins are fixed at the commencement of
the drawdown period.
Japan Bank for International Cooperation (JBIC) facility
On 30 May 2024, the Group entered into a $1,000 million loan facility with JBIC with a term of 10 years, to support the funding of the
Scarborough Energy Project. Interest is based on daily SOFR plus margin. The facility was fully drawn in July 2024.
Medium term notes
On 28 August 2015, the Group established a $3,000 million Global Medium Term Notes Programme listed on the Singapore Stock
Exchange. One note is currently issued under this programme as set out below:
Maturity date | Currency | Carrying amount (million) | Nominal interest rate |
29 January 2027 | US$ |
The unutilised program is not considered to be an unused facility.
US bonds
The Group has three series of unsecured bonds issued in reliance on Rule 144A of the US Securities Act of 1933 and six series of
unsecured bonds issued in accordance with the registration requirements of the US Securities Act of 1933 (SEC-registered bonds) as set
out below:
Maturity date | Carrying amount US$m | Nominal interest rate | Bond type | ||
15 September 2026 | 144A | ||||
15 March 2028 | 144A | ||||
19 May 2028 | SEC-registered | ||||
4 March 2029 | 144A | ||||
19 May 2030 | SEC-registered | ||||
19 May 2032 | SEC-registered | ||||
12 September 2034 | SEC-registered | ||||
19 May 2035 | SEC-registered | ||||
12 September 2054 | SEC-registered |
$1,000 million of unsecured bonds matured in March 2025. Interest on the bonds is payable semi-annually in arrears.
C.3 Contributed equity
Recognition and measurement
Ordinary shares are classified as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share
capital as a deduction, net of tax, from the proceeds.
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Notes to the financial statements C. Debt and capital
for the year ended 31 December 2025
Reserved shares are the Group’s own equity instruments, which are used in employee share-based payment arrangements or the Dividend
Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity. No gain or loss is recognised
in the consolidated income statement on the purchase, sale, issue or cancellation of the Group’s own equity instruments.
Number of shares | US$m | ||
Year ended 31 December 2025 | |||
Opening balance | |||
Shares Issued | |||
Amounts as at 31 December 2025 | |||
Year ended 31 December 2024 | |||
Opening balance | |||
Amounts as at 31 December 2024 | |||
Year ended 31 December 2023 | |||
Opening balance | |||
Amounts as at 31 December 2023 |
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.
Employee share plans | |||
Number of shares | US$m | ||
Year ended 31 December 2025 | |||
Opening balance | ( | ||
Purchases during the year | ( | ||
Vested/allocated during the year | ( | ||
Amounts as at 31 December 2025 | ( | ||
Year ended 31 December 2024 | |||
Opening balance | ( | ||
Purchases during the year | ( | ||
Vested/allocated during the year | ( | ||
Amounts as at 31 December 2024 | ( | ||
Year ended 31 December 2023 | |||
Opening balance | ( | ||
Purchases during the year | ( | ||
Vested/allocated during the year | ( | ||
Amounts as at 31 December 2023 | ( | ||
C.4 Other reserves
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Other reserves | |||||
Employee benefits reserve | |||||
Foreign currency translation reserve | |||||
Hedging reserve | |||||
Distributable profits reserve1 | |||||
Other reserves | ( | ( | ( | ||
Non-controlling interest reserve | ( | ||||
1.For the year ended 31 December 2025, the Group transferred $4,500 million of retained earnings to the distributable profits reserve. The increase was
offset by the 2024 final and 2025 interim dividend payments of $2,012 million.
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Table of Contents
Notes to the financial statements C. Debt and capital
for the year ended 31 December 2025
Employee benefits reserve
Used to record share-based payments associated with the employee share plans.
Foreign currency translation reserve
Used to record foreign exchange differences arising from the translation of the financial statements of foreign entities from their
functional currency to the Group’s presentation currency.
Hedging reserve
Used to record gains and losses on effective portion of hedges designated as cash flow hedges, and foreign currency basis spread arising
from the designation of a financial instrument as a hedging instrument. Gains and losses accumulated in the cash flow hedge reserve for
qualifying assets are capitalised against the carrying amount of that asset and recognised in the income statement as the asset is
depreciated.
Distributable profits reserve
Used to record distributable profits generated by the parent entity, Woodside Energy Group Ltd.
Other reserves
Used to record gains and losses on financial instruments at fair value through other comprehensive income.
Non-controlling interest contribution reserve
Transactions that do not result in a loss of control are accounted for as equity transactions. When ownership interests change, the
carrying amounts of both controlling and non‑controlling interests are adjusted to reflect the revised ownership proportions, with any
difference between the adjustment and the consideration received recognised in the non-controlling interest contribution reserve within
other reserves.
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Table of Contents
Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
In this section
This section addresses the other assets and liabilities position at the end of the reporting period including, where applicable, the
accounting policies applied and the significant estimates and judgements made.
D. | Other assets and liabilities | |
D.1 | Segment assets and liabilities | Page F-47 |
D.2 | Receivables | Page F-47 |
D.3 | Inventories | Page F-48 |
D.4 | Payables | Page F-49 |
D.5 | Provisions | Page F-49 |
D.6 | Other financial assets and liabilities | Page F-51 |
D.7 | Leases | Page F-55 |
Key financial and capital risks in this section
Credit risk is the risk that a counterparty will not meet its payment obligation under a financial instrument or customer contract,
leading to a financial loss to the Group. Credit risk arises from the financial instruments of the Group, which include trade and other
receivables, loans receivables and deposits with banks and financial institutions.
The Group manages its credit risk on trade receivables and financial instruments by predominantly dealing with counterparties with
an investment grade credit rating. Sufficient financial security is obtained to mitigate the risk of financial loss when transacting with
counterparties with below investment grade credit ratings. Customers who wish to trade on unsecured credit terms are subject to credit
assessment procedures. Receivable balances are monitored on an ongoing basis. As a result, the Group’s exposure to credit loss is not
significant. The Group’s maximum credit exposure is limited to the carrying amount of its financial assets.
Customer credit risk is managed by the Treasury function subject to the Group’s established policy, procedures and controls relating
to customer credit risk management. The credit quality of a customer is assessed based on various credit metrics, including its credit
rating, and individual credit limits and requirements are defined in accordance with this assessment. Outstanding customer receivables
are regularly monitored.
At 31 December 2025, the Group had 20 customers (2024: 23 customers) that owed the Group more than $10 million each and
accounted for approximately 90 % (2024: 88 %) of product-related trade receivables. Depending on the product, standard settlement terms
are 7 to 30 days from the date of invoice or bill of lading.
The Group considers the probability of default upon initial recognition of the asset and whether there has been a significant depreciation
in credit quality on an ongoing basis. A significant decrease in credit quality is defined as a debtor being greater than 30 days past due in
making a contractual payment. Credit losses for trade receivables (including lease receivables) and contract assets are determined by
applying the simplified approach and are measured at an amount equal to lifetime expected loss. Under the simplified approach,
determination of the loss allowance provision and expected loss rate incorporates past experience and forward-looking information,
including the outlook for market demand and forward-looking interest rates. A default on other financial assets is considered to be when
the counterparty fails to make contractual payments within 60 days of when they fall due.
At 31 December 2025, the Group had a provision for credit losses of nil (2024: nil ). Subsequent to 31 December 2025, 99 %(2024: 96 %)
of product-related trade receivables balance of $948 million (2024: $972 million) has been received.
Credit risk from balances with banks is managed by the Treasury function in accordance with the Group’s policy. The Group places
funds from time to time as short-term deposits with reputable financial institutions with investment grade credit ratings. At 31 December
2025 and 31 December 2024, there were no significant concentrations of credit risk within the Group and financial instruments are
spread amongst a number of financial institutions to minimise the risk of counterparty default. The maximum exposure to financial
institution credit risk is represented by the sum of all cash deposits plus accrued interest, bank account balances and fair value of
derivative assets. The Group’s counterparty credit policy limits this exposure to commercial and investment banks, according
to approved credit limits based on the counterparty’s credit rating.
11.
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Table of Contents
Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
D.1 Segment assets and liabilities
2025 | 20241 | ||
US$m | US$m | ||
(a) Segment assets | |||
Australia | |||
International | |||
Marketing | |||
Corporate | |||
2025 | 20241 | ||
US$m | US$m | ||
(b) Segment liabilities | |||
Australia | |||
International | |||
Marketing | |||
Corporate | |||
1.The 2024 amounts have been restated to reflect the changes in operating segments.
$2,614 72
‘Operating segment information’ in Note A.1 for details.
Refer to Note A.1 for descriptions of the Group’s segments. Corporate assets mainly comprise cash and cash equivalents, deferred tax
assets, new energy assets in development and lease assets. Corporate liabilities mainly comprise interest-bearing liabilities, deferred tax
liabilities and lease liabilities.
Segment assets include non-current assets1 of $30,203 million (2024: $29,466 million) in Australia, $17,347 million (2024: $13,847
million) in USA, $3,854 million (2024: $5,268 million) in Senegal, $2,364 million (2024: $1,357 million) in Mexico, and $1,453 million
(2024: $1,370 million) in other locations.
