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, 2024

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

Woodside Energy Group Ltd

(Exact name of Registrant as specified in its charter)

N/A

(Translation of Registrant’s name into English)

Australia

(Jurisdiction of incorporation or organization)

Woodside Energy Group Ltd

Mia Yellagonga, 11 Mount Street

Perth, Western Australia 6000

Australia

(Address of principal executive offices)

Marcela Louzada

Woodside Energy Group Ltd

|Mia Yellagonga, 11 Mount Street

Perth, Western Australia 6000

Australia

Tel: +61 8 9348 4000

+61 456 994 243

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
American Depositary Shares	WDS	New York Stock Exchange
Ordinary Shares, no par value per share*		New York Stock Exchange

* 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: 1,898,749,771

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ 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. ☐ Yes ☒ 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. ☒ Yes ☐ 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). ☒ Yes ☐ 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.

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ 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. ☐

† 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.

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. ☒

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. ☐

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). ☐

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ☐ International Financial Reporting Standards as issued
by the International Accounting Standards Board ☒ Other ☐

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. 

☐ Item 17 ☐ 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). ☐ Yes ☒ 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. ☐ Yes ☐ No

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	8
ITEM 4.	INFORMATION ON THE COMPANY	16
A.	History and Development of the Company	16
B.	Business Overview	17
C.	Organizational Structure	30
D.	Property, Plant and Equipment	30
ITEM 4A.	UNRESOLVED STAFF COMMENTS	30
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	30
A.	Operating Results	30

B.	Liquidity and capital resources	36
C.	Research and development, Patents and Licences, etc.	36
D.	Trend information	37
E.	Critical Accounting Estimates	37
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	37
A.	Directors and Senior Management	37
B.	Compensation	37
C.	Board Practices	37
D.	Employees	37
E.	Share Ownership	37
F.	Disclosure of a registrant’s action to recover erroneously awarded compensation.	37
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	37
A.	Major shareholders	37
B.	Related Party Transactions	38
C.	Interests of Experts and Counsel	38
ITEM 8.	FINANCIAL INFORMATION	38
A.	Consolidated Statements and Other Financial Information	38
B.	Significant Changes	38
ITEM 9.	THE OFFER AND LISTING	38
A.	Offer and Listing Details	38
B.	Plan of Distribution	38
C.	Markets	38
D.	Selling Shareholders	38
E.	Dilution	38
F.	Expenses of the Issue	39
ITEM 10.	ADDITIONAL INFORMATION	39
A.	Share Capital	39
B.	Memorandum and Articles of Association	39
C.	Material Contracts	39
D.	Exchange controls	39

1

E.	Taxation	39
F.	Dividends and Paying Agents	42
G.	Statement by Experts	42
H.	Documents on Display	42
I.	Subsidiary Information	42
J.	Annual Report to Security Holders.	43
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	43
A.	Debt Securities	43
B.	Warrants and Rights	43
C.	Other Securities	43
D.	American Depositary Shares	43
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]	44
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	44
ITEM 16B.	CODE OF ETHICS	44

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	45
ITEM 16G.	CORPORATE GOVERNANCE	45
ITEM 16H.	MINE SAFETY DISCLOSURE	45
ITEM 16I.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	45
ITEM 16J.	INSIDER TRADING POLICIES	46
ITEM 16K.	CYBERSECURITY DISCLOSURE.	46
PART III
ITEM 17.	FINANCIAL STATEMENTS	47
ITEM 18.	FINANCIAL STATEMENTS	47
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 2024 (“2024 Form 20-F”). Reference is made to our 2024 Annual Report, portions of which are attached hereto as Exhibit 15.2 (the “2024 Annual Report”). Only (i) the information included in this 2024 Form 20-F, (ii) the information in the 2024 Annual Report that is incorporated by reference in this 2024 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 2024 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) and Form S-8 filed on 15 September 2022 (File No. 333-267432) and any other documents filed by us pursuant to the Securities Act of 1933, as amended, which purport to incorporate by reference the 2024 Form 20-F. The full 2024 Annual Report, inclusive of our sustainability report and other information omitted from, or otherwise not incorporated by reference into, this 2024 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 254-257 of the 2024 Annual Report is incorporated herein by reference.

The 2024 Form 20-F contains references to our website (https://www.woodside.com). Information on our website or any other website referenced in the 2024 Form 20-F is not incorporated into this document and should not be considered part of this document. All references to websites in this 2024 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 2024 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 2024 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 2024 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 with respect to Woodside’s business and operations, market conditions, results of operations and financial condition, including, for example, but not limited to, outcomes of transactions, statements regarding long-term demand for Woodside’s products, development, completion and execution of Woodside’s projects, expectations regarding future capital expenditures, 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, capital and exploration expenditure and gas hub exposure, and expectations regarding the achievement of Woodside’s net equity Scope 1 and 2 greenhouse gas emissions reduction and new energy investment targets 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 ‘guidance’, ‘foresee’, ‘likely’, ‘potential’, ‘anticipate’, ‘believe’, ‘aim’, ‘aspire’, ‘estimate’, ‘expect’, ‘intend’, ‘may’, ‘target’, ‘plan’, ‘strategy’, ‘forecast’, ‘outlook’, ‘project’, ‘schedule’, ‘will’, ‘should’, ‘seek’ and other similar words or expressions. Similarly, statements that describe the objectives, plans, goals or expectations of Woodside are forward-looking statements. 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 and assumptions.

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 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, 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 conflict in Ukraine) on economic activity and oil and gas supply and demand, cost estimates, legislative, fiscal and regulatory developments 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 should not be relied on as, and 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 based on industry publications and studies conducted by third parties, as well as 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 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. Accordingly, undue reliance should not be placed on any of the industry, market and competitive position data contained in this report.

4

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, and our methodologies for measuring or quantifying greenhouse gas emissions may evolve as best practices continue to develop and data quality and quantity continue to improve.

Woodside “greenhouse gas” or “emissions” information reported are net equity Scope 1 greenhouse gas emissions, Scope 2 greenhouse gas emissions, and/or Scope 3 greenhouse gas emissions, as the context requires.

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 2024 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.

5

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 250-253 of the 2024 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 254-257 of the 2024 Annual Report.

6

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.

7

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 enable risk-informed decision making, which protects us against potential negative impacts and enable us to seek the right opportunities. The objective of our risk management framework is to provide 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 vital 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 teams 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 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 within Woodside’s sphere of influence that could affect our ability to achieve our strategic objectives. Management and the Board consider a range of risks and opportunities that have the potential to deliver or erode value for our organisation in both the near and longer term. We factor these risks into our strategic decision making, as the decisions we make can create, amplify, reduce, or remove current risks and improve our resilience to emerging risks.

Examples of strategic risks and opportunities relevant to Woodside include delivering growth and long-term value through acquisitions and divestments, and the competitiveness of our portfolio mix under a range of scenarios.

2. Emerging risks

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. Examples 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.

Informed by the International Standard ISO31000 for Risk Management, our risk management process involves these features:

• Communicating and consulting

• Defining risk scope, context and criteria

• Assessing risk

• Treating risk

• Monitoring and review

• Recording and reporting risks.

The risk management process provides a consistent way of identifying, managing and reporting risks that have the potential to materially affect the achievement of Woodside’s objectives. Potential impacts of these risks, were they to eventuate, include those related to health and safety, the environment, the community and culture, our reputation and brand, legal and compliance, and financial. These impacts may lead to a loss in shareholder value, loss of market share to competitors, decreases in the value of assets, delays or stoppages in our operations, loss of revenue, increased expenses, infringements on our ability to execute and complete transactions, reduced capacity to fund capital projects, delayed or suspended regulatory approvals, legal liabilities and adverse impacts on Woodside’s reputation, social licence to operate and on the delivery of our strategy.

8

Woodside prioritises risk management actions and governance through use of a risk register. The functionality within the register provides transparency and enhances the ability of senior leaders to effectively manage and govern risks, including checking that identified actions to address, manage or remove risk have been closed out.

Woodside’s Risk Management Process

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.

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 people, 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 disruption from severe weather events.

• 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 include potential incidents resulting 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.

Examples of how this factor may affect Woodside

• An incident may result in a significant loss of hydrocarbon to the environment, including when caused by factors that are outside Woodside’s direct control. These factors include natural disasters and severe weather events, such as cyclones, floods, freezes and heatwaves, droughts, earthquakes or other acts of nature, pandemics, well blowouts, fires, explosions, pipeline ruptures, chemical releases, oil 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.

9

CLIMATE

The global response to climate change is changing the way the world produces and consumes energy. Our strategy requires us to make risk-based decisions and seek opportunities to deliver energy solutions. The complex and pervasive nature of climate change means transition risks are interconnected with, and may amplify, other risks. Additionally, the inherent uncertainty of potential societal responses to climate change may create a systemic risk to the global economy. Continuing political, social and industry attention to climate change has resulted in both existing and pending international agreements and national, regional and local legislation and regulatory programs to reduce emissions. These and other government actions could require Woodside to increase operating and maintenance costs and may result in reduced demand for oil and gas. Climate change may also create significant 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, the policy and legal environment for its exploration, development and production, and Woodside’s reputation and operating environment. We may also face risks related to climate change’s potential to cause physical damage or disruptions to our assets or our value chains.

Examples of how this factor may affect Woodside

• Physical impacts on our assets or those of our suppliers, customers or communities caused by increased frequency or intensity of natural disasters and severe weather events.

• Over- and under- investing in oil and gas reserves leading to an imbalance between our supply and global demand.

• Failure to transition to new energy at a pace that serves the global demand, or stakeholder sentiments, or to develop and implement lower-carbon technologies on which Woodside’s strategy may depend.

• Some of Woodside’s goals are dependent upon the successful implementation of new and existing technologies on an industrial scale. These technologies are in various stages of development or implementation and may require more capital, or take longer to develop, than currently expected.

• Climate-driven changes to legislation, regulation and policy or climate-related litigation resulting in additional costs, preventing or restricting Woodside from conducting activities and having adverse impacts on Woodside’s reputation.

• Failure of other organisations to meet emissions targets across the broader oil and gas industry and the reputational impacts for the industry as a whole.

PRODUCTION AND OPERATIONS

We manage a range of risks within our operations, including commercial risks relating to third-party relationships such as joint venture partners, 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, and subsequent downward adjustments of Woodside’s reported reserves estimates are possible.

How is this factor relevant to Woodside?

Our operating assets are subject to a range of operating risks associated with process safety incidents, breaches of cybersecurity, extreme weather events and supply chain disruptions. Disruptions to our supply chain or failure of our contractual counterparties to fulfil their obligations could adversely affect our production, operations and our financial performance, result in litigation or class actions and cause long-term damage to our reputation.

The majority of our major projects and operations are conducted in joint ventures, which may limit our control over, and our ability to effectively manage risks associated with, such projects. For projects in which we are not the operator, we may be unable to directly control the behaviour, performance and cost of operations.

Our operations are subject to various national and local laws, regulations and approvals relating to the exploration, development, production, marketing, pricing, transportation and storage of our products, as well as the management, decommissioning, clean-up and restoration of our properties, and management and disclosure of our operations and impacts.

These laws or regulations could change, and any such changes could have a material adverse effect on our business and financial condition. As such laws and regulations are subject to amendment and reinterpretation over time, we are unable to predict the future cost or impact of complying with such laws. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with applicable laws, regulations and approvals. The adoption and implementation of new or more stringent legislation, regulations or other regulatory initiatives that result in the imposition of more stringent standards for greenhouse gas emissions from the oil and gas industry could restrict the areas in which this sector may operate and could result in increased compliance costs and changes in product pricing, which could affect consumer demand for our products.

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Additionally, 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.

Estimating proved oil and gas reserves involves subjective judgements and determinations based on available geological, technical, contractual and economic information. New information from production or drilling activities, changes in economic factors, such as oil and gas prices, alterations in the regulatory policies of host governments in the jurisdictions in which we operate, or other events may cause estimates to change over time. Additionally, estimates may change to reflect acquisitions, divestments, new discoveries, extensions of existing fields and improved recovery techniques.

Examples of how this factor may affect Woodside

• Certain activities are undertaken in deep waters where operations, support services and decommissioning activities are more difficult and costly than in shallower waters. Deepwater locations lack the physical and oilfield service infrastructure present in shallower waters. As a result, these operations may have additional risks and require significant time between a discovery and the time that Woodside can market its production.

• Our joint venture participants (JVPs) 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 JVPs and contractual counterparties may not be able to meet their financial or other obligations to the projects. In addition, the actions of our partners, contractors and subcontractors could result in legal liability and financial loss for Woodside.

• A failure to comply with applicable laws, regulations and approvals relating to our operations may result in the assessment of sanctions, including administrative, civil, and criminal penalties, the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures and demand for reimbursement for government or regulatory actions, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of current or proposed projects including via government orders, suspension or revocation of licences, permits, government contracts or approvals, and issuance of injunctions restricting or prohibiting some or all of our activities in a particular area.

• 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.

• Joint venture participants or contractual counterparties may be primarily responsible for the adequacy of the human or technical competencies and capabilities which they bring to bear on the joint project, which may not be adequate.

• 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.

• Government policy objectives in the countries in which we do business, now or in the future, could take the form of increased governmental regulations (including in respect of restoration, protection of the environment, levels of greenhouse gas emissions, protection of natural resources, and worker health and safety), redirection of product distribution (such as domestic gas reservation policies), changes in taxation regulation or enforcement (including, for example, changes in tax rates or increased focus on audits), taxation subsidies or royalties, nationalisation of resource assets or restrictions or moratoriums on our operations on government leases, limitations on periods of lease retention, interference with the confidentiality and availability of information, forced renegotiation of contracts, changes in laws and policies governing operations of foreign-based companies, trade sanctions, currency restrictions and exchange rate fluctuations and other governmental steps.

• 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 process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently uncertain. Actual production, revenues, expenditures, prices of hydrocarbons and taxes with respect to Woodside’s reserves may vary from estimates and the variance may be material. Woodside has in the past and may in the future record impairments resulting from declines in oil and gas prices or other factors. Downward adjustments of our reported reserves estimates could indicate lower future production volumes or the impairment of assets.

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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

In order to maintain our production levels and deliver shareholder value, Woodside must continue to identify growth opportunities, organic and inorganic, and commercialise them. To maintain a stable pipeline of future projects and realise the full value of growth opportunities, Woodside competes with a wide range of multinational and nationalised oil and gas companies, in addition to individual producers and new energy companies. Failure to effectively compete with these companies may result in the inability to continue to expand Woodside’s current operations and meet our objectives.

Woodside must continue to effectively manage relationships with industry partners. For example, at times we enter joint ventures with organisations that may also be competing oil and gas suppliers. It is essential that our voice is heard both within our industry and more broadly. In order for us to effectively communicate, we may at times align with industry bodies to advocate what we believe is in the best interests of our stakeholders. In addition, our current and planned projects involve uncertainties and operating risks that could prevent us from realising profits or result in the total or partial loss of our investment.

New energy

We have set targets for our new energy products and lower-carbon services.¹ 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. In addition, new sources of energy, such as hydrogen or ammonia, 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.

Examples of how this factor may affect Woodside

• An unbalanced portfolio of oil and gas and new energy, which may not meet the market’s needs.

• Limited or reduced market share resulting in a loss of shareholder value.

• Our competitors may be able to pay more for exploratory prospects and productive oil and natural gas properties or may be able to define, evaluate, bid for and purchase a greater number of properties and prospects, including operatorships and licences, than our financial or human resources permit.

• Our projects could experience slippage in implementing schedules, permitting delays, shortages of or delays in the delivery of equipment or purpose-built components from suppliers, escalation in capital cost estimates, possible shortages of construction or other personnel, other labour shortages, environmental occurrences during construction that result in a failure to comply with environmental regulations or conditions on development, or delays and higher-than-expected costs due to the remote location of the projects, the impact of global conflicts on the relevant workforce or supply chain, other unanticipated supply chain disruptions, natural disasters, accidents, miscalculations, political or other opposition, litigation, acts of terrorism, operational difficulties, climate change-related risks or other events associated with that construction that may result in the delay, suspension or termination of our projects.

• An inability to obtain financing at acceptable costs, or at all, for the development of new projects.

• Failure to implement our new energy plans within our anticipated timeframe and in line with global demands.

1. 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. Not guidance. Potentially includes both organic and inorganic investment.

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• Failure to identify, execute or implement strategic transactions, including acquisitions and divestments, or to achieve the full benefits of those transactions. In particular, difficulties in integrating and developing acquired assets may result in operational and other challenges, including the diversion of management’s attention from ongoing business concerns. The integration and development process may be subject to delays or changed circumstances, and we can give no assurance that the acquired assets will perform in accordance with our expectations or that our expectations with respect to the opportunities from any acquisitions will materialise.

• The development of acquired assets may lead to the incurrence of significant capital and operating expenses, in addition to potential capital expenditures that may occur as a result of executing our previously disclosed strategy in relation to our new energy investment target and other potential growth projects. For instance, in 2024, we completed two significant transactions involving major energy projects in the US Gulf Coast – Louisiana LNG and the Beaumont New Ammonia Project. The complexity and magnitude of the development effort associated with the acquired assets, particularly in relation to Louisiana LNG, may require significant capital and operating expenses to support the development of those operations.

• A significant increase in capital expenditures could have adverse consequences on our business, financial conditions and future prospects, including that we may be required to incur additional debt and we may not be able to obtain financing in the future on acceptable terms or at all for working capital, capital expenditures, acquisitions, debt service requirements or other purposes.

• Credit rating agencies could downgrade our credit ratings below currently expected levels, and we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions.

• Failure to remain commercially and technologically competitive to efficiently develop and operate an attractive portfolio of assets, to obtain access to new opportunities and to keep pace with deployment of new technologies and products.

• Woodside operates in highly competitive markets. A number of competitors are larger and have greater resources than Woodside. There may be greater-than-expected competition in the markets in which Woodside competes, including those for new energy products and lower-carbon services.

• Failure to generate returns in line with our capital allocation framework.

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 environmental impact and community contribution), particularly as these expectations evolve and as Woodside expands its operations around the world.

How is this factor relevant to Woodside?

Traditional Owners and Custodians, government authorities, investors and other groups form significant relationships with our organisation. These relationships are built on the trust that Woodside will meet our stakeholders’ expectations. We must also consider the role our commercial agreements play in relation to human rights around the world, as we have a responsibility to ensure the rights of all humans are not negatively affected by our organisation.

These are some of the most significant risks to our relationships with stakeholders:

• Engaging in activities that have real or perceived adverse impacts on the environment, climate, biodiversity, human rights or cultural heritage.

• Failing to meet our net equity Scope 1 and 2 emissions reduction targets. or investment targets in new energy products and lower carbon services.^1,2

• Inadequately responding to quickly evolving expectations of Woodside (including expectations that may significantly differ in the various jurisdictions in which we operate).

Additionally, third-party risks that are outside of our control could negatively affect our reputation and licence to operate, such as oil spills or other disasters, or crisis scenarios that cause collateral damage to Woodside’s licence to operate via reputational damage to the oil and gas industry at large.

1. Targets and aspiration are for net equity Scope 1 and 2 greenhouse gas emissions relative to a starting base of 6.32 Mt CO₂-e which is representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and which may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with a FID prior to 2021. Net equity emissions include the utilisation of carbon credits as offsets.

2. 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. Not guidance. Potentially includes both organic and inorganic investment.

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Examples of how this factor may affect Woodside

• Lost or limited stakeholder support for our current business and future opportunities, including the refusal of, or delay in, the extension or grant of exploration, development or production contracts or leases, and development delays and cost overruns due to approval delays for, or denial of, drilling, construction, environmental and other regulatory approvals, permits and authorisations.

• Woodside is a global company, operating in a number of jurisdictions. Stakeholders and regulators in the areas in which we operate have increasingly expressed or pursued divergent views, legislation and investment expectations with respect to sustainability matters, which may increase the social licence risks in those areas.

• New or amended laws and regulations, or new or different applications or interpretations of existing laws and regulations,

• Risks related to the violation of certain laws and regulations, including 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.

• Decreased ability to attract and retain a talented workforce, and other operational concerns.

PEOPLE & CULTURE

These risks are associated with the ability to attract, retain, develop and motivate key 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 will 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.

• An inability to reach timely agreements with employees including where representation by third parties may result in industrial action.

• Actual or alleged misconduct, including fraud and corruption.

FINANCIAL MANAGEMENT

These risks are those associated with interest rates, inflation, and fluctuations in commodity price and foreign exchange.

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.

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.

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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 2024 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 2024 Form 20-F for further information.

Examples of how this factor may affect Woodside

• A reduced ability to fund our strategy including our projects.

• Impairments of assets, goodwill or other intangible assets, or a significant increase in capital and operational expenditure as a result of acquisitions, 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

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. 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 2024 Form 20-F.

Examples of how this factor may affect Woodside

• Significant volatility in energy prices, such as the volatility experienced in recent years, may increase the challenges associated with future revenue and delivery of our strategy

• An imbalance in supply and demand can affect commodity prices and our ability to forecast market conditions determines whether we are affected positively or negatively.

• The exploration and production of hydrocarbons is a highly competitive business. Woodside has many competitors (including national oil companies), some of which are larger and better funded; may be willing to accept greater risks; have greater access to capital; have substantially larger staffs; or have special competencies.

• Woodside may become a less attractive joint venture participant.

• Shareholder returns are reduced due to lower commodity prices.

• Woodside’s acquisition activities carry risks that it may not fully realise anticipated benefits due to less-than-expected reserves or production or changed circumstances, such as declines in prices of hydrocarbons 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 costs or liabilities that are greater than anticipated.

• 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.

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How is this factor relevant to Woodside?

Woodside must relentlessly protect the confidentiality, integrity and availability of digital information and operational technologies. Woodside’s technology systems including artificial intelligence and machine learning technologies 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 affect Woodside

• 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.

• 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 2024 Annual Report is incorporated herein by reference:

• Section 1: Overview from pages 6-15

• Section 3: Our Business from pages 26-42

• Documents on display in Section 6.4: Shareholder statistics on page 240.

See Three-Year Financial Analysis in “Item 5.A Operating Results” of this 2024 Form 20-F.

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B. Business Overview

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 1: Overview from pages 6-15

• Section 2: Strategy and Financial Performance from pages 16-25

• Section 3: Our Business from pages 26-42

• Section 6.3: Additional disclosures from pages 225-237.

See Three-Year Financial Analysis in “Item 5.A Operating Results” of this 2024 Form 20-F.

Applicable laws and regulations

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Government regulations in Section 6.3: Additional disclosures from pages 230-236

• Material limitations in Section 6.3: Additional disclosures on page 236

• Summary of material legal proceedings in Section 6.3: Additional disclosures on page 236-237.

Disclosures regarding oil and gas operations

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Drilling and other exploratory and development activities in Section 6.3: Additional disclosures on page 225

• Present development activities continuing as of 31 December 2024 in Section 6.3: Additional disclosures on page 225

• Oil and gas properties, wells, operations and acreage in Section 6.3: Additional disclosures on pages 226

• Delivery commitments in Section 6.3: Additional disclosures on page 226

• Production in Section 6.3: Additional disclosures on page 227.

RESERVES STATEMENT

About the Reserves Statement

This Reserves Statement presents Woodside’s proved oil and gas reserves, as of 31 December 2024, 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 2024. 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 2024 to 31 December 2024. 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”.

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 primarily as fuel in operations.² At 31 December 2024, Woodside’s remaining proved (1P) reserves were 1,975.7 MMboe (Table 1, 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).

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In 2024, revisions of previous estimates and extensions resulted in proved reserves increases of 54.9 MMboe. Key drivers for these changes include:

• 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.

Table 1: Woodside’s proved reserves^4,5,6 overview (net Woodside share, as at 31 December 2024)

	Natural gas7 Bcf10		NGLs8 MMbbl11		Oil & condensate MMbbl		Total9 MMboe12		Fuel included in total MMboe
Proved13 developed14 and undeveloped15		8,049.9		18.9		544.6		1,975.7		178.2
Proved developed		1,995.0		17.4		339.4		706.8		59.3
Proved undeveloped		6,054.9		1.5		205.2		1,268.9		119.0

Small differences due to rounding

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 primarily 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

• 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 include:

• 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.

2022 proved reserves

Woodside produced 156.8 MMboe for sale in 2022, including 61.4 MMboe produced from 1 June 2022 from interests acquired as part of the merger with the BHP Petroleum business on 1 June 2022 (Acquired Assets). An additional 14.9 MMboe of production was consumed primarily as fuel in operations in the year ended 31 December 2022 resulting in a total production of 171.7 MMboe for 2022.² At 31 December 2022, Woodside’s remaining proved reserves were 2,385.2 MMboe (Table 2).

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The acquisition of the Acquired Assets on 1 June 2022 increased Woodside’s proved reserves as at 1 June 2022 by 922.8 MMboe to 2,339.6 MMboe. These changes are further described below.

2022 included revisions of previous estimates of 202.5 MMboe for proved reserves. Key drivers for the revisions include:

• completion of an Atlantis full field integrated subsurface study that resulted in a 46.3 MMboe increase in proved reserves

• inclusion of offshore fuel gas reserves and favourable commodity prices resulting in a net increase of 51.7 MMboe to proved undeveloped reserves at Scarborough

• inclusion of fuel gas reserves and incorporation of drilling results at Sangomar resulting in a proved undeveloped reserves increase of 24.7 MMboe

• improved overall field performance at Pluto, North West Shelf, and Julimar-Brunello led to proved reserves increases of 31.7 MMboe, 17.6 MMboe, and 25.7 MMboe, respectively.

The transfers of undeveloped reserves to developed reserves are discussed in the 2022 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, 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 26 years of relevant experience.

