6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of August 2024

Commission File Number: 001-41404

Woodside Energy Group Ltd

(ABN 55 004 898 962)

(Registrant’s name)

Woodside Energy Group Ltd

Mia Yellagonga, 11 Mount Street

Perth, Western Australia 6000

Australia

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ☑   Form 40-F ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

THIS REPORT ON FORM 6-K IS BEING FILED FOR THE PURPOSES OF INCORPORATION BY REFERENCE IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NOs. 333-277499 AND 333-277499-01) AND THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NOS. 333-274296, 333-270076, 333-267432 AND 333-265606). THIS REPORT SHALL BE DEEMED FILED AND INCORPORATED BY REFERENCE IN SUCH REGISTRATION STATEMENTS AND SHALL BE DEEMED TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FILED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

The documents included as exhibits to this report includes portions from previously published announcements of Woodside Energy Group Ltd (the “Company”) for the purposes of incorporating certain information by reference into the Company’s Registration Statement on Form F-3 in accordance with the terms set out in that document. This document does not update or otherwise supplement the information contained in the previously published announcements identified below.

EXHIBIT INDEX

Exhibit Number	Description
99.1	Half Year Report for the period ended June 30, 2024, containing the unaudited consolidated financial statements for the half year ended June 30, 2024.
99.2	Second Quarter Report for the period ended June 30, 2024, containing operational information for the period ended June 30, 2024.
99.3	Select information concerning the Company’s strategy, industry and performance previously published in connection with the Company’s full-year 2023 and half-year 2024 results.
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)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: August 30, 2024

WOODSIDE ENERGY GROUP LTD
By:	/s/ Lucy Bowman
	Lucy Bowman Corporate Secretary

EX-99.1

Exhibit 99.1

About this report

This Half-Year Report 2024 is a summary of Woodside’s operations, activities and financial position as at 30 June 2024. Woodside Energy Group Ltd (ABN 55 004 898 962) is the parent company of the Woodside group of companies. In this report, unless otherwise stated, references to ‘Woodside’, ‘the company’, ‘the Group’, ‘we’, ‘us’ and ‘our’ refer to Woodside Energy Group Ltd and its controlled entities as a whole. The text does not distinguish between the activities of the parent company and those of its controlled entities.

References to ‘H1’ refer to the first half of the year, i.e. the period between 1 January 2024 and 30 June 2024. All dollar figures are expressed in US currency unless otherwise stated. Production and sales volumes, reserves and resources are quoted as Woodside share. A glossary of key terms, units of measure and conversion factors is on pages A-10 to A-14.

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, statements regarding outcomes of transactions, including the timing, terms and potential benefits of the proposed acquisition of Tellurian and OCI’s Clean Ammonia Project, 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, assumptions 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 include, but are not limited to, fluctuations in commodity prices, actual demand for Woodside’s 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, environmental risks, climate related risks, physical risks, legislative, fiscal and regulatory developments, changes in accounting standards, economic and financial markets conditions in various countries and regions, political risks, the actions of third parties, project delay or advancement, regulatory approvals, the impact of armed conflict and political instability (such as the ongoing conflict in Ukraine and in the Middle East) on economic activity and oil and gas supply and demand, cost estimates, 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 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.

In addition to the summary of ‘Principal risks and uncertainties’ on page 18 of this report, a more detailed summary of the key risks relating to Woodside and its business can be found in the “Risk” section of Woodside’s most recent Annual Report released to the Australian Securities Exchange and the London Stock Exchange and in Woodside’s most recent Annual Report on Form 20-F filed with the United States Securities and Exchange Commission and available on the Woodside website at https://www.woodside.com/investors/reports-investor-briefings. 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.

Woodside Energy Group Ltd | Half-Year Report 2024 1

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, Woodside does not intend to, undertake to, or assume 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, 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.

Non-IFRS Measures

Throughout this report, a range of financial and non-financial measures are used to assess Woodside’s performance, including a number of financial measures that are not defined in, and have not been prepared in accordance with, International Financial Reporting Standards (IFRS) and are not recognised measures of financial performance or liquidity under IFRS (Non-IFRS Financial Measures). These measures include EBIT, EBITDA excluding impairment, Gearing, Underlying NPAT, Net debt, Liquidity, Free cash flow, Capital expenditure, Exploration expenditure, Return on Equity, Return on average capital employed, Cash margin, Production cost margin, Other cash cost margin, Net tangible assets and Net tangible assets per ordinary security. These Non-IFRS Financial Measures are defined in the glossary on pages A-10 to A-14 of this report. A quantitative reconciliation of these measures to the most directly comparable financial measure calculated and presented in accordance with IFRS can be found in the Alternative Performance Measures section of this report on pages A-8 to A-9.

Woodside’s management uses these measures to monitor Woodside’s financial performance alongside IFRS measures to improve the comparability of information between reporting periods and business units and Woodside believes that the Non-IFRS Financial Measures it presents provide a useful means through which to examine the underlying performance of its business.

Undue reliance should not be placed on the Non-IFRS Financial Measures contained in this report and these Non-IFRS Financial Measures should be considered in addition to, and not as a substitute for, or as superior to, measures of financial performance, financial position or cash flows reported in accordance with IFRS. Non-IFRS Financial Measures are not uniformly defined by all companies, including those in Woodside’s industry. Accordingly, they may not be comparable with similarly titled measures and disclosures by other companies.

Climate strategy and emissions data

All greenhouse gas emissions data in 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 emissions, Scope 2 greenhouse emissions, and/or Scope 3 greenhouse emissions, unless otherwise stated. For more information on Woodside’s climate strategy, including references to ‘lower carbon’ and ‘lower carbon services’ as part of that strategy, and emissions data, refer to Woodside’s Climate Transition Action Plan and 2023 Progress Report available at woodside.com.

No express or implied prices

This report does not include any express or implied prices at which Woodside will buy or sell financial products.

Woodside Energy Group Ltd | Half-Year Report 2024 2

HALF-YEAR REPORT FOR PERIOD ENDED 30 JUNE 2024

ASX: WDS | NYSE: WDS | LSE: WDS

Tuesday, 27 August 2024

High-quality business delivering strong dividends

Financial highlights

• Net profit after tax of $1,937 million.

• Underlying net profit after tax of $1,632 million.1

• Cash flow from operating activities of $2,393 million, cash flow used in investing activities of US$(1,653) million and positive free cash flow of $740 million.1

• Australian tax and royalty payments of A$2,682 million.

• Liquidity of $8,479 million.1,2

• Determined a fully franked interim dividend of 69 US cents per share (cps), at the top end of the payout range and representing a half-year annualised dividend yield of 7.3%.3

Operational highlights

• Delivered H1 production of 89.3 MMboe (491 Mboe/d). Full year production guidance remains unchanged.

• Reduced unit production cost to $8.3/boe ($8.8/boe in H1 2023) despite the inflationary environment.

• Achieved first oil at the Sangomar Project in June 2024. Subsequent to the period the project achieved nameplate capacity with gross production rates of 100,000 barrels per day.

• Continued to embed the Field Leadership Program to strengthen our learning culture and improve safety outcomes.

• Took a final investment decision (FID) on Lambert West, Xena-3 and Atlantis Drill Centre 1 Expansion (DC1X).

Business highlights

• The Scarborough Energy Project was 67% complete at the end of H1 2024, with first LNG cargo expected in 2026.4

• Signed an agreement with JERA for the sale of a 15.1% non-operated participating interest in the Scarborough Joint Venture (SJV). Estimated total consideration for the sale is $1,400 million.5

• Completed the sale of a 10% non-operated participating interest in the SJV to LNG Japan for $910 million.6

• Signed sale and purchase agreements (SPAs) with Korea Gas Corporation (KOGAS) and CPC Corporation, Taiwan (CPC) for the long-term supply of LNG to Korea and Taiwan respectively.