1.Excluding deferred tax assets of $2,658 million (2024: $2,393 million).
D.2 Receivables
2025 | 2024 | ||
US$m | US$m | ||
(a) Receivables (current) | |||
Trade receivables1 | |||
Other receivables1,2 | |||
Loans receivable | |||
Lease receivables | |||
Interest receivable | |||
(b) Receivables (non-current) | |||
Other receivables | |||
Loans receivable | |||
Lease receivables | |||
1.Interest-free and settlement terms are usually between 14 and 30 days.
2.$715 million of the carrying amount as at 31 December 2024 related to expected reimbursements from OCI N.V. for forecast capital spend. The full
F-48
Table of Contents
Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
Trade receivables are initially recognised at the transaction price determined under IFRS 15 Revenue from Contracts with Customers.
Other receivables are initially recognised at fair value. Receivables that satisfy the contractual cash flow and business model tests are
subsequently measured at amortised cost less an allowance for uncollectable amounts. Uncollectable amounts are determined using the
expected loss impairment model. Collectability and impairment are assessed on a regular basis.
Subsequent recoveries of amounts previously written off are credited against other expenses in the consolidated income statement.
Certain receivables that do not satisfy the contractual cash flow and business model tests are subsequently measured at fair value (refer to
Note D.6).
The Group’s customers are required to pay in accordance with agreed payment terms. Depending on the product, settlement terms are 7
to 30 days from the date of invoice or bill of lading and customers regularly pay on time. There are no significant overdue product-
related trade receivables as at the end of the reporting period (2024: nil ).
Fair value
The carrying amount of trade and other receivables approximates their fair value.
Foreign exchange risk
The Group held $493 million of receivables at 31 December 2025 (2024: $479 million) in currencies other than US dollars
(predominantly Australian dollars).
Loans receivable
On 9 January 2020, the Group 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. The carrying amount of the loan receivable is $451 million at 31 December 2025 (2024: $464 million), which approximates
its fair value. Loan repayments commenced from July 2025 and the Group continues to receive repayments in instalments. The
remaining balance of loans receivable is due from non-controlling interests.
D.3 Inventories
2025 | 2024 | ||
US$m | US$m | ||
(a) Inventories (current) | |||
Products | |||
Goods in transit | |||
Finished stocks | |||
Warehouse stores and materials | |||
Carbon credits | |||
(b) Inventories (non-current) | |||
Warehouse stores and materials | |||
Carbon credits | |||
Inventories include hydrocarbon stocks, consumable supplies, maintenance spares and carbon credits expected to be utilised to offset
future emissions. Inventories are valued at the lower of cost and net realisable value. Cost is determined on a weighted average basis and
includes direct costs and an appropriate portion of fixed and variable production overheads where applicable. Inventories determined to
be obsolete or damaged are written down to net realisable value, being the estimated selling price less selling costs.
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Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
D.4 Payables
2025 | 2024 | ||
US$m | US$m | ||
Trade and other payables1 | 1,492 | ||
Interest payable2 | 112 | ||
1,604 |
1.Interest-free and normally settled on 30 day terms.
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 $208 million of payables at 31 December 2025 (2024: $140 million) in currencies other than US dollars (predominantly
Australian dollars).
Maturity profile of payables
The Group’s payables balances at 31 December 2025 and 31 December 2024 are due for payment within 12 months.
D.5 Provisions
Restoration1 | Employee benefits | Other | Total | ||||
US$m | US$m | US$m | US$m | ||||
Year ended 31 December 2025 | |||||||
At 1 January 2025 | |||||||
Adjustment to purchase price allocation2 | |||||||
Change in provision | ( | ||||||
Unwinding of present value discount | |||||||
Disposals3 | ( | ( | ( | ( | |||
Carrying amount at 31 December 2025 | |||||||
Current | |||||||
Non-current | |||||||
Net carrying amount | |||||||
Year ended 31 December 2024 | |||||||
At 1 January 2024 | |||||||
Acquisitions through business combinations and asset acquisitions2 | |||||||
Change in provision | ( | ( | |||||
Unwinding of present value discount | |||||||
Carrying amount at 31 December 2024 | |||||||
Current | |||||||
Non-current | |||||||
Net carrying amount |
1.2025 change in provision is due to changes in estimates of $898 million and changes in foreign exchange rates of $233 million offset by provisions
used of $823 million and a revision of discount rates of $54 million. Changes in estimates are due to new activities, revisions to cost and removal
scope assumptions and rate changes supported by most recent estimates and benchmarks.
2.Refer to Note B.5 for details of business combination.
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Table of Contents
Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an
outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the
amount of the obligation.
The restoration provision is first recognised in the period in which the obligation arises. The nature of restoration activities includes the
removal of facilities, abandonment of wells and restoration of affected areas. Restoration provisions are updated annually, with the
corresponding movement recognised against the related exploration and evaluation assets or property, plant and equipment or expensed
for late life projects with no corresponding asset.
Over time, the liability is increased for the change in the present value based on a pre-tax discount rate appropriate to the risks inherent in
the liability. The unwinding of the discount is recorded as an accretion charge within finance costs. The carrying amount capitalised in
property, plant and equipment is depreciated over the useful life of the related asset (refer to Note B.3).
Costs incurred that relate to an existing condition caused by past operations, and which do not have a future economic benefit,
are expensed.
Provision is made for employee benefits accumulated as a result of employees rendering services up to the end of the reporting period.
These benefits include wages, salaries, annual leave and long service leave.
Liabilities in respect of employees’ services rendered that are not expected to be wholly settled within one year after the end of the
period in which the employees render the related services are recognised as long-term employee benefits.
These liabilities are measured at the present value of the estimated future cash outflow to the employees using the projected unit credit
method. Liabilities expected to be wholly settled within one year after the end of the period in which the employees render the related
services are classified as short-term benefits and are measured at the amount due to be paid.
Provision is made for loss-making contracts at the present value of the lower of the net cost of fulfilling and the cost arising from failure
to fulfil each contract. The Group had no onerous contract provision as at 31 December 2025.
(a) Restoration obligations
The Group estimates the future decommissioning and remediation costs of offshore oil and gas platforms, offshore and onshore
production facilities, wells and pipelines at different stages of the development and construction of assets or facilities including for new
energy assets. In many instances, decommissioning of assets occurs many years into the future.
The Group’s restoration obligations are based on compliance with the requirements of relevant regulations which vary for different
jurisdictions. For example Australian regulations require full removal for offshore assets unless regulator approval is received to
decommission in-situ. It is currently the Group’s assumption that in some regulatory jurisdictions and environments, certain
infrastructures are decommissioned in-situ where it can be demonstrated that this will deliver equal or better environmental outcomes
than full removal and that regulatory approval is obtained where arrangements are satisfactory to the regulator. The Group maintains
technical expertise to ensure that industry learnings, scientific research and local and international guidelines are reviewed in assessing
its restoration obligations.
The restoration obligation requires judgemental assumptions regarding removal timing, applicable environmental legislation
and regulations, the extent of restoration activities required, the engineering methodology and the technologies used for estimating costs.
These assumptions inform the estimated future cash flows, which are then discounted using the risk-free discount rates aligned to the
expected timing of the cash outflows.
Expected value approach
For both onshore and offshore assets, provision has been made taking into consideration a risked range of possible removal outcomes,
including full removal of certain assets or project-specific risks (where applicable). Individual site provisions are an estimate of the
expected value of future cash flows required to rehabilitate the relevant site using current restoration standards and techniques and taking
into account risks and uncertainties. Individual site provisions are discounted to their present value using risk-free country-specific
discount rates aligned to the estimated timing of cash outflows. This approach also takes into consideration the possibility that full
removal of all assets may be required.
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Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
Inherent uncertainties
The basis of the restoration obligation provision for assets with approved decommissioning plans or general directions issued by the
regulator can differ from the assumptions disclosed above. Whilst the provisions reflect the Group’s best estimate based on current
knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be ongoing to
ensure that the most accurate information is available when detailed decommissioning plans are required to be submitted to the relevant
regulatory authorities. Actual costs and cash outflows can materially differ from the current estimate as a result of changes in regulations
and their application, prices, analysis of site conditions, further studies, timing of restoration and changes in removal technology. These
uncertainties may result in actual expenditure differing from amounts included in the provision recognised as at 31 December 2025.
A range of pre-tax discount rates between 3.5 % and 5.2 % (2024: 4.0 % and 4.9 %) has been applied. If the discount rates were decreased
by 0.5 % then the provision would be $355 million higher. If the cost estimates were increased by 10 % then the provision would be $689
million higher. The proportion of the non-current balance not expected to be settled within 10 years is 56 % (2024: 53 %).