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Table 2: Proved developed and undeveloped reserves reconciliation (net Woodside share, three years ending 31 December 2024)

	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 2021		7,370.0		0.0		57.5		1,350.5		0.0		0.0		81.2		81.2		7,370.0		0.0		138.7		1,431.6
Acquisitions and divestments18		3,096.1		18.3		34.0		595.4		251.2		7.7		275.6		327.4		3,347.4		26.0		309.6		922.8
Extensions and discoveries19		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0
Revision of previous estimates20		682.3		3.6		12.3		135.6		112.0		2.1		45.2		66.9		794.3		5.7		57.5		202.5
Production		-692.5		-4.5		-24.0		-150.0		-35.4		-0.8		-14.7		-21.7		-728.0		-5.3		-38.7		-171.7
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 divestments		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 discoveries		0.0		0.0		0.0		0.0		177.9		0.4		172.5		204.1		177.9		0.4		172.5		204.1
Revision of previous estimates		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
Revision 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 202421		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
Fuel included in 31 December 2024 reserves		859.7		0.8		0.0		151.7		151.5		0.0		0.0		26.6		1,011.2		0.8		0.0		178.2
Proved developed and undeveloped reserves
Proved developed reserves
as at 31 December 2021		1,744.5		0.0		50.2		356.3		0.0		0.0		0.0		0.0		1,744.5		0.0		50.2		356.3
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
Proved undeveloped reserves
as at 31 December 2021		5,625.5		0.0		7.2		994.2		0.0		0.0		81.2		81.2		5,625.5		0.0		88.4		1,075.3
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

Small differences due to rounding

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).

20

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.

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 $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.

2022 proved undeveloped reserves

At 31 December 2022, Woodside’s remaining proved undeveloped reserves were 1,615.2 MMboe, which is roughly 68% of the total remaining proved reserves of 2,385.2 MMboe (Table 3). This represents an increase in proved undeveloped reserves of 539.9 MMboe from the 1,075.3 MMboe as at 31 December 2021. The largest element of this increase was a 529.7 MMboe increase as a result of the acquisition of the Acquired Assets.

During 2022, a total of 54.0 MMboe proved undeveloped reserves were transferred to proved developed reserves through development activities primarily in the following projects: Greater Western Flank Phase 3 and Lambert Deep developments at North West Shelf in Australia (20.5 MMboe), infill well (XNA02) to support ongoing production from the Pluto LNG Project in Australia (15.8 MMboe), and multiple development opportunities at Shenzi in the United States including installation and commissioning of subsea multiphase pumping and well completions (17.1 MMboe).

21

Development plan changes in Sangomar and Julimar-Brunello Phase 3 resulted in increases to proved undeveloped reserves of 24.7 MMboe and 4.1 MMboe, respectively. Favourable commodity prices resulted in an increase of 15.5 MMboe in proved undeveloped reserves. Additionally, a net increase of 19.9 MMboe in proved undeveloped reserves occurred due to positive revisions in Scarborough²¹ and Bass Strait partially offset by negative revisions due to technical studies and performance at Pluto and Julimar-Brunello.

During 2022, Woodside incurred approximately $3.5 billion progressing the transfer of proved undeveloped reserves for projects where development status was achieved in 2022 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 2024)

MMboe	2024		2023		2022
Proved undeveloped opening balance		1,712.5		1,615.2		1,075.3
Extensions and discoveries		7.1		204.1		0.0
Transfers to proved developed reserves		-132.6		-87.7		-54.0
Revision of previous estimates		5.0		-19.2		64.2
Performance, technical studies, and other		-0.2		-3.4		19.9
Development plan changes		5.2		0.0		28.8
Price		0.0		-15.8		15.5
Acquisitions and divestments		-323.0		0.0		529.7
Proved undeveloped closing balance		1,268.9		1,712.5		1,615.2

Small differences 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 0.9 MMboe (2022), 1.1 MMboe (2023), and 1.2 MMboe (2024) in excess of reserves working interest percentage from Pluto non-operating participants 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, effective as of 1 January 2024. 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.

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.

22

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 2024. The United States accounts for the largest percentage of proved reserves within the ‘International’ segment. In reporting years 2022, 2023, and 2024, the United States accounted for 325.3 MMboe (14%), 291.6 MMboe (12%), and 249.7 MMboe (13%) 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. ‘Revision 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. Scarborough proved undeveloped reserves as at 31 December 2024 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
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
2022
Unproved properties		1,154			1,834			2,988
Proved properties1		49,190			15,546			64,736
Total costs		50,344			17,380			67,724
Less: Accumulated depreciation, depletion, amortisation and valuation provisions		(24,353)			(2,491)			(26,844)
Net capitalised costs		25,991			14,889			40,880

 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
2024
Acquisitions of proved property		-		-		-
Acquisitions of unproved property		-		-		-
Exploration1		61		358		419
Development2		3,072		1,714		4,786
Total costs3		3,133		2,072		5,205
2023
Acquisitions of proved property		-		-		-
Acquisitions of unproved property		-		-		-
Exploration1		103		420		523
Development		3,315		2,124		5,439
Total costs3		3,418		2,544		5,962
2022
Acquisitions of proved property		8,488		11,098		19,586
Acquisitions of unproved property		-		180		180
Exploration1		39		541		580
Development		2,365		1,740		4,105
Total costs3		10,892		13,559		24,451

 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 $4,403 million of expenditure and $383 million of capitalised interest in 2024.

 3. Total costs include $4,885 million (2023: $5,683 million, 2022: $23,991 million) capitalised during the year.

Results of operations from oil and gas production activities

	Australia US$m			International US$m			Total US$m
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
2022
Oil and gas revenue		12,453			1,575			14,028
Production costs		(1,277)			(353)			(1,630)
Exploration expenses		(20)			(440)			(460)
Depreciation, depletion, amortisation and valuation provision1		(1,476)			(460)			(1,936)
Production taxes2		(429)			(16)			(445)
Accretion expense3		(85)			(23)			(108)
Income taxes		(2,707)			(151)			(2,858)
Royalty-related taxes4		(501)			-			(501)
Results of oil and gas producing activities5		5,958			132			6,090

1. Includes valuation provision recognition of nil (2023: a valuation provision recognition of $1,917 million; 2022: reversal of $900 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 $(487) million (2023: $531 million; 2022: $(814) 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” of this 2024 Form 20-F. Other income, other expenses, general and administrative costs and amounts relating to the marketing and new energy/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 2024 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 Standard 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 US$m		International US$m		Total US$m
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
2022
Future cash inflows		197,194		38,256		235,450
Future production costs		(31,157)		(9,698)		(40,855)
Future development costs1		(12,259)		(4,487)		(16,746)
Future income taxes		(62,182)		(4,823)		(67,005)
Future net cash flows		91,596		19,248		110,844
Discount at 10% per annum		(48,924)		(7,777)		(56,701)
Standardised measure		42,672		11,471		54,143

1. Future development costs include decommissioning.

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Changes in standardised measure are presented in the following table.

	2024		2023		2022
	US$m		US$m		US$m
Changes in the standardised measure
Standardised measure at the beginning of the year		32,153		54,143		15,737
Revisions:
Prices, net of production costs		(12,139)		(41,132)		22,558
Changes in future development costs		(2,695)		(2,288)		(873)
Revisions of reserves quantity estimates		1,848		3,156		5,898
Accretion of discount		4,496		8,039		4,051
Changes in production timing and other		662		(707)		2,371
Sales of oil and gas, net of production costs		(9,963)		(10,500)		(10,202)
Acquisitions of reserves-in-place		-		-		28,309
Sales of reserves-in-place		(3,492)		-		-
Previously estimated development costs incurred		5,061		5,276		3,339
Extensions, discoveries and improved recoveries, net of future costs		160		1,174		-
Changes in future income taxes		6,764		14,992		(17,045)
Standardised measure at the end of the year		22,855		32,153		54,143

Changes in reserves quantities are shown in the Reserves Statement in “Item 4. Information on the Company” of this 2024 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.

27

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 2024, 31 December 2023 and 31 December 2022.

	2024		2023		2022
	US$m		US$m		US$m
Movement in capitalised exploratory well costs1
At the beginning of the year		668		807		614
Acquisitions to the capitalised exploratory well costs pending the determination of proved reserves		-		-		180
Additions to the capitalised exploratory well costs pending the determination of proved reserves		90		169		111
Capitalised exploratory well costs expensed2		(8)		(4)		(62)
Capitalised exploratory well costs reclassified to wells, equipment and facilities based on the determination of proved reserves		(29)		(304)		(36)
Sale of suspended wells		-		-		-
At the end of the year		721		668		807

 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.

	2024		2023		2022
	US$m		US$m		US$m
Ageing of capitalised exploratory well costs
Exploratory well costs capitalised for a period of one year or less		97		71		124
Exploratory well costs capitalised for a period greater than one year		624		597		683
At the end of the year		721		668		807

	2024		2023		2022
Number of projects that have been capitalised for a period greater than one year1		7		12		21

1. 2023 has been restated.

29

C. Organizational Structure

See “Item 18. Financial Statements” of this 2024 Form 20-F.

Exhibit 8.1 to this 2024 Form 20-F is incorporated herein by reference.

D. Property, Plant and Equipment

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 1.5: Global portfolio from pages 14-15

• Section 3: Our Business from pages 26-42

• NPAT reconciliation in Section 6.3: Additional disclosures on page 228

• Section 6.5: Asset facts from pages 246-249.

See “Item 18. Financial Statements” of this 2024 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 2024 Form 20-F. See also “Use and reconciliation of Non-IFRS Financial Measures” for further information concerning non-IFRS financial measures presented in this 2024 Form 20-F.

A. Operating Results

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 1: Overview from pages 6-15

• Section 2: Strategy and Financial Performance from pages 16-25

• Section 3: Our Business from pages 26-42

• Government regulations in Section 6.3: Additional disclosures from pages 230-236

• Material limitations in Section 6.3: Additional disclosures on page 236.

See “Item 18. Financial Statements” of this 2024 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 2022 gas prices hit record highs driven by years of underinvestment and the supply shock caused by Russia’s invasion of Ukraine. In 2022 there was a significant increase in the scale of Woodside’s production portfolio, with the completion of the merger with BHP’s petroleum business on 1 June 2022. In 2023, prices declined, however remained above historic averages with the decline triggered by milder weather conditions and higher stock levels across Europe. Despite ongoing geopolitical events in 2024, energy prices were range bound. Supported by OPEC+ market management, dated Brent averaged $80/bbl and LNG prices dropped from the highs of 2022 as countries prioritised energy security and maintaining storage levels. However, uncertainty remains, particularly due to the ongoing conflict in Ukraine and geopolitical events in the Middle East.

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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	2024     US$m			2023     US$m			2022     US$m
Operating revenue		13,179			13,994			16,817
Cost of sales		(7,501	)		(7,519	)		(6,540	)
Gross profit		5,678			6,475			10,277
Other income		624			322			735
Other expenses		(1,788	)		(1,573	)		(2,726	)
Impairment losses		-			(1,917	)		-
Impairment reversals		-			-			900
Profit before tax and net finance costs		4,514			3,307			9,186
Net finance costs		(145	)		(34	)		(12	)
Total tax expense		(723	)		(1,551	)		(2,599	)
Profit after tax		3,646			1,722			6,575
Attributable to equity holders of the parent		3,573			1,660			6,498
Attributable to non-controlling interests		73			62			77
Profit for the period		3,646			1,722			6,575

Woodside’s profit after tax attributable to equity holders of the parent increased to $3,573 million in 2024 from $1,660 million in 2023 and $6,498 million in 2022. Operating revenue of $13,179 million decreased by $815 million, or 6%, from 2023. 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. This decrease was partly offset by the start of production at Sangomar. Operating revenue decreased by $2,823 million, or 17%, from 2022 to 2023. The decrease was driven by lower average Brent, TTF and JKM price markers which was partly offset by an additional five months of production from BHP’s petroleum business acquired on 1 June 2022.

Cost of sales decreased by $18 million, or nil percent movement, to $7,501 million compared to 2023, 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. Cost of sales increased by $979 million, or 15%, from 2022 to 2023. The increase was driven by an additional five months of activity from the assets acquired as part of the merger with BHP’s petroleum business.

Other income increased by $302 million, or 94%, to $624 million from 2023, primarily due to profit on the sell-down of non-operating interests in Scarborough to LNG Japan and JERA. Other income decreased by $413 million, or 56% from 2022 to 2023, primarily due to profit on the sell-down of Pluto Train 2 in 2022.

Other expenses increased by $215 million, or 14%, to $1,788 million from 2023, primarily due to a fair value reduction for an embedded derivative associated to urea and increased restoration provision estimates at closed sites partially offset by lower losses on hedging activities. Other expenses decreased by $1,153 million, or 42% from 2022 to 2023, primarily due to lower losses on hedging activities and the incurrence of merger transaction costs in 2022.

In 2024, there were no impairment losses, compared to an impairment loss totaling $1,917 million for 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 “Item 18. Financial Statements” of this 2024 Form 20-F.

Net finance costs increased by $111 million, or 326%, from 2023, to $145 million. This was primarily due to reduced average cash in term deposits and higher debt drawdown. Net finance costs increased by $22 million, or 183%, from 2022 to 2023. This was primarily due to higher restoration accretion, driven by an additional five months activity from the assets acquired as part of the merger with BHP’s petroleum business, offset by higher interest rates on cash deposits.

Total tax expense comprises income tax and petroleum resource rent tax (PRRT). Income tax expense increased from 2023 to 2024 by $161 million, or 25%, to $814 million driven by higher taxable profit. PRRT was a $91 million benefit in 2024, up $989 million, or 110% from 2023 following the recognition of a PRRT deferred tax asset (DTA) at Pluto due to an increase in forecast assessable income due to higher prices. Income tax expense decreased from 2022 to 2023 primarily due to lower assessable income and the recognition of a DTA on the Trion FID. PRRT expense increased from 2022 to 2023 due to the partial de-recognition of the Pluto PRRT DTA.

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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 2024, 2023 and 2022.

	Units	2024		2023		2022
Production volumes1
LNG	Bcf		487.3		505.0		485.1
Pipeline gas	Bcf		219.6		226.3		163.0
Crude oil and condensate	MMbbl		63.2		51.8		38.7
NGLs	MMbbl		6.6		7.1		5.3
Total production	MMboe		193.9		187.2		157.7
Sales volumes
LNG	Bcf		547.8		595.7		550.6
Pipeline gas	Bcf		215.5		225.7		161.9
Crude oil and condensate	MMbbl		63.2		50.3		39.3
NGLs	MMbbl		6.4		7.1		4.6
Total sales volumes	MMboe		203.5		201.5		168.9
	Units	2024		2023		2022
Average realised prices
LNG	$/Mcf		11.7		13.7		20.5
Pipeline gas	$/Mcf		6.3		6.1		8.4
Crude oil and condensate	$/bbl		77.2		79.0		95.8
NGLs	$/bbl		48.0		39.5		44.4
Volume – weighted average	$/boe		63.6		68.6		98.4
Operating revenue
LNG	$m		6,401		8,165		11,289
Pipeline gas	$m		1,349		1,374		1,362
Crude oil and condensate	$m		4,887		3,981		3,758
NGLs	$m		306		281		206
Other revenue	$m		236		193		202
Operating revenue	$m		13,179		13,994		16,817

1. Production volumes for 2024, 2023 and 2022 include 1.2 MMboe, 1.1 MMboe and 0.9 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 2024, 2023 and 2022 include 12.3 MMboe, 15.6 MMboe and 14.7 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.

LNG

Revenue from the sale of LNG in 2024 decreased by $1,764 million, or 22%, to $6,401 million for 2024 from 2023, primarily due to decreases in Brent, JCC JKM and TTF price markers and lower volumes due to NWS natural field decline.

Revenue from the sale of LNG in 2023 decreased by $3,124 million, or 28%, for 2023 from 2022, primarily due to decreasing gas price markers. Lower prices were partially offset by five additional months of increased volumes following the merger with BHP Petroleum.

Pipeline gas

Revenue from the sale of pipeline gas in 2024 decreased by $25 million, or 2%, to $1,349 million for 2024 from 2023, primarily due to Bass Strait natural field decline, planned turnaround and lower prices at Trinidad.

Revenue from the sale of pipeline gas in 2023 increased by $12 million, or 1%, to $1,374 million for 2023 from 2022, primarily due to five months of increased pipeline gas volumes as a result of the merger with BHP Petroleum offset by lower average prices.

Crude oil and condensate

Revenue from the sale of crude oil and condensate in 2024 increased by $906 million, or 23%, to $4,887 million for 2024 from 2023, primarily due to Sangomar first production.

Revenue from the sale of crude oil and condensate in 2023 increased by $223 million, or 6%, to $3,981 million for 2023 from 2022, due to five months of increased crude oil and condensate volumes as a result of the merger with BHP Petroleum, however was offset by lower average realised prices.

NGLs

Revenue from the sale of NGLs in 2024 increased by $25 million, or 9%, to $306 million for 2024 from 2023, due to higher traded volumes via third party purchases.

32

Revenue from the sale of NGLs in 2023 increased by $75 million, or 36%, to $281 million for 2023 from 2022, due to five months of increased NGLs volumes as a result of the merger with BHP Petroleum.

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 in assessing performance and are based on the nature and geographical location of the related activity. For more information on our reportable segments, refer to note A.1 Segment revenue and expenses in “Item 18. Financial Statements” of this 2024 Form 20-F.

The disclosed operating segments in 2024 remain consistent to 2023 and 2022.

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 2024, 2023 and 2022.

Key metric	Units	2024		2023		2022
Operating revenue	$m		8,541		9,802		12,299
Profit before tax and net finance costs	$m		4,614		4,487		9,415
Total production	MMboe		139.5		145.1		136.6
Average realised prices
LNG	$/Mcf		11.0		13.4		19.0
Pipeline gas	$/Mcf		7.1		6.8		8.3
Crude oil and condensate	$/bbl		78.7		80.0		99.9
Natural gas liquids	$/bbl		51.2		39.1		47.2

Financial results

Operating revenue of $8,541 million decreased by $1,261 million, or 13%, from 2023 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. Refer to ‘Three-Year Pricing Overview’ for more information.

Profit before tax and net finance costs of $4,614 million increased by $127 million, or 3%, from 2023 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.

Operating revenue decreased by $2,497 million, from 2022 to 2023 primarily due to lower realised prices and planned turnaround activities, partially offset by five additional months of increased volumes following the merger with BHP Petroleum. Refer to ‘Three-Year Pricing Overview’ for more information.

Profit before tax and net finance costs of $4,487 million decreased by $4,928 million, or 52%, from 2022 to 2023 primarily due to lower prices and the pre-tax impairment of Wheatstone and Pyrenees assets of $534 million.

Production

Production volumes for the Australia segment decreased by 5.6 MMboe in 2024 compared to 2023, primarily due to natural field decline at Bass Strait and NWS partially offset by absence of Pluto planned turnaround activities.

Production volumes for the Australia segment increased by 8.5 MMboe in 2023 compared to 2022, primarily due to strong reliability of Pluto, additional interconnector cargoes and five additional months of increased volumes following the merger with BHP Petroleum.

International

Financial and operating information for our international operations comparing 2024, 2023 and 2022 is detailed below.

Key metric	Units	2024		2023			2022
Operating revenue	$m		3,405		2,549			1,570
Profit/(loss) before tax and net finance costs	$m		601		(808	)		125
Total production	MMboe		54.4		42.1			21.1
Average realised prices
Pipeline gas	$/Mcf		4.0		4.3			8.6
Crude oil and condensate	$/bbl		75.3		76.8			88.7
Natural gas liquids	$/bbl		24.8		21.1			31.3

33

Financial results

Operating revenue of $3,405 million in 2024 increased by $856 million in 2024 from 2023 primarily due to the start of production at Sangomar partially offset by planned turnaround and timing of crude lifts at Trinidad. For more information refer to note A.1 Segment revenue and expenses in “Item 18. Financial Statements” of this 2024 Form 20-F.

Profit before tax and net finance costs of $601 million increased by $1,409 million primarily due to the absence of pre-tax impairment of the Shenzi asset of $1,383 million.

Operating revenue of $2,549 million in 2023 increased by $979 million in 2023 from 2022 primarily due to five additional months of increased volumes following the merger with BHP Petroleum and the start of production at Argos in the United States.

Loss before tax and net finance costs of $808 million was primarily due to the pre-tax impairment of the Shenzi asset of $1,383 million.

Production

The International segment achieved an increase in production volumes of 12.3 MMboe in 2024 compared to 2023, primarily due to the start of production at Sangomar.

Production volumes for the International segment increased by 21 MMboe in 2023 compared to 2022 primarily due to five additional months of increased volumes following the merger with BHP Petroleum and the Argos asset starting production in April 2023.

Marketing

Financial and operating information for our marketing operations comparing 2024, 2023 and 2022 is detailed below.

Key metric	Units	2024	2023	2022
Operating revenue	$m	1,233	1,643	2,948
Profit before tax and net finance costs	$m	427	375	848
Average realised prices
LNG	$/Mcf	12.1	13.4	29.0
Liquids	$/boe	61.5	78.9	165.6

Financial results

Operating revenue of $1,233 million, 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 of $427 million, 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.

Operating revenue of $1,643 million, decreased by $1,305 million, or 44%, from 2022 to 2023 primarily due to lower average realised price and fewer third-party trades.

Profit before tax and net finance costs of $375 million, decreased by $473 million, or 56%, from 2022 to 2023 primarily due to lower average realised price.

New Energy/Corporate items

Financial information for our New Energy/Corporate items comparing 2024, 2023 and 2022 is detailed below.

Key metric	Units	2024	2023	2022
Loss before tax and net finance costs	$m	(1,128)	(747)	(1,202)

Loss before tax and net finance costs of $1,128 million increased by $381 million, or 51%, from 2023 to 2024 primarily due to an embedded derivative fair value adjustment as a result of weaker urea forward curve and higher discount rate.

Loss before tax and net finance costs of $747 million decreased by $455 million, or 38%, from 2022 to 2023 primarily due to the absence of merger cost in 2023.

34

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.

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 2024 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

	Units	2024	2023	2022
Australia	$m	3,297	3,515	2,440
International2	$m	2,351	2,588	2,093
Total	$m	5,648	6,103	4,533

1. Includes capital additions on other corporate spend. The 2022 amounts have been restated to be presented on the same basis.

2. Capital and exploration expenditure incurred in all other locations excluding Australia.

Australian capital and exploration expenditure decreased by $218 million, or 6%, to $3,297 million 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.

Australian capital and exploration expenditure increased by $1,075 million, or 44%, to $3,515 million from 2022 to 2023, primarily due to continued investment into the Scarborough and Pluto Train 2 assets.

International capital and exploration expenditure decreased by $237 million, or 9%, to $2,351 million from 2023 to 2024, primarily due to completion of the Sangomar project in 2024 and Argos in 2023, completion of Shenzi North in 2023 and less drilling activity at Atlantis partially offset by continued investment into the Trion asset.

International capital and exploration expenditure increased by $495 million, or 24%, to $2,588 million from 2022 to 2023, primarily due to continued investment into the Sangomar and Trion assets.

CASH FLOW ANALYSIS

The following section describes movements in Woodside’s cash flows for the years ending 31 December 2024, 2023 and 2022.

	2024   $m	2023   $m	2022   $m
Net cash from operating activities	5,847	6,145	8,811
Net cash used in investing activities	(5,747)	(5,585)	(2,265)
Net cash from/(used in) financing activities	2,101	(5,000)	(3,364)
Net increase/(decrease) in cash	2,201	(4,440)	3,182

Net cash from operating activities

Net cash from operating activities in 2024 decreased $298 million, or 5%, to $5,847 million from 2023, primarily due to higher payments for restoration ($358 million); return of collateral on Brent hedges in 2023 ($506 million); offset in part 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 from operating activities decreased $2,666 million, or 30%, to $6,145 million from 2022 to 2023, primarily due to lower EBITDA as a result of lower revenue driven by lower realised price; higher income tax and PRRT paid for record 2022 profits ($1,698 million); higher payments for restoration ($184 million); offset in part by return of collateral on Brent hedges versus payment in 2022 ($1,012 million); and higher receipts from interest ($156 million) due to higher interest rates from 2022 to 2023, despite reduction in deposits.

35

Net cash used in investing activities

Net cash used in investing activities in 2024 increased $162 million, or 3%, to $5,747 million from 2023, 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 used in investing activities increased $3,320 million, or 147%, to $5,585 million from 2022 to 2023, primarily due to investments in major projects at Scarborough, Sangomar and Trion. These new investments are intended to generate future operating cash flows and returns across the price cycle.

Net cash from/(used in) financing activities

Net cash from financing activities in 2024 increased $7,101 million, or 142%, to $2,101 million from 2023, 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).

Net cash used in financing activities increased $1,636 million, or 49%, to $5,000 million from 2022 to 2023, primarily due to higher final prior year dividend paid to shareholders ($1,695 million) due to the higher 2022 NPAT; and higher repayment of the principal portion of lease liabilities ($92 million) predominantly due to Sangomar.

B. Liquidity and capital resources

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 2.2: Capital management from pages 18-21

• Section 2.3: Financial overview from pages 22-23

• Exchange controls in Section 6.4: Shareholder statistics on pages 241-242

See Three-Year Financial Analysis in “Item 5.A Operating Results” of this 2024 Form 20-F.

See notes B.3, C and D.7 in “Item 18. Financial Statements” of this 2024 Form 20-F.

C. Research and development, Patents and Licences, etc.

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 3.7: New energy opportunities on pages 40-42

• Research and development in Section 4.2: Directors’ report on page 114.

36

D. Trend information

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 2.3: Financial overview from pages 22-23.

See Three-Year Financial Analysis in “Item 5.A Operating Results” and “Item 18. Financial Statements” of this 2024 Form 20-F.

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 2024 Annual Report is incorporated herein by reference:

• Section 4.1.2: Board of directors from pages 90-98

• Section 4.1.3 Board Committees from pages 99-101

• Section 4.1.4 Executive Leadership Team from pages 102-103.

B. Compensation

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 4.3: Remuneration Report from pages 117-144.

C. Board Practices

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 4.1: Corporate Governance Statement from pages 87-116.

D. Employees

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Employees in Section 6.3: Additional disclosures on page 228.

E. Share Ownership

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 4.3: Remuneration Report from pages 117-144.

See Note E.2 in “Item 18. Financial Statements” of this 2024 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 2024 Annual Report is incorporated herein by reference:

• Section 6.4: Shareholder statistics from pages 238-240.

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B. Related Party Transactions

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 4.3: Remuneration Report from pages 117-144.

See Note E.3 in “Item 18. Financial Statements” of this 2024 Form 20-F.

C. Interests of Experts and Counsel

Not applicable.