• Continued to progress the Trion Project engineering, procurement and contracting.

• Subsequent to the period, Woodside entered into two transactions that have significant cash generation potential to underpin long-term shareholder value. These are agreements to acquire:

• Tellurian, including its US Gulf Coast Driftwood LNG development opportunity, for an all-cash payment of approximately $900 million; and

• OCI’s Clean Ammonia Project in Beaumont, Texas for an all-cash consideration of approximately $2,350 million.

1  Non-IFRS measure. Refer to pages A-8 to A-9 for further information.

2  Woodside cancelled $1,550 million of undrawn facilities in July 2024. This cancellation has the effect of reducing our liquidity by US$1,550 million.

3  Calculated based on Woodside’s closing share price on 28 June 2024 of A$28.21 and a US$:A$ exchange rate of 0.67.

4  The completion % excludes the Pluto Train 1 modifications project.

5  The SPA is with JERA Scarborough Pty Ltd which is a wholly owned subsidiary of JERA Co., Inc. Subject to completion of the transaction, targeted for the second half of 2024.

6  LJ Scarborough Pty Ltd (LNG Japan) is a jointly owned subsidiary of LNG Japan Corporation (which is a 50:50 joint venture between Sumitomo Corporation and Sojitz Corporation) and Japan Organization for Metals and Energy Security (JOGMEC). JOGMEC has a 49.9% interest in LJ Scarborough Pty Ltd.

Woodside Energy Group Ltd | Half-Year Report 2024 3

Summary

Woodside reported net profit after tax (NPAT) for the half-year of $1,937 million. Production was 89.3 MMboe (491 Mboe/d) and underlying NPAT7 was $1,632 million, down 14% on the corresponding period in 2023.

The directors have determined a fully franked interim dividend of 69 US cents per share (cps), representing an approximately 80% payout ratio of underlying NPAT.

Woodside Energy CEO Meg O’Neill said the results demonstrate how Woodside’s high performing base business continues to deliver strong dividends to shareholders while laying a foundation for future success.

“We maintained high reliability of 97.9% at our operated LNG assets and continue to manage costs effectively in an inflationary environment.

“In the first half of 2024 we delivered on a significant element of our strategy, achieving first production from Sangomar, Senegal’s first offshore oil project. Production ramp-up at Sangomar has progressed well and subsequent to the period, peak gross production rate of 100,000 barrels per day was achieved, demonstrating Woodside’s world-class project execution capability. Sangomar will deliver enduring value for Woodside shareholders and benefits for our partner Petrosen and the people of Senegal.

“We also made good progress on the Scarborough Energy Project in Western Australia, which is more than two-thirds complete and on track for first LNG cargo in 2026. Work on the Scarborough floating production unit passed a major milestone with structural completion of the topsides. Pluto Train 2 site works continued with 29 of the 51 modules delivered and 25 modules set in position.

“We completed the sale of a 10% non-operating participating interest in the Scarborough Joint Venture (SJV) to LJ Scarborough Pty Ltd (LNG Japan) for $910 million and executed a binding sale and purchase agreement for the sale of a further 15.1% non-operating participating interest in the SJV to JERA.

“Long-term LNG supply agreements were also reached with Korea Gas Corporation and with CPC Corporation, Taiwan, underlining the importance of LNG in regional energy security.

“Our agreement last month to acquire Tellurian, including its US Gulf Coast Driftwood LNG development further strengthens our LNG portfolio, complementing our existing Pacific basin position with additional exposure in the Atlantic basin. Woodside expects to leverage its global LNG expertise to unlock this development and enable long-term cashflow generation.

“In our new energy business, all primary environmental approvals have been secured for the Hydrogen Refueller @H2Perth, which is targeting supplying industrial customers in Western Australia in 2025. We have also progressed several carbon capture and storage (CCS) opportunities, including the signing of a memorandum of understanding between the Angel CCS Joint Venture and Yara Pilbara Fertilisers to study the use of the technology.

“We continue to deliver on our strategy to thrive through the energy transition whilst maintaining our disciplined capital management. Our agreement to acquire OCI’s Clean Ammonia project in Texas positions Woodside to be an early mover in the emerging lower carbon ammonia industry and makes a significant contribution to delivering our Scope 3 targets.

“Above all, we are committed to continually improving safety and have focused on strengthening our safety culture, simplifying our processes and improving our systems.

“As we officially mark 70 years as an Australian company, I am proud that Woodside is facing the future with the same spirit of innovation and determination that our founders showed.”

7  Non-IFRS measure. Refer to pages A-8 to A-9 for further information.

Woodside Energy Group Ltd | Half-Year Report 2024 4

Financial summary

Key metrics

			H1 2024			H1 2023			Change %
Operating revenue	$	million		5,988			7,400			(19	%)
EBITDA excluding impairment8	$	million		4,371			4,888			(11	%)
EBIT8	$	million		2,362			2,791			(15	%)
Net profit after tax (NPAT)9,10	$	million		1,937			1,740			11	%
Underlying NPAT8	$	million		1,632			1,896			(14	%)
Cash flow from operating activities11	$	million		2,393			2,951			(19	%)
Cash flow used in investing activities	$	million		(1,653	)		(2,637	)		37	%
Free cash flow8,11,12	$	million		740			314			136	%
Dividends distributed	$	million		1,310			1,519			(14	%)
Interim dividend declared		US cps		69			80			(14	%)
Key ratios
Earnings		US cps		102.2			91.7			11	%
Gearing8		%		13.3			8.2			5.1	%
Production volumes13,14
Gas		MMboe		60.9			63.5			(4	%)
Liquids		MMboe		28.4			27.8			2	%
Total		MMboe		89.3			91.3			(2	%)
Production volumes per day13
Gas		MMscf/d		1,907			1,999			(5	%)
Liquids		Mbbl/d		156			154			1	%
Total		Mboe/d		491			504			(3	%)
Sales volumes14
Gas		MMboe		65.0			72.0			(10	%)
Liquids		MMboe		28.9			26.8			8	%
Total		MMboe		93.9			98.8			(5	%)
Sales volumes per day
Gas		MMscf/d		2,035			2,268			(10	%)
Liquids		Mbbl/d		159			148			7	%
Total		Mboe/d		516			546			(5	%)

8  This 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, but 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. Refer to Alternative Performance Measures on pages A-8 to A-9 for a reconciliation for these measures to Woodside’s financial statements and Non-IFRS Measures on page 2 for more information about non-IFRS measures.

9  Net profit after tax attributable to equity holders of the parent.

10  Subsequent to achieving first oil on the Sangomar project in June 2024, the Group has recognised a net deferred tax asset of $305 million. The expected sale of Woodside’s 15.1% share in the Scarborough Joint Venture resulted in the recognition of a net tax benefit of $91 million. These events have resulted in a reduction of the global effective income tax rate from 25.6% to 6.9%. In the prior period, as a result of the final investment decision to develop the Trion resource, the Group recognised deferred tax assets of $319 million, resulting in a reduction of the global effective income tax rate from 29.6% to 13.9%.

11  Purchases of shares relating to employee share plans, which were previously classified within cash flows used in operating activities, has been classified within cash flows used in financing activities for the half-year ended 2024. The 2023 comparatives have been reclassified to be presented on the same basis.

12  Cash flow from operating activities less cash flow from investing activities.

13  Includes production of 88.7 MMboe from Woodside reserves and 0.6 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

14  The conversion factors used throughout this report are set out on pages A-13 to A-14, unless otherwise stated. Sales volumes differ from production volumes primarily due to the timing of liftings and the exclusion of third-party purchased volumes.