D.6 Other financial assets and liabilities
2025 | 2024 | ||
US$m | US$m | ||
Other financial assets | |||
Financial instruments at fair value through profit and loss | |||
Derivative financial instruments designated as hedges | |||
Other financial assets | |||
Financial instruments at fair value through other comprehensive income | |||
Other financial assets | |||
Total other financial assets | |||
Current | |||
Non-current | |||
Net carrying amount | |||
Other financial liabilities | |||
Financial instruments at fair value through profit and loss | |||
Derivative financial instruments designated as hedges | |||
Embedded derivative | |||
Other financial liabilities | |||
Total other financial liabilities | |||
Current | |||
Non-current | |||
Net carrying amount |
Derivative financial instruments
Derivative financial instruments that are designated within qualifying hedge relationships are initially recognised at fair value on the date
the contract is entered into. For relationships designated as fair value hedges, subsequent fair value movements of the derivative are
recognised in the consolidated income statement.
For relationships designated as cash flow hedges, subsequent fair value movements of the derivative for the effective portion of the
hedge are recognised in other comprehensive income and accumulated in reserves in equity; fair value movements for the ineffective
portion are recognised immediately in the consolidated income statement. Costs of hedging have been separated from the hedging
arrangements and deferred to other comprehensive income and accumulated in reserves in equity. Amounts accumulated in equity are
reclassified to the consolidated income statement in the periods when the hedged item affects profit or loss.
Hedge effectiveness is determined at the inception of the hedge relationship, and through periodic prospective effectiveness assessments
to ensure that an economic relationship exists between the hedged exposure and the hedging instrument. The Group assesses whether the
derivative designated in each hedging relationship has been, and is expected to be, effective in offsetting changes in cash flows of the
hedged exposure using the hypothetical derivative method.
Ineffectiveness is recognised where the cumulative change in the designated component value of the hedging instrument on an absolute
basis exceeds the change in value of the hedged exposure attributable to the hedged risk.
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Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
Ineffectiveness may arise where the timing of the transaction changes from what was originally estimated such as delayed shipments or
changes in timing of forecast sales. This may also arise where the commodity swap pricing terms do not perfectly match the pricing
terms of the revenue contracts.
Fair value
Except for the other financial assets and other financial liabilities set out in this note, there are no material financial assets or financial
liabilities carried at fair value.
The fair value of commodity derivative financial instruments is determined based on observable quoted forward pricing and swap
models and is classified as Level 2 on the fair value hierarchy. The most frequently applied valuation techniques include forward pricing
and swap models that use present value calculations. The models incorporate various inputs including the credit quality of counterparties
and forward rate curves of the underlying commodity.
The fair value of interest rate swaps is calculated by discounting estimated future cash flows based on the terms of maturity of each
contract, using market interest rates for a similar instrument at the reporting date, and is classified as Level 2 on the fair value hierarchy.
The fair value of foreign exchange forward contracts is determined using quoted forward exchange rates at the reporting date and present
value calculations based on high credit quality yield curves in the respective currencies and is classified as Level 2 on the fair value
hierarchy.
The fair values of other financial assets and other financial liabilities are predominantly determined based on observable quoted forward
pricing and are predominantly classified as Level 2 on the fair value hierarchy.
Embedded commodity derivatives are classified as Level 3 on the fair value hierarchy with no market observable inputs.
Except for the revised valuation inputs for the embedded commodity derivative, there were no changes to the Group’s valuation
processes, valuation techniques and types of inputs used in the fair value measurements during the period.
Foreign exchange
The derivative financial instruments include foreign exchange forward contracts that are denominated in Australian dollars. The Group
had no material other financial assets and liabilities denominated in currencies other than US dollars.
Hedging activities
During the period, the following hedging activities were undertaken:
•As at 31 December 2025, the Group hedged approximately 10 MMboe of 2026 oil priced exposure at an average price
of approximately 70.1 per barrel.
•The Group also has a hedging program for Corpus Christi LNG volumes designed to protect against downside pricing risk. These
hedges are HH and TTF commodity swaps. Approximately 89 % of 2026 volumes have been hedged.
•Through foreign exchange forward contracts, the Group hedged the Australian dollar to US dollar exchange rate for a portion of the
Australian dollar denominated capital expenditure expected to be incurred for the Scarborough development.
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Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
2025 | 2024 | ||
Brent commodity swaps (cash flow hedges) | |||
Carrying amount (US$m) | |||
Notional amount (MMbbl)1 | |||
Maturity date | 2026 | 2025 | |
Hedge ratio | |||
Weighted average hedged rate (US$/MMbbl) | |||
HH LNG commodity swaps (cash flow hedges) | |||
Carrying amount (US$m) | ( | ||
Notional amount (TBtu)1 | |||
Maturity date | 2026 | 2025-2026 | |
Hedge ratio | |||
Weighted average hedged rate (US$/MMBtu) | |||
TTF LNG commodity swaps (cash flow hedges) | |||
Carrying amount (US$m) | ( | ||
Notional amount (TBtu)1 | |||
Maturity date | 2026 | 2025-2026 | |
Hedge ratio | |||
Weighted average hedged rate (US$/MMBtu) | |||
Interest rate swap (cash flow hedges) | |||
Carrying amount (US$m) | |||
Notional amount (US$m) | |||
Maturity date | 2027 | 2027 | |
Hedge ratio | |||
Weighted average hedged rate | |||
FX forwards (cash flow hedges) | |||
Carrying amount (US$m) | ( | ||
Notional amount (AUD$m)2 | |||
Maturity date | 2026 | 2025 | |
Hedge ratio | |||
Weighted average hedged rate (AUD:USD) |
1.The notional amounts relate to unrealised volumes of the hedge item included in the cash flow hedge reserve.
2.This notional amount represents total since inception of which AUD$513 million is unrealised volumes of the hedge item included in the cash flow
hedge reserve.
Hedge ineffectiveness gain of $21 million (2024: $5 million loss) has been recognised in the profit and loss.
Embedded derivative
In 2024, the Group entered into a revised long-term gas sale and purchase contract (GSPA) with Perdaman, where a component of the
selling price is linked to the price of urea. The contract was assessed to contain an embedded commodity derivative that is required to be
separated and recognised at fair value through profit and loss. The carrying value of the embedded derivative at 31 December 2025
amounted to a net liability of $212 million (2024: net liability of $349 million). The derivative is remeasured to fair value at each
reporting date. For the year ended 31 December 2025, an unrealised gain of $137 million has been recognised through other income
(2024: unrealised loss of $314 million through other expenses).
(a) Change in embedded derivative valuation inputs
The Group has reassessed the valuation inputs of the Perdaman embedded derivative factoring current market conditions and as a result
revised pricing inputs that reflect the long-term nature of the contract and external market data. The change has been applied from 1
January 2025, resulting in an increase in fair value gains of $151 million for the year ended 31 December 2025. The effect of future
periods is not disclosed because estimating it is impracticable.
(b) Embedded derivative
The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires
management to make certain assumptions about the model inputs, including forecast cash flows, discount rate, credit risk and volatility.
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Table of Contents
Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
These assumptions require significant judgement and are subject to risk and uncertainty. The present value of the embedded derivative
was estimated using the assumptions set out below.
•Inflation rate – 2.5 % (2024: 2.5 %) has been applied.
•Discount rate – a pre-tax interest rate curve with a range of 4.69 % to 7.53 % (2024: range of 5.80 % to 6.95 %).
•Domestic gas pricing – forecast sales are subject to urea pricing. Price assumptions are based on the best market information
available at measurement date and derived from short- and long-term views of global supply and demand, building upon past
experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the
prevailing gas hub (TTF) prices available in the market.
The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses
recognised in other income/expenses.
The nominal impacts of the effects of changes to discount rate and long term price assumptions are estimated as follows. The valuation is
over a contract period of 20 years and the below change in assumptions applies a linear increase or decrease in inputs over the life of the
contract. A spot increase is not represented by the sensitivity below.
Change in assumption1 | US$m | |
TTF sales price: increase of | ||
TTF sales price: decrease of | ( | |
Discount rate: increase of | ( | |
Discount rate: decrease of |
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.
F-55
Table of Contents
Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
D.7 Leases
Land and buildings | Oil and gas properties | Other plant and equipment | Total | ||||
US$m | US$m | US$m | US$m | ||||
Lease assets | |||||||
Year ended 31 December 2025 | |||||||
Carrying amount at 1 January 2025 | |||||||
Additions | |||||||
Disposals at written down value | ( | ( | |||||
Lease remeasurements | |||||||
Depreciation | ( | ( | ( | ( | |||
Carrying amount at 31 December 2025 | |||||||
At 31 December 2025 | |||||||
Historical cost | |||||||
Accumulated depreciation and impairment | ( | ( | ( | ( | |||
Net carrying amount | |||||||
Lease liabilities | |||||||
Year ended 31 December 2025 | |||||||
At 1 January 2025 | |||||||
Additions | |||||||
Disposals | ( | ( | |||||
Repayments (principal and interest) | ( | ( | ( | ( | |||
Accretion of interest | |||||||
Lease remeasurements | |||||||
Carrying amount at 31 December 2025 | |||||||
Current | |||||||
Non-current | |||||||
Carrying amount at 31 December 2025 | |||||||
Lease assets | |||||||
Year ended 31 December 2024 | |||||||
Carrying amount at 1 January 2024 | |||||||
Acquisitions through asset acquisitions1 | |||||||
Additions | |||||||
Disposals at written down value | ( | ( | ( | ||||
Lease remeasurements | |||||||
Depreciation | ( | ( | ( | ( | |||
Carrying amount at 31 December 2024 | |||||||
At 31 December 2024 | |||||||
Historical cost | |||||||
Accumulated depreciation and impairment | ( | ( | ( | ( | |||
Net carrying amount | |||||||
Lease liabilities | |||||||
Year ended 31 December 2024 | |||||||
At 1 January 2024 | |||||||
Acquisitions through asset acquisitions1 | |||||||
Additions | |||||||
Disposals | ( | ( | ( | ||||
Repayments (principal and interest) | ( | ( | ( | ( | |||
Accretion of interest | |||||||
Lease remeasurements | ( | ( | |||||
Carrying amount at 31 December 2024 | |||||||
Current | |||||||
Non-current | |||||||
Carrying amount at 31 December 2024 |
1.Refer to Note B.7 for details of asset acquisitions.