ITEM 8. FINANCIAL INFORMATION

A. Consolidated Statements and Other Financial Information

The information set forth under the following heading of the 2024 Annual Report is incorporated herein by reference:

• Capital management in Section 2.2: Capital management on page 18

• Summary of material legal proceedings in Section 6.3: Additional disclosures on page 236-237

• Dividend payments in Section 6.4: Shareholder statistics on page 240.

See “Item 18. Financial Statements” of this 2024 Form 20-F.

B. Significant Changes

See Note E.5 in “Item 18. Financial Statements” of this 2024 Form 20-F.

ITEM 9. THE OFFER AND LISTING

A. Offer and Listing Details

The information set forth under the following heading of the 2024 Annual Report is incorporated herein by reference:

• Section 6.4: Shareholder statistics from pages 238-242.

Exhibit 2.1 to this 2024 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 2024 Annual Report is incorporated herein by reference:

• Section 6.4: Shareholder statistics from pages 238-242.

D. Selling Shareholders

Not applicable.

E. Dilution

Not applicable.

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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 2024 Form 20-F is incorporated herein by reference.

C. Material Contracts

Exhibits 4.1 and 4.2 to this 2024 Form 20-F are incorporated herein by reference.

D. Exchange controls

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Exchange Controls in Section 6.4: Shareholder statistics on pages 241-242.

E. Taxation

This section describes the material US and Australian income tax consequences to a US holder (as defined below) of owning shares or ADSs (together, “Woodside securities”). 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 US 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 the following:

• a dealer in securities,

• a trader in securities who elects to use a mark-to-market method of accounting for securities holdings,

• a tax-exempt organisation,

• a life insurance company,

• a person who 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 who holds shares or ADSs as part of a straddle or a hedging or conversion transaction,

• a person who purchases or sells shares or ADSs as part of a wash sale for tax purposes,

• 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 US federal income tax purposes:

• a citizen or resident of the United States,

• a domestic corporation,

• an estate whose income is subject to US federal income tax regardless of its source,

• a trust if a US court can exercise primary supervision over the trust’s administration and one or more US persons are authorised to control all substantial decisions of the trust.

If an entity or arrangement that is treated as a partnership for US federal income tax purposes holds the shares or ADSs, the US 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 their tax adviser with regard to the US federal income tax treatment of an investment in the shares or ADSs.

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You should consult your own tax advisor regarding the US 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 US 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 US 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 (PFIC), for US federal income tax purposes. Except as discussed below under Passive foreign investment company’ classification, this discussion assumes that we are not classified as such a company for US 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 US federal income tax purposes), other than certain pro-rata distributions of our shares, will be treated as a dividend that is subject to US 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.

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 US corporations in respect of dividends received from other US 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 A$/US$ 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 US 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 US 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 US 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 US 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 US 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 US 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 passive foreign investment company for US federal income tax purposes and we do not expect to become a passive foreign investment company in the foreseeable future. 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 passive foreign investment company in a future taxable year.

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In general, we will be a passive foreign investment company 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 passive foreign investment company 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 passive foreign investment company 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 passive foreign investment company if we were a passive foreign investment company 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 or are treated as a passive foreign investment company 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, their legislative history, existing and proposed regulations, published rulings and court decisions, all as currently in effect, as well as on the Treaty. These authorities are subject to change, possibly on a retroactive basis.

Dividends (including other distributions treated as dividends for Australian tax purposes) paid by Woodside to a US holder who 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, which are not fully franked, paid to such US holders, 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 by taxed by assessment in Australia if the US holder meets one of these conditions:

• 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).

• 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, (but 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 Woodside securities

Gains made by US holders on the sale of Woodside securities will generally not be taxed in Australia.

The precise Australian tax treatment of gains made by US holders on the sale of Woodside securities 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 meet one of these conditions:

• they are not eligible for benefits under the Australian Tax Treaty and the gain is sourced in Australia for Australian tax purposes

• 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):

o business profits of an enterprise attributable to a permanent establishment situated in Australia through which the enterprise carries on business in Australia

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o 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

o 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 Woodside securities after 19 September 1985 and one or more of the following applies:

• the US holder is an Australian resident for Australian tax purposes

• the Woodside securities have been used by the US holder in carrying on a business through permanent establishment in Australia

• the Woodside securities constitute an “indirect Australian real properly interest” for Australian capital gains tax 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 (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)

• 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 Woodside securities subject to Australian capital gains tax.

In certain circumstances, if the Woodside securities constitute an “indirect Australian real property interest” for Australian capital gains tax purposes, the purchaser may be required to withhold under the non-resident capital gains tax 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. Affected US holders should seek their own advice in relation to how this withholding regime may apply to them.

The comments above on the sale of Woodside securities do not apply in these circumstances:

• to temporary residents of Australia who should seek advice that is specific to their circumstances

• 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 WOODSIDE SECURITIES. 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 WOODSIDE SECURITIES, 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 2024 Annual Report is incorporated herein by reference:

• Documents on display in Section 6.4: Shareholder statistics on page 240.

I. Subsidiary Information

See Note E.8 in “Item 18. Financial Statements” of this 2024 Form 20-F.

Exhibit 8.1 to this 2024 Form 20-F is incorporated herein by reference.

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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 2024 Annual Report is incorporated herein by reference:

• Quantitative and qualitative disclosures about market risk in Section 6.3: Additional disclosures from pages 228-229.

See Notes A and C in “Item 18. Financial Statements” of this 2024 Form 20-F.

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

A. Debt Securities

Not applicable.

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 2024 Annual Report is incorporated herein by reference:

• American Depositary Receipts in Section 6.4: Shareholder statistics on page 241

• Fees Payable by the Depositary to the Issuer in Section 6.4: Shareholder statistics on page 241.

Exhibit 2.1 to this 2024 Form 20-F is incorporated herein by reference.

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 2024. Based on that evaluation, the CEO and CFO concluded that Woodside’s disclosure controls and procedures were effective, as at 31 December 2024, in ensuring that information required to be disclosed by Woodside in the reports that it files or submits under the Exchange Act is recorded, processed, summarised and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to Woodside’s management, including the CEO and CFO, to allow timely decisions regarding required disclosure.

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 control 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 2024.

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Woodside acquired 100% of OCI Clean Ammonia Holding B.V. and its Beaumont New Ammonia Project on 30 September 2024 and all the issued and outstanding common stock of Tellurian Inc. on 8 October 2024 (Acquisitions). As permitted by the SEC Staff interpretative guidance that an assessment of internal controls over financial reporting of a recently acquired business may be excluded from management’s evaluation of disclosure controls and procedures for up to one year from the date of acquisition, Woodside has excluded the Acquisitions from management’s report on internal control over financial reporting as of 31 December 2024. The Acquisitions, collectively, represented approximately 7% of Woodside’s consolidated total assets as of 31 December 2024 and approximately 0% of Woodside’s consolidated total revenues as of 31 December 2024.

Because of 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 2024 has been audited by PwC, an independent registered accounting firm that also audits Woodside’s Financial Statements. Their audit report on the internal control over financial reporting is included in “Item 18. Financial Statements” in this 2024 Form 20-F.

Changes in Internal Control Over Financial Reporting

Effective 1 January 2024, we implemented an updated enterprise resource planning (ERP) system. As a result, we have evaluated and made corresponding changes to our business processes and information systems, updating applicable internal controls over financial reporting as necessary.

There were no other changes in our internal control over financial reporting during FY2024 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 2024 Annual Report is incorporated herein by reference:

• Section 4.1.5: Promoting responsible and ethical behaviour from pages 104-105.

Exhibit 11.1 to this 2024 Form 20-F is incorporated herein by reference.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• External Audit and Reporting in Section 4.1.6: Risk management and internal control from pages 106-107.

See Note E.4 in “Item 18. Financial Statements” of this 2024 Form 20-F.

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

See “Item 16G. Corporate Governance” of this 2024 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 2024 Annual Report is incorporated herein by reference:

• Section 6.4: Shareholder statistics from pages 238-242.

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ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.

ITEM 16G. CORPORATE GOVERNANCE

The information set forth under the following headings of the 2024 Annual Report is incorporated herein by reference:

• Section 4.1: Corporate Governance Statement from pages 87-116.

ITEM 16H. MINE SAFETY DISCLOSURE

Not applicable.

ITEM 16I. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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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 2024 Form 20-F is incorporated herein by reference.

ITEM 16K. CYBERSECURITY DISCLOSURE

Our Cyber Resilience Process and Risk Management

Woodside’s approach to managing material risks from cybersecurity threats is integrated into our overall risk management processes.

Woodside’s cybersecurity resilience and risk management strategy and process are based on the National Institute of Standards 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.

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2. to monitor and strengthen Woodside’s cybersecurity posture while preventing, detecting, analysing and responding to cybersecurity incidents.

3. to embed a cyber-safe culture across Woodside and foster industry collaboration.

4. to enable compliance with all applicable legislation.

The 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 Item 3.D Risk Factors.

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 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 2023.

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 up-front 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 on-boarding 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.

Woodside continuously monitors its digital information landscape and has various threat detection measures in place. Woodside is 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 controls

As part of its oversight of the Risk Management Policy, the Audit & Risk Committee oversees risks from cybersecurity threats. 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.

The identification and direct management of cybersecurity risks and threats are performed by Woodside’s cybersecurity function, 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 has held multiple technology and business facing roles.

The Cyber Resilience Process includes the monitoring, prevention, detection, mitigation and remediation of cybersecurity risks and incidents.

The Woodside Board and the Audit & Risk Committee are kept informed of any material 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.

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 2024 Form 20-F. The audit report of PricewaterhouseCoopers, an independent registered accounting firm, is included herein following the audited Consolidated Financial Statements.

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5.1

Financial Statements

Contents

Financial Statements		F-3
Consolidated income statement		F-3
Consolidated statement of comprehensive income		F-4
Consolidated statement of financial position		F-5
Consolidated statement of cash flows		F-6
Consolidated statement of changes in equity		F-7
Notes to the financial statements		F-8
About these statements		F-8
Climate change and energy transition		F-9
A.	Earnings for the year	F-13
A.1	Segment revenue and expenses	F-14
A.2	Finance costs	F-19
A.3	Dividends paid and proposed	F-19
A.4	Earnings per share	F-19
A.5	Taxes	F-20
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-29
B.4	Impairment of exploration and evaluation, property, plant and equipment and goodwill	F-30
B.5	Business combination	F-37
B.6	Intangible assets	F-38
B.7	Significant production and growth asset acquisitions	F-39
B.8	Disposal of assets	F-40
C.	Debt and capital	F-41
C.1	Cash and cash equivalents	F-42
C.2	Interest-bearing liabilities and financing facilities	F-43
C.3	Contributed equity	F-45
C.4	Other reserves	F-46
D.	Other assets and liabilities	F-47
D.1	Segment assets and liabilities	F-48
D.2	Receivables	F-48
D.3	Inventories	F-49
D.4	Payables	F-49
D.5	Provisions	F-50
D.6	Other financial assets and liabilities	F-52
D.7	Leases	F-54
E.	Other items	F-57
E.1	Contingent liabilities and assets	F-58
E.2	Employee benefits	F-58
E.3	Related party transactions	F-60
E.4	Auditor remuneration	F-60
E.5	Events after the end of the reporting period	F-60
E.6	Joint arrangements	F-61
E.7	Parent entity information	F-62
E.8	Subsidiaries	F-62
E.9	Other accounting policies	F-66
Consolidated entity disclosure statement		F-68
Directors’ declaration		F-69
PwC - Report of Independent Registered Public Accounting Firm (PricewaterhouseCoopers, Australia, Auditor Firm ID: 1379)		F-70

F-1

Significant changes in the current reporting period

The financial performance and position of the Group were particularly affected by the following events and transactions during the reporting period:

· On 26 March 2024, the Group completed the sell-down of a 10% non-operating participating interest in the Scarborough Joint Venture to LJ Scarborough Pty Ltd (LNG Japan). Proceeds from the sale were $910 million, including capital reimbursements and escalation. As a result, the Group recognised a pre-tax gain of $121 million on the transaction (refer to Note B.8).

· On 11 June 2024, the Sangomar project in Senegal achieved first oil. For the year ended 31 December 2024, Sangomar contributed $948 million in operating revenue. The Group also recognised a net deferred tax asset of $342 million (refer to Note A.5).

· On 30 September 2024, the Group acquired 100% of the issued share capital of OCI Clean Ammonia Holding B.V. and its Beaumont New Ammonia project (previously Clean Ammonia project). The transaction has been accounted for as a business combination (refer to Note B.5).

· On 8 October 2024, the Group acquired 100% of the issued and outstanding common stock of Tellurian Inc. (subsequently renamed Woodside Energy (LA) Holdings Inc.) including its owned and operated Louisiana LNG (previously US Gulf Coast Driftwood LNG) development opportunity. The transaction has been accounted for as an asset acquisition (refer to Note B.7).

· On 31 October 2024, the Group completed the sell-down of a 15.1% non-operating participating interest in the Scarborough Joint Venture to JERA Scarborough Pty Ltd (JERA). Proceeds from the sale were $1,425 million including capital reimbursements. As a result, the Group recognised a pre-tax gain of $88 million on the transaction (refer to Note B.8).

· The Group recognised a $502 million increase to the Pluto PRRT deferred tax asset due to the recognition of previously unrecognised deductible expenditure that is now considered to be recoverable on the basis of future taxable profits being available to utilise the expenditure (refer to Note A.5).

F-2

Financial Statements

Consolidated income statement

for the year ended 31 December 2024

	Notes	2024 US$m			2023 US$m			2022 US$m
Operating revenue	A.1		13,179			13,994			16,817
Cost of sales	A.1		(7,501	)		(7,519	)		(6,540	)
Gross profit			5,678			6,475			10,277
Other income	A.1		624			322			735
Other expenses	A.1		(1,788	)		(1,573	)		(2,726	)
Impairment losses	A.1		-			(1,917	)		-
Impairment reversals	A.1		-			-			900
Profit before tax and net finance costs			4,514			3,307			9,186
Finance income			220			273			155
Finance costs	A.2		(365	)		(307	)		(167	)
Profit before tax			4,369			3,273			9,174
Petroleum resource rent tax (PRRT) benefit/(expense)	A.5		91			(898	)		313
Income tax expense	A.5		(814	)		(653	)		(2,912	)
Profit after tax			3,646			1,722			6,575
Profit attributable to:
Equity holders of the parent			3,573			1,660			6,498
Non-controlling interest	E.8		73			62			77
Profit for the period			3,646			1,722			6,575
Basic earnings per share attributable to equity holders of the parent (US cents)	A.4		188.5			87.5			430.0
Diluted earnings per share attributable to equity holders of the parent (US cents)	A.4		186.9			86.9			426.3

The accompanying notes form part of the Financial Statements.

F-3

Consolidated statement of comprehensive income

for the year ended 31 December 2024

	2024 US$m	2023 US$m	2022 US$m
Profit for the period	3,646	1,722	6,575
Other comprehensive income/(loss)
Items that may be reclassified to the income statement in subsequent periods:
(Losses)/gains on cash flow hedges	(139)	459	(1,097)
Losses on cash flow hedges reclassified to the income statement	86	299	847
Tax recognised within other comprehensive income	(34)	(84)	64
Exchange fluctuations on translation of foreign operations taken to equity	-	(1)	3
Items that will not be reclassified to the income statement in subsequent periods:
Remeasurement (loss)/gain on defined benefit plan	(11)	14	34
Net (loss)/gain on financial instruments at fair value through other comprehensive income	(8)	(32)	2
Other comprehensive (loss)/income for the period, net of tax	(106)	655	(147)
Total comprehensive income for the period	3,540	2,377	6,428
Total comprehensive income attributable to:
Equity holders of the parent	3,467	2,315	6,351
Non-controlling interest	73	62	77
Total comprehensive income for the period	3,540	2,377	6,428

The accompanying notes form part of the Financial Statements.

F-4

Consolidated statement of financial position

as at 31 December 2024

	Notes	2024 US$m		2023 US$m
Current assets
Cash and cash equivalents	C.1		3,923		1,740
Receivables	D.2		2,390		1,517
Inventories	D.3		684		616
Other financial assets	D.6		185		209
Assets held for sale			-		826
Tax receivable			288		118
Other assets			93		92
Total current assets			7,563		5,118
Non-current assets
Receivables	D.2		876		839
Inventories	D.3		213		120
Other financial assets	D.6		118		120
Exploration and evaluation assets	B.2		721		668
Property, plant and equipment	B.3		42,636		40,791
Deferred tax assets	A.5		2,393		1,717
Lease assets	D.7		1,291		1,230
Investments accounted for using the equity method			249		249
Intangible assets1	B.6		4,826		4,183
Other assets1			378		326
Total non-current assets			53,701		50,243
Total assets			61,264		55,361
Current liabilities
Payables	D.4		2,185		1,724
Interest-bearing liabilities	C.2		990		-
Other financial liabilities	D.6		139		67
Liabilities directly associated with assets held for sale			-		94
Provisions	D.5		1,322		1,506
Tax payable			308		1,108
Lease liabilities	D.7		189		298
Other liabilities			724		185
Total current liabilities			5,857		4,982
Non-current liabilities
Interest-bearing liabilities	C.2		9,007		4,883
Deferred tax liabilities	A.5		1,497		1,627
Other financial liabilities	D.6		379		42
Provisions	D.5		6,225		6,451
Tax payable			28		40
Lease liabilities	D.7		1,434		1,317
Other liabilities			684		849
Total non-current liabilities			19,254		15,209
Total liabilities			25,111		20,191
Net assets			36,153		35,170
Equity
Issued and fully paid shares	C.3		29,001		29,001
Shares reserved for employee share plans	C.3		(58)		(49)
Other reserves	C.4		4,108		5,261
Retained earnings			2,348		186
Equity attributable to equity holders of the parent			35,399		34,399
Non-controlling interest	E.8		754		771
Total equity			36,153		35,170

1. Intangible assets include software and contract assets which were previously presented within other assets (non-current). The 2023 amounts have been reclassified to be presented on the same basis (refer to Note B.6).

The accompanying notes form part of the Financial Statements.

F-5

Consolidated statement of cash flows

for the year ended 31 December 2024

	Notes	2024 US$m			2023 US$m		2022 US$m
Cash flows from/(used in) operating activities
Profit after tax for the period			3,646			1,722		6,575
Adjustments for:
Non-cash items
Depreciation and amortisation			4,552			3,960		2,808
Depreciation of lease assets			210			179		140
Change in fair value of derivative financial instruments			352			349		960
Net finance costs			145			34		12
Tax expense			723			1,551		2,599
Exploration and evaluation written off			9			77		164
Impairment losses	B.4		-			1,917		-
Impairment reversals			-			-		(900)
Restoration movement			199			147		272
Gain on disposal of property, plant and equipment (including revaluation gain)			(238)			-		(494)
Movement in onerous contracts provision			-			-		(245)
Other			(135)			(226)		(254)
Changes in assets and liabilities
(Increase)/decrease in trade and other receivables			(301)			107		(77)
Increase in inventories			(161)			(31)		(146)
Increase/(decrease) in provisions			3			(114)		131
Decrease in lease liabilities			-			-		(31)
Increase in other assets and liabilities			(45)			(736)		(961)
Increase/(decrease) in trade and other payables			175			(135)		184
Cash generated from operations			9,134			8,801		10,737
Purchases of shares and payments relating to employee share plans			(81)			(57)		(45)
Interest received			183			264		108
Dividends received			12			20		19
Borrowing costs relating to operating activities			(41)			(26)		(21)
Income tax and PRRT paid			(2,555)			(2,916)		(1,218)
Payments for restoration			(805)			(447)		(263)
Receipts/(payments) for hedge collateral			-			506		(506)
Net cash from operating activities			5,847			6,145		8,811
Cash flows from/(used in) investing activities
Cash (paid)/received on business combination, net of cash acquired	B.5		(1,896)			-		1,082
Payments for capital and exploration expenditure			(4,902)			(5,291)		(3,136)
Payments for asset acquisition, net of cash acquired	B.7		(1,042	)		-		-
Reimbursements received from external parties for capital expenditure			155			-		-
Borrowing costs relating to investing activities			(369)			(311)		(287)
Advances to other external entities			-			-		(48)
Proceeds from disposal of non-current assets			2,307			19		132
Funding of equity accounted investments			-			(2)		(8)
Net cash used in investing activities			(5,747)			(5,585)		(2,265)
Cash flows from/(used in) financing activities
Proceeds from borrowings	C.2		5,114			-		-
Repayment of borrowings	C.2		(169)			(284)		(283)
Borrowing costs relating to financing activities			(2)			(4)		(18)
Repayment of the principal portion of lease liabilities			(278)			(340)		(248)
Borrowing costs relating to lease liabilities			(15)			(21)		(10)
Purchases of shares and payments relating to Dividend Reinvestment Plan			-			-		(144)
Contributions to non-controlling interests			(100)			(98)		(98)
Dividends paid			(2,449)			(4,253)		(2,558)
Net payments from share issuance			-			-		(5)
Net cash from/(used in) in financing activities			2,101			(5,000)		(3,364)
Net increase/(decrease) in cash held			2,201			(4,440)		3,182
Cash and cash equivalents at the beginning of the period			1,740			6,201		3,025
Effects of exchange rate changes			(18)			(21)		(6)
Cash and cash equivalents at the end of the period	C.1		3,923			1,740		6,201

The accompanying notes form part of the Financial Statements.

F-6

Consolidated statement of changes in equity

for the year ended 31 December 2024

	Issued and fully paid shares		Reserved shares		Employee benefits reserve		Foreign currency translation reserve		Hedging reserve		Distributable profits reserve		Other reserves		Retained earnings		Equity holders of the parent		Non- controlling interest		Total equity
Notes	C.3 US$m		C.3 US$m		C.4 US$m		C.4 US$m		C.4 US$m		C.4 US$m		C.4 US$m		US$m		US$m		E.8 US$m		US$m
At 1 January 2024		29,001		(49)		290		795		88		4,118		(30)		186		34,399		771		35,170
Profit for the period		-		-		-		-		-		-		-		3,573		3,573		73		3,646
Other comprehensive loss		-		-		-		-		(87)		-		(8)		(11)		(106)		-		(106)
Total comprehensive (loss)/income for the period		-		-		-		-		(87)		-		(8)		3,562		3,467		73		3,540
Transfers		-		-		-		-		-		1,400		-		(1,400)		-		-		-
Employee share plan purchases		-		(81)		-		-		-		-		-		-		(81)		-		(81)
Employee share plan redemptions		-		72		(72)		-		-		-		-		-		-		-		-
Share-based payments (net of tax)		-		-		63		-		-		-		-		-		63		-		63
Dividends paid		-		-		-		-		-		(2,449)		-		-		(2,449)		(90)		(2,539)
At 31 December 2024		29,001		(58)		281		795		1		3,069		(38)		2,348		35,399		754		36,153
At 1 January 2023		29,001		(38)		278		796		(586)		3,541		2		3,342		36,336		791		37,127
Profit for the period		-		-		-		-		-		-		-		1,660		1,660		62		1,722
Other comprehensive income/(loss)		-		-		-		(1)		674		-		(32)		14		655		-		655
Total comprehensive income/(loss) for the period		-		-		-		(1)		674		-		(32)		1,674		2,315		62		2,377
Transfers		-		-		-		-		-		4,830		-		(4,830)		-		-		-
Employee share plan purchases		-		(57)		-		-		-		-		-		-		(57)		-		(57)
Employee share plan redemptions		-		46		(46)		-		-		-		-		-		-		-		-
Share-based payments (net of tax)		-		-		58		-		-		-		-		-		58		-		58
Dividends paid		-		-		-		-		-		(4,253)		-		-		(4,253)		(82)		(4,335)
At 31 December 2023		29,001		(49)		290		795		88		4,118		(30)		186		34,399		771		35,170
At 1 January 2022		9,409		(30)		232		793		(400)		58		-		3,381		13,443		786		14,229
Profit for the period		-		-		-		-		-		-		-		6,498		6,498		77		6,575
Other comprehensive income/(loss)		-		-		-		3		(186)		-		2		34		(147)		-		(147)
Total comprehensive income/(loss) for the period		-		-		-		3		(186)		-		2		6,532		6,351		77		6,428
Transfers		-		-		-		-		-		5,553		-		(5,553)		-		-		-
Shares purchased for Dividend Reinvestment Plan		-		(144)		-		-		-		-		-		-		(144)		-		(144)
Dividend Reinvestment Plan		332		144		-		-		-		-		-		-		476		-		476
Shares issued for acquisition of BHPP		19,265		-		-		-		-		-		-		-		19,265		-		19,265
Replacement employee share plan issued for acquisition of BHPP		-		-		18		-		-		-		-		-		18		-		18
Employee share plan purchases		-		(45)		-		-		-		-		-		-		(45)		-		(45)
Employee share plan redemptions		-		37		(37)		-		-		-		-		-		-		-		-
Share-based payments (net of tax)		-		-		65		-		-		-		-		-		65		-		65
Dividends paid		-		-		-		-		-		(2,070)		-		(1,018)		(3,088)		(72)		(3,160)
Transaction costs associated with the issue of shares		(5)		-		-		-		-		-		-		-		(5)		-		(5)
At 31 December 2022		29,001		(38)		278		796		(586)		3,541		2		3,342		36,336		791		37,127

The accompanying notes form part of the Financial Statements.

F-7

Notes to the financial statements

for the year ended 31 December 2024

About these statements

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). On 19 November 2024, the Group delisted its shares from the Main Market for listed securities of the London Stock Exchange (LSE). The nature of the operations and the principal activities of the Group are described in the Directors’ Report and in the segment information in Note A.1.

The financial statements were authorised for issue in accordance with a resolution of the Directors on 25 February 2025.

Statement of compliance

The financial statements are general purpose financial statements, which have been prepared in accordance with the requirements of the International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board. They also include additional disclosures required for foreign registrants by the United States Securities and Exchange Commission (US SEC).

The Group’s accounting policies are materially consistent with those disclosed in the Group’s 2023 Financial Statements. Adoption of new or amended standards and interpretations effective 1 January 2024 did not result in any significant changes to the Group’s accounting policies.