Woodside Energy Group Ltd | Half-Year Report 2024 5

Appendix 4D

Results for announcement to the market

More information is available on page 44

					US$ million
Revenue from ordinary activities	Decreased	19	%15	to		5,988
Profit from ordinary activities after tax attributable to members	Increased	11	%15	to		1,937
Net profit for the period attributable to members	Increased	11	%15	to		1,937
Interim dividend – fully franked	69 US cps H1 2024
Record date for determining entitlements to the dividend	6 September 2024

Net profit after tax reconciliation

The following table summarises the variance between the H1 2023 and H1 2024 results for the contribution of each line item to NPAT.

	US$m	Primary reasons for variance
2023 H1 reported NPAT	1,740
Revenue from sale of hydrocarbons
Price	(1,077)	Lower average realised prices.
Volume	(364)	Fewer third-party LNG trades classified as revenue and natural field decline.
Other operating revenue	29	Increase in processing and services revenue.
Cost of sales	600	Lower royalties, trading costs and depreciation expense in H1 2024 and Pluto turnaround activities in the prior period.
Other income	181	Gain on SJV sell-down to LNG Japan.
Other expenses	134	Lower fair value losses on embedded derivatives.
Impairment losses	68	Pre-tax impairment of Pyrenees recognised in prior period.
Income tax and PRRT expense	724	Recognition of the Trion deferred tax asset (DTA) offset by derecognition of the Pluto PRRT DTA, both not present in the current period. H1 2024 includes the first-time recognition of a net DTA for the Sangomar Project.
Other	(98)
2024 H1 reported NPAT	1,937
2024 H1 NPAT adjustments	(305)	Adjustment for the recognition of the Sangomar DTA.
2024 H1 underlying NPAT	1,632

15  Comparisons are to half-year ended 30 June 2023.

Woodside Energy Group Ltd | Half-Year Report 2024 6

Capital management

Woodside’s capital management framework provides us with the flexibility to optimise value and shareholder returns delivered from our portfolio.

Interim dividend and dividend reinvestment plan

A 2024 fully franked interim dividend of 69 US cps has been determined, representing a half-year annualised dividend yield of 7.3%.16 The total amount of the interim dividend payment is $1,310 million which represents approximately 80% of underlying NPAT for the first half of 2024.17

The dividend reinvestment plan (DRP) remains suspended.

Liquidity and Balance sheet

In H1 2024, Woodside generated $2,393 million of cash flow from operating activities and $(1,653) million of cash flow used in investing activities and delivered positive free cash flow of $740 million.17,18

Woodside increased its standby debt facilities from $6,050 million to $6,500 million. Cash and cash equivalents at the end of the period were $1,979 million. Liquidity19 at the end of the period was $8,479 million and Woodside’s drawn debt at the end of the period was $5,850 million.

Woodside entered into a $1,000 million 10-year loan with the Japan Bank for International Cooperation (JBIC) to support the Scarborough Energy Project which was available for drawdown from the end of June 2024. In addition, Woodside entered into a $450 million 10-year loan from commercial banks for general corporate purposes. Subsequent to the period, $1,550 million of undrawn facilities were cancelled. This cancellation has the effect of reducing our liquidity by $1,550 million. As part of active debt management, Woodside continues to review options to further access the debt market.

Net debt at the end of the period increased 67% from H1 2023 to $5,388 million, in line with planned capital expenditure.17 Woodside’s gearing at the end of the first half was 13.3%, within our target range of 10-20%.17

As a result of the recent announcements to acquire Tellurian, including its Driftwood LNG development, and OCI’s Clean Ammonia Project, Woodside expects its gearing to be above the top end of the target range for a period of time as the balance sheet is managed through the investment cycle.

Woodside’s commitment to an investment grade credit rating remains unchanged and supports our aim of providing sustainable returns to shareholders and investing in future growth opportunities, in accordance with the capital allocation framework.

Commodity price risk management

Woodside hedges to protect the balance sheet against downside commodity price risk, particularly during periods of high capital expenditure.

As at 30 June 2024, Woodside has placed oil price hedges for:

• approximately 29.3 MMboe of 2024 production at an average price of $75.6 per barrel, of which approximately 14.4 MMboe has been delivered; and

• a further 15 MMboe of 2025 production at an average price of approximately $81.2 per barrel.

Woodside has also placed a number of hedges for Corpus Christi LNG volumes to protect against downside commodity price risk. These hedges are Henry Hub and Title Transfer Facility (TTF) commodity swaps. Approximately 70% of Corpus Christi volumes for the remainder of 2024, 48% of 2025 and 9% of 2026 volumes have reduced pricing risk as a result of hedging activities.

16  Calculated based on Woodside’s closing share price on 28 June 2024 of A$28.21 and a US$:A$ exchange rate of 0.67.

17  These are non-IFRS measures. Refer to Alternative Performance Measures for a reconciliation for these measures to Woodside’s financial statements on pages A-8 to A-9 and Non-IFRS Measures on page 2 for more information about non-IFRS measures.

18  Cash flow from operating activities less cash flow used in investing activities.

19  Liquidity refers to total cash and cash equivalents and available undrawn debt facilities less restricted cash. Subsequent to the period, Woodside cancelled $1,550 million of undrawn facilities. As a result, Woodside’s liquidity was $6,929 million.

Woodside Energy Group Ltd | Half-Year Report 2024 7

Australian operations

Pluto LNG

Pluto LNG is a gas processing facility in the Pilbara region of Western Australia, comprising an offshore platform and one onshore LNG processing train.

Woodside’s share of production in H1 2024 was 26.9 MMboe. This was a 15% increase compared with H1 2023 which was impacted by planned turnaround activities, partially offset by reduced reliability following an offshore trip and a separate electrical fault onshore in H1 2024.

Woodside took FID for the Xena-3 well to support ongoing production from the project and started-up the produced water handling unit at the Pluto A platform.

Drilling of the PLA-08 production well commenced in June 2024.

Approvals were also granted to extend Pluto gas flows through the Pluto-Karratha Gas Plant Interconnector (Interconnector) from April 2024 to approximately December 2025, enabling continued acceleration of LNG and domestic gas production. The Interconnector generated incremental revenue of $315 million in H1 2024.

Woodside is operator and holds a 90% participating interest.

Woodside Solar

Woodside is progressing a potential opportunity to reduce gross Scope 1 greenhouse gas emissions at Pluto LNG by utilising solar energy from the proposed Woodside Solar Project.

In H1 2024, Woodside continued to work closely with the Western Australian Government to progress its plans to develop common user transmission infrastructure that will be required to transmit renewable energy from the proposed solar facility to Pluto LNG via the North-West Interconnected System.

Woodside Solar FID and first solar energy import timing are subject to securing access to this new power transmission infrastructure and finalising associated commercial agreements.

North West Shelf Project

The North West Shelf Project (NWS) consists of three offshore platforms and the onshore Karratha Gas Plant (KGP) which includes five onshore LNG processing trains and two domestic gas trains.

Woodside’s share of production in H1 2024 was 19.6 MMboe. This was a 14% decrease compared with H1 2023 due to planned offshore maintenance and natural field decline. In H1 2024, 6.0 MMboe of Pluto gas was processed at KGP through the Interconnector.

Woodside continues to look for opportunities to harness value from our late-life assets. In H1 2024, the NWS Joint Venture participants took FID on the Lambert West Project which will support ongoing production from NWS. Discussions continue between the NWS Joint Venture participants and other resource owners for the processing of third-party gas to utilise ullage at KGP. Processing of Waitsia gas continued and is expected to ramp up when the Waitsia Stage 2 facility commences production, which is expected in late 2024.

As the NWS celebrates 40 years of operations, the project is entering a period of production decline. KGP currently has processing ullage due to natural field decline and the current level of third-party gas processing demand. To manage both operating costs and emissions, NWS is preparing to take one LNG train offline between late 2024 and mid-2025.