F-56
Table of Contents
Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
When a contract is entered into, the Group assesses whether the contract contains a lease. A lease arises when the Group has the right to
direct the use of an identified asset which is not substitutable and to obtain substantially all economic benefits from the use of the asset
throughout the period of use. The leases recognised by the Group predominantly relate to LNG vessels, property and drilling rigs.
The Group separates the lease and non-lease components of the contract and accounts for these separately. The Group allocates the
consideration in the contract to each component on the basis of their relative stand-alone prices.
Leases as a lessee
Lease assets and lease liabilities are recognised at the lease commencement date, which is when the assets are available for use. The
assets are initially measured at cost, which is the present value of future lease payments adjusted for any lease payments made at or
before the commencement date, plus any make-good obligations and initial direct costs incurred.
Lease assets are depreciated using the straight-line method over the shorter of their useful life and the lease term. Refer to Note B.3 for
the useful lives of assets. Periodic adjustments are made for any re-measurements of the lease assets and for impairment losses, assessed
in accordance with the Group’s impairment policies.
Lease liabilities are initially measured at the present value of future minimum lease payments, discounted using the Group’s incremental
borrowing rate if the rate implicit in the lease cannot be readily determined, and are subsequently measured at amortised cost using the
effective interest rate. Minimum lease payments are fixed payments or index-based variable payments incorporating the Group’s
expectations of extension options and do not include non-lease components of a contract. A portfolio approach was taken when
determining the implicit discount rate for LNG vessels with similar terms and conditions on transition.
The lease liability is remeasured when there are changes in future lease payments arising from a change in rates, index or lease terms
from exercising an extension or termination option. A corresponding adjustment is made to the carrying amount of the lease assets, with
any excess recognised in the consolidated income statement.
There are no restrictions placed upon the lessee by entering into these leases.
Short-term leases and leases of low value assets
Short-term leases (lease term of 12 months or less) and leases of low value assets are recognised as incurred as an expense in the
Foreign exchange risk
The Group held $437 million of lease liabilities at 31 December 2025 (2024: $408 million) in currencies other than the US dollar
(predominantly Australian dollars).
Maturity profile of lease liabilities
interest. The figures will not necessarily reconcile with the amounts disclosed in the consolidated statement of financial position.
2025 | 2024 | ||
US$m | US$m | ||
Due for payment in: | |||
1 year or less | |||
1-2 years | |||
2-3 years | |||
3-4 years | |||
4-5 years | |||
More than 5 years | |||
F-57
Table of Contents
Notes to the financial statements D. Other assets and liabilities
for the year ended 31 December 2025
Lease commitments
cancellable leases not yet commenced, representing principal and interest.
2025 | 2024 | ||
US$m | US$m | ||
Due for payment: | |||
Within one year | |||
After one year but not more than five years | |||
Later than five years | |||
Payments of $296 million (2024: $292 million) for short-term leases (lease term of 12 months or less) and payments of $10 million
(2024: $17 million) for leases of low value assets were expensed in the consolidated income statement. Total payments for leases in the
consolidated statement of cash flows are $645 million (2024: $689 million), with $233 million (2024: $293 million) included in
financing 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 financial statements, of $249 million (2024: $276 million).
(a) Control
Judgement is required to assess whether a contract is or contains a lease at inception by assessing whether the Group has the right to
direct the use of the identified asset and obtain substantially all the economic benefits from the use of that asset.
(b) Lease term
Judgement is required when assessing the term of the lease and whether to include optional extension and termination periods. Option
periods are only included in determining the lease term at inception when they are reasonably certain to be exercised. Lease terms are
reassessed when a significant change in circumstances occurs. On this basis, possible additional lease payments amounting to $2,342
million (2024: $2,113 million) were not included in the measurement of lease liabilities.
(c) Interest in joint arrangements
Judgement is required to determine the Group’s rights and obligations for lease contracts within joint operations, to assess whether lease
liabilities are recognised gross (100 %) or in proportion to the Group’s participating interest in the joint operation. This includes an
evaluation of whether the lease arrangement contains a sublease with the joint operation.
(d) Discount rates
Judgement is required to determine the discount rate, where the discount rate is the Group’s incremental borrowing rate if the rate
implicit in the lease cannot be readily determined. The incremental borrowing rate is determined with reference to the Group’s
borrowing portfolio at the inception of the arrangement or the time of the modification.
F-58
Table of Contents
Notes to the financial statements E. Other items
for the year ended 31 December 2025
In this section
This section includes Group structure information and other disclosures.
E. | Other items | |
E.1 | Contingent liabilities and assets | Page F-58 |
E.2 | Employee benefits | Page F-58 |
E.3 | Related party transactions | Page F-61 |
E.4 | Auditor remuneration | Page F-61 |
E.5 | Events after the end of the reporting period | Page F-61 |
E.6 | Joint arrangements | Page F-61 |
E.7 | Parent entity information | Page F-63 |
E.8 | Subsidiaries | Page F-63 |
E.9 | Other accounting policies | Page F-69 |
E.1 Contingent liabilities and assets
2025 | 2024 | ||
US$m | US$m | ||
Contingent liabilities at reporting date | |||
Contingent liabilities | |||
Guarantees | |||
Contingent liabilities relate predominantly to possible obligations whose existence will only be confirmed by the occurrence or
non‑occurrence of uncertain future events, and therefore the Group has not provided for such amounts in these financial statements. The
Group operates in complex tax and legislative regimes. The amounts disclosed above include estimates made in relation to ongoing
disputes with various tax and government authorities. Assessing a value of contingent liabilities requires a high degree of judgement. The
contingent liabilities relating to tax matters are estimated based on notices received from authorities before interest and penalties. The
possibility of further claims related to the same matters cannot be ruled out and the judicial processes may take extended periods to
conclude. Additionally, there are a number of other claims and possible claims that have arisen in the course of business against entities
in the Group, the outcome of which cannot be estimated at present and for which no amounts have been included in the table above.
E.2 Employee benefits
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Employee benefits | |||||
Share-based payments | |||||
Defined contribution plan costs | |||||
Defined benefit plan expense | |||||
(a) Employee benefits
Employee benefits for the reporting period:
The Group’s accounting policy for employee benefits other than superannuation is set out in Note D.5. The policy relating to share-based
payments is set out in Note E.2(c).
All employees of the Group are entitled to benefits on retirement, disability or death. The Group operates a number of pension schemes
throughout the world. Employees entitled to defined contribution schemes receive fixed contributions from Group companies and the
Group’s legal or constructive obligation is limited to these contributions. Contributions to defined contribution funds are recognised as
an expense as they become payable. Prepaid contributions are recognised as an asset to the extent that a cash refund or a reduction in the
future payment is available.
F-59
Table of Contents
Notes to the financial statements E. Other items
for the year ended 31 December 2025
(b) Compensation of key management personnel
2025 | 2024 | 2023 | |||
US$ | US$ | US$ | |||
Short-term employee benefits | |||||
Post-employment benefits | |||||
Share-based payments1 | ( | ||||
Long-term employee benefits | |||||
Termination benefits | |||||
1.The amounts relating to share-based payments includes the reversal of accounting expenditure as a result of the forfeiture of unvested Restricted
Shares and Performance Rights for Ms O’Neill.
(c) Share plans
The Group provides benefits 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 and subsequent to 2022, participants are entitled to receive a Woodside share on the vesting date, three years after
the grant date. Awards made in 2021 and 2020 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 five 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.
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’ approval. Accordingly, the 2024
Restricted Shares and Performance Rights were granted on 25 February 2025 for Executives and 8 May 2025 for the CEO and have been
included in the table below. The expense estimated as at 31 December 2024 in relation to the 2024 performance year was updated to the
fair value on grant date during the period.
The 2025 Restricted Shares and Performance Rights have not been included in the table below as they have not been approved as at
31 December 2025. An expense related to the 2025 performance year has been estimated for the Restricted Shares and Performance
Rights, using fair value estimates based on inputs at 31 December 2025.
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’ approval. Accordingly, the 2024 Restricted Shares were granted on 25 February 2025 and have been included in the table
below. The expense estimated as at 31 December 2024 in relation to the 2024 performance year was updated to the fair value on grant
date during the period.