Estimates have been revised, where required, to reflect current market conditions including the impact of climate change. Updated assumptions used for impairment assessments and restoration are disclosed in Notes B.4 and D.5 respectively; these assumptions could change in the future. New estimates and judgements relating to a business combination and asset acquisition are disclosed in Notes B.5 and B.7 respectively.

Currency

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

Transactions in foreign currencies are initially recorded in the functional currency of the transacting entity at the exchange rates ruling at the date of transaction. Monetary assets and liabilities denominated in foreign currencies at the reporting date are translated at the rates of exchange ruling at that date. Exchange differences in the consolidated financial statements are taken to the income statement.

Rounding of amounts

The financial statements are rounded to the nearest million dollars, except where otherwise indicated.

Basis of preparation

The financial statements have been prepared on a historical cost basis, except for derivative financial instruments and certain other financial assets and financial liabilities, which have been measured at fair value or amortised cost adjusted for changes in fair value attributable to the risks that are being hedged in effective hedge relationships. Where not carried at fair value, if the carrying value of financial assets and financial liabilities does not approximate their fair value, the fair value has been included in the notes to the financial statements.

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

The financial statements comprise the financial position and results of the Group as at and for the year ended 31 December 2024 (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-8

Notes to the financial statements

for the year ended 31 December 2024

Climate change and energy transition

Climate considerations

Woodside’s global portfolio includes oil, gas and new energy assets across Australia, the United States, Trinidad and Tobago, Senegal, Mexico, Timor-Leste and Canada. Woodside has considered the impact of climate and the energy transition in assessing the carrying values of its assets and liabilities. This note describes climate-related assumptions that underpin key areas of the financial statements and the potential short-term and long-term impacts differing scenarios could have on the financial results and financial position of Woodside.

Financial planning and assumptions

Woodside considers a range of climate and macroeconomic scenarios to help benchmark our long-term price assumptions and inform our decision making to maintain a resilient financial position. These scenarios are informed by a wide range of externally published data, including Paris-aligned and non-Paris-aligned outcomes, and are part of a broad consideration of risks, opportunities, competitiveness and resilience. The assumptions applied in assessing amounts within the 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 the goals of the Paris Agreement, as well as scenarios in which the transition is not, or may not be, sufficiently rapid. They also place some weight on a range of other assumptions which can drive prices (e.g. inflation) and which are not related to the Paris 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. Physical risks could also impact emerging new business in the new energy products and lower carbon services such as bushfire or drought risk for nature-based carbon origination projects, or access to water for use in electrolysis for hydrogen.

The high degree of uncertainty around the nature, timing and magnitude of climate-related risks, and the uncertainty as to how the energy transition will evolve, makes it difficult to determine the risks and their potential impacts with precision.

Woodside continues to monitor the uncertainty around climate change risks and expects to take into account ongoing developments into its assumptions, including assumptions concerning commodity and carbon pricing, as considered appropriate. Investment cases include a carbon price assumption which takes into consideration uncertainty around the impact of climate change. Commodity pricing assumptions are key value drivers with greater significance to assets and liabilities than carbon pricing.

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

In accordance with the Group’s accounting policies and applicable accounting standards, elements of Woodside’s financial statements are based on reasonable and supportable assumptions that represent management’s current best estimate of the range of economic conditions that may exist in the foreseeable future.

The estimation of recoverable amounts for impairment testing includes estimating what an independent market participant would pay to acquire the asset as at the reporting date. Market participants will be guided by their own views on future economic and technical conditions and therefore Woodside considers a range of data sources in determining a future price forecast, including industry and market benchmarks along with asset sales transaction data to support the recoverable amount.

The completion of the sale of the 10% and 15.1% non-operating participating interest in the Scarborough Joint Venture to LNG Japan and JERA respectively in 2024, is a clear example of an independent market valuation fully supporting the carrying value of the multi-decade asset.

Price forecasts are adjusted for premiums and discounts based on the nature and quality of the product. Commodity oil price estimates have considered the impacts of climate policies 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. The IEA’s World Energy Outlook 2024 (WEO) explores three main climate change scenarios. The IEA scenarios are not predictions and the IEA does not have a single view on the future of the energy system. There is significant uncertainty as to whether any of these scenarios will eventuate. As Woodside considers what a market participant would pay to acquire an asset in assessing impairments, these external scenarios are not necessarily consistent with the pricing assumptions used for the Group’s impairment assessment as disclosed in Table A below and Note B.4.

The WEO explores three main scenarios1:

• The Net Zero Emissions by 2050 Scenario (NZE)

• The Announced Pledges Scenario (APS)

• The Stated Policies Scenario (STEPS)

F-9

Notes to the financial statements

for the year ended 31 December 2024

Table A: Average real terms 2024 oil price (US$/bbl, Brent) 2, North Asian LNG price (US$/MMBtu) 2 and carbon price (US$/tCO2-e) 3 consistent with IEA dataset compared against Woodside’s assumptions:

Average Brent (RT US$/bbl)	2025-2029		2030-2034		2035-2040
NZE		52		40		32
APS		76		72		67
STEPS		82		81		80
Woodside		78		78		78
Average North Asian LNG (RT US$/MMBtu)	2025-2029		2030-2034		2035-2040
NZE		6		5		5
APS		8		7		6
STEPS		9		8		9
Woodside		10		10		11
Average Carbon (RT US$/tonne)	2025-2029		2030-2034		2035-2040
NZE		112		161		199
APS		110		150		173
STEPS		80		80		80
Woodside		80		80		80

1. IEA 2024. ‘World Energy Outlook 2024’. All rights reserved.

2. Based on data from IEA 2024. ‘World Energy Outlook 2024’ as modified by Woodside analysis. Woodside used interpolation techniques to estimate Brent annual price points in between the years that the IEA disclose prices for. For gas pricing assumptions all non-contracted LNG volumes were assessed at IEA’s Japan import price, as a proxy for North Asian LNG spot price. Woodside used interpolation techniques to estimate annual gas price points in between the years that the IEA disclose prices for. For oil linked LNG contracts, prices are derived from the Brent forecasts and the terms of the contracts.

3. Based on data from IEA 2024. ‘World Energy Outlook 2024’ as modified by Woodside analysis. The IEA only provide carbon prices from 2030 onwards. As a result, Woodside used a starting point of US$80/tCO2-e consistent with internal carbon pricing. Woodside used the 2024 starting price point and the IEA’s published 2030, 2035 and 2040 carbon prices for each scenario to interpolate annual price points through to 2040.

Woodside’s assumptions for Brent and JKM sit within the range of various external scenarios, including but not limited to NZE, APS and STEPS, considered by management. These include scenarios consistent with the temperature goals of the Paris climate change agreement as well as industry outlooks.

The benchmarked pricing above has limitations and is based on a wide range of assumptions. The impact of the benchmark pricing assumptions may be addressed to varying degrees by decisions Woodside could make in response such as acquisitions, divestments or cost reductions as well as other consequential changes. The scenarios must therefore not be interpreted as Woodside’s investment guidance. These are scenarios, not forecasts, and no likelihood or probability is assigned to any of these scenarios eventuating.

Impact on remaining life of assets

Oil and gas properties, included within property, plant and equipment, are depreciated using the unit of production basis over either proved or proved plus probable reserves. The energy transition may result in changes to the expected useful life of oil and gas properties and economically recoverable reserves and resources thereby accelerating depreciation charges or resulting in an impairment. New energy assets under development still require significant capital expenditure. The Group will review depreciation methodology and useful life of new energy assets as they are brought into use.

Carbon credits

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

The Group has available carbon credits that can be used in the short and medium term for emissions which are otherwise not technically or economically viable to avoid or reduce. One carbon credit is intended to represent a tonne of emissions avoided, reduced or removed outside of our facilities.

As at 31 December 2024, the Group recognised $202 million (2023: $123 million) of carbon credits within inventory.

Restoration and other provisions

The energy transition may result in restoration activities occurring earlier than expected. 53% (2023: 55%) 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.

Long term contracts

Climate risks may impact underlying assumptions used to assess the forecast cash flows of long-term contracts. These judgemental assumptions include pricing forecast and discount rate adjustments based on the nature of the product.

As at 31 December 2024, the Corpus Christi contract has a positive value and therefore is not currently onerous (2023: not onerous). This and other contractual arrangements could be impacted by adverse market conditions arising from climate-related factors.

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

Deferred tax assets

The Group has determined that it is probable that sufficient future taxable income will be available to utilise the deferred tax assets relating to carry forward unused tax losses and credits recognised as at 31 December 2024. The recoverability of deferred tax assets is dependent on the Group’s future taxable income which can be impacted by the uncertainty of commodity and carbon pricing.

Regulatory environment

Regulation of climate-related emissions can change over time. Woodside is not currently aware of any specific proposal that would materially affect the information in these financial statements.

Woodside continues to monitor the development of global sustainability standards relevant to our activities around the world to ensure compliance.

This includes the Australian Sustainability Reporting Standards issued by the Australian Accounting Standards Board (AASB) climate standard (AASB S2) and sustainability standard (AASB S1), the US SEC climate rules, the International Financial Reporting Standards (IFRS) Foundation’s International Sustainability Standards Board (ISSB) standards relevant to sustainability and climate related disclosures and the European Corporate Sustainability Reporting Directive and associated European Sustainability Reporting Standards including the Corporate Sustainability Due Diligence Directive.

F-10

Notes to the financial statements

for the year ended 31 December 2024

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. See “Item 3.D Risk Factors” in this 2024 Form 20-F 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-41
Section C	Liquidity risk management	Page F-41
Section C	Interest rate risk management	Page F-41
Section D	Credit risk management	Page F-47

F-11

Notes to the financial statements

for the year ended 31 December 2024

Key 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-20
Note B.2	Exploration and evaluation	Page F-27
Note B.3	Property, plant and equipment	Page F-29
Note B.4	Impairment of exploration and evaluation, property, plant and equipment and goodwill	Page F-30
Note B.5	Business combination	Page F-37
Note B.6	Intangible assets	Page F-38
Note B.7	Significant production and growth asset acquisitions	Page F-39
Note D.5	Provisions	Page F-50
Note D.6	Other financial assets and liabilities	Page F-52
Note D.7	Leases	Page F-54
Note E.6	Joint arrangements	Page F-61

F-12

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

In this section

This section addresses financial performance of the Group for the reporting period including, where applicable, the accounting policies applied and the key estimates and judgements made. This section also includes the tax position of the Group for and at the end of the reporting period.

A.	Earnings for the year
A.1	Segment revenue and expenses	Page F-14
A.2	Finance costs	Page F-19
A.3	Dividends paid and proposed	Page F-19
A.4	Earnings per share	Page F-19
A.5	Taxes	Page F-20

Key financial and capital risks in this section

Commodity price risk management

The Group’s revenue is exposed to commodity price fluctuations through the sale of hydrocarbons. Commodity price risks are measured by monitoring and stress testing the Group’s forecast financial position to sustained periods of low commodity prices. This analysis is regularly performed on the Group’s portfolio and as required for discrete projects and transactions.

The Group’s management of commodity price risk includes the use of commodity derivatives to hedge its exposure (refer to Note D.6). The hedged exposure includes oil-linked revenue related to produced volumes and revenues derived from trading operations. Commodity derivatives protect the Group against downside 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 $27 million (2023: $123 million net asset) exposed to commodity price risk. An increase in relevant commodity prices of 10% would decrease the instruments’ carrying value by $239 million, the effect of which would be recognised within reserves and/or the income statement in accordance with hedge accounting application. A 10% decrease would have the same but opposite effect. This analysis assumes that all other variables remain constant (including the price on underlying physical exposures).

Foreign exchange risk management

Foreign exchange risk arises from future commitments, 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 also hedged its Australian dollar to US dollar exchange rate exposure in relation to the Australian dollar denominated tax and dividend payments.

As at the reporting date, the Group held hedging foreign currency financial instruments with a net liability carrying value of $45 million (2023: net asset carrying value of $8 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 (+10%/-10% (2023: +12%/-12%)), with all other variables held constant, would not have a material impact on the Group’s equity or the income statement. Refer to Notes C1, C2, D2, D4 and D7 for details of the denominations of cash and cash equivalents, interest-bearing liabilities, receivables, payables and lease liabilities held at 31 December 2024.

F-13

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

A.1 Segment revenue and expenses

Operating segment information

The Group has identified its operating segments based on the internal reports that are reviewed and used by the Chief Executive Officer (Chief Operating Decision Maker) in assessing performance and determining the allocation of resources.

Operating segments outlined below are identified by management based on the nature and geographical location of the business and venture.

  Australia:   Exploration, evaluation, development, production and sale of liquefied natural gas, pipeline gas, crude oil and condensate and natural gas liquids in Australia.   International:   Exploration, evaluation, development, production and sale of pipeline gas, crude oil and condensate and natural gas liquids in international jurisdictions outside of Australia.   Marketing:   Marketing, shipping and trading of Woodside’s oil and gas portfolio (including purchased volumes) and optimisation activities attributed to Marketing which generate incremental value.   New Energy/Corporate items:   New energy/Corporate comprise Woodside’s new energy portfolio and corporate non-segmental items. Corporate non-segmental items of revenue and expenses and associated assets and liabilities are not allocated to operating segments as they are not considered part of the core operations of any segment.  

Customer concentration

The Group has two major customers which respectively account for 7% and 6% of the Group’s external revenue. The sales are generated by the Australia and Marketing operating segments (2023: two major customers; 8% and 7% generated by the Australia and Marketing operating segments and 2022: two major customers; 12% and 9% generated by the Australia and Marketing operating segments).

Geographical information

Geographical Information	Revenue from external customers1
	2024		2023		2022
	US$m		US$m		US$m
Asia Pacific		8,445		9,823		12,521
Americas		2,462		2,564		1,545
Europe		2,272		1,607		2,751
Consolidated		13,179		13,994		16,817

1. Revenue is attributable to geographic location based on the location of the customers.

Recognition and measurement

Revenue from contracts with customers

Revenue is recognised when or as the Group transfers control of products or provides services to a customer at the amount to which the Group expects to be entitled. If the consideration includes a variable component, the Group estimates the amount of the expected consideration receivable. Variable consideration is estimated throughout the contract and is recognised to the extent that it is highly probable a 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.

Expenses

· Royalties, excise and levies - Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group’s entitlement to physical production.

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

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

· Leases - Refer to Note D.7.

· Employee benefits - Refer to Note E.2.

F-14

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

Key estimates and judgements

(a) Revenue from contracts with customers

The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices.

Judgement is also used to determine if it is highly probable that a 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.

F-15

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

For the year ended 31 December 2024

	Australia		International		Marketing		New energy/ Corporate		Consolidated
	2024 US$m		2024 US$m		2024 US$m		2024 US$m		2024 US$m
Liquefied natural gas	5,361		-		1,040		-		6,401
Pipeline gas	1,119		230		-		-		1,349
Crude oil and condensate	1,668		3,143		76		-		4,887
Natural gas liquids	196		39		71		-		306
Revenue from sale of hydrocarbons	8,344		3,412		1,187		-		12,943
Intersegment revenue1	(23	)	(7	)	30		-		-
Processing and services revenue	220		-		-		-		220
Shipping and other revenue	-		-		16		-		16
Other revenue	197		(7	)	46		-		236
Operating revenue2	8,541		3,405		1,233		-		13,179
Production costs	(1,051	)	(528	)	-		-		(1,579	)
Royalties, excise and levies	(349	)	(23	)	-		-		(372	)
Insurance	(27	)	(9	)	-		11		(25	)
Inventory movement	55		29		-		-		84
Costs of production	(1,372	)	(531	)	-		11		(1,892	)
Property, plant and equipment depreciation and amortisation	(2,621	)	(1,848	)	-		(54	)	(4,523	)
Shipping and direct sales costs	(89	)	(86	)	(130	)	-		(305	)
Trading costs	(4	)	-		(691	)	-		(695	)
Other hydrocarbon costs	(51	)	-		-		-		(51	)
Other cost of sales	(22	)	(7	)	-		(6	)	(35	)
Movement in onerous contract provision	-		-		-		-		-
Other cost of sales	(166	)	(93	)	(821	)	(6	)	(1,086	)
Cost of sales	(4,159	)	(2,472	)	(821	)	(49	)	(7,501	)
Gross profit	4,382		933		412		(49	)	5,678
Other income3	568		50		23		(17	)	624
Exploration and evaluation expenditure4	(44	)	(276	)	-		-		(320	)
Amortisation of permit acquisition	-		(8	)	-		-		(8	)
Write-offs	(3	)	(6	)	-		-		(9	)
Exploration and evaluation	(47	)	(290	)	-		-		(337	)
General, administrative and other costs	-		-		-		(445	)	(445	)
Amortisation of intangible assets	-		-		-		(21	)	(21	)
Depreciation of lease assets	(58	)	(1	)	(101	)	(50	)	(210	)
Restoration movement	(176	)	6		-		(29	)	(199	)
Other5	(55	)	(97	)	93		(517	)	(576	)
Other costs	(289	)	(92	)	(8	)	(1,062	)	(1,451	)
Other expenses	(336	)	(382	)	(8	)	(1,062	)	(1,788	)
Impairment losses	-		-		-		-		-
Impairment reversals	-		-		-		-		-
Profit/(loss) before tax and net finance costs	4,614		601		427		(1,128	)	4,514

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.

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-16

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

For the year ended 31 December 2023

	Australia		International		Marketing		New energy/ Corporate		Consolidated
	2023 US$m		2023 US$m		2023 US$m		2023 US$m		2023 US$m
Liquefied natural gas	6,867		-		1,298		-		8,165
Pipeline gas	1,088		286		-		-		1,374
Crude oil and condensate	1,611		2,246		124		-		3,981
Natural gas liquids	218		32		31		-		281
Revenue from sale of hydrocarbons	9,784		2,564		1,453		-		13,801
Intersegment revenue1	(166	)	(15	)	181		-		-
Processing and services revenue	184		-		-		-		184
Shipping and other revenue	-		-		9		-		9
Other revenue	18		(15	)	190		-		193
Operating revenue2	9,802		2,549		1,643		-		13,994
Production costs	(1,173	)	(389	)	-		-		(1,562	)
Royalties, excise and levies	(462	)	(41	)	-		-		(503	)
Insurance	(41	)	(11	)	-		(8	)	(60	)
Inventory movement	(40	)	3		-		-		(37	)
Costs of production	(1,716	)	(438	)	-		(8	)	(2,162	)
Property, plant and equipment depreciation and amortisation	(2,754	)	(1,168	)	-		(34	)	(3,956	)
Shipping and direct sales costs	(164	)	(83	)	(54	)	(18	)	(319	)
Trading costs	(12	)	-		(1,056	)	-		(1,068	)
Other hydrocarbon costs	(7	)	-		-		-		(7	)
Other cost of sales	(7	)	-		-		-		(7	)
Movement in onerous contract provision	-		-		-		-		-
Other cost of sales	(190	)	(83	)	(1,110	)	(18	)	(1,401	)
Cost of sales	(4,660	)	(1,689	)	(1,110	)	(60	)	(7,519	)
Gross profit	5,142		860		533		(60	)	6,475
Other income3	160		54		26		82		322
Exploration and evaluation expenditure4	(24	)	(253	)	-		(2	)	(279	)
Amortisation of permit acquisition	-		(4	)	-		-		(4	)
Write-offs	(31	)	(46	)	-		-		(77	)
Exploration and evaluation	(55	)	(303	)	-		(2	)	(360	)
General, administrative and other costs	-		-		-		(453	)	(453	)
Amortisation of intangible assets	-		-		-		(2	)	(2	)
Depreciation of lease assets	(50	)	(14	)	(75	)	(40	)	(179	)
Restoration movement	(125	)	(22	)	-		-		(147	)
Other5	(51	)	-		(109	)	(272	)	(432	)
Other costs	(226	)	(36	)	(184	)	(767	)	(1,213	)
Other expenses	(281	)	(339	)	(184	)	(769	)	(1,573	)
Impairment losses6	(534	)	(1,383	)	-		-		(1,917	)
Impairment reversals	-		-		-		-		-
Profit/(loss) before tax and net finance costs	4,487		(808	)	375		(747	)	3,307

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.

5. Includes losses on hedging activities, a $35 million fair value loss on embedded derivatives and other expenses not associated with the ongoing operations of the business.

6. Impairment on property, plant and equipment and goodwill. Refer to Note B.4 for more details.

F-17

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

For the year ended 31 December 2022

	Australia			International			Marketing			New energy/ Corporate			Consolidated
	2022 US$m			2022 US$m			2022 US$m			2022 US$m			2022 US$m
Liquefied natural gas		8,855			-			2,434			-			11,289
Pipeline gas		1,086			276			-			-			1,362
Crude oil and condensate		2,467			1,273			18			-			3,758
Natural gas liquids		171			26			9			-			206
Revenue from sale of hydrocarbons		12,579			1,575			2,461			-			16,615
Intersegment revenue1		(455)			(5)			460			-			-
Processing and services revenue		175			-			-			-			175
Shipping and other revenue		-			-			27			-			27
Other revenue		(280)			(5)			487			-			202
Operating revenue2		12,299			1,570			2,948			-			16,817
Production costs		(975)			(313)			-			7			(1,281)
Royalties, excise and levies		(540)			(39)			-			(17)			(596)
Insurance		(35)			(7)			-			(1)			(43)
Inventory movement		44			(3)			-			-			41
Costs of production		(1,506)			(362)			-			(11)			(1,879)
Property, plant and equipment depreciation and amortisation		(2,326	)		(439	)		-			(33	)		(2,798	)
Shipping and direct sales costs		(312	)		(36	)		(73	)		142			(279	)
Trading costs		(14	)		-			(1,763	)		-			(1,777	)
Other hydrocarbon costs		(19	)		-			-			-			(19	)
Other cost of sales		(4	)		-			-			-			(4	)
Movement in onerous contract provision3		-			-			216			-			216
Other cost of sales		(349	)		(36	)		(1,620	)		142			(1,863	)
Cost of sales		(4,181	)		(837	)		(1,620	)		98			(6,540	)
Gross profit		8,118			733			1,328			98			10,277
Other income4		722			4			5			4			735
Exploration and evaluation expenditure5		(20	)		(277	)		-			1			(296	)
Amortisation of permit acquisition		(1	)		(9	)		-			-			(10	)
Write-offs6		-			(164	)		-			-			(164	)
Exploration and evaluation		(21	)		(450	)		-			1			(470	)
General, administrative and other costs7		(13	)		(21	)		(10	)		(747	)		(791	)
Depreciation of lease assets		(49	)		(11	)		-			(80	)		(140	)
Restoration movement		(234	)		(46	)		-			8			(272	)
Other8		(8	)		(84	)		(475	)		(486	)		(1,053	)
Other costs		(304	)		(162	)		(485	)		(1,305	)		(2,256	)
Other expenses		(325	)		(612	)		(485	)		(1,304	)		(2,726	)
Impairment losses		-			-			-			-			-
Impairment reversals9		900			-			-			-			900
Profit/(loss) before tax and net finance costs		9,415			125			848			(1,202	)		9,186

1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment’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 $16,790 million and sub-lease income of $27 million disclosed within shipping and other revenue.

3. Comprises changes in estimates of $245 million offset by provisions used of $29 million.

4. Includes initial gain on Train 2 sell-down of $427 million, revaluation gain on the remeasurement of the Train 2 sell-down variable consideration of $71 million, fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business.

5. Includes $142 million for various costs relating to the Group’s exit from the Orphan Basin exploration licences in Canada.

6. $125 million relates to costs of unsuccessful wells that have been written off.

7. Transaction costs of $419 million incurred as a result of the BHPP merger on 1 June 2022 are included in the New energy/Corporate segment.

8. Includes losses on hedging activities and changes in fair value of derivative financial instruments of $960 million in the Marketing and New energy/Corporate segments and other expenses not associated with the ongoing operations of the business.