State and Commonwealth regulatory approval processes are progressing for the North West Shelf Project Extension, which will support long-term operations and processing of future third-party gas resources at KGP.

Woodside is operator and holds a 33.33% participating interest.

Woodside Energy Group Ltd | Half-Year Report 2024 8

Wheatstone and Julimar-Brunello

Wheatstone is an LNG processing facility near Onslow, Western Australia, comprising an offshore production platform and two onshore LNG production trains. It processes gas from several offshore gas fields including Julimar and Brunello.

Woodside’s share of Wheatstone production in H1 2024 was 5.8 MMboe. This was a 12% decrease compared with H1 2023, due to unplanned outages impacting the Julimar subsea production system and the Wheatstone facility respectively.

Woodside is operator and holds a 65% participating interest in the Julimar-Brunello fields.

Woodside holds a 13% non-operating participating interest in the Wheatstone Project.

Bass Strait

Bass Strait is located in the south east of Australia and produces oil and gas through a network of offshore platforms, pipelines and onshore processing facilities. The Bass Strait assets include the Gippsland Basin Joint Venture (GBJV) and the Kipper Unit Joint Venture (KUJV).

Woodside’s share of production from Bass Strait was 8.5 MMboe in H1 2024, a 22% decrease from H1 2023 predominantly due to lower domestic gas market demand, offshore maintenance, and reduced crude oil production due to field decline. All of Woodside’s share of the gas produced from Bass Strait is supplied into the eastern Australian domestic gas market.

The GBJV is optimising facilities through the Gippsland Asset Streamlining project as production rates from the Bass Strait decline. As planned, production from the West Kingfish and Halibut oil platforms ceased in March and April 2024 respectively.

The Kipper Compression Project offshore modules have been successfully installed. The project is planning for startup in Q3 2024, to enable continued supply of gas to the domestic market.

Woodside holds a 50% non-operating participating interest in the GBJV and a 32.5% non-operating participating interest in the KUJV.

Other Australian oil and gas assets

Woodside operates three FPSO facilities off the north west coast of Western Australia. These are the Okha FPSO (Woodside participating interest: 50%), Ngujima-Yin FPSO (Woodside participating interest: 60%) and Pyrenees FPSO (Woodside participating interest: 40% in WA-43-L and 71.4% in WA-42-L).

Woodside’s share of production from the FPSO assets was 3.0 MMboe in H1 2024. This was a 3% decrease from H1 2023 primarily due to the planned five-yearly Pyrenees FPSO maintenance turnaround and the Pyrenees shut-in following a produced-water leak identified subsea at the facility. Production at Pyrenees recommenced in June 2024 and the produced-water leak has been rectified.

Macedon (Woodside participating interest: 71.4%), also operated by Woodside, is a gas project located near Onslow, Western Australia which produces pipeline gas for the Western Australian domestic gas market.

Woodside’s share of production from Macedon was 3.9 MMboe, down from 4.1 MMboe in H1 2023. The Macedon facility delivered approximately 11% of the Western Australian domestic gas market supply in H1 2024.

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International operations

Sangomar

The Sangomar Field Development Phase 1 is a deepwater project including a stand-alone FPSO facility moored approximately 100 kilometres offshore Senegal and subsea infrastructure that is designed to allow subsequent development phases.

First oil was achieved in June 2024, marking the delivery of Senegal’s first offshore oil project. Woodside’s share of production from Sangomar in H1 2024 was 0.5 MMboe. Subsequent to the period, nine production wells have come online, and the project successfully achieved peak gross rate of 100,000 barrels per day. Commissioning activities are expected to continue through 2024.

Sales of the initial Sangomar crude cargoes have been finalised, with interest received from European and Asian refiners. Subsequent to the period, the first two cargoes were loaded and delivered to Europe and a third cargo was loaded for delivery to Asia.

The project was 98% complete at the end of H1 2024. The development drilling program continues with 22 of the 23 wells drilled and completed.20 An additional 24th well approved by the Rufisque, Sangomar and Sangomar Deep (RSSD) Joint Venture was also drilled and completed.

Woodside has filed action with the High Court of Dakar disputing a tax assessment from the Senegalese tax authorities. The majority of the tax claims relate to the application of an exemption that applied during the project development phase.

Woodside is operator and has an 82% participating interest in the project.

Shenzi

Shenzi is a conventional oil and gas field developed through a tension leg platform located in the US Gulf of Mexico. Woodside’s share of production in H1 2024 was 5.2 MMboe. This was a 7% decrease compared with H1 2023 due to natural field decline and maintenance activity. Woodside is operator and holds a 72% participating interest.

Atlantis

Atlantis is a conventional oil and gas development and is one of the largest producing fields in the US Gulf of Mexico. The Atlantis development includes a semi-submersible facility with 28 active producer wells and three water injector wells.

Woodside’s share of production in H1 2024 was 5.1 MMboe. This was a 19% decrease compared with H1 2023 due to planned turnaround activity.

In H1 2024, the first horizontal well in the field was successfully completed, potentially unlocking future infill opportunities for the asset. An FID was taken at DC1X, which will be a two-well tie back to the Atlantis facility through the existing DC1 manifold in the southwest of the field. Woodside holds a 44% non-operating participating interest.

Mad Dog

Mad Dog is a conventional oil and gas development located in the US Gulf of Mexico. Mad Dog Phase 2 is a development of the southern flank of the Mad Dog field though the new Argos floating production facility.

Woodside’s share of production in H1 2024 was 6.0 MMboe. This was a 122% increase compared with H1 2023 primarily due to a full period of production from Mad Dog Phase 2.

The Argos facility continued to safely and systematically ramp up production in H1 2024, following completion of the riser flex joint remediation, and achieved peak production of approximately 130 Mbbl/d. The first water injection at the Argos platform was achieved in April 2024. Woodside holds a 23.9% non-operating participating interest.

20  The 22nd well was drilled subsequent to the period.

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Greater Angostura

Greater Angostura includes the Angostura and Ruby conventional oil and gas fields, located offshore Trinidad and Tobago. The development includes an offshore central processing facility and five wellhead platforms.

Woodside’s share of production in H1 2024 was 4.5 MMboe. This was a 20% decrease compared with H1 2023 due to the planned maintenance activity.

In H1 2024, Woodside continued to pursue opportunities to maximise value and safely optimise production and operating costs. A planned facility maintenance turnaround was completed in June 2024.

Woodside is operator of both fields and holds a 45% participating interest in the Angostura field and a 68.5% participating interest in the Ruby field.

Marketing and Trading

The marketing segment’s profit before tax and net finance costs in H1 2024 was $218 million. This reflected the optimisation activities and incremental value generated through the marketing, trading and shipping of Woodside’s oil and gas and through third-party purchased volumes.

In H1 2024, Woodside signed SPAs with KOGAS and CPC for the long-term supply of LNG to Korea and Taiwan respectively. The KOGAS SPA is for the supply of approximately 0.5 Mtpa of LNG from 2026, for a period of 10.5 years.

The CPC SPA is for the supply of approximately 6 million tonnes of LNG over 10 years, from July 2024. Under the CPC SPA, Woodside may also deliver approximately 8.4 million tonnes of LNG for a further 10 years, from 2034 to 2043.21

LNG delivered under both SPAs will be sourced from volumes across Woodside’s global portfolio.

In Western Australia, Woodside executed 14 PJ of sales for delivery into the domestic market from May to the end of 2024. Woodside continues to support the Western Australian domestic market by offering additional supply for 2025, 2026 and 2027.