F-60
Table of Contents
Notes to the financial statements E. Other items
for the year ended 31 December 2025
The 2025 Restricted Shares have not been included in the table below as they have not been approved as at 31 December 2025. An
expense related to the 2025 performance year has been estimated for the Restricted Shares, using fair value estimates based on inputs at
31 December 2025.
All compensation under WEP, SWEP, PBP Plus and EIS Restricted Shares and Performance Rights is accounted for as share-based
payments to employees for services provided. The cost of equity-settled transactions with employees is measured by reference to the fair
values of the equity instruments at the date at which they are granted. The fair value of share-based payments is recognised, together
with the corresponding increase in equity, over the period in which the vesting conditions are fulfilled, ending on the date on which the
relevant employee becomes fully entitled to the shares. At each balance sheet date, the Group reassesses the number of awards that are
expected to vest based on service conditions. The expense recognised each year takes into account the most recent estimate.
The fair value of the benefit provided for the WEP and SWEP is estimated using the Black-Scholes option pricing technique.
The fair value of the Restricted Shares is estimated as the closing share price at grant date. The fair value of the benefit provided for the
relative total shareholder return Performance Rights is calculated using the Binomial or Black-Scholes option pricing technique
combined with a Monte Carlo simulation methodology, where relevant, using historical volatility to estimate the volatility of the share
price in the future.
Number of performance awards | |||||||
Employee plans | Executive plans | ||||||
WEP | SWEP | Short-term awards4 | Long-term awards4 | ||||
Year ended 31 December 2025 | |||||||
Opening balance | |||||||
Granted during the year1,2,3 | |||||||
Vested during the year | ( | ( | ( | ( | |||
Forfeited during the year | ( | ( | ( | ( | |||
Awards at 31 December 2025 | |||||||
US$m | US$m | US$m | US$m | ||||
Fair value of awards granted during the year |
Number of performance awards | |||||||
Employee plans | Executive plans | ||||||
WEP | SWEP | Short-term awards4 | Long-term awards4 | ||||
Year ended 31 December 2024 | |||||||
Opening balance | |||||||
Granted during the year1,2,3 | |||||||
Vested during the year | ( | ( | ( | ( | |||
Forfeited during the year | ( | ( | ( | ( | |||
Awards at 31 December 2024 | |||||||
US$m | US$m | US$m | US$m | ||||
Fair value of awards granted during the year |
1.For the purpose of valuation, the share price on grant date for the 2025 WEP allocations was $11.85 (2024: $13.54 ).
2.For the purpose of valuation, the share price on grant date for the 2025 SWEP allocations was $12.89 (2024: $16.04 ).
3.For the purpose of valuation, the share price on grant date for Restricted Shares was $15.21 and $14.37 (2024: $19.74 and $19.33 ) and Performance
Rights was $9.14 (2024:$12.89 ).
4.Includes awards issued under Executive Incentive Plan (EIP), EIS and PBP Plus. Short-term awards relate to awards with a vesting period of less than
F-61
Table of Contents
Notes to the financial statements E. Other items
for the year ended 31 December 2025
E.3 Related party transactions
The Group’s related party transactions are predominantly with associates of the Group. During the period, the transactions with related
parties include purchases of goods/services of $26,949 thousand (2024: $42,162 thousand), sale of goods/services of $6,309 thousand
(2024: $5,720 thousand) and dividend income of $25,572 thousand (2024: $14,776 thousand). As at 31 December 2025, the total
amounts owing to related parties is nil (2024: $2,015 thousand) and amounts owing from related parties is $1,946 thousand (2024:
$92 thousand).
The Group is party to contractual arrangements with Driftwood Pipeline LLC that outline future obligations associated with the
development and use of transportation services. Refer to Note B.9(a). These arrangements include commitments that become binding
once specified milestones and conditions are met.
All transactions to/from related parties are made at arm’s length (normal market rates and on normal commercial terms).
There were no transactions with directors during the year, other than directors' fees. Key management personnel compensation is
disclosed in Note E.2(b).
E.4 Auditor remuneration
Note not required for the purposes of US reporting.
E.5 Events after the end of the reporting period
Except for the matters disclosed in Note A.3 no events have occurred after the reporting date that would materially affect the amounts or
disclosures in these financial statements
E.6 Joint arrangements
Group interest % | ||||||
Entity | Principal activity | 2025 | 2024 | |||
North West Shelf Gas Pty Ltd | Contract administration services for venturers for LNG sales to Japan. Marketing and administration services for venturers for gas processing. | |||||
North West Shelf Liaison Company Pty Ltd1 | Liaison for venturers in the sale of LNG to the Japanese market. | |||||
China Administration Company Pty Ltd | Contract administration services for venturers for LNG sales to China. | |||||
North West Shelf Shipping Service Company Pty Ltd2 | LNG vessel fleet advisor. | |||||
North West Shelf Lifting Coordinator Pty Ltd | Allocating, scheduling and administering the lifting of LNG and pipeline gas. | |||||
1.Entity was deregistered on 29 August 2025.
F-62
Table of Contents
Notes to the financial statements E. Other items
for the year ended 31 December 2025
Group interest %1 | |||
2025 | 2024 | ||
Producing and developing assets | |||
Australia | |||
Scarborough | |||
North West Shelf | |||
Greater Enfield and Vincent | |||
Pluto | |||
Pluto Train 2 | |||
Wheatstone | |||
Bass Strait | |||
Macedon | |||
Pyrenees | |||
International | |||
Sangomar | |||
Atlantis | |||
Mad Dog | |||
Shenzi | |||
Trion | |||
Greater Angostura2 | |||
Exploration and evaluation assets | |||
Oceania | |||
Browse Basin | |||
Carnarvon Basin | |||
Bonaparte Basin | |||
Africa | |||
Congo | |||
Senegal | |||
Egypt3 | |||
Americas | |||
US Gulf of America4 | |||
Liard | |||
Kitimat | |||
Asia | |||
Myanmar | |||
Sunrise | |||
Caribbean | |||
Barbados | |||
Calypso | |||
Other Joint Operations | |||
Angel CCS | |||
Bonaparte Basin CCS | |||
Pluto LNG Trucking | |||
NeoSmelt5 | |||
1.Certain arrangements included in the table are unincorporated contractual arrangements under which the Group has direct rights to specific assets and
obligations for specific liabilities. Accordingly, the Group recognises its proportionate share of interest in those assets, liabilities, revenues, and
expenses in accordance with the contractual arrangements.
2.The Group divested its interests in the Angostura and Ruby fields in 2025.
3.The Red Sea Block 1 licence in Egypt expired in 2025.
4.Various licences were assigned or relinquished/expired in 2025.
The principal activities of the joint operations are exploration, development and production of hydrocarbons.
F-63
Table of Contents
Notes to the financial statements E. Other items
for the year ended 31 December 2025
(a) Accounting for interests in other entities
Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity. Depending upon
the facts and circumstances in each case, Woodside may obtain control, joint control or significant influence over the entity or
arrangement. Judgement is applied when determining the relevant activities of a project and if joint control is held over it.
Relevant activities include, but are not limited to, work program and budget approval, investment decision approval, voting rights in joint
operating committees, amendments to permits and changes to joint arrangement participant holdings. Transactions which give Woodside
control of a business are business combinations. If Woodside obtains joint control of an arrangement, judgement is also required to
assess whether the arrangement is a joint operation or a joint venture. If Woodside has neither control nor joint control, it may be in a
position to exercise significant influence over the entity, which is then accounted for as an associate.
Joint arrangements are arrangements in which two or more parties have joint control. Joint control is the contractual agreed sharing of
control of the arrangement which exists only when decisions about the relevant activities require unanimous consent of the parties
sharing control. Joint arrangements are classified as either a joint operation or joint venture, based on the rights and obligations arising
from the contractual obligations between the parties to the arrangement.
To the extent the joint arrangement provides the Group with rights to the individual assets and obligations arising from the joint
arrangement, the arrangement is classified as a joint operation, and as such the Group recognises its:
•assets, including its share of any assets held jointly;
•liabilities, including its share of any liabilities incurred jointly;
•revenue from the sale of its share of the output arising from the joint operation;
•share of revenue from the sale of the output by the joint operation; and
•expenses, including its share of any expenses incurred jointly.
To the extent the joint arrangement provides the Group with rights to the net assets of the arrangement, the investment is classified as a
joint venture and accounted for using the equity method.
Joint arrangements acquired which are deemed to be carrying on a business are accounted for applying the principles of IFRS 3 Business
Combinations. Joint arrangements which are not deemed to be carrying on a business are treated as asset acquisitions.
E.7 Parent entity information
Note not required for the purposes of US reporting.