9. Impairment reversals on property, plant and equipment.

F-18

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

A.2 Finance costs

	2024 US$m		2023 US$m		2022 US$m
Interest on interest-bearing liabilities		350		229		212
Interest on lease liabilities		102		102		103
Accretion charge		293		238		110
Other finance costs		30		49		36
Less: Finance costs capitalised against qualifying assets		(410)		(311)		(294)
		365		307		167

A.3 Dividends paid and proposed

Woodside Energy Group Ltd, the parent entity, paid and proposed dividends set out below:

	2024 US$m		2023 US$m		2022 US$m
(a) Dividends paid during the financial year
Prior year fully franked final dividend1		1,139		2,734		1,018
Current year fully franked interim dividend2		1,310		1,519		2,070
		2,449		4,253		3,088
(b) Dividend declared subsequent to the reporting period (not recorded as a liability)
Final dividend3		1,006		1,139		2,734
(c) Other information
Current year dividends per share (US cents)		122		140		253

1. 2024: US$0.60, paid on 4 April 2024

2023: US$1.44, paid on 5 April 2023

2022: US$1.05, paid on 23 March 2022

2. 2024: US$0.69, paid on 3 October 2024

2023: US$0.80, paid on 28 September 2023

2022: US$1.09, paid on 6 October 2022

3. 2024: US$0.53, to be paid on 2 April 2025 

2023: US$0.60, paid on 4 April 2024

2022: US$1.44, paid on 5 April 2023

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

	2024		2023		2022
Profit attributable to equity holders of the parent (US$m)		3,573		1,660		6,498
Weighted average number of shares on issue for basic earnings per share		1,895,703,924		1,896,498,169		1,511,257,404
Effect of dilution from contingently issuable shares		16,221,362		14,444,802		13,061,376
Weighted average number of shares on issue adjusted for the effect of dilution		1,911,925,286		1,910,942,971		1,524,318,780
Basic earnings per share (US cents)		188.5		87.5		430.0
Diluted earnings per share (US cents)		186.9		86.9		426.3

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

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

A.5 Taxes

	2024 US$m		2023 US$m		2022 US$m
(a) Tax expense comprises
Petroleum resource rent tax (PRRT)
Current tax expense	396		367		501
Deferred tax (benefit)/expense	(487	)	531		(814	)
PRRT (benefit)/expense	(91	)	898		(313	)
Income tax
Current year
Current tax expense	1,420		1,872		2,256
Deferred tax (benefit)/expense	(484	)	(1,255	)	701
Adjustment to prior years
Current tax (benefit)/expense	(177	)	14		(276	)
Deferred tax expense	55		22		231
Income tax expense	814		653		2,912
Tax expense	723		1,551		2,599

	2024     US$m		2023     US$m		2022     US$m
(b) Reconciliation of income tax expense
Profit before tax	4,369		3,273		9,174
PRRT benefit/(expense)	91		(898	)	313
Profit before income tax	4,460		2,375		9,487
Income tax expense calculated at 30%	1,338		712		2,847
Effect of tax rate differentials	(75	)	91		(141	)
Effect of deferred tax assets not recognised	76		155		150
Effect of tax losses and credits previously unrecognised	(442	)	(332	)	-
Effect of goodwill impairment	-		109		-
Reduction in deferred tax liability due to held for sale basis	(94	)	(78	)	-
Foreign exchange impact on tax expense/(benefit)	87		(58	)	(44	)
Adjustment to prior years	(122	)	36		(45	)
Integration and transaction costs non-deductible	-		4		142
Other	46		14		3
Income tax expense1	814		653		2,912

	2024     US$m		2023     US$m		2022     US$m
(c) Reconciliation of PRRT expense
Profit before tax	4,369		3,273		9,174
Non-PRRT assessable profit	(2,631	)	(1,780	)	(6,197	)
PRRT projects profit before tax	1,738		1,493		2,977
PRRT expense calculated at 40%	695		598		1,191
(Recognition)/derecognition of Pluto general expenditure2	(502	)	611		(1,362	)
Recognition of transferred exploration spend	-		(18	)	-
Augmentation	(266	)	(292	)	(175	)
Other	(18	)	(1	)	33
PRRT (benefit)/expense	(91	)	898		(313	)

	2024     US$m		2023     US$m		2022     US$m
(d) Deferred tax income statement reconciliation
PRRT
Production and growth assets	(304	)	1,206		(710	)
Augmentation for current year	(266	)	(292	)	(175	)
Provisions	35		(372	)	(12	)
Other	48		(11	)	83
PRRT (benefit)/expense	(487	)	531		(814	)
Income tax
Property, plant and equipment	(660	)	(529	)	292
Exploration and evaluation assets	35		38		14
Lease assets and liabilities	6		(20	)	25
Provisions	62		(232	)	151
PRRT assets and liabilities	251		(175	)	236
Unused tax losses and tax credits	2		(221	)	19
Assets held for sale	(36	)	(86	)	205
Intangible assets	6		-		-
Derivatives	(109	)	(21	)	21
Other	14		13		(31	)
Income tax deferred tax (benefit)/expense	(429	)	(1,233	)	932
Deferred tax (benefit)/expense	(916	)	(702	)	118

	2024     US$m		2023     US$m	2022      US$m
(e) Deferred tax other comprehensive income reconciliation
Income tax
Derivatives	34		77	(64	)
Other	(8	)	7	(2	)
Deferred income tax expense/(benefit) via other comprehensive income	26		84	(66	)

1. The global operations effective income tax rate (EITR) of 18.3% (2023: 27.5%, 2022: 30.7%) is calculated as the Group’s income tax expense divided by profit before income tax. The Australian operations EITR of 26.9% (2023: 30.2%, 2022: 30.0%) is calculated with reference to all Australian companies and excludes foreign exchange on settlement and revaluation of income tax liabilities. The reduction in the 2024 EITR compared to 2023 is predominantly due to a number of one-off transactions, including the recognition of a net deferred tax asset of $342 million on Sangomar subsequent to the project achieving first oil and the recognition of a tax benefit of $94 million related to Woodside’s sale of 15.1% share in the Scarborough project. The EITR would increase to 28.8% for global operations when excluding these one-off transactions, foreign exchange on income tax liabilities and income tax adjustments related to prior periods. The Australian operations EITR would increase to 31.7% when excluding the tax benefit arising from the sale of Woodside’s 15.1% share in the Scarborough project and income tax adjustments related to prior periods.

2. 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 available to utilise the expenditure. In 2023, $637 million of the Pluto PRRT deferred tax asset was derecognised on the basis that it would not be recoverable.

F-20

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

	2024    US$m		2023    US$m
(f) Deferred tax balance sheet reconciliation
Deferred tax assets
PRRT
Production and growth assets		784		455
Augmentation for current year		264		231
Provisions		470		445
Other		(70)		(30)
PRRT deferred tax assets		1,448		1,101
Income tax
Property, plant and equipment		(1,291)		(1,388)
Exploration and evaluation assets		51		60
Lease assets and liabilities		58		40
Unused tax losses and tax credits		1,684		1,686
Derivatives		11		-
Provisions		412		227
Other		20		(9)
Income tax deferred tax assets		945		616
Deferred tax assets		2,393		1,717
Deferred tax liabilities
PRRT
Production and growth assets		990		1,309
Augmentation for current year		(2)		(38)
Provisions		(935)		(995)
Other		121		113
PRRT deferred tax liabilities		174		389
Income tax
Property, plant and equipment		2,386		2,939
Exploration and evaluation assets		153		127
Lease assets and liabilities		(24)		(48)
Provisions		(1,615)		(1,856)
PRRT assets and liabilities		369		118
Assets held for sale		-		36
Intangible assets		160		-
Derivatives		(67)		(2)
Other		(39)		(76)
Income tax deferred tax liabilities		1,323		1,238
Deferred tax liabilities		1,497		1,627

Tax transparency code

Woodside participates in the Australian Board of Taxation’s voluntary Tax Transparency Code (TTC). To increase public confidence in the contributions and compliance of corporate taxpayers, the TTC recommends public disclosure of tax information. Part A of the recommended disclosures is addressed within this Taxes note and Part B disclosed within the Sustainability section on our website.

Recognition and measurement

Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset is realised. The tax rates and laws used to determine the amount are based on those that have been enacted or substantively enacted by the end of the reporting period. Income taxes relating to items recognised directly in equity are recognised in equity.

Current taxes

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

Deferred taxes

Deferred tax expense represents movements in the temporary differences between the carrying amount of an asset or liability in the consolidated statement of financial position and its tax base.

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

Deferred tax assets are recognised for deductible temporary differences, unused tax losses and tax credits only if it is probable that sufficient future taxable income will be available to utilise those temporary differences and losses.

F-21

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

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.

PRRT deductions cap

In May 2024, the Parliament of Australia enacted the Treasury Laws Amendment (Tax Accountability and Fairness) Act 2024 for the PRRT deductions cap which takes effect from 1 July 2023. If an entity is an LNG producer and its petroleum projects meet the criteria of the deduction cap, the entity will have a taxable profit of 10% of the projects’ assessable receipts in the year of tax.

The new legislation has impacted the Pluto and Wheatstone projects resulting in the Group making payments of $163 million and recognising a further $27 million as a current tax payable as at 31 December 2024.

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 estimated that the Pillar Two effective tax rates exceed 15% or satisfies transitional safe harbour measures in all jurisdictions in which it operates. On this basis, the Group has not recognised any Pillar Two tax expense for the year ended 31 December 2024.

F-22

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2024

Key estimates and judgements

(a) Income tax classification

Judgement is required when determining whether a particular tax is an income tax or another type of tax. PRRT is considered, for accounting purposes, to be an income tax. Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes, e.g. North West Shelf royalties, excise and levies which are recognised in cost of sales in the income statement.

(b) Deferred tax asset recognition

Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from the USA Tax Consolidation Group (USA TCG) of $1,274 million (2023: $1,248 million) and $410 million (2023: $333 million) arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a) for details of tax consolidated groups.

DTAs relating to carry forward unused tax losses and credits of $366 million (2023: $232 million) from the USA TCG, $343 million (2023: $189 million) from USA entities outside of the USA TCG and $715 million (2023: $763 million) from countries other than Australia and the USA have not been recognised as it is not currently probable that the losses and credits will be utilised based on current planned activities in those countries.

Subsequent to achieving first oil on the Sangomar project in June 2024, the Group has recognised a net deferred tax asset of $342 million. In the prior year, as a result of the final investment decision to develop the Trion resource, the Group recognised deferred tax assets of $319 million.

PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable profits. During the year ended 31 December 2024, the Group increased the Pluto PRRT DTA by $502 million ($351 million post-tax) on the basis of future taxable profits being available to utilise the deductible expenditure. This is primarily driven by increases in forecast pricing assumptions and actual pricing realised during the year ended 31 December 2024. 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 3.2% (31 December 2023: 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. $7,490 million (2023: $7,428 million) relates to the North West Shelf Project, $601 million (2023: $872 million) relates to remaining Pluto deductible balances and $795 million (2023: $758 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2023: 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-23

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

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 key estimates and judgements applied. This section also includes the impairment position of the Group at the end of the reporting period.

B.	Production and growth assets
B.1	Segment production and growth assets	Page F-25
B.2	Exploration and evaluation	Page F-27
B.3	Property, plant and equipment	Page F-29
B.4	Impairment of exploration and evaluation, property, plant and equipment and goodwill	Page F-30
B.5	Business combination	Page F-37
B.6	Intangible assets	Page F-38
B.7	Significant production and growth asset acquisitions	Page F-39
B.8	Disposal of assets	Page F-40

F-24

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

B.1 Segment production and growth assets

As at 31 December 2024

	Australia 2024 US$m			International 2024 US$m			Marketing 2024 US$m		New Energy/ Corporate 2024 US$m			Consolidated 2024 US$m
Balance as at 31 December
Asia Pacific		571			-			-		-			571
Americas		-			149			-		-			149
Africa		-			1			-		-			1
Total exploration and evaluation		571			150			-		-			721
Balance as at 31 December
Land and buildings		615			57			-		62			734
Oil and gas properties1		14,320			11,467			-		-			25,787
Projects in development		9,556			4,838			-		1,532			15,926
Other plant and equipment1		-			-			-		189			189
Total property, plant and equipment		24,491			16,362			-		1,783			42,636
Balance as at 31 December
Goodwill		2,887			810			-		169			3,866
Contract assets2		-			-			-		757			757
Software2		-			-			-		203			203
Total intangible assets		2,887			810			-		1,129			4,826
Balance as at 31 December
Land and buildings		102			254			-		247			603
Oil and gas properties3		16			1			-		-			17
Other plant and equipment3		123			-			547		1			671
Total lease assets		241			255			547		248			1,291
Additions to exploration and evaluation:
Exploration		-			22			-		-			22
Evaluation		17			60			-		-			77
Restoration4		-			-			-		-			-
		17			82			-		-			99
Additions to property, plant and equipment:
Acquisitions through business combination and asset acquisitions5		-			1,367			-		936			2,303
Property, plant and equipment		2,794			1,828			-		381			5,003
Capitalised borrowings costs6		278			120			-		12			410
Restoration4		(137	)		(54	)		-		(1	)		(192	)
		2,935			3,261			-		1,328			7,524
Additions to intangible assets:
Acquisitions through business combination and asset acquisitions5		-			-			-		941			941
Contract assets2		-			-			-		1			1
Software2		-			-			-		39			39
		-			-			-		981			981
Additions to lease assets:
Acquisitions through asset acquisitions5		-			172			-		-			172
Land and buildings		15			-			-		22			37
Oil and gas properties3		-			-			-		-			-
Other plant and equipment3		-			-			111		-			111
		15			172			111		22			320

1. Transferred exploration and evaluation and plant and equipment, which were categories in 2023, have been reviewed and presented in new categories in 2024. Transferred exploration and evaluation and operational plant and equipment have been combined and presented as ‘oil and gas properties’. All remaining plant and equipment have been presented as ‘other plant and equipment’. The 2023 amounts have been reclassified to be presented on the same basis.

2. Intangible assets include software and contract assets which were previously presented within other assets (non-current). The 2023 amounts have been reclassified to be presented on the same basis.

3. Plant and equipment, which was a category in 2023, has been reviewed and presented as ‘oil and gas properties’ and ‘other plant and equipment’ in 2024. The 2023 amounts have been reclassified to be presented on the same basis.

4. Relates to changes in restoration provision assumptions.

5. Refer to Note B.5 for details on business combination and Note B.7 for details on asset acquisitions.

6. Borrowing costs capitalised were at a weighted average interest rate of 4.4%.

Refer to Note A.1 for descriptions of the Group’s segments and geographical regions.

F-25

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

As at 31 December 2023

	Australia 2023 US$m		International 2023 US$m		Marketing 2023 US$m		New Energy/ Corporate 2023 US$m		Consolidated 2023 US$m
Balance as at 31 December
Asia Pacific		568		-		-		-		568
Americas		-		76		-		-		76
Africa		-		24		-		-		24
Total exploration and evaluation		568		100		-		-		668
Balance as at 31 December
Land and buildings		669		32		-		-		701
Oil and gas properties1		16,858		7,310		-		-		24,168
Projects in development		7,825		7,655		-		244		15,724
Other plant and equipment1		-		-		-		198		198
Total property, plant and equipment		25,352		14,997		-		442		40,791
Balance as at 31 December
Goodwill		3,185		810		-		-		3,995
Contract assets2		-		-		-		15		15
Software2		-		-		-		173		173
Total intangible assets		3,185		810		-		188		4,183
Balance as at 31 December
Land and buildings		94		92		-		244		430
Oil and gas properties3		52		55		-		-		107
Other plant and equipment3		144		2		539		8		693
Total lease assets		290		149		539		252		1,230
Additions to exploration and evaluation:
Exploration		29		59		-		-		88
Evaluation		55		108		-		-		163
Restoration4		(5)		-		-		-		(5)
		79		167		-		-		246
Additions to property, plant and equipment:
Property, plant and equipment		3,127		2,000		-		190		5,317
Capitalised borrowing costs5		188		123		-		-		311
Restoration4		779		188		-		-		967
		4,094		2,311		-		190		6,595
Additions to intangible assets:
Adjustment to BHPP merger purchase price allocation		33		22		-		-		55
Contract assets2		-		-		-		16		16
Software2		-		-		-		118		118
		33		22		-		134		189
Additions to lease assets:
Land and buildings		-		-		-		8		8
Oil and gas properties3		-		-		-		-		-
Other plant and equipment3		6		-		114		-		120
		6		-		114		8		128

1. Transferred exploration and evaluation and plant and equipment, which were categories in 2023, have been reviewed and presented in new categories in 2024. Transferred exploration and evaluation and operational plant and equipment have been combined and presented as ‘oil and gas properties’. All remaining plant and equipment have been presented as ‘other plant and equipment’. The 2023 amounts have been reclassified to be presented on the same basis.

2. Intangible assets include software and contract assets which were previously presented within other assets (non-current). The 2023 amounts have been reclassified to be presented on the same basis.

3. Plant and equipment, which was a category in 2023, has been reviewed and presented as “oil and gas properties” and “other plant and equipment” in 2024. The 2023 amounts have been reclassified to be presented on the same basis.

4. Relates to changes in restoration provision assumptions.

5. Borrowing costs capitalised were at a weighted average interest rate of 4.0%.

F-26

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

B.2 Exploration and evaluation

	Asia Pacific US$m			Americas US$m			Africa US$m			Total US$m
Year ended 31 December 2024
Carrying amount at 1 January 2024		568			76			24			668
Additions		17			81			1			99
Amortisation of licence acquisition costs		-			(8	)		-			(8	)
Expensed		(3	)		-			(6	)		(9	)
Transferred exploration and evaluation		(11	)		-			(18	)		(29	)
Carrying amount at 31 December 2024		571			149			1			721
Year ended 31 December 2023
Carrying amount at 1 January 2023		529			240			38			807
Additions		79			161			6			246
Amortisation of licence acquisition costs		-			(2)			(2)			(4)
Expensed		(31)			(28)			(18)			(77)
Transferred exploration and evaluation1		(9)			(295)			-			(304)
Carrying amount at 31 December 2023		568			76			24			668
Exploration commitments
Year ended 31 December 2024		4			-			10			14
Year ended 31 December 2023		3			1			35			39

1. On 20 June 2023, the Group made a final investment decision to develop the Trion resource in Mexico. Related exploration and evaluation assets of $274 million were transferred to property, plant and equipment. 

Recognition and measurement

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

Areas of interest are based on a geographical area for which the rights of tenure are current. All exploration and evaluation expenditure, including general permit activity, geological and geophysical costs and new venture activity costs, is expensed as incurred except for the following:

· where the expenditure relates to an exploration discovery for which the assessment of the existence or otherwise of economically recoverable hydrocarbons is not yet complete; or

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

The costs of acquiring interests in new exploration and evaluation licences are capitalised. The costs of drilling exploration wells are initially capitalised pending the results of the well.

Costs are expensed where the well does not result in the successful discovery of economically recoverable hydrocarbons and the recognition of an area of interest.

Subsequent to the recognition of an area of interest, all further evaluation costs relating to that area of interest are capitalised. Upon approval for the commercial development of an area of interest, accumulated expenditure for the area of interest is transferred to projects in development within property, plant and equipment.

In the consolidated statement of cash flows, those cash flows associated with capitalised exploration and evaluation expenditure, including unsuccessful wells, are classified as cash flows used in investing activities.

Exploration commitments

The Group has exploration expenditure obligations which are contracted for, but not provided for in the financial statements. These obligations may be varied from time to time and are expected to be fulfilled in the normal course of the Group’s operations.

Impairment

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

F-27

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

Key estimates and judgements

(a) Area of interest

Typically, an area of interest (AOI) is defined by the Group as an individual geographical area whereby the presence of hydrocarbons is considered favourable or proved to exist. The Group has established criteria to recognise and maintain an AOI.

(b) Transfer to projects in development

Development activities commence after project sanctioning by the appropriate level of management. Judgement is applied by management in determining when the project is technically feasible and economically viable to transfer to projects in development.

F-28

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

B.3 Property, plant and equipment

	Land and buildings		Oil and gas properties1		Projects in development2		Other plant and equipment1		Total
	US$m		US$m		US$m		US$m		US$m
Year ended 31 December 2024
Carrying amount at 1 January 2024	701		24,168		15,724		198		40,791
Acquisitions through business combination and asset acquisitions3	92		-		2,211		-		2,303
Additions4	-		(293	)	5,514		-		5,221
Disposals at written down value5	(3	)	(4	)	(1,178	)	-		(1,185	)
Depreciation and amortisation	(56	)	(4,419	)	-		(48	)	(4,523	)
Completions and transfers6	-		6,335		(6,345	)	39		29
Carrying amount at 31 December 2024	734		25,787		15,926		189		42,636
At 31 December 2024
Historical cost	1,830		58,303		16,300		533		76,966
Accumulated depreciation and impairment	(1,096	)	(32,516	)	(374	)	(344	)	(34,330	)
Net carrying amount	734		25,787		15,926		189		42,636
Year ended 31 December 2023
Carrying amount at 1 January 2023	840		23,377		15,541		161		39,919
Additions	-		836		5,759		-		6,595
Disposals at written down value	(8)		(2)		-		-		(10)
Depreciation and amortisation	(67)		(3,844)		-		(45)		(3,956)
Impairment losses7	(64)		(1,048)		(328)		-		(1,440)
Completions and transfers	-		4,855		(4,633)		82		304
Transfer to assets held for sale	-		(6)		(615)		-		(621)
Carrying amount at 31 December 2023	701		24,168		15,724		198		40,791
At 31 December 2023
Historical cost	1,745		51,755		16,443		496		70,439
Accumulated depreciation and impairment	(1,044)		(27,587)		(719)		(298)		(29,648)
Net carrying amount	701		24,168		15,724		198		40,791

This note was previously presented as Oil and Gas Properties and has been renamed to Property, Plant and Equipment.

1. Transferred exploration and evaluation and plant and equipment, which were categories in 2023, have been reviewed and presented in new categories in 2024. Transferred exploration and evaluation and operational plant and equipment have been combined and presented as ‘oil and gas properties’. All remaining plant and equipment have been presented as ‘other plant and equipment’. The 2023 amounts have been reclassified to be presented on the same basis.

2. $1,407 million of the carrying amount as at 31 December 2024 in projects in development relates to new energy assets.

3. Refer to Note B.5 for details on business combination and Note B.7 for details on asset acquisitions. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.

4. Includes $5,003 million of capital additions and $410 million of capitalised borrowing costs offset by $192 million following changes in restoration provision.

5. Refer to Note B.8 for details on disposal of assets.

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.

7. Refer to Note B.4 for details on impairment.

Recognition and measurement

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

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

· Projects in development for oil and gas assets include the costs to acquire, construct, install or complete production and infrastructure facilities such as pipelines and platforms, capitalised borrowing costs, transferred exploration and evaluation assets, development wells and the estimated cost of dismantling and restoration.

· Projects in development for new energy assets include the costs to acquire, construct, install or complete infrastructure facilities, capitalised borrowing costs and the estimated cost of dismantling and restoration.

When commercial production commences, the accumulated costs in projects in development will be transferred to oil and gas properties or new energy assets.

Subsequent capital costs, including major maintenance, are included in the asset’s carrying amount only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be reliably measured.

Depreciation and amortisation

Property, plant and equipment are depreciated to their estimated residual values at rates based on their expected useful lives.

Upstream oil and conventional gas assets have been 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.

F-29

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

Impairment

Refer to Note B.4 for details on impairment.

Capital commitments

The Group has capital expenditure commitments contracted for, but not provided for in the financial statements, of $3,841 million as at 31 December 2024 (2023: $4,245 million). Capital expenditure commitments relate predominantly to the Scarborough, Trion and Louisiana LNG projects (2023: Scarborough and Sangomar projects).

Key estimates and judgements

(a) Reserves

The estimation of reserves requires significant management judgement and interpretation of complex geological and geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs, and their anticipated recoveries.

Estimates of oil and natural gas reserves are used to calculate depreciation and amortisation charges for the Group’s oil and gas properties. Judgement is used in determining the economic reserve base applied to each asset.

Estimates are reviewed at least annually or when there are changes in the economic circumstances impacting specific assets or asset groups. These changes may impact depreciation, asset carrying values, restoration provisions and deferred tax balances. If reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the asset’s carrying value.

(b) Depreciation and amortisation

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

B.4 Impairment of exploration and evaluation, property, plant and equipment and goodwill

Exploration and evaluation

Impairment testing

The recoverability of the carrying amount of exploration and evaluation assets is dependent on successful development and commercial exploitation, or alternatively sale of the respective AOI.

Each AOI is reviewed half-yearly to determine whether economic quantities of hydrocarbons have been found, or whether further exploration and evaluation work is underway or planned to support continued carry forward of capitalised costs. Where a potential impairment is indicated for an AOI, an assessment is performed using a fair value less costs to dispose (FVLCD) method to determine its recoverable amount. Upon approval for commercial development, exploration and evaluation assets are assessed for impairment before they are transferred to 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.

F-30

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

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 these 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 has previously been impaired, the impairment is reversed. The carrying amount of the asset or CGU is increased to its recoverable amount, but only to the extent that the carrying amount does not exceed the value that would have been determined, net of depreciation or amortisation, if no impairment had been recognised. Impairments of goodwill are not reversed.

For the year ended 31 December 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 are as follows:

Segment	CGU	Goodwill carrying amount	Excess of recoverable amount over CGU carrying amount1
		US$m	US$m
Australia	Pluto-Scarborough2	2,445	4,514
Australia	NWS Gas	442	1,612
International	Atlantis	522	98
New energy/Corporate	Beaumont New Ammonia3	169	-
International	Other goodwill	288	879
Total		3,866

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 (refer to Note B.8).

3. Represents goodwill acquired through business combination. Refer to Note B.5 for further details.

Other goodwill of $288 million (2023: $288 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.

F-31

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

Impairment and impairment reversals

No 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 key estimates and judgements for further details.

Sensitivity analysis for CGUs with goodwill

Recoverable amount valuations are sensitive to changes in certain key accounting estimates and judgements (refer to key estimates and judgements for further details). Reasonably possible changes to these key assumptions are set out below:

· Post-tax discount rate – plus or minus 1% (representing a change of 100 basis points)

· Commodity pricing – plus or minus 10%

· Foreign exchange (FX) rate – plus or minus 10%

· Production volumes – plus or minus 4%

F-32

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

The valuations of CGUs with goodwill are most sensitive to changes in commodity prices and discount rates. Reasonably possible changes in these estimates which could result in the estimated recoverable amount being equal to the carrying amount, assuming all other variables are held constant, are as follows:

CGU	Decrease in commodity price1			Increase in post-tax discount rate
	% change			(absolute terms)
Pluto-Scarborough		N/A	2		N/A	2
NWS Gas		N/A	2		N/A	2
Atlantis		(1.5%)			0.5%

1. Brent price applies to Pluto-Scarborough and NWS Gas. WTI price (Brent - $4/bbl) applies to Atlantis.

2. Management considers there to be no reasonably possible change in the respective estimate which, in isolation, would result in the estimated recoverable amount being equal to the carrying amount.

A change in any of the above assumptions would have an impact on other assumptions which when considered together may offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions. Management considers there to be no reasonably possible changes in production volumes or foreign exchange rates that would, in isolation, result in the estimated recoverable amount being equal to the carrying amount. Analysis of key assumptions which could result in the carrying value to equal the recoverable value provides a basis to assess the magnitude of a reasonably possible change to the carrying amounts of respective CGUs.

For the year ended 31 December 2023

Goodwill allocation

The Group performed its annual goodwill impairment test as at 31 December 2023.

The carrying amount of goodwill allocated to each CGU, or groups of CGUs, and excess recoverable amounts are as follows:

Segment	CGU	Goodwill carrying amount	Excess of recoverable amount over CGU carrying amount1
		US$m	US$m
Australia	Pluto-Scarborough2	2,743	3,051
Australia	NWS Gas	442	784
International	Atlantis	522	338
International	Other goodwill	288	1,176
		3,995

1. Amounts are with reference to the total CGU value including goodwill.

2. A portion of the goodwill allocated to Pluto-Scarborough was transferred to assets held for sale (refer to Note B.8).

Other goodwill of $288 million (2022: $283 million) has been allocated across a number of CGUs within the International segment. This represents less than 1% of net assets as at 31 December 2023.