A record quantity of trucked LNG (approximately 850 TJ) was delivered in H1 2024 to customers in northern Western Australia. Since the commencement of operations at the Pluto LNG Truck Loading Facility in 2019, Woodside has delivered more than 2,000 trailers of LNG (approximately 2,240 TJ), offering a lower-carbon alternative to diesel.22

In the east coast of Australia, Woodside was granted an exemption under the applicable domestic gas price cap legislation. The exemption provides Woodside the opportunity to increase delivery to the domestic market by more than 260 PJ (100% share) through to 2033 if needed. Woodside conducted an expression of interest for Bass Strait supply for 2025 and 2026 totalling 50 PJ and is progressing towards final offers in line with the conditions set under the Mandatory Code of Conduct.

In Trinidad and Tobago, incremental gas production from the Angostura field was placed under the existing gas SPA with the National Gas Company of Trinidad and Tobago (NGC). This ongoing optimisation maximises our production efficiency and provides a reliable supply of natural gas to meet growing customer demand.

Woodside’s marketing and trading portfolio is supported by our shipping capacity, which includes seven vessels under long-term charter and multiple vessels on short-term charter. A new 174,000m3 long-term charter LNG vessel, the Woodside Scarlet Ibis, was delivered in June 2024 and the vessel’s efficiency will support efforts to lower the carbon intensity of Woodside’s LNG deliveries.

21  Subject to conditions and agreements on terms for this period.

22  Woodside uses the term “lower-carbon” to describe the characteristic of having lower levels of associated potential GHG emissions when compared to historical and/or current conventions or analogues, for example relating to an otherwise similar product. Refer to ‘Climate strategy and emissions data’ on page 2 for more information.

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Projects

Scarborough Energy Project

The Scarborough gas field is located in the Carnarvon basin, approximately 375 km off the coast of Western Australia.

The development includes installation of a floating production unit (FPU) with eight wells drilled in the initial phase and 13 wells drilled over the life of the Scarborough field. Expansion of the Pluto LNG facility includes construction of a second LNG train (Pluto Train 2), installation of additional domestic gas processing facilities and supporting infrastructure, and modifications to Pluto Train 1 to allow it to process Scarborough gas.

The project was 67% complete at the end of H1 2024.23 Pluto Train 2 module delivery and site works progressed and at the end of H1 2024, 29 modules were delivered to site, with 25 modules set in position. Site integration activities continue to ramp up and are expected to peak in H2 2024.

The FPU reached a major milestone, achieving structural completion of the topsides. The monoethylene glycol (MEG) module and living quarters were installed on the topsides and, subsequent to the period, the hull entered its second dry dock.

Trunkline installation is more than 50% complete and the pipe diameter has transitioned from 36” to 32”. All crossings of other pipelines are complete.

Installation and testing of the three subsea flowlines has been successfully completed. The drilling campaign commenced with the installation of conductors for all eight wells. Two development wells have been drilled, with one well completed and the other to be completed as part of the forward campaign. Reservoir quality was in line with expectations.

All major engineering reviews for Pluto Train 1 modifications have been completed and approximately 80% of materials and equipment have been ordered. Contractor mobilisation to the Thailand module yard and Pluto site commenced.

Subsequent to the period, the Integrated Remote Operating Centre building works were completed with fit out now underway.

In February 2024, Woodside signed an agreement with JERA, as part of a broader strategic relationship, for the sale of a 15.1% non-operated participating interest in the SJV. Estimated total consideration for the sale is $1,400 million, subject to completion which is targeted for the second half of 2024.24

In March 2024, Woodside completed the sale of a 10% non-operated participating interest in the SJV to LNG Japan for $910 million.25

Woodside is operator and holds a 90% participating interest in Scarborough and a 51% participating interest in Pluto Train 2.26

Trion

Trion is an oil development located in the Gulf of Mexico, approximately 180 km off the Mexican coastline and 30 km south of the United States/Mexico maritime border. The Trion project includes a semi-submersible FPU capable of producing and transferring 100,000 barrels of oil per day to a floating storage and offloading (FSO) vessel. Oil from the FSO is expected to be exported to the market, with excess gas transferred to existing offshore gas export infrastructure.

The project progressed engineering, procurement and contracting (EPC) activities in H1 2024. The FPU detailed engineering achieved key milestones including the completion of integrated model reviews of the hull and topsides with key vendor data and formal risk assessments of the facility’s design and operability. Technical maturity in engineering has enabled the FPU EPC contractor to start procurement of equipment. 

23  The completion % excludes the Pluto Train 1 modifications project.

24  The SPA is with JERA Scarborough Pty Ltd which is a wholly owned subsidiary of JERA Co., Inc.

25  LJ Scarborough Pty Ltd (LNG Japan) is a jointly owned subsidiary of LNG Japan Corporation (which is a 50:50 joint venture between Sumitomo Corporation and Sojitz Corporation) and Japan Organization for Metals and Energy Security (JOGMEC). JOGMEC has a 49.9% interest in LJ Scarborough Pty Ltd. The sale proceeds received by Woodside of US$910 million for equity in the Scarborough Joint Venture comprises the purchase price, reimbursed expenditure and escalation.

26  Woodside’s 90% participating interest in the Scarborough Joint Venture is prior to the completion of the sell-down of 15.1% interest to JERA.

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Model testing was completed as part of FSO front-end engineering design (FEED). Other key achievements include completion of hull and disconnectable turret module model reviews and the hazards and operability assessment.

Subsea delivery also advanced with the start of manufacturing activities.

Key contracts were awarded for subsea marine installation, FPU dry transportation, gas gathering line pipe and drilling equipment and consumables.

Woodside is currently carrying Pemex’s portion of development capital expenditure (approximately $460 million post FID) and Pemex is not expected to contribute to cash calls until 2025.

Woodside is targeting first oil in 2028. Woodside is operator and holds a 60% participating interest in the project.

Driftwood LNG

Subsequent to the period, Woodside entered into a definitive agreement to acquire all issued and outstanding common stock of Tellurian including its owned and operated US Gulf Coast Driftwood LNG development opportunity.

Driftwood LNG is a fully permitted, pre-FID development opportunity located near Lake Charles, Louisiana. The current development plan comprises five LNG trains through four phases, with a total permitted capacity of 27.6 Mtpa. Once operating, the Driftwood LNG development will increase Woodside’s LNG portfolio, complementing the significant Pacific basin exposure with additional Atlantic basin exposure.

The transaction remains subject to approvals and conditions precedent, with completion targeted in Q4 2024. If completed, Woodside is targeting FID readiness for Phase 1 of the development opportunity from Q1 2025.

Decommissioning

Woodside continued execution of planned decommissioning activities in H1 2024, spending approximately $325 million across our portfolio.

At Enfield, the final two of 18 xmas trees were removed and wellhead severance activities commenced. Deconstruction of the Nganhurra riser turret mooring (RTM) was completed at the Australian Marine Complex, enabling more than 95% of the RTM to be recycled or reused.

At Griffin, all rigid piping has been recovered and wellhead severance activities have been completed.

The Transocean Endurance drill rig mobilised to the Stybarrow field and commenced the ten well plug and abandonment (P&A) campaign.

At Bass Strait, the GBJV continued to progress significant decommissioning activity including ongoing execution of P&A of platform wells and commenced execution of the P&A of two subsea wells. In addition, FEED for the removal of platforms no longer in use has progressed.

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Exploration and Development

Calypso

Calypso is located approximately 220 km off the coast of Trinidad in 2,100m water depth. The resource comprises several gas discoveries in Block 23(a) and Block TTDAA 14. The development is located in a region with existing infrastructure and a favourable demand outlook.

In H1 2024, Woodside continued pre-FEED engineering studies to mature the technical definition and cost estimate for the deepwater infield host. Marketing and commercial discussions continue with key stakeholders to evaluate options to monetise the resource.

Woodside is operator and holds a 70% participating interest.