E.8 Subsidiaries
Name of entity | Country of incorporation | 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) | |
Pluto LNG Pty Ltd | Australia | (5) | |
Woodside Burrup Train 2 A Pty Ltd | Australia | (2,4) | |
Woodside Energy (Karratha Services) 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) |
F-64
Table of Contents
Notes to the financial statements E. Other items
for the year ended 31 December 2025
Name of entity | Country of incorporation | Notes | |
Woodside Energy (Canada LNG) Limited | Canada | (4) | |
Woodside Energy (Canada PTP) Limited | Canada | (4) | |
KM LNG Operating General Partnership | Canada | (11) | |
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) | |
Woodside Energy Holdings (NA) LLC | United States | (4) | |
Woodside Energy (LA) Holdings Inc. | United States | (4) | |
Woodside Energy (LA) Investments LLC | United States | (4,17) | |
Woodside Energy (LA) Production Holdings LLC | United States | (4) | |
Woodside Energy (LA) Production LLC | United States | (4) | |
Woodside Energy (LA) Production Investments LLC | United States | (4) | |
Woodside Energy (LA) OpCo LLC | United States | (4) | |
Woodside Energy (LA) Capital Holdings LLC | United States | (4) | |
Woodside Energy (LA) Operating LLC | United States | (4) | |
Louisiana LNG Expansion LLC | United States | (4) | |
Louisiana LNG Expansion II LLC | United States | (4) | |
Louisiana LNG LLC | United States | (6) | |
Louisiana LNG Gas Management LLC | United States | (4) | |
Louisiana LNG Infrastructure LLC | United States | (7) | |
Louisiana LNG Common Facilities LLC | United States | (4) | |
Woodside Energy (LA) Corporate Services LLC | United States | (4) | |
Woodside Energy (LA) Asset Services LLC | United States | (4) | |
Woodside Energy (LA) Services LLC | United States | (4) | |
Woodside Energy (LA) Management LLC | United States | (4) | |
Delhi Connector LLC | United States | (4) | |
Woodside Energy (LA) Trading LLC | United States | (4) | |
Woodside Energy (LA) Marketing Ltd | United Kingdom | (4) | |
Woodside Energy (LA) Trading UK Ltd. | United Kingdom | (4) | |
Woodside Energy (LA) Singapore Pte Ltd | Singapore | (4) | |
Woodside Energy (LA) UK Ltd | United Kingdom | (4) | |
Woodside Energy (LA) Supply LLC | United States | (4) | |
PT Woodside Energy Indonesia | Indonesia | (8) | |
Woodside Energy (Cameroon) SARL | Cameroon | (4) | |
Woodside Energy (Gabon) 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 (Tanzania) Limited | Tanzania | (9) | |
Woodside Energy (Norge) Pty Ltd | Australia | (2,4) | |
Woodside Energy Holdings II Pty Ltd | Australia | (2,4) | |
Woodside Power Pty Ltd | Australia | (2,4) |
F-65
Table of Contents
Notes to the financial statements E. Other items
for the year ended 31 December 2025
Name of entity | Country of incorporation | Notes | |
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 | (10) | |
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 (Namibia) Limited | United Kingdom | (4) | |
Woodside Energy Services (Qingdao) Co Ltd | China | (4) | |
Woodside Energy Julimar Pty Ltd | Australia | (2,3,4) | |
Woodside Energy Technologies Pty Ltd | Australia | (2,4,18) | |
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) | |
LakesEntrance Private Limited | India | (12) | |
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) | |
Woodside Petroleum (Timor Sea 20) Pty Ltd | Australia | (2,4) | |
Woodside Petroleum Holdings Pty Ltd | Australia | (2,4,19) | |
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 | (13) | |
Perdido Mexico Pipeline, S. de R.L. de C.V. | Mexico | (13) | |
Woodside Energy Investments Pty Ltd | Australia | (2,4) | |
Woodside Energia Brasil Investimentos Ltda. | Brazil | (14) | |
Woodside Energia Brasil Exploração e Produção Ltda. | Brazil | (14) | |
Woodside Energy (Great Britain) Limited | United Kingdom | (4) | |
Woodside Energy (North West Shelf) Pty Ltd | Australia | (2,3,4,19) | |
Woodside Energy USA Operations Inc | United States | (15) | |
Hamilton Brothers Petroleum Corporation | United States | (4) | |
Hamilton Oil Company LLC | 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 | (4,20) | |
Woodside Energy Resources Inc. | United States | (4) |
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Notes to the financial statements E. Other items
for the year ended 31 December 2025
Name of entity | Country of incorporation | Notes | |
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 | (4,21) | |
Woodside Energy (USA New Energy Holdings) LLC | United States | (4) | |
Beaumont New Ammonia LLC | United States | (4) | |
Woodside Energy (H2 Oklahoma) LLC | United States | (4) | |
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 (Egypt) Limited | United Kingdom | (4) | |
Woodside Energy (Carlisle Bay) Limited | United Kingdom | (4) | |
Woodside Energy (Mexico) Limited | United Kingdom | (4) | |
Woodside Energía Servicios Administrativos, S. de R.L. de C.V. | Mexico | (16) | |
Woodside Energía Servicios de México, S. de R.L. de C.V. | Mexico | (16) | |
Woodside Energy (Mexico Holdings) LLC | United States | (4) | |
Operaciones Conjuntas, S. de R.L. de C.V. | Mexico | (16) | |
Woodside Energía Holdings de México, S. de R.L. de C.V. | Mexico | (16) | |
Woodside Petróleo Operaciones de México, S. de R.L. de C.V. | Mexico | (16) | |
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) | |
Woodside Energy (Canada) Corporation | Canada | (4) | |
Koolbardi Pte Ltd | Singapore | (2,4) |
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 2025.
3.These companies were parties to the Deed of Cross Guarantee at 31 December 2025.
4.All subsidiaries are wholly owned except those referred to in Notes 5 to 16.
5.Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd each hold a 5
controlled.
6.Williams Louisiana LNG LLC holds a 10 % interest in the shares of Louisiana LNG LLC, a subsidiary controlled by the Group.
7.Stonepeak Wallaby I Acquiror LP holds a 57 % interest in the shares of Louisiana LNG Infrastructure LLC, a subsidiary controlled by the Group.
Stonepeak’s non-controlling interest (NCI) percentage is based on the proportion of total contributions to date and will fluctuate during the
construction phase. The NCI percentage is expected to revert to 40 % when the project starts generating revenue.
8.As at 31 December 2025, 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.
9.As at 31 December 2025, 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.
10.As at 31 December 2025, Woodside Energy Holdings (South America) Pty Ltd held 87.64 % interest in the shares of Woodside Energia (Brasil) Apoio
Administrativo Ltda and Woodside Energy Ltd held the remaining interest.
11.As at 31 December 2025, 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. Country of incorporation reflects
the place of formation.
12.As at 31 December 2025, Woodside Energy Ltd held 99 %interest in the shares of LakesEntrance Private Limited. Woodside Energy Holdings Pty Ltd
held the remaining 1 % interest.
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Notes to the financial statements E. Other items
for the year ended 31 December 2025
13.As at 31 December 2025, Woodside Energy Global Holdings Pty Ltd held a 99.99 % interest in shares of Perdido Mexico Pipeline Holdings, S.A. de
C.V. Woodside Energy Investments Pty Ltd held the remaining 0.01 % interest. As at 31 December 2025, Perdido Mexico Pipeline Holdings S.A. de
C.V. held a 99.99 % interest in shares of Perdido Mexico Pipeline S. de R.L. de C.V. Woodside Energy Investments Pty Ltd held the remaining 0.01 %
interest.
14.As at 31 December 2025, 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 2025, Woodside Energia Brasil Investimentos Ltda.
held >99.99 % interest in shares of Woodside Energia Brasil Exploração e Produção Ltda. Woodside Energy Global Holdings Pty Ltd held the
remaining interest.
15.As at 31 December 2025, 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 10.00 % voting interest and 62.33 % interest in shares.
16.As at 31 December 2025, Woodside Energy (Mexico) Limited held a 99
R.L. de C.V., Woodside Energía Servicios de México, S. de R.L. de C.V. and Operaciones Conjuntas, S. de R.L. de C.V. and 99.99 % interest in
shares of Woodside Energía Holdings de México, S. de R.L. de C.V. Woodside Energy (Mexico Holdings) LLC held the remaining 1 0.01 %
interests. As at 31 December 2025, Woodside Energía Holdings de México, S. de R.L. de C.V. held a 99 % interest in shares of Woodside Petróleo
Operaciones de México, S. de R.L. de C.V. Woodside Energy (Mexico Holdings) LLC held the remaining 1 % interest.
17.As at 31 December 2025, Woodside Energy (LA) Investments LLC held 20.00 % of the shares in Driftwood Pipeline LLC. This investment has been
accounted for as an investment in associate.
18.As at 31 December 2025, Woodside Energy Technologies Pty Ltd held 16.17 % of the shares in Blue Ocean Seismic Services Limited and 25.32 % of the shares
in Oakbio Inc which are accounted for as investments in associate.
19.As at 31 December 2025, Woodside Energy (North West Shelf) Pty Ltd and Woodside Petroleum Holdings Pty Ltd each held 16.67
International Gas Transportation Company Limited. This investment has been accounted for as an investment in associate.
20.As at 31 December 2025, 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.