Recognised impairment and impairment reversals

As at 31 December 2023, the Group assessed each AOI and CGU to determine whether an indicator of impairment or impairment reversal existed. The Group identified the following indicators of impairment on CGUs where an impairment loss has been recognised:

CGU	Description	Indicator of impairment
Pyrenees	Oil asset consisting of a floating production storage and offloading (FPSO) facility off the north-west coast of Western Australia.	Reduction in future production volumes, reflecting a lower-than-expected outcome of drilling activities.
Shenzi	Conventional oil and gas field developed through a tension leg platform (TLP) located in the United States.	Reduction in future production volumes, reflecting lower-than-expected performance of infill sidetracks and performance of the Shenzi North development following start-up.
Wheatstone	LNG processing facility in Western Australia, comprising an offshore production platform and two onshore LNG processing trains, a domestic gas plant and associated infrastructure.	Updated short-term price assumptions (in particular the Japan/Korea Marker (JKM)).

F-33

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

An impairment was recognised in the profit and loss, refer to Note A.1. The results were as follows:

					Impairment loss
					Intangible assets		Property, plant and equipment
Segment	CGU	Recoverable amount US$m		Goodwill US$m		Land and buildings US$m		Oil and gas properties1 US$m		Projects in development US$m		Other plant and equipment1 US$m		Total US$m
Australia	Pyrenees		159		-		-		68		-		-		68
Australia	Wheatstone		2,418		-		64		391		11		-		466
International	Shenzi		1,862		477		-		589		317		-		1,383

1. Transferred exploration and evaluation and plant and equipment, which were categories in 2023, have been reviewed and presented in new categories in 2024. Transferred exploration and evaluation and operational plant and equipment have been combined and presented as ‘oil and gas properties’. All remaining plant and equipment have been presented as ‘other plant and equipment’. The 2023 amounts have been reclassified to be presented on the same basis.

For CGUs where goodwill has been allocated, with the exception of Shenzi, no impairment was recognised as the recoverable amount exceeds the carrying amount of the CGU.

Recoverable amounts have been determined using the FVLCD method using discounted cash 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 key estimates and judgements for further details.

Sensitivity analysis

Recoverable amount valuations are sensitive to changes in certain key accounting estimates and judgements (refer to key estimates and judgements for further details). Reasonably possible changes to these key assumptions are set out below:

· Post-tax discount rate – plus or minus 1% (representing a change of 100 basis points)

· Commodity pricing – plus or minus 10%

· Foreign exchange (FX) rate – plus or minus 12%

· Production volumes – plus or minus 4%

Management’s analysis on the impact of reasonably possible changes to these assumptions on recoverable amounts is detailed below.

CGUs with impairment or impairment reversals

Changes in the following key assumptions have been estimated to result in a higher or lower carrying amount1 than what was determined as at 31 December 2023:

Sensitivity (US$m)2
CGU	Discount rate increase3			Discount rate decrease3		Commodity price increase3		Commodity price decrease3			FX increase3			FX decrease3		Production increase3		Production decrease3
Shenzi		(67	)		71		359		(359	)		N/A			N/A		47		(46	)
Wheatstone		(88	)		94		431		(370	)		(36	)		87		90		(42	)

1. Increases to carrying amounts are limited to historical impairment losses recognised, net of depreciation and amortisation, that would have been recognised had no impairment taken place.

2. The sensitivities represent the reasonably possible changes to discount rate, commodity price, FX and production volumes assumptions.

3. The relationship between the discount rate, commodity price, FX and production and the carrying amount is non-linear in certain circumstances which may include fixed costs impacts as well as economic cut-off modelling. As such, sensitivities are unlikely to result in a symmetrical impact and should not be interpreted in isolation.

A change in any of the above assumptions would likely have an impact on other assumptions which, when considered together, may offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions.

F-34

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

CGUs with goodwill

The valuation of CGUs with goodwill are most sensitive to changes in commodity prices and discount rates. Reasonably possible changes in these estimates which could result in the estimated recoverable amount being equal to the carrying amount, assuming all other variables are held constant, are as follows:

CGU	Decrease in commodity price1			Post-tax discount rate
	% change			(absolute terms)
Pluto-Scarborough		N/A	2		N/A	2
NWS Gas		N/A	2		N/A	2
Atlantis		(5%	)		N/A	2

1. Brent price applies to Pluto-Scarborough and NWS Gas. WTI price (Brent - $3/bbl) applies to Atlantis.

2. Management considers there to be no reasonably possible change in the respective estimate which, in isolation, would result in the estimated recoverable amount being equal to the carrying amount.

A change in any of the above assumptions would have an impact on other assumptions which when considered together may offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions. Management considers there to be no reasonably possible changes in production volumes, carbon prices or foreign exchange rates that would, in isolation, result in the estimated recoverable amount being equal to the carrying amount. Analysis of key assumptions which could result in the carrying value to equal the recoverable value provides a basis to assess the magnitude of a reasonably possible change to the carrying amounts of respective CGUs.

F-35

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

Key estimates and judgements

(a) CGU determination

Identification of a CGU requires management judgement. Management has determined CGUs based on the smallest group of assets that generate significant cash inflows that are independent from other assets or groups of assets.

(b) Allocation of goodwill

Judgement is required in the allocation of goodwill from the acquisition of BHP Petroleum International Ltd 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. 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 2024 and 31 December 2023 is set out below:

· Resource estimates – 2P and a portion of 2C reserves (where applicable) for oil and gas properties. The reserves are as disclosed in the Reserves and Resources Statement in the 31 December 2024 and 31 December 2023 Annual Reports.

· Inflation rate – an inflation rate of 2.0% (2023: 2.0%) has been applied for US based assets and 2.3% (2023: 2.5%) for Australian based assets.

· Foreign exchange rates – a rate of $0.75 (2023: $0.75) US$:AU$ is based on management’s view of long-term exchange rates.

· Discount rates – a range of post-tax discount rates between 8.5% and 9.5% (2023: 8.5% and 10.5%) 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 (2023: US$80/tonne (2022 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. There is significant uncertainty around how society will respond to the climate challenge; 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. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in the Climate change and energy transition section within the basis of preparation. The nominal Brent oil prices (US$/bbl) used for the year ended 31 December 2024 were:

		2025	2026	2027	2028	2029	2030
	31 December 20241	80	82	83	84	86	88
	31 December 20232	80	76	77	79	80	82
	1. Long-term oil prices are based on US$78/bbl (2024 real terms) from 2027 and prices are escalated at 2.0% onwards. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards.

The nominal Brent oil prices (US$/bbl) used for the year ended 31 December 2023 were:
		2024	2025	2026	2027	2028	2029
	31 December 20233	82	80	76	77	79	80
	31 December 20224	78	74	76	77	79	80
	3. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards. 4. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% on-wards.

F-36

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

B.5 Business combination

Acquisition of OCI Clean Ammonia Holding B.V.

On 5 August 2024, Woodside entered into a binding agreement to acquire 100% of OCI Clean Ammonia Holding B.V. (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 was completed on 30 September 2024 and accounted for as a business combination. The Group’s net profit after tax for the year ended 31 December 2024 incorporates 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 will position the Group as an early mover in the growing lower carbon ammonia market.

Due to the size, complexity and timing of the transaction, the related acquisition accounting is not yet finalised and accordingly the assets acquired and liabilities assumed are measured on a provisional basis. If new information is obtained within 12 months from the acquisition date about facts and circumstances that existed at the acquisition date, adjustments will be made to the provisional amounts recognised including the value of goodwill.

Details of the purchase consideration and the provisional fair value of goodwill, identifiable assets and liabilities of OCI acquired are as follows:

Provisional fair value of net identifiable assets and goodwill arising on acquisition date	US$m
Cash and cash equivalents		4
Receivables		720
Property, plant and equipment		936
Intangible assets		766
Other assets		2
Payables		(43	)
Deferred tax liabilities		(168	)
Provisions		(16	)
Provisional fair value of net identifiable assets acquired		2,201
Goodwill arising on acquisition		169
Total purchase consideration1		2,370

1. Total purchase consideration includes $20 million of working capital adjustment.

Purchase consideration	US$m
Cash payment		1,900
Contingent considerationt2		470
Total purchase consideration		2,370

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		(1,900	)
Cash and cash equivalents acquired		4
Net cash flow on acquisition		(1,896	)

Acquisition-related costs of $2 million have been included as an expense in general, administration and other costs in the consolidated income statement.

F-37

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

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 includes $715 million of expected reimbursements from OCI N.V. for forecast capital expenditure. The full reimbursement is expected to be collected prior to the payment of the contingent consideration. $155 million has subsequently been received between acquisition date and 31 December 2024.

Intangible assets

$766 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 $169 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.

Key estimates and judgements

(a) Nature of acquisition

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

The project is under construction, with agreements in place to complete construction and transfer a fully operational asset together with a workforce to the Group in 2025. The agreements are in place at acquisition date and provide Woodside with control over the future economic benefits of the project, and the necessary inputs and processes to create outputs, meeting the definition of a business combination.

(b) Fair value determination for net assets acquired

Judgement is required to determine the fair value of assets acquired and liabilities assumed in a business combination, which can have a material impact on resultant goodwill. This includes the use of a cash flow model to estimate the expected future cash flows and the discount rate used.

On acquisition date, the reproduction cost method was used to fair value the property, plant and equipment in its construction phase. The reproduction cost method calculates the cost to construct an equivalent asset with the same specifications.

(c) Contingent consideration

Judgement is required to determine the fair value of the contingent consideration which includes consideration on the construction progress, estimates to complete compared to the schedule and performance guarantees.

B.6 Intangible assets

	Goodwill US$m		Contract assets1 US$m		Software1 US$m		Total US$m
Year ended 31 December 2024
Carrying amount at 1 January 2024		3,995		15		173		4,183
Acquisitions through business combination and assets acquisitions2		169		766		6		941
Additions		-		1		39		40
Amortisation		-		(25)		(15)		(40)
Goodwill disposed3		(298)		-		-		(298)
Carrying amount at 31 December 2024		3,866		757		203		4,826
At 31 December 2024
Cost		4,343		784		218		5,345
Accumulated impairment/amortisation		(477)		(27)		(15)		(519)
Net carrying amount		3,866		757		203		4,826
Year ended 31 December 2023
Carrying amount at 1 January 2023		4,614		1		55		4,670
Adjustment to BHPP merger purchase price allocation		55		-		-		55
Additions		-		16		118		134
Amortisation		-		(2)		-		(2)
Impairment losses4		(477)		-		-		(477)
Transfer to assets held for sale		(197)		-		-		(197)
Carrying amount at 31 December 2023		3,995		15		173		4,183
At 31 December 2023
Cost		4,472		17		173		4,662
Accumulated impairment/amortisation		(477)		(2)		-		(479)
Net carrying amount		3,995		15		173		4,183

1. Intangible assets include software and contract assets which were previously presented within other assets (non-current). The 2023 amounts have been reclassified to be presented on the same basis.

2. Refer to Note B.5 for details on business combination and Note B.7 for details on asset acquisitions.

3. Refer to Note B.8 for details of the sell-down of the Scarborough Joint Venture.

4. Refer to Note B.4 for details on impairment.

F-38

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

Recognition and measurement

Goodwill is initially measured at cost and is subsequently measured at cost less any accumulated impairment losses. For the purposes of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s CGUs or groups of CGUs no larger than an operating segment that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.

Where goodwill has been allocated to a CGU and part of the operation within that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal.

Goodwill is not amortised but will be assessed at least annually for impairment and more frequently if events or changes in circumstances indicate that it might be impaired.

The contract assets were acquired as part of a business combination and represent the difference in contract pricing and market prices, adjusted for time value of money. The contracts are recognised at fair value at the acquisition date and are subsequently amortised over 6 months to 17 years.

Software is recognised at historical cost less accumulated amortisation and impairment. All software costs are amortised over the useful life of 5-15 years on a straight-line basis.

Key estimates and judgements

(a) Goodwill allocation

Judgement is required in the allocation of goodwill to the Group’s CGUs that are expected to benefit from the synergies of the business combination. Refer to Note B.4 for the details of the goodwill allocation.

(b) Contract assets

In determining the fair value of the contract assets as part of a business combination, estimates are made regarding the pricing assumptions and discount rate. These estimates require management judgement and changes in economic conditions can impact the fair value assessment of the contracts.

B.7 Significant production and growth asset acquisitions

(a) 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 called.

The transaction was completed on 8 October 2024 and accounted for as an asset acquisition.

Assets acquired and liabilities assumed

The assets and liabilities acquired as at the date of the acquisition inclusive of transaction costs are:

	US$m
Cash and cash equivalents		24
Receivables		32
Other financial assets		6
Property, plant and equipment		1,367
Intangible assets		6
Lease assets		172
Other assets		62
Payables		(46	)
Other financial liabilities		(56	)
Provisions		(152	)
Tax payable		(2	)
Lease liabilities		(178	)
Interest-bearing liabilities		(169	)
Fair value of net identifiable assets on acquisition		1,066

Acquisition cost	US$m
Cash paid for shares		876
Loan facility		146
Payments for employee related awards		32
Transaction costs		12
Total acquisition cost		1,066

F-39

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2024

Analysis of cash flows on acquisition	US$m
Acquisition cost		(1,066	)
Cash and cash equivalent acquired		24
Net cash flow on acquisition		(1,042	)

Asset acquisition accounting

Purchase consideration, including capitalised transaction cost, has been allocated against identifiable assets and liabilities acquired on the following basis:

· Assets and liabilities initially measured at an amount other than cost, are measured by the Group at the amounts specified in the applicable accounting standards. Assets and liabilities in this category include financial assets and financial liabilities recognised initially at fair value, lease assets and liabilities measured in accordance with the accounting standard for leases, and employee benefit liabilities measured in accordance with the accounting standard for employee benefits.

· The residual transaction price is allocated to the remaining identifiable assets and liabilities based on their relative fair values at the date of the acquisition.

Key estimates and judgements

(a) Nature of acquisition

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

The Louisiana LNG project is in its preliminary phase with significant construction milestones and costs to be incurred prior to the facility being operational and the acquired assets and liabilities did not meet the criteria for a business combination due to the absence of a substantive process and organised workforce required to convert inputs to outputs.

(b) Employee compensation program

As part of the acquisition, the Group has assumed the obligation of Tellurian’s compensation programs to its employees. Judgement is required to determine the measurement of the employee provision on acquisition as certain conditions in the compensation programs are linked to future milestones of the Louisiana LNG project. This includes determining the likelihood and timing of the milestones.

(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 16.67% interest in the North West Shelf (NWS) project and the NWS Oil project and 20% interest in the Angel Carbon Capture and Storage (CCS) project, and to transfer its 13% non-operated interest in the Wheatstone project and 65% 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. At completion, there will be customary adjustments for net working capital and interim period cash flows.

As at 31 December 2024, 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.

B.8 Disposal of assets

(a) Sell-down of Scarborough Joint Venture to LNG Japan

On 8 August 2023 the Group entered into a sale and purchase agreement with LNG Japan for the sale of a 10% non-operating participating interest in the Scarborough Joint Venture.

As at 31 December 2023, the Group reclassified $823 million of assets, being the carrying value of the 10% interest in the Scarborough Joint Venture, to assets held for sale. Liabilities of $94 million were reclassified to liabilities directly associated with assets held for sale.

The transaction completed on 26 March 2024, reducing the Group’s participating interest from 100% to 90%. Proceeds from the sale were $910 million, including capital reimbursements and escalation. Delays to the first cargo or cost overruns in specific circumstances may result in payments by Woodside to LNG Japan of up to a maximum of $50 million. For the year ended 31 December 2024, the Group recognised a pre-tax gain on sale of $121 million.

(b) Sell-down of Scarborough Joint Venture to JERA

On 23 February 2024, the Group entered into a sale and purchase agreement with JERA for the sale of a 15.1% non-operating participating interest in the Scarborough Joint Venture.

As at 30 June 2024, the Group reclassified $1,378 million of assets, being the carrying value of the 15.1% interest in the Scarborough Joint Venture within the Australia segment, to assets held for sale. Liabilities of $119 million were reclassified to liabilities directly associated with assets held for sale. No impairment of assets occurred on reclassification to held for sale.

The transaction completed on 31 October 2024, reducing the Group’s participating interest from 90% to 74.9%. Proceeds from the sale were $1,425 million which includes the reimbursement from JERA for its share of expenditure for the Scarborough project from the effective date of 1 January 2022. For the year ended 31 December 2024, the Group recognised a pre-tax gain on sale of $88 million.

F-40

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2024

In this section

This section addresses cash, debt and the capital position of the Group at the end of the reporting period including, where applicable, the accounting policies applied and the key estimates and judgements made.

C.	Debt and capital
C.1	Cash and cash equivalents	Page F-42
C.2	Interest-bearing liabilities and financing facilities	Page F-43
C.3	Contributed equity	Page F-45
C.4	Other reserves	Page F-46

Key financial and capital risks in this section

Capital risk management

Group Treasury is responsible for the Group’s capital management including cash, debt and equity. Capital management is undertaken to ensure that a secure, cost-effective and 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 management

Liquidity risk arises from the financial liabilities of the Group and the Group’s subsequent ability to meet its obligations to repay financial liabilities as and when they fall due. The liquidity position of the Group is managed to ensure sufficient liquid funds are available to meet its financial commitments in a timely and cost-effective manner.

The Group’s liquidity is continually reviewed, including cash flow forecasts to determine the forecast liquidity position and maintain appropriate liquidity levels. At 31 December 2024, the Group had a total of $6,723 million (2023: $7,790 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.

Interest rate risk management

Interest rate risk is the risk that the Group’s financial position will fluctuate due to changes in market interest rates.

The Group’s exposure to the risk of changes in market interest rates relates primarily to financial instruments with floating interest rates including long-term debt obligations, cash and short-term deposits. The Group manages its interest rate risk by maintaining an appropriate mix of fixed and floating rate debt. To manage the ratio of fixed rate debt to floating rate debt, the Group may enter into interest rate swaps. The Group holds interest rate swaps to hedge the interest rate risk associated with the $600 million syndicated facility. Refer to Notes C.2 and D.6 for further details.

At the reporting date, the Group was exposed to various benchmark interest rates that were not designated in cash flow hedges, primarily through $3,923 million (2023: $1,605 million) on cash and cash equivalents and $3,150 million (2023: nil) on interest-bearing liabilities (excluding transaction costs).

A reasonably possible change in the Secured Overnight Financing Rate (SOFR) (+2.0%/-2.0% (2023: +2.0%/-2.0%)), with all variables held constant, would not have a material impact on the Group’s equity or the income statement in the current period.

F-41

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2024

C.1 Cash and cash equivalents

	2024     US$m		2023     US$m
Cash and cash equivalents
Cash at bank		1,603		1,198
Term deposits		2,320		542
Total cash and cash equivalents		3,923		1,740

Recognition and measurement

Cash and cash equivalents in the consolidated statement of financial position comprise cash at bank and short-term deposits with an original maturity of three months or less. Cash and cash equivalents are stated at face value in the consolidated statement of financial position. There are no cash and cash equivalents (2023: nil) restricted by legal or contractual arrangements.

Foreign exchange risk

The following table summarises the Group’s cash and cash equivalents by currency.

	2024     US$m		2023     US$m
US dollar		3,617		1,480
Australian dollar		173		112
Other		133		148
Total cash and cash equivalents		3,923		1,740

F-42

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2024

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 2024
At 1 January 2024		(1	)		(6	)		594			-			4,087			200			-			4,874
Debt acquired through asset acquisitions1		-			-			-			-			-			-			169			169
Repayments1,2		-			-			-			-			-			-			(169	)		(169	)
Drawdowns2		-			500			1,650			1,000			2,000			-			-			5,150
Transaction costs capitalised and amortised		1			1			(11	)		-			(18	)		-			-			(27	)
Carrying amount at 31 December 2024		-			495			2,233			1,000			6,069			200			-			9,997
Current		-			(2	)		(4	)		-			996			-			-			990
Non-current		-			497			2,237			1,000			5,073			200			-			9,007
Carrying amount at 31 December 2024		-			495			2,233			1,000			6,069			200			-			9,997
Undrawn balance at 31 December 2024		-			1,600			1,200			-			-			-			-			2,800
Year ended 31 December 2023
At 1 January 2023		-			(5	)		591			83			4,084			385			-			5,138
Repayments2		-			-			-			(83	)		-			(201	)		-			(284	)
Fair value adjustment and foreign exchange movement		-			-			-			-			-			16			-			16
Transaction costs capitalised and amortised		(1	)		(1	)		3			-			3			-			-			4
Carrying amount at 31 December 2023		(1	)		(6	)		594			-			4,087			200			-			4,874
Current3		(1	)		(2	)		(3	)		-			(3	)		-			-			(9	)
Non-current		-			(4	)		597			-			4,090			200			-			4,883
Carrying amount at 31 December 2023		(1	)		(6	)		594			-			4,087			200			-			4,874
Undrawn balance at 31 December 2023		1,800			2,250			2,000			-			-			-			-			6,050

1. Refer to Note B.7 for details on asset acquisitions. The debt acquired through asset acquisitions was repaid during the year.

2. Included in cash flows classified within financing activities in the consolidated statement of cash flows.

3. The balance relates to capitalised costs amortised within 12 months. This balance was reclassified to other assets (current) for presentation on the consolidated statement of financial position.

Recognition and measurement

All borrowings are initially recognised at fair value less transaction costs. Borrowings are subsequently carried at amortised cost. Any difference between the proceeds received and the redemption amount is recognised in the income statement over the period of the borrowings using the effective interest method.

Borrowings designated as a hedged item are measured at amortised cost adjusted to record changes in the fair value of risks that are being hedged in fair value hedges.

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 $6,069 million (2023: $4,087 million) and a fair value of $5,879 million (2023: $3,936 million). The medium term notes have a carrying amount of $200 million (2023: $200 million) and a fair value of $191 million (2023: $188 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.

F-43

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2024

Maturity profile of interest-bearing liabilities

The table below presents the contractual undiscounted cash flows associated with the Group’s interest-bearing liabilities, representing principal and interest. The figures will not necessarily reconcile with the amounts disclosed in the consolidated statement of financial position.

	2024     US$m		2023     US$m
Due for payment in:
1 year or less		1,480		212
1-2 years		1,747		1,181
2-3 years		1,262		962
3-4 years		1,325		907
4-5 years		1,965		883
More than 5 years		5,815		1,534
		13,594		5,679

Amounts exclude transaction costs.

Liquidity facilities

In October 2023, the Group obtained 12-month liquidity facilities to the value of $1,800 million in aggregate. Interest rates are based on daily SOFR plus credit adjustment spread (CAS) and margins, fixed at the commencement of the drawdown period.

In July 2024, the Group cancelled liquidity facilities totalling $1,450 million. The remaining $350 million liquidity facilities were cancelled in September 2024.

Bilateral facilities

The Group has 13 bilateral loan facilities totalling $2,100 million (2023: 15 bilateral loan facilities totalling $2,250 million). Details of bilateral loan facilities at the reporting date are as follows:

Number of facilities	Term (years)	Currency	Extension option
1	5 - 6	US$	Evergreen
4	4 - 5	US$	Evergreen
4	3 - 4	US$	Evergreen
4	3 years or less	US$	Evergreen

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 January 2024, the Group drew down on two bilateral facilities, totalling $500 million.

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.

In 2022, Woodside refinanced and increased the existing facilities to $2,000 million, with $800 million expiring on 11 October 2024, $600 million expiring on 12 July 2025 and $600 million expiring on 12 July 2027. Interest rates are based on SOFR plus CAS and margins are fixed at the commencement of the drawdown period.

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. In conjunction with the execution of the new term loan facility, the Group cancelled $800 million of the syndicated facility which was due to expire on 11 October 2024.

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$		200		3.07	%

The unutilised program is not considered to be an unused facility.

F-44

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2024

US bonds

The Group has four series of unsecured bonds issued in reliance on Rule 144A of the US Securities Act of 1933 and two 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
5 March 2025		1,000		3.65	%		144A
15 September 2026		800		3.70	%		144A
15 March 2028		800		3.70	%		144A
4 March 2029		1,500		4.50	%		144A
12 September 2034		1,250		5.10	%		SEC-registered
12 September 2054		750		5.70	%		SEC-registered

Interest on the bonds is payable semi-annually in arrears.

C.3 Contributed equity

Recognition and measurement

Issued capital

Ordinary shares are classified as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds.

Reserved shares

Reserved shares 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 income statement on the purchase, sale, issue or cancellation of the Group’s own equity instruments.

(a) Issued and fully paid shares

	Number of shares		US$m
Year ended 31 December 2024
Opening balance		1,898,749,771		29,001
Amounts as at 31 December 2024		1,898,749,771		29,001
Year ended 31 December 2023
Opening balance		1,898,749,771		29,001
Amounts as at 31 December 2023		1,898,749,771		29,001
Year ended 31 December 2022
Opening balance		969,631,826		9,409
DRP – ordinary shares issued at US$23.14 (2021 final dividend)1		14,348,997		332
Ordinary shares issued at US$21.06 for the acquisition of BHPP2		914,768,948		19,265
Transaction costs associated to the issue of shares		-		(5)
Amounts as at 31 December 2022		1,898,749,771		29,001

1. Relates to ordinary shares issued for the DRP as part of the 2021 final dividend. The Group purchased on-market shares for the issuance of DRP as part of the 2022 interim dividend. Refer to Note C.3(b) for details of the on-market purchases and allocation.

2. 914,768,948 new Woodside shares were issued as consideration for the BHPP merger.

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.

F-45

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2024

(b) Reserved shares

	Employee share plans				Dividend reinvestment plan
	Number of shares		US$m		Number of shares		US$m
Year ended 31 December 2024
Opening balance	2,140,927		(49)		-		-
Purchases during the year	4,293,699		(81)		-		-
Vested/allocated during the year	(3,353,784)		72		-		-
Amounts at 31 December 2024	3,080,842		(58)		-		-
Year ended 31 December 2023
Opening balance		1,873,777		(38)		-		-
Purchases during the year		2,332,121		(57)		-		-
Vested/allocated during the year		(2,064,971)		46		-		-
Amounts at 31 December 2023		2,140,927		(49)		-		-
Year ended 31 December 2022
Opening balance		1,819,744		(30)		-		-
Purchases during the year		2,232,589		(45)		6,823,092		(144)
Vested during the year		(2,178,556)		37		(6,823,092)		144
Amounts at 31 December 2022		1,873,777		(38)		-		-

C.4 Other reserves

	2024      US$m		2023      US$m		2022      US$m
Other reserves
Employee benefits reserve		281		290		278
Foreign currency translation reserve		795		795		796
Hedging reserve		1		88		(586)
Distributable profits reserve1		3,069		4,118		3,541
Other reserves		(38)		(30)		2
		4,108		5,261		4,031

1. For the year ended 31 December 2024, the Group transferred $1,400 million of retained earnings to the distributable profits reserve. The increase was offset by the 2023 final and 2024 interim dividend payments of $2,449 million.