Browse

The Browse development comprises the Calliance, Brecknock and Torosa gas and condensate fields located approximately 425 km north of Broome, Western Australia.

Key work scopes continued in support of the proposed Browse to NWS Project development, including engagement with regulators on environmental and regulatory approvals and progressing commercial discussions. A carbon capture and storage solution has been incorporated into the offshore infrastructure, designed to sequester the majority of Browse reservoir CO2. In June 2024, a Declaration of an Identified Greenhouse Gas Storage Formation was made by the Commonwealth Government over the Calliance Storage Formation within the G-8-AP Greenhouse Gas Assessment Permit.

Woodside is operator and holds a 30.6% participating interest.

Liard

The Liard field is an unconventional gas field located in British Columbia, Canada. Woodside holds a 50% non-operating participating interest.

Sunrise

The Sunrise development comprises the Sunrise and Troubadour gas and condensate fields, located approximately 450 km north-west of Darwin and 150 km south of Timor-Leste.

The Sunrise Joint Venture participants continued to negotiate a new Production Sharing Contract, Petroleum Mining Code and fiscal regime with the Australian and Timor-Leste Governments in H1 2024. The Greater Sunrise Concept Study commenced in April 2024, with local content and socio-economic data gathering and engagement with potential site owners planned for H2 2024.

Woodside is operator and holds a 33.44% participating interest.

Exploration

Woodside continued to build its position in the US Gulf of Mexico during the period, acquiring 18 leases in Lease Sale 261 in the central and western Gulf of Mexico areas within the highly contested Paleogene trends. Woodside also participated in the Corvus well (non-operated) in the Gulf of Mexico which completed drilling in March 2024. The well did not encounter commercial hydrocarbons and detailed analysis of well results is ongoing.

In Congo, Woodside is participating in the Niamou Marine-1 well (non-operated) which is currently drilling.

Woodside also continued to optimise its exploration portfolio, exiting blocks that are no longer considered prospective. This included a decision to exit Block 2 in the offshore Herodotus basin in Egypt and completing all formal exit activities for permit WA-356-P in Australia and the Carlisle Bay Block in Barbados.

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New energy

Beaumont Clean Ammonia Project

Subsequent to the period, Woodside entered into a binding agreement to acquire 100% of OCI Clean Ammonia Holding B.V. and its lower carbon ammonia project in Beaumont, Texas. This acquisition provides Woodside with an early-mover advantage in the growing lower carbon ammonia market.

Phase 1 of the project, which is expected to exceed Woodside’s capital allocation target for new energy projects has a design capacity of 1.1 Mtpa and is under construction.

The transaction is subject to an OCI shareholder vote and satisfaction of customary conditions precedent, with completion targeted in H2 2024. If completed, Woodside is targeting production of first ammonia from 2025 and lower carbon ammonia from 2026 following commencement of CCS operations.26

H2OK

H2OK is a proposed liquid hydrogen project in Ardmore, Oklahoma, and is expected to produce up to 60 tonnes per day of liquid hydrogen.

In H1 2024, Woodside continued to progress discussions with potential offtakers on pricing and volumes. Woodside also provided comments on the proposed 45V Clean Hydrogen Production Tax Credit guidelines issued by the United States Department of Treasury and the Internal Revenue Service.

Hydrogen Refueller @H2Perth

The Hydrogen Refueller @H2Perth is a proposed self-contained hydrogen production, storage and refuelling station.

All primary environmental approvals have been secured for the project. Woodside awarded the major services contract which includes detailed engineering, construction, commissioning and startup work scopes to enable progression towards ready for start-up.

Woodside is targeting supply of hydrogen to customers in 2025.

H2Perth

Woodside has changed the H2Perth concept from ammonia and hydrogen production to liquid hydrogen only, following feedback from potential customers. In supporting the opportunity, Woodside progressed engineering and technology studies for large-scale liquefied hydrogen production.

H2TAS

H2TAS is a proposed renewable ammonia and hydrogen production facility to be located in Tasmania.

Subsequent to the period, Woodside withdrew environmental applications submitted under the Environmental Management and Pollution Control Act 1994 and Environment Protection and Biodiversity Conservation Act 1999. Woodside continues to assess the viability of this potential opportunity.

Southern Green Hydrogen

Subsequent to the period, Woodside ceased discussions with Meridian Energy Limited, Mitsui & Co.,Ltd and Murihiku Regeneration, representing Ngāi Tahu, regarding a potential collaboration with respect to the Southern Green Hydrogen Project.

26  The supply of carbon abated hydrogen is dependent on ExxonMobil’s CCS facility becoming operational.

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Carbon solutions

Carbon capture and storage (CCS)

Woodside is progressing several CCS opportunities in Australia, including Angel CCS (as operator), South East Australia (SEA) CCS (non-operator) and Bonaparte CCS (non-operator).

The proposed Angel CCS Project progressed engineering and marketing activities to support FEED entry. In April 2024, the Angel CCS Joint Venture announced a non-binding memorandum of understanding with Yara Pilbara Fertilisers Pty Ltd (Yara) to study the feasibility of using CCS to decarbonise Yara’s existing operations near Karratha in Western Australia. Terrestrial ecological surveys have been completed and heritage surveys are scheduled for August 2024.

The Bonaparte CCS Joint Venture progressed appraisal activities in the G-7-AP Assessment Permit Area, which included the acquisition of the West Peron Marine 3D Seismic Survey.

The SEA CCS continued to progress engineering studies.

Carbon credits portfolio

Woodside acquires carbon credits through both market purchases and the development of its own carbon origination projects.

During H1 2024, Woodside began planting activities on approximately 4,900 hectares of land at Woodside-owned properties as part of our Native Reforestation Project. The full-year program is forecast to plant over 3.2 million mixed biodiverse seedlings. These activities were 40% complete by the end of H1 2024. Subsequent to the period, Woodside signed an agreement to fund the reforestation of 5,000 hectares of land in the Chaco region in Paraguay. The Woodside portion of the project is expected to generate approximately 1.6 million carbon credits over 40 years.

Climate and Sustainability

Climate

Woodside released its Climate Transition Action Plan and 2023 Progress Report (CTAP) on 27 February 2024. The CTAP was put to a non-binding advisory vote of shareholders at the 2024 Annual General Meeting (AGM) on 24 April 2024 and received a vote of 58.36% against the resolution. All other Board proposed resolutions were approved including the Remuneration Report and Director elections.

Management is reflecting on the results of the CTAP vote and is engaging with investors to seek feedback.

In January 2024, Woodside became the first Australian company to join the Oil and Gas Methane Partnership (OGMP2.0) to voluntarily improve the accuracy and transparency of methane emissions reporting.

Woodside also committed to providing $12.5 million over a period of five years to fund the creation of the Woodside-Rice Decarbonisation Accelerator. This collaboration with Rice University in the United States aims to bring breakthrough decarbonisation technology to market.

Health, Safety and Environment

Woodside experienced two Tier 2 process safety events in H1 2024. The contributing factors to these events are understood, with corrective actions identified. Woodside is strengthening process safety management through an expanded company-wide Process Safety Critical Role competency development program in 2024. Woodside is targeting a 95% conformance to training and assessment requirements for senior roles.

At 30 June 2024, the year-to-date total recordable injury rate was 2.27 per million work hours compared with 1.86 recorded for full-year 2023. There were no fatalities or permanent injuries recorded in H1 2024.

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To improve safety performance Woodside is focusing on simplifying safety processes, implementing improvements around safe hardware and engineering systems, and promoting a learning culture through implementation of its Field Leadership Program.

Environmental performance remained strong in H1 2024, with no events leading to any significant environmental impacts.

Supporting local suppliers

Woodside continues to identify opportunities in Australia to award contracts to local and Indigenous suppliers.