21.As at 31 December 2025, Woodside Energy (Deepwater) Inc held 25.00 % of the shares in Caesar Oil Pipeline Company LLC, 22.00 % of the shares in
Cleopatra Gas Gathering Company LLC and 13.08 % of the shares in Marine Well Containment Company LLC. These are accounted for as investments in
associates.
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
(b) Subsidiaries with material non-controlling interests
Name of entity | Principal place of business | % held by NCI | NCI parties | ||
Burrup Facilities Company Pty Ltd | Australia | Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd | |||
Burrup Train 1 Pty Ltd | Australia | Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd | |||
Louisiana LNG Infrastructure LLC1 | United States | Stonepeak | |||
Louisiana LNG LLC | United States | Williams |
1.The non-controlling interest in Louisiana LNG Infrastructure LLC is measured at its proportionate share of the subsidiary’s net
assets. The proportion of net assets each member is entitled to upon liquidation varies prior to operations commencement. Prior to
this milestone, entitlements are determined in proportion to the cumulative capital contributions made by each member. The NCI
percentage is expected to revert to 40 % when the project commences operations.
material NCI is as follows:
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Notes to the financial statements E. Other items
for the year ended 31 December 2025
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Burrup Facilities Company Pty Ltd | |||||
Current assets | |||||
Non-current assets | |||||
Current liabilities | ( | ( | ( | ||
Non-current liabilities | ( | ( | ( | ||
Net assets | |||||
Accumulated balance of NCI | |||||
Revenue | |||||
Profit | |||||
Profit allocated to NCI | |||||
Dividends paid to NCI | ( | ( | ( | ||
Operating | |||||
Investing | ( | ( | ( | ||
Financing | ( | ( | ( | ||
Net increase/(decrease) in cash and cash equivalents | |||||
Burrup Train 1 Pty Ltd | |||||
Current assets | |||||
Non-current assets | |||||
Current liabilities | ( | ( | ( | ||
Non-current liabilities | ( | ( | ( | ||
Net assets | |||||
Accumulated balance of NCI | |||||
Revenue | |||||
Profit | |||||
Profit allocated to NCI | |||||
Dividends paid to NCI | ( | ( | ( | ||
Operating | |||||
Investing | ( | ( | ( | ||
Financing | ( | ( | |||
Net increase/(decrease) in cash and cash equivalents |
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Notes to the financial statements E. Other items
for the year ended 31 December 2025
2025 | 2024 | 2023 | |||
US$m | US$m | US$m | |||
Louisiana LNG Infrastructure LLC | |||||
Current assets | |||||
Non-current assets | |||||
Current liabilities | ( | ||||
Non-current liabilities | ( | ||||
Net assets | |||||
Accumulated balance of NCI | |||||
Revenue | |||||
Profit | |||||
Profit allocated to NCI | |||||
Dividends paid to NCI | |||||
Operating | |||||
Investing | ( | ||||
Financing | |||||
Net increase/(decrease) in cash and cash equivalents | |||||
Louisiana LNG LLC | |||||
Current assets | |||||
Non-current assets | |||||
Current liabilities | ( | ||||
Non-current liabilities | ( | ||||
Net assets | |||||
Accumulated balance of NCI | |||||
Revenue | |||||
Profit | ( | ||||
Profit allocated to NCI | |||||
Dividends paid to NCI | |||||
Operating | |||||
Investing | ( | ||||
Financing | |||||
Net increase/(decrease) in cash and cash equivalents |
(c) Deed of Cross Guarantee and Closed Group
Note not required for the purposes of US reporting.
E.9 Other accounting policies
Australia tax consolidation
The parent and its wholly owned Australian controlled entities have elected to enter a tax consolidation, with Woodside Energy Group
Ltd as the head entity of the tax consolidated group. The members of the Australian tax consolidated group are identified in Note E.8(a).
The tax expense/benefit, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax
consolidated group are recognised in the separate financial statements of the members of the tax consolidated group, using the stand-
alone approach.
Entities within the tax consolidated group have entered into a tax funding arrangement and a tax sharing agreement with the head entity.
Under the tax funding agreement, Woodside Energy Group Ltd and each of the entities in the tax consolidated group have agreed to pay
or receive a tax equivalent payment to or from the head entity, based on the current tax liability or current tax asset of the entity.
The tax sharing agreement entered into between members of the tax consolidated group provides for the determination of the allocation
of income tax liabilities between the entities, should the head entity default on its tax payment obligations. No amounts have been
recognised in the financial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is
considered remote.
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Notes to the financial statements E. Other items
for the year ended 31 December 2025
US tax consolidation
The Group has two separate USA Tax Consolidation Groups as at 31 December 2025:
•Woodside Energy USA Operations Inc. and its wholly owned USA controlled entities have elected to file a consolidated tax return,
with Woodside Energy USA Operations Inc. as the parent of the tax consolidated group (USA TCG 1).
•Woodside Energy Holdings (USA) Inc. and its wholly owned USA controlled entities have elected to file a consolidated tax return,
with Woodside Energy Holdings (USA) Inc. as the parent of the tax consolidated group. The consolidated tax return will include the
subsidiaries acquired as part of the Tellurian acquisition from acquisition date. Deferred tax assets and liabilities arising from
temporary differences within this consolidated group have been recognised to the extent that they do not meet the initial recognition
exemption in relation to the Tellurian acquisition (USA TCG 2).
The tax expense/benefit, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax
consolidated group are computed on a separate company basis.
Entities within the tax consolidated group have entered into a tax sharing agreement. Under the tax sharing agreement, the tax liability
for the consolidated group or the utilisation of tax attributes are settled periodically between the members of the group. The tax sharing
agreement between members of the tax consolidated group has no overall impact on the financial statements.
New and amended accounting standards adopted
A number of amended standards became applicable for the current reporting period. The Group did not make any significant changes to
its accounting policies and did not make retrospective adjustments as a result of adopting these amended standards. These amendments
Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory
for the 31 December 2025 reporting period and have not been early adopted by the Group:
•IFRS 18 Presentation and Disclosure in Financial Statements will replace IAS 101 Presentation of financial statements, introducing
new requirements that will help to achieve comparability of the financial performance of similar entities and provide more relevant
information and transparency to users. Even though IFRS 18 will not impact the recognition or measurement of items in the financial
statements, its impacts on presentation and disclosure are expected to be pervasive, particularly those related to the consolidated
income statement and providing management-defined performance measures within the financial statements. Management
is currently assessing the detailed implications of applying the new standard on the Group’s financial statements. The Group
will apply the new standard from its mandatory effective date of 1 January 2027. Retrospective application is required.
•Amendments to IFRS 7 & IFRS 9 Classification and Measurement of Financial Instruments introducing an option to derecognise
financial liabilities that are settled via electronic transfer before the settlement date. The amendments also provide additional
guidance on the assessment of whether contractual cash flows of certain financial assets meet the “solely payments of principal and
interest” (SPPI) criterion, including assets with terms that may alter the timing or amount of cash flows, assets with non‑recourse
features, and contractually linked instruments. In addition, the amendments introduce new disclosure requirements for financial
instruments with contractual terms that allow cash flows to change in response to events not directly related to basic lending risks.
Management is currently assessing the detailed implications of applying the new standard on the Group’s financial statements.
The Group will apply the new standard from its mandatory effective date of 1 January 2026.
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Consolidated entity disclosure statement
As at 31 December 2025
Consolidated entity disclosure statement
Note not required for the purposes of US reporting.
F-72
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Directors’ declaration
Directors’ declaration
Not required for the purposes of US reporting.
F-73
Table of Contents
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Woodside Energy Group Ltd
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated statements of financial position of Woodside Energy Group Ltd and its subsidiaries (the
“Company”) as of December 31, 2025 and 2024, and the related consolidated statements of income, comprehensive income, changes in
equity and cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively
referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of
December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the
Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period
ended December 31, 2025 in conformity with International Financial Reporting Standards as issued by the International Accounting
Standards Board (“IFRS”). Also in our opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by
the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over
financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's
Annual Report on Internal Control over Financial Reporting appearing under Item 15 Controls and Procedures. Our responsibility is to
express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting
based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)
(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error
or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures
included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits
also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating
the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect
on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of
any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements
that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are
material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole,
F-74
Table of Contents
and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the
accounts or disclosures to which they relate.
Impairment Assessment of certain property, plant and equipment and goodwill
As described in Notes B.3 and B.4 to the consolidated financial statements, the Company’s property, plant and equipment (PP&E)
balance was $46,555 million, and the Company’s goodwill balance was $3,952 million as of December 31, 2025. As further described in
Note B.4 to the consolidated financial statements, cash-generating units (“CGUs”) with allocated goodwill are tested for impairment at
least annually, while CGUs without allocated goodwill are tested for impairment when there is an indicator of impairment. Certain CGUs
meeting those criteria were tested for impairment as at December 31, 2025, whereby the recoverable amount of the CGU is compared
with its carrying value. The recoverable amounts of those CGUs were estimated using the fair value less costs of disposal approach
utilizing cash flow models. Management’s cash flow models included significant judgments and assumptions relating to oil and gas
reserves and resources, estimates of future production and commodity prices, forecast expenditures incorporating expected inflation and
foreign exchange rates, discount rate assumptions, and estimates of carbon costs.