Nature and purpose

Employee benefits reserve

Used to record share-based payments associated with the employee share plans.

Foreign currency translation reserve

Used to record foreign exchange differences arising from the translation of the financial statements of foreign entities from their functional currency to the Group’s presentation currency.

Hedging reserve

Used to record gains and losses on effective portion of hedges designated as cash flow hedges, and foreign currency basis spread arising from the designation of a financial instrument as a hedging instrument. Gains and losses accumulated in the cash flow hedge reserve for qualifying assets are capitalised against the carrying amount of that asset and recognised in the income statement as the asset is depreciated.

Distributable profits reserve

Used to record distributable profits generated by the parent entity, Woodside Energy Group Ltd.

Other reserves

Used to record gains and losses on financial instruments at fair value through other comprehensive income.

F-46

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

In this section

This section addresses the other assets and liabilities position at the end of the reporting period including, where applicable, the accounting policies applied and the key estimates and judgements made.

D.	Other assets and liabilities
D.1	Segment assets and liabilities	Page F-48
D.2	Receivables	Page F-48
D.3	Inventories	Page F-49
D.4	Payables	Page F-49
D.5	Provisions	Page F-50
D.6	Other financial assets and liabilities	Page F-52
D.7	Leases	Page F-54

Key financial and capital risks in this section

Credit risk management

Credit risk is the risk that a counterparty will not meet its payment obligation under a financial instrument or customer contract, leading to a financial loss to the Group. Credit risk arises from the financial assets of the Group, which comprise 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 bad debts 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 2024, the Group had 23 customers (2023: 19 customers) that owed the Group more than $10 million each and accounted for approximately 88% (2023: 82%) 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 2024, the Group had a provision for credit losses of nil (2023: nil). Subsequent to 31 December 2024, 96% (2023: 97%) of product-related trade receivables balance of $972 million (2023: $885 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 2024 and 31 December 2023, 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.

F-47

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

D.1 Segment assets and liabilities

	2024    US$m		2023 US$m
(a) Segment assets
Australia		29,678		31,602
International		19,556		17,923
Marketing		754		835
New energy/Corporate		11,276		5,001
		61,264		55,361

	2024    US$m		2023 US$m
(b) Segment liabilities
Australia		6,953		7,833
International		2,616		2,624
Marketing		1,115		751
New energy/Corporate		14,427		8,983
		25,111		20,191

Refer to Note A.1 for descriptions of the Group’s segments. New energy/Corporate assets mainly comprise cash and cash equivalents, deferred tax assets, new energy assets in development and lease assets. New energy/Corporate liabilities mainly comprise interest-bearing liabilities, deferred tax liabilities and lease liabilities.

Segment assets include non-current assets¹ of $29,466 million (2023 $30,432 million) in Australia, $13,847 million (2023: $10,967 million) in USA, $5,268 million (2023: $5,295 million) in Senegal, $1,357 million (2023: $567 million) in Mexico, $1,370 million (2023: $1,265 million) in other locations.

1. Excluding deferred tax assets of $2,393 million (2023: $1,717 million).

D.2 Receivables

	2024    US$m		2023 US$m
(a) Receivables (current)
Trade receivables1		972		963
Other receivables1,2		1,270		456
Loans receivable		133		73
Lease receivables		9		24
Interest receivable		6		1
		2,390		1,517
(b) Receivables (non-current)
Other receivables		51		21
Loans receivable		776		771
Lease receivables		49		47
		876		839

1. Interest-free and settlement terms are usually between 14 and 30 days.

2. $560 million of the carrying amount as at 31 December 2024 relates to expected reimbursements from OCI N.V. for forecast capital expenditure. Refer to Note B.5 for details.

Recognition and measurement

Trade receivables are initially recognised at the transaction price determined under IFRS 15 Revenue from Contracts with Customers. Other receivables are initially recognised at fair value. Receivables that satisfy the contractual cash flow and business model tests are subsequently measured at amortised cost less an allowance for uncollectable amounts. Uncollectable amounts are determined using the expected loss impairment model. Collectability and impairment are assessed on a regular basis.

Subsequent recoveries of amounts previously written off are credited against other expenses in the consolidated income statement. Certain receivables that do not satisfy the contractual cash flow and business model tests are subsequently measured at fair value (refer to Note D.6).

The Group’s customers are required to pay in accordance with agreed payment terms. Depending on the product, settlement terms are 8 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 (2023: nil).

Fair value

The carrying amount of trade and other receivables approximates their fair value.

Foreign exchange risk

The Group held $479 million of receivables at 31 December 2024 (2023: $305 million) in currencies other than US dollars (predominantly Australian dollars).

Loans receivable

On 9 January 2020, Woodside Energy Finance (UK) Ltd entered into a secured loan agreement with Petrosen (the Senegal National Oil Company) to provide up to $450 million for the purpose of funding Sangomar project costs. The facility has a maximum term of 12 years and semi-annual repayments of the loan are due to commence at the earlier of 12 months after RFSU or 30 June 2025. The carrying amount of the loan receivable is $464 million at 31 December 2024 (2023: $435 million), which approximates its fair value. The remaining balance of loans receivable is due from non-controlling interests.

F-48

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

D.3 Inventories

	2024 US$m		2023 US$m
(a) Inventories (current)
Petroleum products
Goods in transit		85		41
Finished stocks		135		93
Warehouse stores and materials		457		476
Carbon credits		7		6
		684		616
(b) Inventories (non-current)
Warehouse stores and materials		18		3
Carbon credits		195		117
		213		120

Recognition and measurement

Inventories include hydrocarbon stocks, consumable supplies, maintenance spares and carbon credits expected to be utilised to offset future emissions. Inventories are valued at the lower of cost and net realisable value. Cost is determined on a weighted average basis and includes direct costs and an appropriate portion of fixed and variable production overheads where applicable. Inventories determined to be obsolete or damaged are written down to net realisable value, being the estimated selling price less selling costs.

D.4 Payables

	2024 US$m		2023 US$m
Trade and other payables1		2,075		1,655
Interest payable2		110		69
		2,185		1,724

1. Interest-free and normally settled on 30 day terms.

2. Details regarding interest-bearing liabilities are contained in Note C.2.

Recognition and measurement

Trade and other payables are carried at amortised cost and are recognised when goods and services are received, whether or not billed to the Group, prior to the end of the reporting period.

Fair value

The carrying amount of payables approximates their fair value.

Foreign exchange risk

The Group held $140 million of payables at 31 December 2024 (2023: $534 million) in currencies other than US dollars (predominantly Australian dollars).

Maturity profile of payables

The Group’s payables balances at 31 December 2024 and 31 December 2023 are due for payment within 12 months.

F-49

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

D.5 Provisions

	Restoration1 US$m			Employee benefits US$m		Other US$m		Total   US$m
Year ended 31 December 2024
At 1 January 2024		7,154			522		281		7,957
Acquisitions through business combination and asset acquisitions2		16			104		48		168
Change in provision		(936	)		28		37		(871	)
Unwinding of present value discount		292			-		1		293
Carrying amount at 31 December 2024		6,526			654		367		7,547
Current		753			402		167		1,322
Non-current		5,773			252		200		6,225
Net carrying amount		6,526			654		367		7,547
Year ended 31 December 2023
At 1 January 2023		6,253			517		409		7,179
Change in provision		664			5		(128)		541
Unwinding of present value discount		237			-		-		237
Carrying amount at 31 December 2023		7,154			522		281		7,957
Current		1,011			351		144		1,506
Non-current		6,143			171		137		6,451
Net carrying amount		7,154			522		281		7,957

1. 2024 change in provision is due to provisions used of $887 million, changes in macroeconomic factors increasing the provisions by $647 million, offset by changes in estimates of $598 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 and Note B.7 for details of asset acquisitions.

Recognition and measurement

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.

Restoration

The restoration provision is first recognised in the period in which the obligation arises. The nature of restoration activities includes the removal of facilities, abandonment of wells and restoration of affected areas. Restoration provisions are updated annually, with the corresponding movement recognised against the related exploration and evaluation assets or property, plant and equipment or expensed for late life projects with no corresponding asset.

Over time, the liability is increased for the change in the present value based on a pre-tax discount rate appropriate to the risks inherent in the liability. The unwinding of the discount is recorded as an accretion charge within finance costs. The carrying amount capitalised in property, plant and equipment is depreciated over the useful life of the related asset (refer to Note B.3).

Costs incurred that relate to an existing condition caused by past operations, and which do not have a future economic benefit, are expensed.

Employee benefits

Provision is made for employee benefits accumulated as a result of employees rendering services up to the end of the reporting period. These benefits include wages, salaries, annual leave and long service leave.

Liabilities in respect of employees’ services rendered that are not expected to be wholly settled within one year after the end of the period in which the employees render the related services are recognised as long-term employee benefits.

These liabilities are measured at the present value of the estimated future cash outflow to the employees using the projected unit credit method. Liabilities expected to be wholly settled within one year after the end of the period in which the employees render the related services are classified as short-term benefits and are measured at the amount due to be paid.

Onerous contract provision

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.

F-50

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

Key estimates and judgements

(a) Restoration obligations

The Group estimates the future decommissioning and remediation costs of offshore oil and gas platforms, offshore and onshore production facilities, wells and pipelines at different stages of the development and construction of assets or facilities 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 date, environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating cost, technologies used in determining the decommissioning cost, and liability-specific discount rates to determine the present value of these cash flows.

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 takes into consideration the possibility that full removal of all assets may be required.

Inherent uncertainties

The basis of the restoration obligation provision for assets with approved decommissioning plans or general directions issued by the regulator can differ from the assumptions disclosed above. Whilst the provisions reflect the Group’s best estimate based on current knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be ongoing to ensure that the most accurate information is available when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash outflows can materially differ from the current estimate as a result of changes in regulations and their application, prices, analysis of site conditions, further studies, timing of restoration and changes in removal technology. These uncertainties may result in actual expenditure differing from amounts included in the provision recognised as at 31 December 2024.

A range of pre-tax discount rates between 4.0% and 4.9% (2023: 3.7% and 5.0%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $336 million higher. If the cost estimates were increased by 10% then the provision would be $653 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 53% (2023: 55%).

F-51

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

D.6 Other financial assets and liabilities

	2024    US$m		2023    US$m
Other financial assets
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		186		248
Other financial assets		28		53
Financial instruments at fair value through other comprehensive income
Other financial assets		89		28
Total other financial assets		303		329
Current		185		209
Non-current		118		120
Net carrying amount		303		329
Other financial liabilities
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		169		74
Embedded derivative		349		35
Total other financial liabilities		518		109
Current		139		67
Non-current		379		42
Net carrying amount		518		109

Recognition and measurement

Other financial assets and liabilities

Receivables subject to provisional pricing adjustments are initially recognised at the transaction price and subsequently measured at fair value with movements recognised in the consolidated income statement.

Derivative financial instruments

Derivative financial instruments that are designated within qualifying hedge relationships are initially recognised at fair value on the date the contract is entered into. For relationships designated as fair value hedges, subsequent fair value movements of the derivative are recognised in the consolidated income statement.

For relationships designated as cash flow hedges, subsequent fair value movements of the derivative for the effective portion of the hedge are recognised in other comprehensive income and accumulated in reserves in equity; fair value movements for the ineffective portion are recognised immediately in the consolidated income statement. Costs of hedging have been separated from the hedging arrangements and deferred to other comprehensive income and accumulated in reserves in equity. Amounts accumulated in equity are reclassified to the consolidated income statement in the periods when the hedged item affects profit or loss.

Hedge effectiveness is determined at the inception of the hedge relationship, and through periodic prospective effectiveness assessments to ensure that an economic relationship exists between the hedged exposure and the hedging instrument. The Group assesses whether the derivative designated in each hedging relationship has been, and is expected to be, effective in offsetting changes in cash flows of the hedged exposure using the hypothetical derivative method.

Ineffectiveness is recognised where the cumulative change in the designated component value of the hedging instrument on an absolute basis exceeds the change in value of the hedged exposure attributable to the hedged risk.

Ineffectiveness may arise where the timing of the transaction changes from what was originally estimated such as delayed shipments or changes in timing of forecast sales. This may also arise where the commodity swap pricing terms do not perfectly match the pricing terms of the revenue contracts.

F-52

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

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.

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 2024, the Group hedged approximately 30 MMboe of 2025 oil production at an average price of approximately $78.7 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 94% of 2025 and 67% 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.

	2024		2023
Brent commodity swaps (cash flow hedges)
Carrying amount (US$m)		137		(14	)
Notional amount (MMbbl)1		31		29
Maturity date		2025		2024
Hedge ratio		1:1		1:1
Weighted average hedged rate (US$/MMbbl)		79		76
HH Natural Gas commodity swaps (cash flow hedges)
Carrying amount (US$m)		8		(44	)
Notional amount (TBtu)1		79		38
Maturity date		2025-2026		2024-2025
Hedge ratio		1:1		1:1
Weighted average hedged rate (US$/MMBtu)		3.6		4.4
TTF LNG commodity swaps (cash flow hedges)
Carrying amount (US$m)		(118)		181
Notional amount (TBtu)1		69		32
Maturity date		2025-2026		2024-2025
Hedge ratio		1:1		1:1
Weighted average hedged rate (US$/MMBtu)		11.9		18.3
Interest rate swap (cash flow hedges)
Carrying amount (US$m)		35		43
Notional amount (US$m)		600		600
Maturity date		2027		2027
Hedge ratio		1:1		1:1
Weighted average hedged rate		1.7%		1.7%
FX forwards (cash flow hedges)
Carrying amount (US$m)		(45)		8
Notional amount (AUD$m)2		2,484		1,834
Maturity date		2025		2024-2025
Hedge Ratio		1:1		1:1
Weighted average hedged rate (AUD:USD)		0.67		0.68

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$985 million is unrealised volumes of the hedge item included in the cash flow hedge reserve.

Hedge ineffectiveness loss of $5 million (2023: $15 million loss) has been recognised in the profit and loss.

Embedded commodity derivative

In 2023, 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 2024 amounted to a net liability of $349 million (2023: net liability of $35 million). The derivative is remeasured to fair value at each reporting date in accordance with the urea price at that date. For the year ended 31 December 2024, an unrealised loss of $314 million (2023: unrealised loss of $35 million) has been recognised through other expenses.

F-53

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

Key estimates and judgements

(a) Embedded commodity derivative

The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast pricing, discount rate, credit risk and volatility. These assumptions require significant management 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% (2023: 2.5%) has been applied.

· Discount rate – a pre-tax interest rate curve with a range of 5.80% to 6.95% (2023: range of 5.39% to 7.12%).

· 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 at reporting date.

The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses recognised in other income/expenses in the future.

The nominal impact of the effects of changes to discount rate and long-term price assumptions are estimated as follows:

Change in assumption1	US$m
Urea sales price: increase of 10%	125
Urea sales price: decrease of 10%	(125	)
Discount rate: increase of 1.5%2	(163	)
Discount rate: decrease of 1.5%2	201

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.

D.7 Leases

	Land and buildings		Oil and gas properties1		Other plant and equipment1		Total
	US$m		US$m		US$m		US$m
Lease assets
Year ended 31 December 2024
Carrying amount at 1 January 2024		430		107		693		1,230
Acquisitions through assets acquisitions2		172		-		-		172
Additions		37		-		111		148
Disposals at written down value		-		(1)		(1)		(2)
Lease remeasurements		16		17		10		43
Depreciation		(52)		(106)		(142)		(300)
Carrying amount at 31 December 2024		603		17		671		1,291
At 31 December 2024
Historical cost and remeasurements		825		518		1,235		2,578
Accumulated depreciation, impairment and disposals		(222)		(501)		(564)		(1,287)
Net carrying amount		603		17		671		1,291
Lease liabilities
Year ended 31 December 2024
At 1 January 2024		607		130		878		1,615
Acquisitions through assets acquisitions2		178		-		-		178
Additions		37		-		111		148
Disposals		-		(7)		(1)		(8)
Repayments (principal and interest)		(83)		(118)		(210)		(411)
Accretion of interest		26		4		72		102
Lease remeasurements		(31)		24		6		(1)
Carrying amount at 31 December 2024		734		33		856		1,623
Current		55		32		102		189
Non-current		679		1		754		1,434
Carrying amount at 31 December 2024		734		33		856		1,623
Lease assets
Year ended 31 December 2023
Carrying amount at 1 January 2023		464		225		575		1,264
Additions		8		-		120		128
Transfer to assets held for sale		-		(3)		-		(3)
Lease remeasurements		7		59		125		191
Depreciation		(49)		(174)		(127)		(350)
Carrying amount at 31 December 2023		430		107		693		1,230
At 31 December 2023
Historical cost and remeasurements		600		502		1,115		2,217
Accumulated depreciation, impairment and disposals		(170)		(395)		(422)		(987)
Net carrying amount		430		107		693		1,230
Lease liabilities
Year ended 31 December 2023
At 1 January 2023		623		238		773		1,634
Additions		24		-		121		145
Transfer to liabilities directly associated with assets held for sale		-		(6)		(1)		(7)
Repayments (principal and interest)		(78)		(188)		(203)		(469)
Accretion of interest		27		12		63		102
Lease remeasurements		11		74		125		210
Carrying amount at 31 December 2023		607		130		878		1,615
Current		54		114		130		298
Non-current		553		16		748		1,317
Carrying amount at 31 December 2023		607		130		878		1,615

1. Plant and equipment, which was a category in 2023, has been reviewed and presented as ‘oil and gas properties’ and ‘other plant and equipment’ in 2024. The 2023 amounts have been reclassified to be presented on the same basis.

2. Refer to Note B.7 for details of asset acquisitions.

F-54

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

Recognition and measurement

When a contract is entered into, the Group assesses whether the contract contains a lease. A lease arises when the Group has the right to direct the use of an identified asset which is not substitutable and to obtain substantially all economic benefits from the use of the asset throughout the period of use. The leases recognised by the Group predominantly relate to LNG vessels, property and drilling rigs.

The Group separates the lease and non-lease components of the contract and accounts for these separately. The Group allocates the consideration in the contract to each component on the basis of their relative stand-alone prices.

Leases as a lessee

Lease assets and lease liabilities are recognised at the lease commencement date, which is when the assets are available for use. The assets are initially measured at cost, which is the present value of future lease payments adjusted for any lease payments made at or before the commencement date, plus any make-good obligations and initial direct costs incurred.

Lease assets are depreciated using the straight-line method over the shorter of their useful life and the lease term. Refer to Note B.3 for the useful lives of assets. Periodic adjustments are made for any re-measurements of the lease assets and for impairment losses, assessed in accordance with the Group’s impairment policies.

Lease liabilities are initially measured at the present value of future minimum lease payments, discounted using the Group’s incremental borrowing rate if the rate implicit in the lease cannot be readily determined, and are subsequently measured at amortised cost using the effective interest rate. Minimum lease payments are fixed payments or index-based variable payments incorporating the Group’s expectations of extension options and do not include non-lease components of a contract. A portfolio approach was taken when determining the implicit discount rate for LNG vessels with similar terms and conditions on transition.

The lease liability is remeasured when there are changes in future lease payments arising from a change in rates, index or lease terms from exercising an extension or termination option. A corresponding adjustment is made to the carrying amount of the lease assets, with any excess recognised in the consolidated income statement.

There are no restrictions placed upon the lessee by entering into these leases.

Short-term leases and leases of low value

Short-term leases (lease term of 12 months or less) and leases of low value assets are recognised as incurred as an expense in the consolidated income statement. Low value assets comprise plant and equipment.

F-55

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2024

Foreign exchange risk

The Group held $408 million of lease liabilities at 31 December 2024 (2023: $447 million) in currencies other than the US dollar (predominantly Australian dollars).

Maturity profile of lease liabilities

The table below presents the contractual undiscounted cash flows associated with the Group’s lease liabilities, representing principal and interest. The figures will not necessarily reconcile with the amounts disclosed in the consolidated statement of financial position.

	2024        US$m	2023       US$m
Due for payment in:
1 year or less	286	415
1-2 years	218	240
2-3 years	198	194
3-4 years	195	180
4-5 years	195	181
More than 5 years	899	1,032
	1,991	2,242

Lease commitments

The table below presents the contractual undiscounted cash flows associated with the Group’s future lease commitments for non-cancellable leases not yet commenced, representing principal and interest.

	2024       US$m	2023      US$m
Due for payment:
Within one year	32	33
After one year but not more than five years	775	889
Later than five years	2,360	1,242
	3,167	2,164

Payments of $292 million (2023: $121 million) for short-term leases (lease term of 12 months or less) and payments of $17 million (2023: $12 million) for leases of low value assets were expensed in the consolidated income statement. Total payments for leases in the consolidated statement of cash flows are $689 million (2023: $575 million), with $293 million (2023: $361 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 $276 million (2023: $232 million).

Key estimates and judgements

(a) Control

Judgement is required to assess whether a contract is or contains a lease at inception by assessing whether the Group has the right to direct the use of the 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 $2,113 million (2023: $2,000 million) were not included in the measurement of lease liabilities.

(c) lnterest 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-56

Notes to the financial statements E. Other items

for the year ended 31 December 2024

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-60
E.4	Auditor remuneration	Page F-60
E.5	Events after the end of the reporting period	Page F-60
E.6	Joint arrangements	Page F-61
E.7	Parent entity information	Page F-62
E.8	Subsidiaries	Page F-62
E.9	Other accounting policies	Page F-66

F-57

Notes to the financial statements E. Other items

for the year ended 31 December 2024

E.1 Contingent liabilities and assets

	2024 US$m		2023 US$m
Contingent liabilities at reporting date
Contingent liabilities		281		260
Guarantees		1		2
		282		262

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.

The Group has contingent assets of $30 million as at 31 December 2024 (2023: $47 million).

E.2 Employee benefits

	2024 US$m		2023 US$m		2022 US$m
Employee benefits		521		494		415
Share-based payments		23		39		26
Defined contribution plan costs		51		53		41
Defined benefit plan expense		7		17		9
		602		603		491

(a) Employee benefits

Employee benefits for the reporting period are as follows:

Recognition and measurement

The Group’s accounting policy for employee benefits other than superannuation is set out in Note D.5. The policy relating to share-based payments is set out in Note E.2(c).

All employees of the Group are entitled to benefits on retirement, disability or death from the Group’s retirement plans. 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.

(b) Compensation of key management personnel

Key management personnel (KMP) compensation for the financial year was as follows:

	2024 US$		2023 US$		2022 US$
Short-term employee benefits		6,810,215		5,245,763		5,730,340
Post-employment benefits		262,790		215,856		155,086
Share-based payments		5,265,736		3,693,072		3,114,043
Long-term employee benefits		483,452		213,562		4,300
Termination benefits		724,287		-		152,531
		13,546,480		9,368,253		9,156,300

In 2024, the number of executive KMPs increased from 4 to 6.

(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.

F-58

Notes to the financial statements E. Other items

for the year ended 31 December 2024

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 2023 Restricted Shares and Performance Rights were granted on 27 February 2024 for Executives and 24 April 2024 for the CEO and have been included in the table below. The expense estimated as at 31 December 2023 in relation to the 2023 performance year was updated to the fair value on grant date during the period.

The 2024 Restricted Shares and Performance Rights have not been included in the table below as they have not been approved as at 31 December 2024. An expense related to the 2024 performance year has been estimated for the Restricted Shares and Performance Rights, using fair value estimates based on inputs at 31 December 2024.

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 2023 Restricted Shares were granted on 27 February 2024 and have been included in the table below. The expense estimated as at 31 December 2023 in relation to the 2023 performance year was updated to the fair value on grant date during the period.

The 2024 Restricted Shares have not been included in the table below as they have not been approved as at 31 December 2024. An expense related to the 2024 performance year has been estimated for the Restricted Shares, using fair value estimates based on inputs at 31 December 2024.

Recognition and measurement

All compensation under WEP, SWEP, PBP Plus and EIS Restricted Shares and Performance Rights is accounted for as share-based payments to employees for services provided. The cost of equity-settled transactions with employees is measured by reference to the fair values of the equity instruments at the date at which they are granted. The fair value of share-based payments is recognised, together with the corresponding increase in equity, over the period in which the vesting conditions are fulfilled, ending on the date on which the relevant employee becomes fully entitled to the shares. At each balance sheet date, the Group reassesses the number of awards that are expected to vest based on service conditions. The expense recognised each year takes into account the most recent estimate.

The fair value of the benefit provided for the WEP and SWEP is estimated using the Black-Scholes option pricing technique.

The fair value of the Restricted Shares is estimated as the closing share price at grant date. The fair value of the benefit provided for the relative total shareholder return Performance Rights is calculated using the Binomial or Black-Scholes option pricing technique combined with a Monte Carlo simulation methodology, where relevant, using historical volatility to estimate the volatility of the share price in the future.

F-59

Notes to the financial statements E. Other items

for the year ended 31 December 2024

The number of awards and movements for all share plans are summarised as follows:

	Number of performance awards
	Employee Plans						Executive Plans
	WEP			SWEP			Short-term awards4			Long-term awards4
Year ended 31 December 2024
Opening balance		9,125,440			1,556,573			1,066,237			2,696,552
Granted during the year1,2,3		5,188,220			48,179			918,543			364,378
Vested during the year		(1,833,896	)		(1,038,583	)		(231,156	)		(250,149	)
Forfeited during the year		(716,686	)		(108,599	)		(201,956	)		(361,735	)
Awards at 31 December 2024		11,763,078			457,570			1,551,668			2,449,046
	US$m			US$m			US$m			US$m
Fair value of awards granted during the year		70			1			18			8
	Number of performance awards
	Employee Plans						Executive Plans
	WEP			SWEP			Short-term awards4			Long-term awards4
Year ended 31 December 2023
Opening balance		6,629,681			2,884,076			993,197			2,554,422
Granted during the year1,2,3		3,445,234			100,811			420,429			658,969
Vested during the year		(600,271	)		(1,071,291	)		(286,979)			(106,430	)
Forfeited during the year		(349,204	)		(357,023	)		(60,410	)		(410,409	)
Awards at 31 December 2023		9,125,440			1,556,573			1,066,237			2,696,552
	US$m			US$m			US$m			US$m
Fair value of awards granted during the year		60			2			10			12

1. For the purpose of valuation, the share price on grant date for the 2024 WEP allocations was $13.54 (2023: $17.54).

2. For the purpose of valuation, the share price on grant date for the 2024 SWEP allocations was $16.04 (2023: $20.78).

3. For the purpose of valuation, the share price on grant date for Restricted Shares was $19.74 and $19.33 (2023: $23.48 and $23.33) and Performance Rights was $12.89 (2023: $15.96).