In H1 2024, 16 new local subcontracts were awarded in the Pilbara region for Pluto Train 2.

In Sangomar, Woodside has progressed work with key contractors to provide opportunities for Senegalese people and suppliers, whilst meeting the requirements of in-country local content legislation. Woodside has also continued to grow local contracting opportunities in Trinidad and Tobago and the Gulf of Mexico.

In support of the Trion Project’s National Content program in Mexico, Woodside sponsored a second group of 33 small-to-medium-sized suppliers from the Tamaulipas state to participate in a program called BlueWave. The program supports the development of suppliers and provides an opportunity to assess capabilities according to global business standards.

Communities

Woodside released its 2023 Social Contribution Impact Report in April 2024, outlining its total global social contribution spend of A$33.3 million. This report was complemented by the North West Community Development Report which highlights the significant contribution Woodside continues to make in the Pilbara region of Western Australia as operator of the Karratha Gas Plant, Pluto LNG and Scarborough Energy Project.

Subsequent to the period, Woodside released its third Reconciliation Action Plan 2021 – 2025 (RAP) Report. The report reflects on Woodside’s progress against the four pillars outlined in the RAP, namely:

• Respect for Culture and Heritage;

• Economic Participation;

• Capability and Capacity; and

• Stronger Communities.

The RAP demonstrates that although Woodside has made significant advancements towards our stated targets, continued focus is needed to achieve our goals relevant to the four pillars.

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Principal risks and uncertainties

There are several risk factors or uncertainties that could result in a material effect on the company’s results over the next six months. These risks and uncertainties may arise from Woodside’s activities globally, including in connection with its operated (or non-operated) assets, and third parties engaged through the value chain.

Information on Woodside’s risks and how they are managed can be found on pages 40-47 of the Annual Report on Form 20-F for the year ended 31 December 2023. There have been no material changes to the risk factors described in the Annual Report 2023 since the date of that report, but risk factors have been retitled and recategorised to align with Woodside’s Risk Appetite Statement.

Key changes to the categorisation include the Health and Safety and Environment risk factors being split from Operations and Climate Change, to provide greater visibility of topics most relevant to our business activities and stakeholders and to reflect where our tolerance for uncertainty is low. Additionally, Finance and Market has been split into Finance Management and Commercial and Market to acknowledge a difference in risk appetite. The risks are summarised below.

Health and safety	Our business is subject to risks related to safety or major hazard events in connection with our activities or facilities which may include unanticipated or unforeseeable adverse events that impact our ability to respond, manage and recover from such events.
Environment	Risks associated with major hazard events in connection with our activities or facilities, including potential incidents resulting in significant loss of hydrocarbon. We work to avoid incidents and prevent harm to the environment, by integrating environmental management into our activities. We are also subject to risks associated with progressing biodiversity positive outcomes and emission reductions in a timely manner, consistent with regulatory and stakeholder expectations.
People and culture	Risks associated with the ability to attract, retain, develop and motivate key employees to succeed and safeguard both current or future performance and growth.
Social integrity	Risks 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 global operations.
Strategy and climate change	The global response to climate change is changing the way the world produces and consumes energy. Our strategy requires us to take risk-based decisions and seek opportunities to continue 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. 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.
Growth	Risks associated with delivery of both major and complex multi-year execution project activities and transactions (including acquisitions and divestments) across multiple global locations, including a reliance on third parties for materials, products, and services.
Production and operations	Due to the nature of our operations, Woodside and neighbouring communities are potentially exposed to a broad range of risks. This is a result of factors such as the geographical range, operational diversity and technical complexity of our assets. These types of risks include health and safety; commercial; regulation; and reserves and resources estimates.
Financial management	Risks associated with interest rate, commodity price and foreign exchange fluctuations and inflation.
Commercial and market	Risks associated with the ability to capture value whether markets are stable or volatile.
Technology, innovation and systems	Risks associated with adopting and implementing new technologies, whilst safeguarding our digital information and landscape (including from cyber threats) across our value chain.

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Directors’ Report

The directors of Woodside Energy Group Ltd present their report (including the review of operations of Woodside Energy Group Ltd and its controlled entities (Group) set out on pages 3 - 18 which forms part of this report) together with the Half-Year Financial Statements of the Group.

Board of directors

The names of directors in office during or since the end of the 2024 half-year are as follows:

Mr Richard Goyder, AO (Chair)	Ms Meg O’Neill (CEO and Managing Director)
Mr Larry Archibald	Mr Ashok Belani (appointed 29 January 2024)
Mr Arnaud Breuillac	Ms Swee Chen Goh
Mr Ian Macfarlane	Ms Angela Minas
Mr Tony O’Neill (appointed 3 June 2024)	Ms Ann Pickard
Mr Ben Wyatt
Mr Frank Cooper, AO (retired 24 April 2024)	Mr Gene Tilbrook (retired 28 February 2024)

Change of Group Company Secretary

Mr Warren Baillie ceased to be Group Company Secretary on 27 August 2024 and the Board appointed Mr Damien Gare as Group Company Secretary, effective 27 August 2024.

Rounding of amounts

Woodside Energy Group Ltd is an entity to which the Australian Securities and Investments Commission (ASIC) Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 (ASIC Instrument 2016/191) applies. Amounts in this report have been rounded in accordance with ASIC Instrument 2016/191. This means that amounts contained in this report have been rounded to the nearest million dollars, unless otherwise stated.

Signed in accordance with a resolution of the directors.

R J Goyder, AO

Chair

Perth, Western Australia

27 August 2024

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HALF-YEAR FINANCIAL

STATEMENTS

for the half-year ended 30 June 2024

F-1

HALF-YEAR FINANCIAL STATEMENTS

CONTENTS

CONDENSED CONSOLIDATED INCOME STATEMENT		F-3
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME		F-4
CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION		F-5
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS		F-6
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY		F-7
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS		F-8
A.	Earnings for the period	F-10
	A.1 Segment revenue and expenses	F-10
	A.2 Finance costs	F-11
	A.3 Dividends paid and proposed	F-11
	A.4 Earnings per share	F-11
	A.5 Taxes	F-12
B.	Production and growth assets	F-13
	B.1 Exploration and evaluation	F-13
	B.2 Oil and gas properties	F-14
	B.3 Goodwill	F-15
	B.4 Disposal of assets	F-15
C.	Debt and capital	F-17
	C.1 Contributed equity	F-17
	C.2 Interest-bearing liabilities and financing facilities	F-17
D.	Other assets and liabilities	F-18
	D.1 Segment assets and liabilities	F-18
	D.2 Provisions	F-18
	D.3 Other financial assets and liabilities	F-19
E.	Other items	F-21
	E.1 Contingent liabilities and assets	F-21
	E.2 Changes to the composition of the Group	F-21
	E.3 New standards and interpretations	F-21
	E.4 Events after the end of the reporting period	F-22

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 23 February 2024, the Group and JERA Scarborough Pty Ltd (JERA) entered into a sale and purchase agreement for JERA to acquire a 15.1% non-operating participating interest in the Scarborough Joint Venture. The transaction is expected to complete in the second half of 2024. As a result, $1,378 million of assets have been reclassified as assets held for sale and $119 million of liabilities have been reclassified as liabilities directly associated with assets held for sale (refer to Note B.4). This has also resulted in the recognition of a net tax benefit of $91 million (refer to Note A.5).

• On 26 March 2024, the Group completed the sell-down of a 10% non-operating participating interest in the Scarborough Joint Venture to 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.4).

• In June 2024, the Sangomar project in Senegal achieved first oil. During the half-year ended 30 June 2024, Sangomar produced 0.54 MMboe of crude oil. Production will continue to ramp up in 2024. The Group also recognised a net deferred tax asset of $305 million (refer to Note A.5).