The principal considerations for our determination that performing procedures relating to the impairment assessment of certain PP&E
and goodwill is a critical audit matter are (i) there is a significant level of judgment applied by management, including the use of
management’s specialists, in the determination of the significant estimates and assumptions included in the impairment models; (ii) this
in turn led to a high degree of auditor judgment, effort and subjectivity in performing procedures and evaluating management’s
significant assumptions and estimates; and (iii) the nature and extent of audit effort required to perform the procedures and evaluate
management’s significant assumptions and estimates involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on
the consolidated financial statements. These procedures included, among others, (i) testing the effectiveness of controls relating to
management’s assessment of the significant estimates and assumptions included within the impairment models; (ii) assessing the
reasonableness of significant estimates and assumptions applied by management; (iii) evaluating the work of management’s specialists
involved in the determination of significant estimates and assumptions; (iv) evaluating the disclosures made regarding the impairment
assessment of PP&E and goodwill in the consolidated financial statements against the requirements of IFRS; and (v) professionals with
specialized skill and knowledge were used to assist in evaluating the appropriateness of management’s recoverable amount estimates.
Valuation of the Petroleum Resource Rent Tax (PRRT) deferred tax assets (DTAs) - Pluto
As described in Note A.5 to the consolidated financial statements, the Company has recognized deferred tax assets of $2,658 million as
of December 31, 2025, of which $1,408 million relates to PRRT, including the Pluto PRRT DTA. PRRT is considered, for accounting
purposes, to be an income tax. PRRT DTAs are based on estimates of future taxable profits available to recover incurred general and
exploration expenditure. Management’s estimation of the PRRT DTAs involves significant judgments and assumptions including
assessing the forecast future taxable profits (which are risk-adjusted where appropriate by a market premium risk rate to reflect
uncertainty inherent in long-term forecasts) generated from the Australian assets, which have regard to the future commodity price
assumptions, future augmentation and forecast assessable revenues, exploration and general expenditure.
The principal considerations for our determination that performing procedures relating to valuation of the Pluto PRRT DTAs is a critical
audit matter are (i) there is a significant level of judgment applied by management in determining the recoverability of the PRRT DTAs,
including having regard to the judgments and assumptions mentioned above, and considering the specialized knowledge and input of
management’s specialists informing significant estimates and assumptions; (ii) this in turn led to a high degree of auditor judgment,
effort and subjectivity in performing procedures and evaluating management’s methodology, significant assumptions and estimates; and
(iii) the nature and extent of audit effort required to perform the procedures and evaluate management’s methodology, significant
assumptions and estimates involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on
the consolidated financial statements. These procedures included, among others, (i) testing the effectiveness of controls relating to
management’s assessment of the significant judgments and assumptions included within the PRRT modelling and recoverability
assessment; (ii) assessing the reasonableness of significant judgments and assumptions applied by management to estimate the
recoverable amount of DTAs; (iii) evaluating the work of management’s specialists involved in the determination of significant
judgments and estimates; (iv) evaluating the disclosures made regarding the PRRT DTAs recognized in the consolidated financial
statements against the requirements of IFRS; and (v) professionals with specialized skill and knowledge were used to assist in evaluating
the appropriateness of management’s assessment of recoverability of the PRRT DTAs including certain significant assumptions.
/s/ PricewaterhouseCoopers
February 24, 2026
We have served as the Company’s auditor since 2022.
Supplementary information on oil and gas (unaudited)
See “Item 4.B Business Overview” in this 2025 Form 20-F for Supplementary oil and gas (unaudited) information pursuant to FASB
932.
Table of Contents
ITEM 19. EXHIBITS
Exhibit no | Description | |
1.1 | Constitution of Woodside Energy Group Ltd (incorporated by reference to Exhibit 99.4 to the Registrant’s Report on Form 6-K (File No. 333-264268) filed with the Commission on 20 May 2022). | |
2.1* | Description of Securities | |
4.1 | Indenture, dated as of 12 September 2024, among Woodside Finance Limited, Woodside Energy Group Ltd, and the Bank of New York Mellon (incorporated by reference to Exhibit 4.1 of the Registrant’s Report on Form 6-K (File No. 001-41404) filed with the Commission on 12 September 2024). | |
4.2 | Equity Award Rules (incorporated by reference to Exhibit 4.2 to the Registrant’s annual report on Form 20-F filed with the Commission on February 27, 2024). | |
4.3 | Woodside Equity Plan (incorporated by reference to Exhibit 10.1 of the Registrant’s registration statement on Form S-8 (File No. 333-267432) filed with the Commission on 15 September 2022). | |
4.4 | Supplementary Woodside Equity Plan (incorporated by reference to Exhibit 10.2 of Woodside’s registration statement on Form S-8 (File No. 333-267432) filed with the Commission on 15 September 2022). | |
8.1* | List of Subsidiaries | |
11.1* | Code of ethics | |
11.2* | Securities Dealing Policy of Woodside Energy Group Ltd | |
12.1* | CEO certification under Section 302 of the Sarbanes-Oxley Act of 2002 | |
12.2* | CFO certification under Section 302 of the Sarbanes-Oxley Act of 2002 | |
13.1# | CEO certification under Section 906 of the Sarbanes-Oxley Act of 2002 | |
13.2# | CFO certification under Section 906 of the Sarbanes-Oxley Act of 2002 | |
15.1* | Consent of PricewaterhouseCoopers | |
15.2 | Woodside 2025 Annual Report | |
17.1* | List of subsidiary guarantors and issuers of guaranteed securities | |
97.1* | Compensation Recovery Policy of Woodside Energy Group Ltd | |
101.INS* | Inline XBRL Instance Document | |
101.SCH* | Inline XBRL Taxonomy Extension Schema Document | |
101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document | |
104* | Cover page Interactive Data File (embedded within the Inline XBRL document) |
*Filed herewith
#Furnished herewith
The total amount of long-term debt securities of Woodside Energy Group Ltd and its subsidiaries authorised under
instruments other than those listed above does not exceed 10% of the total assets of Woodside Energy Group Ltd and its
subsidiaries on a consolidated basis. The company agrees to furnish copies of any such instruments to the Commission
upon request.
Certain of the information included within Exhibit 15.2, which is provided pursuant to Rule 12b-23 of the Securities
Exchange Act of 1934, as amended, is incorporated by reference in this 2025 Form 20-F, as specified elsewhere in this 2025
Form 20-F. With the exception of the items and pages so specified, the Woodside 2025 Annual Report is not deemed to be
filed as part of this 2025 Form 20-F.
Table of Contents
SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the
undersigned to sign this annual report on its behalf.
Woodside Energy Group Ltd |
/s/ Liz Westcott |
Liz Westcott |
Acting Chief Executive Officer |
Dated: 24 February 2026 |
FAQ
What proved reserves did Woodside Energy (WDS) report in its 2025 Form 20-F?
Woodside reported proved reserves of 1,882.1 million barrels of oil equivalent (MMboe) as of 31 December 2025. This figure includes crude oil, condensate, natural gas and NGLs and is calculated under SEC rules using SEC-compliant pricing and economic assumptions.
How much did Woodside Energy (WDS) produce in 2025 according to the 20-F?
Woodside produced 211.4 MMboe in 2025, including 197.7 MMboe sold and 13.7 MMboe used as fuel in operations. These production figures differ slightly from other company reports because they include all fuel consumed and exclude certain purchased feed gas volumes.
What are Woodside Energy’s proved undeveloped reserves at year-end 2025?
At 31 December 2025, Woodside’s proved undeveloped reserves totaled 1,238.5 MMboe. Around 88% of these volumes are scheduled to be developed within five years of initial disclosure, with the remainder tied to large, complex projects facing facility capacity and drilling schedule constraints.
How much capital has Woodside Energy invested in oil and gas properties?
Woodside reported aggregate capitalised oil and gas costs of $79,713 million at year-end 2025, split between Australia and international assets. After $39,585 million of accumulated depreciation, depletion, amortisation and valuation provisions, net capitalised costs were $40,128 million for its upstream portfolio.
What oil and gas results did Woodside Energy (WDS) report for 2025 operations?
For 2025, Woodside’s oil and gas producing activities generated $11,257 million in revenue and $2,110 million of results from producing activities. These results reflect production costs, exploration expenses, DD&A, production and royalty-related taxes, accretion expense and income taxes across Australian and international segments.
Which key risks does Woodside Energy highlight in its 2025 Form 20-F?
Woodside outlines risks across health and safety, environment, climate transition, production and operations, growth projects, social licence, people and culture, financial management, commercial markets and cybersecurity. These risks could affect operational continuity, project execution, reputation, access to capital and long-term portfolio value.
How does Woodside Energy estimate and govern its oil and gas reserves?
Reserves are estimated under SEC Rule 4‑10(a) using deterministic methods, geoscience and engineering data, and SEC pricing assumptions. A dedicated Corporate Reserves Team reviews estimates, which are approved by a Qualified Petroleum Reserves Evaluator, senior management and the Board before public disclosure.
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