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 5 years. Long-term awards relate to awards with a vesting period of 5 years.

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 $42,162 thousand (2023: $71,407 thousand), sale of goods/services of $5,720 thousand (2023: $27,142 thousand) and dividend income of $14,776 thousand (2023: $15,296 thousand). As at 31 December 2024, the total amounts owing to related parties is $2,015 thousand (2023: $1,559 thousand) and amounts owing from related parties is $92 thousand (2023: $1,960 thousand). 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

The Group increased its currency hedge positions by AUD$354 million to protect against foreign exchange risks associated with anticipated capital expenditure on the Scarborough Energy Project.

F-60

Notes to the financial statements E. Other items

for the year ended 31 December 2024

E.6 Joint arrangements

(a) Interest percentage in joint ventures

		Group Interest %
Entity	Principal activity	2024		2023
North West Shelf Gas Pty Ltd	Contract administration services for venturers for LNG sales to Japan. Marketing and administration services for venturers for gas processing.		33.3		33.3
North West Shelf Liaison Company Pty Ltd	Liaison for ventures in the sale of LNG to the Japanese market.		33.3		33.3
China Administration Company Pty Ltd	Contract administration services for venturers for LNG sales to China.		33.3		33.3
North West Shelf Shipping Service Company Pty Ltd	LNG vessel fleet advisor.		33.3		33.3
North West Shelf Lifting Coordinator Pty Ltd	Allocating, scheduling and administering the lifting of LNG and pipeline gas.		33.3		33.3

(b) Interest percentage in joint operations

	Group Interest %
	2024		2023
Producing and developing assets
Australia
Scarborough1		74.9		100.0
North West Shelf		25.0 - 66.7		25.0 - 66.7
Greater Enfield and Vincent		60.0		60.0
Pluto		90.0		90.0
Wheatstone		13.0 -65.0		13.0 -65.0
Bass Strait		25.0 -50.0		25.0 -50.0
Macedon		71.4		71.4
Pyrenees		40.0 -71.4		40.0 -71.4
International
Sangomar		82.0		82.0
Atlantis		44.0		44.0
Mad Dog		23.9		23.9
Shenzi		72.0		72.0
Trion		60.0		60.0
Greater Angostura		45.0 -68.5		45.0 -68.5
Exploration and evaluation assets
Oceania
Browse Basin		30.6		30.6
Carnarvon Basin2		31.6 -70.0		31.6 -70.0
Bonaparte Basin3		26.7 -35.0		26.7 -35.0
Africa
Congo		22.5		22.5
Senegal		90.0		90.0
Egypt4		25.0 -45.0		25.0 -45.0
Americas
US Gulf of Mexico6		23.9 -75.0		23.9 -75.0
Liard		50.0		50.0
Kitimat		50.0		50.0
Asia
Myanmar		45.0		45.0
Sunrise		33.4		33.4
Caribbean
Barbados5		60.0		60.0
Calypso		70.0		70.0
Other joint operations
Angel		20.0		20.0
Bonaparte Basin		21.0		21.0

1. The Group sold down a total of 25.1% interest in the Scarborough project in 2024; 10% to LNG Japan and 15.1% to JERA.

2. The Group surrendered WA-356-P for Carnarvon in 2024.

3. The Group surrendered NT/P86 for Bonaparte in 2024.

4. The Group exited Herodotus Block 2 for Egypt in 2024.

5. The Group relinquished Carlisle Bay for Barbados in 2024.

6. On 20 January 2025, President Trump issued an Executive Order renaming the area known as the “Gulf of Mexico” as the “Gulf of America”. The US Interior Department formally announced the change on 24 January 2025 and US federal agencies are currently in the process of implementing the change. In this 2024 Annual Report, Woodside uses the term “Gulf of Mexico” to refer to the area in which its Shenzi, Mad Dog and Atlantis projects are located, as that term was in effect during the period covered by this report. Woodside will adopt the naming conventions required by applicable laws and regulations in relation to US waters.

The principal activities of the joint operations are exploration, development and production of hydrocarbons.

F-61

Notes to the financial statements E. Other items

for the year ended 31 December 2024

Key estimates and judgements

(a) Accounting for interests in other entities

Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity. Depending upon the facts and circumstances in each case, Woodside may obtain control, joint control or 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.

Recognition and measurement

Joint arrangements are arrangements in which two or more parties have joint control. Joint control is the contractual agreed sharing of control of the arrangement which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control. Joint arrangements are classified as either a joint operation or joint venture, based on the rights and obligations arising from the contractual obligations between the parties to the arrangement.

To the extent the joint arrangement provides the Group with rights to the individual assets and obligations arising from the joint arrangement, the arrangement is classified as a joint operation, and as such the Group recognises its:

· assets, including its share of any assets held jointly;

· liabilities, including its share of any liabilities incurred jointly;

· revenue from the sale of its share of the output arising from the joint operation;

· share of revenue from the sale of the output by the joint operation; and

· expenses, including its share of any expenses incurred jointly.

To the extent the joint arrangement provides the Group with rights to the net assets of the arrangement, the investment is classified as a joint venture and accounted for using the equity method.

Joint arrangements acquired which are deemed to be carrying on a business are accounted for applying the principles of IFRS 3 Business Combinations. Joint arrangements which are not deemed to be carrying on a business are treated as asset acquisitions.

E.7 Parent entity information

Note not required for the purposes of US reporting.

E.8 Subsidiaries

(a) 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	)

F-62

Notes to the financial statements E. Other items

for the year ended 31 December 2024

Name of entity	Country of incorporation		Notes
Woodside Energy Australia Asia Holdings Pte Ltd		Singapore		(4	)
Woodside Energy Holdings International Pty Ltd		Australia		(2,4	)
Woodside Energy International (Canada) Limited		Canada		(4	)
Woodside Energy (Canada LNG) Limited		Canada		(4	)
Woodside Energy (Canada PTP) Limited		Canada		(4	)
KM LNG Operating General Partnership		Canada		(9	)
KM LNG Operating Ltd		Canada		(4	)
Woodside Energy Holdings Pty Ltd		Australia		(2,3,4	)
Woodside Energy Holdings (USA) Inc		United States		(4	)
Woodside Energy (USA) Inc		United States		(4	)
Gryphon Exploration Company		United States		(4	)
Woodside Energy Holdings (NA) LLC		United States		(4	)
Woodside Energy (LA) Holdings Inc.		United States		(4,18	)
Woodside Energy (LA) Holdings Investments LLC		United States		(4,18	)
Woodside Energy (LA) Production Holdings LLC		United States		(4,18	)
Woodside Energy (LA) Production LLC		United States		(4,18	)
Woodside Energy (LA) Production Investments LLC		United States		(4,18	)
Woodside Energy (LA) OpCo LLC		United States		(4,18	)
Louisiana LNG Gas Management LLC		United States		(4,18	)
Woodside Energy (LA) Capital Holdings LLC		United States		(4,18	)
Woodside Energy (LA) Operating LLC		United States		(4,18	)
Louisiana LNG Expansion LLC		United States		(4,18	)
Louisiana LNG Expansion II LLC		United States		(4,18	)
Louisiana LNG LLC		United States		(4,18	)
Driftwood Pipeline LLC		United States		(4,18	)
Louisiana LNG Common Facilities LLC		United States		(4,18	)
Louisiana LNG Infrastructure LLC		United States		(4,18	)
Woodside Energy (LA) Corporate Services LLC		United States		(4,18	)
Woodside Energy (LA) Asset Services LLC		United States		(4,18	)
Woodside Energy (LA) Services LLC		United States		(4,18	)
Woodside Energy (LA) Management LLC		United States		(4,18	)
Delhi Connector LLC		United States		(4,18	)
Woodside Energy (LA) Trading LLC		United States		(4,18	)
Woodside Energy (LA) Marketing Ltd		United Kingdom		(4,18	)
Woodside Energy (LA) Trading UK Ltd.		United Kingdom		(4,18	)
Tellurian LNG Singapore Pte Ltd		Singapore		(4,18	)
Woodside Energy (LA) UK Ltd		United Kingdom		(4,18	)
Woodside Energy (LA) Supply LLC		United States		(4,18	)
PT Woodside Energy Indonesia		Indonesia		(6	)
Woodside Energy (Cameroon) SARL		Cameroon		(4	)
Woodside Energy (Gabon) Pty Ltd		Australia		(2,4	)
Woodside Energy (Indonesia) Pty Ltd		Australia		(2,4	)
Woodside Energy (Indonesia II) Pty Ltd		Australia		(2,4	)
Woodside Energy (Malaysia) Pty Ltd		Australia		(2,4	)
Woodside Energy (Ireland) Pty Ltd		Australia		(2,4	)
Woodside Energy (Korea) Pte Ltd		Singapore		(4	)
Woodside Energy (Korea II) Pte Ltd		Singapore		(4	)
Woodside Energy (Myanmar) Pte Ltd		Singapore		(4	)
Woodside Energy (Morocco) Pty Ltd		Australia		(2,4	)
Woodside Energy (New Zealand) Limited		New Zealand		(4	)
Woodside Energy Holdings (New Zealand) Limited		New Zealand		(4	)
Woodside Energy (Peru) Pty Ltd		Australia		(2,4	)
Woodside Energy (Tanzania) Limited		Tanzania		(7	)
Woodside Energy Holdings II Pty Ltd		Australia		(2,4	)
Woodside Power Pty Ltd		Australia		(2,4	)
Woodside Power (Generation) Pty Ltd		Australia		(2,4	)
Woodside Energy Holdings (South America) Pty Ltd		Australia		(2,4	)
Woodside Energia (Brasil) Apoio Administrativo Ltda		Brazil		(8	)
Woodside Energy Holdings (UK) Pty Ltd		Australia		(2,4	)

F-63

Notes to the financial statements E. Other items

for the year ended 31 December 2024

Name of entity	Country of incorporation		Notes
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 (Norway) Pty Ltd		Australia		(2,4	)
Woodside Energy Technologies Pty Ltd		Australia		(2,4,14	)
Woodside Technology Solutions Pty Ltd		Australia		(2,4	)
Woodside Energy Scarborough Pty Ltd		Australia		(2,3,4	)
Woodside Energy Carbon Holdings Pty Ltd		Australia		(2,4	)
Woodside Energy Carbon (Assets) Pty Ltd		Australia		(2,4	)
Woodside Energy Carbon (Services) Pty Ltd		Australia		(2,4	)
Woodside Energy (Financial Advisory Services) Pty Ltd		Australia		(2,4	)
Woodside Energy Trading Singapore Pte Ltd		Singapore		(4	)
WelCap Insurance Pte Ltd		Singapore		(4	)
Woodside Energy Shipping Singapore Pte Ltd		Singapore		(4	)
Metasource Pty Ltd		Australia		(2,4	)
Mermaid Sound Port and Marine Services Pty Ltd		Australia		(2,4	)
Woodside Finance Limited		Australia		(2,4	)
Woodside Petroleum (Timor Sea 19) Pty Ltd		Australia		(2,4	)
Woodside Petroleum (Timor Sea 20) Pty Ltd		Australia		(2,4	)
Woodside Petroleum Holdings Pty Ltd		Australia		(2,4,15	)
Woodside Energy Global Holdings Pty Ltd		Australia		(2,3,4	)
Woodside Energy Global Pty Ltd		Australia		(2,3,4	)
Perdido Mexico Pipeline Holdings, S.A. de C.V.		Mexico		(10	)
Perdido Mexico Pipeline, S. de R.L. de C.V.		Mexico		(10	)
Woodside Energy Investments Pty Ltd		Australia		(2,4	)
Woodside Energia Brasil Investimentos Ltda.		Brazil		(11	)
Woodside Energia Brasil Exploração e Produção Ltda.		Brazil		(11	)
Woodside Energy (Great Britain) Limited		United Kingdom		(4	)
Woodside Energy (North West Shelf) Pty Ltd		Australia		(2,3,4,15	)
Woodside Energy (Trinidad) Holdings Ltd		Saint Lucia		(4	)
Woodside Energy (Trinidad-3A) Ltd		R. of Trinidad and Tobago		(4	)
Woodside Energy USA Operations Inc		United States		(12	)
Hamilton Brothers Petroleum Corporation		United States		(4	)
Hamilton Oil Company LLC		United States		(4	)
Woodside Energy Boliviana Inc.		United States		(4	)
Woodside Energy (North America) LLC		United States		(4	)
Woodside Energy (Americas) Inc.		United States		(4	)
Woodside Energy (GOM) Inc.		United States		(4	)
Woodside Energy Hawaii Inc.		United States		(4,16	)
Woodside Energy Resources Inc.		United States		(4	)
Woodside Energy Holdings (Resources) Inc.		United States		(4	)
Woodside Energy USA Services Inc.		United States		(4	)
Woodside Energy Marketing Inc.		United States		(4	)
Woodside Energy (Deepwater) Inc.		United States		(4,17	)
Woodside Energy (USA New Energy Holdings) LLC		United States		(4	)
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	)

F-64

Notes to the financial statements E. Other items

for the year ended 31 December 2024

Name of entity	Country of incorporation		Notes
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		(13	)
Woodside Energía Servicios de México, S. de R.L. de C.V.		Mexico		(13	)
Woodside Energy (Mexico Holdings) LLC		United States		(4	)
Operaciones Conjuntas, S. de R.L. de C.V.		Mexico		(13	)
Woodside Energía Holdings de México, S. de R.L. de C.V.		Mexico		(13	)
Woodside Petróleo Operaciones de México, S. de R.L. de C.V.		Mexico		(13	)
Woodside Energy (Australia) Pty Ltd		Australia		(2,3,4	)
Woodside Energy (International Exploration) Pty Ltd		Australia		(2,4	)
Woodside Energy (Bass Strait) Pty Ltd		Australia		(2,3,4	)
Woodside Energy (Victoria) Pty Ltd		Australia		(2,4	)
Woodside Energy Holdings LLC		United States		(2,4	)
Woodside Energy (Trinidad-2C) Ltd		Canada		(4	)
OCI Clean Ammonia Holding BV		Netherlands		(4,19	)
OCI Clean Ammonia LLC		United States		(4,19	)
Woodside Energy (Canada) Corporation		Canada		(4	)
Koolbardi Pte Ltd		Singapore		(2,4,20	)

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 2024.

3. These companies were parties to the Deed of Cross Guarantee at 31 December 2024.

4. All subsidiaries are wholly owned except those referred to in Notes 5 to 13.

5. Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd (previously Tokyo Gas Pluto Pty Ltd) each hold a 5% interest in the shares of these subsidiaries. These subsidiaries are controlled.

6. As at 31 December 2024, Woodside Energy Holdings Pty Ltd held a 99% interest in the shares of PT Woodside Energy Indonesia. Woodside Energy Ltd held the remaining 1% interest.

7. As at 31 December 2024, Woodside Energy Holdings Pty Ltd held >99.99% interest in the shares of Woodside Energy (Tanzania) Limited and Woodside Energy Ltd held the remaining interest.

8. As at 31 December 2024, Woodside Energy Holdings (South America) Pty Ltd held >99.99% interest in the shares of Woodside Energia (Brasil) Apoio Administrativo Ltda and Woodside Energy Ltd held the remaining interest.

9. As at 31 December 2024, 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.

10. As at 31 December 2024, 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 2024, 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.

11. As at 31 December 2024, 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 2024, 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.

12. As at 31 December 2024, Woodside Energy Global Holdings Pty Ltd held 90% voting interest and 37.67% interest in shares of Woodside Energy USA Operations Inc. Woodside Energy Holdings LLC held the remaining 10% voting interest and 62.33% interest in shares.

13. As at 31 December 2024, Woodside Energy (Mexico) Limited held a 99% interest in shares of Woodside Energía Servicios Administrativos, S. de 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% and 0.01% interests. As at 31 December 2024, 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.

14. As at 31 December 2024, Woodside Energy Technologies Pty Ltd held 16.17% of the shares in Blue Ocean Seismic Services Limited which is accounted for as an investment in associate.

15. As at 31 December 2024, Woodside Energy (North West Shelf) Pty Ltd and Woodside Petroleum Holdings Pty Ltd each held 16.67% of the shares in International Gas Transportation Company Limited. This investment has been accounted for as an investment in associate.

16. As at 31 December 2024, Woodside Energy Hawaii Inc held 14.96% of the shares in Iwilei District Participating Parties LLC which is accounted for as an investment in associate.

17. As at 31 December 2024, Woodside Energy (Deepwater) Inc held 25% of the shares in Caesar Oil Pipeline Company LLC, 22% of the shares in Cleopatra Gas Gathering Company LLC and 10% of the shares in Marine Well Containment Company LLC. These are accounted for as investments in associates.

18. Subsidiaries acquired as part of the acquisition of Tellurian which completed on 8 October 2024.

19. Subsidiaries acquired as part of the acquisition of OCI which completed on 30 September 2024.

20. Koolbardi Pte Ltd was incorporated on 21 February 2024.

Classification

Subsidiaries are all the entities over which the Group has the power over the investee such that the Group is able to direct the relevant activities, has exposure, or rights, to variable returns from its involvement with the investee and has the ability to use its power over the investee to affect the amount of the investor’s returns.

F-65

Notes to the financial statements E. Other items

for the year ended 31 December 2024

(b) Subsidiaries with material non-controlling interests

The Group has two Australian subsidiaries with material non-controlling interests (NCI).

Name of entity	Principal place of business	% held by NCI
Burrup Facilities Company Pty Ltd	Australia		10%
Burrup Train 1 Pty Ltd	Australia		10%

The NCI in both subsidiaries is 10% held by the same parties (refer to Note E.8(a) footnote 5 for details).

The summarised financial information (including consolidation adjustments but before intercompany eliminations) of subsidiaries with material NCI is as follows:

	2024		2023		2022
	US$m		US$m		US$m
Burrup Facilities Company Pty Ltd
Current assets		332		513		567
Non-current assets		5,069		5,020		5,047
Current liabilities		(51)		(58)		(68)
Non-current liabilities		(553)		(568)		(528)
Net assets		4,797		4,907		5,018
Accumulated balance of NCI		480		491		502
Revenue		873		839		889
Profit		450		400		489
Profit allocated to NCI		45		40		49
Dividends paid to NCI		(56)		(51)		(43)
Operating		549		570		601
Investing		(47)		(58)		(45)
Financing		(502)		(512)		(556)
Net increase/(decrease) in cash and cash equivalents		-		-		-
Burrup Train 1 Pty Ltd
Current assets		291		453		429
Non-current assets		3,009		2,806		2,900
Current liabilities		(239)		(121)		(119)
Non-current liabilities		(322)		(341)		(325)
Net assets		2,739		2,797		2,885
Accumulated balance of NCI		274		280		289
Revenue		1,448		1,393		1,471
Profit		284		222		282
Profit allocated to NCI		28		22		28
Dividends paid to NCI		(34)		(31)		(29)
Operating		497		321		391
Investing		(242)		(80)		(55)
Financing		(255)		(241)		(336)
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

(a) Summary of other material accounting policies

Australia tax consolidation

The parent and its wholly owned Australian controlled entities have elected to enter a tax consolidation, with Woodside Energy Group Ltd as the head entity of the tax consolidated group. The members of the Australian tax consolidated group are identified in Note E.8(a).

The tax expense/benefit, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax consolidated group are recognised in the separate financial statements of the members of the tax consolidated group, using the stand-alone approach.

Entities within the tax consolidated group have entered into a tax funding arrangement and a tax sharing agreement with the head entity. Under the tax funding agreement, Woodside Energy Group Ltd and each of the entities in the tax consolidated group have agreed to pay or receive a tax equivalent payment to or from the head entity, based on the current tax liability or current tax asset of the entity.

F-66

Notes to the financial statements E. Other items

for the year ended 31 December 2024

The tax sharing agreement entered into between members of the tax consolidated group provides for the determination of the allocation of income tax liabilities between the entities, should the head entity default on its tax payment obligations. No amounts have been recognised in the financial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is considered remote.

US tax consolidation

The Group has two separate USA Tax Consolidation Groups as at 31 December 2024:

· 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.

· 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. The deferred tax assets and liabilities arising from temporary differences of the members of this tax consolidated group have not been recognised.

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. 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.

(b) New standards and interpretations

New and amended accounting standards adopted

A number of amended standards became applicable for the current reporting period. The Group did not make any significant changes to its accounting policies and did not make retrospective adjustments as a result of adopting these amended standards. These amendments did not materially impact the accounting policies or amounts disclosed in the year end financial statements of the Group.

New standards and interpretations not yet adopted

Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for the 31 December 2024 reporting period and have not been early adopted by the Group. These standards, amendments or interpretations are not expected to have a material impact to the Group in the current or future reporting periods and on foreseeable future transactions. The assessment of the impact of IFRS 18 Presentation and Disclosure in Financial Statements effective from 1 January 2027 is currently in progress.

F-67

Consolidated entity disclosure statement

As at 31 December 2024

Consolidated entity disclosure statement

Note not required for the purposes of US reporting.

F-68

Directors’ declaration

Directors’ declaration

Not required for the purposes of US reporting.

F-69

PwC - 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 statement of financial position of Woodside Energy Group Ltd and its subsidiaries (the “Company”) as of December 31, 2024 and 2023, and the related statements of consolidated income, consolidated comprehensive income, consolidated changes in equity and consolidated cash flows for each of the three years in the period ended December 31, 2024, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 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, 2024, 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 within 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.

As described in management’s annual report on internal control over financial reporting within Item 15 Controls and Procedures, management has excluded OCI Clean Ammonia Holding B.V. and Tellurian Inc. from its assessment of internal control over financial reporting as of December 31, 2024 because they were acquired by the Company in purchase business combinations during 2024. We have also excluded OCI Clean Ammonia Holding B.V. and Tellurian Inc. from our audit of internal control over financial reporting. OCI Clean Ammonia Holding B.V. and Tellurian Inc. are wholly-owned subsidiaries whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent in aggregate 7% and 0%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2024.

F-70

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, 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.

OCI Clean Ammonia Holding B.V. business combination – valuation of the fair value of net assets acquired

As described in Note B.5 to the consolidated financial statements, the Company completed the acquisition of OCI Clean Ammonia Holding B.V. and its Beaumont New Ammonia project for total purchase consideration of $2,370 million on September 30, 2024. The acquisition method of accounting was used by management to account for this business combination, under which the fair value of net identifiable assets was provisionally estimated at acquisition date to be $2,201 million, giving rise to goodwill from the acquisition of $169 million. Estimating the fair value of net assets acquired requires the selection of appropriate valuation methodologies which included the reproduction cost method to value the property, plant and equipment acquired, and the use of cash flow models underpinned by significant estimates and assumptions to value the acquired intangible assets.

The principal considerations for our determination that performing procedures relating to the valuation of the fair value of net assets acquired as part of the OCI Clean Ammonia Holding B.V. business combination is a critical audit matter are (i) there is a significant level of judgment applied by management in determining the fair value of net assets acquired, including the use of management’s specialists to assist in the estimation of fair value; (ii) this in turn led to a high degree of auditor judgment, effort and subjectivity in performing procedures and evaluating management’s valuation methodology, significant assumptions and estimates; and (iii) the nature and extent of audit effort required to perform the procedures and evaluate management’s valuation methodology, significant assumptions and estimates required 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 business combinations; (ii) assessing the nature of the acquisition to determine if the acquisition is a business combination due to the stage of completion on the Beaumont New Ammonia project and the timing of transfer of employees; (iii) evaluating management’s accounting for the fair value of net assets acquired in a business combination against the requirements of IFRS, and our understanding of the acquisition agreement and the acquired net assets of OCI Clean Ammonia Holding B.V.; (iv) assessing the valuation methodology applied by management to estimate the fair value of net assets acquired at September 30, 2024, including assessing the reasonableness of significant estimates and assumptions; (v) evaluating the work of management’s specialists involved in the determination of significant assumptions and estimates; (vi) evaluating the disclosures made regarding the business combination in the consolidated financial statements against the requirements of IFRS; and (vii) professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of management’s fair value estimates.

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 $42,636 million, and the Company’s goodwill balance was $3,866 million as of December 31, 2024. 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, 2024, 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.

F-71

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 required 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 $2,393 million as of December 31, 2024, of which $1,448 million relates to PRRT, including the Pluto PRRT DTA which increased by $502 million during the year on the basis of future taxable profits being available to utilize the deductible expenditure. 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 required 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

Perth, Australia

February 25, 2025

We have served as the Company’s auditor since 2022.

F-72

Supplementary information on oil and gas (unaudited)

See “Item 4.B Business Overview” in this 2024 Form 20-F for Supplementary oil and gas information pursuant to FASB 932.

F-73

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	Indenture, dated as of 3 November 2003, by and among Woodside Finance Limited, Woodside Petroleum Ltd., Woodside Energy Ltd. and the Bank of New York (incorporated by reference to Exhibit 10.1 of the Registrant’s registration statement on Form F-4 (File No. 333-264268) filed with the Commission on 13 April 2022).
4.3	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).
4.4	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).
4.5	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 of Woodside
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 2024 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 2024 Form 20-F, as specified elsewhere in this 2024 Form 20-F. With the exception of the items and pages so specified, the Woodside 2024 Annual Report is not deemed to be filed as part of this 2024 Form 20-F.

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/ Marguerite O’Neill

Marguerite O’Neill

Chief Executive Officer

Dated: 25 February 2025