Woodside Energy Group Ltd | Half-Year Report 2024 F-2

CONDENSED CONSOLIDATED INCOME STATEMENT

for the half-year ended 30 June 2024

	Notes		2024 US$m			2023 US$m
Operating revenue		A.1		5,988			7,400
Cost of sales		A.1		(3,272	)		(3,872	)
Gross profit				2,716			3,528
Other income		A.1		315			134
Other expenses		A.1		(669	)		(803	)
Impairment losses		A.1		—			(68	)
Profit before tax and net finance costs				2,362			2,791
Finance income				95			174
Finance costs		A.2		(147	)		(137	)
Profit before tax				2,310			2,828
Petroleum resource rent tax (PRRT) expense				(192	)		(778	)
Income tax expense		A.5		(146	)		(284	)
Profit after tax				1,972			1,766
Profit attributable to:
Equity holders of the parent				1,937			1,740
Non-controlling interest				35			26
Profit for the period				1,972			1,766
Basic earnings per share attributable to equity holders of the parent (US cents)		A.4		102.2			91.7
Diluted earnings per share attributable to equity holders of the parent (US cents)		A.4		101.4			91.1

The accompanying notes form part of the half-year financial statements.

Woodside Energy Group Ltd | Half-Year Report 2024 F-3

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

for the half-year ended 30 June 2024

	2024 US$m			2023 US$m
Profit for the period		1,972			1,766
Other comprehensive income
Items that may be reclassified to the income statement in subsequent periods:
(Losses)/gains on cash flow hedges		(165	)		413
Losses on cash flow hedges reclassified to the income statement		38			241
Tax recognised within other comprehensive income		19			(76	)
Exchange fluctuations on translation of foreign operations taken to equity		—			1
Items that will not be reclassified to the income statement in subsequent periods:
Remeasurement loss on defined benefit plan		(15	)		—
Net loss on financial instruments at fair value through other comprehensive income		(11	)		(23	)
Other comprehensive (loss)/income for the period, net of tax		(134	)		556
Total comprehensive income for the period		1,838			2,322
Total comprehensive income attributable to:
Equity holders of the parent		1,803			2,296
Non-controlling interest		35			26
Total comprehensive income for the period		1,838			2,322

The accompanying notes form part of the half-year financial statements.

Woodside Energy Group Ltd | Half-Year Report 2024 F-4

CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

as at 30 June 2024

	Notes		30 June 2024 US$m			31 December 2023 US$m
Current assets
Cash and cash equivalents				1,979			1,740
Receivables				1,459			1,517
Inventories				719			616
Other financial assets		D.3		154			209
Assets held for sale		B.4		1,378			826
Tax receivable				306			118
Other assets				57			92
Total current assets				6,052			5,118
Non-current assets
Receivables				790			839
Inventories				183			120
Other financial assets		D.3		106			120
Exploration and evaluation assets		B.1		714			668
Oil and gas properties		B.2		40,125			40,791
Deferred tax assets				1,969			1,717
Lease assets				1,187			1,230
Investments accounted for using the equity method				248			249
Goodwill		B.3		3,697			3,995
Other assets				571			514
Total non-current assets				49,590			50,243
Total assets				55,642			55,361
Current liabilities
Payables				1,597			1,724
Interest-bearing liabilities				992			—
Other financial liabilities		D.3		152			67
Liabilities directly associated with assets held for sale		B.4		119			94
Provisions		D.2		1,223			1,506
Tax payable				416			1,108
Lease liabilities				217			298
Other liabilities				165			185
Total current liabilities				4,881			4,982
Non-current liabilities
Interest-bearing liabilities				4,830			4,883
Deferred tax liabilities				1,312			1,627
Other financial liabilities		D.3		203			42
Provisions		D.2		6,454			6,451
Tax payable				39			40
Lease liabilities				1,328			1,317
Other liabilities				766			849
Total non-current liabilities				14,932			15,209
Total liabilities				19,813			20,191
Net assets				35,829			35,170
Equity
Issued and fully paid shares		C.1		29,001			29,001
Shares reserved for employee share plans		C.1		(65	)		(49	)
Other reserves				4,726			5,261
Retained earnings				1,408			186
Equity attributable to equity holders of the parent				35,070			34,399
Non-controlling interest				759			771
Total equity				35,829			35,170

The accompanying notes form part of the half-year financial statements.

Woodside Energy Group Ltd | Half-Year Report 2024 F-5

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

for the half-year ended 30 June 2024

	Notes		2024 US$m			2023 US$m
Cash flows from operating activities
Profit after tax for the period				1,972			1,766
Adjustments for:
Non-cash items
Depreciation and amortisation				1,908			1,948
Depreciation of lease assets				101			81
Change in fair value of derivative financial instruments				205			269
Net finance costs/(income)				52			(37	)
Tax expense				338			1,062
Exploration and evaluation written off				—			1
Impairment losses				—			68
Restoration movement				15			20
Gain on disposal of oil and gas properties				(143	)		—
Other				(66	)		(180	)
Changes in assets and liabilities
Decrease in trade and other receivables				113			488
Increase in inventories				(166	)		(72	)
Decrease in provisions				(31	)		(110	)
Decrease in lease liabilities				—			(8	)
Decrease/(increase) in other assets and liabilities				39			(234	)
Increase/(decrease) in trade and other payables				6			(220	)
Cash generated from operations				4,343			4,842
Interest received				77			174
Dividends received				—			6
Borrowing costs relating to operating activities				(2	)		(8	)
Income tax and PRRT paid				(1,700	)		(2,233	)
Payments for restoration				(325	)		(162	)
Receipts from hedge collateral				—			332
Net cash from operating activities1				2,393			2,951
Cash flows used in investing activities
Payments for capital and exploration expenditure				(2,418	)		(2,457	)
Borrowing costs relating to investing activities				(155	)		(181	)
Proceeds from disposal of non-current assets				920			3
Funding of equity accounted investments				—			(2	)
Net cash used in investing activities				(1,653	)		(2,637	)
Cash flows used in financing activities
Proceeds from borrowings		C.2		950			—
Repayment of borrowings		C.2		—			(41	)
Purchases of shares relating to employee share plans1				(25	)		(20	)
Repayment of the principal portion of lease liabilities				(213	)		(168	)
Borrowing costs relating to lease liabilities				(21	)		(3	)
Contributions to non-controlling interests				(48	)		(51	)
Dividends paid				(1,139	)		(2,738	)
Net cash used in financing activities1				(496	)		(3,021	)
Net increase/(decrease) in cash held				244			(2,707	)
Cash and cash equivalents at the beginning of the period				1,740			6,201
Effects of exchange rate changes				(5	)		(25	)
Cash and cash equivalents at the end of the period				1,979			3,469

1. Purchases of shares relating to employee share plans, which were previously classified within cash flows used in operating activities, has been classified within cash flows used in financing activities for the half-year ended 2024. The 2023 comparatives have been reclassified to be presented on the same basis.

The accompanying notes form part of the half-year financial statements.

Woodside Energy Group Ltd | Half-Year Report 2024 F-6

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

for the half-year ended 30 June 2024

	Issued and fully paid shares		Reserved shares			Employee benefits reserve			Foreign currency translation reserve		Hedging reserve			Distributable profits reserve			Other reserve			Retained earnings			Equity holders of the parent			Non-controlling interest			Total equity
Notes	C.1 US$m		C.1 US$m			US$m			US$m		US$m			US$m			US$m			US$m			US$m			US$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		—		—			—			—		—			—			—			1,937			1,937			35			1,972
Other comprehensive loss		—		—			—			—		(108	)		—			(11	)		(15	)		(134	)		—			(134	)
Total comprehensive (loss)/income for the period		—		—			—			—		(108	)		—			(11	)		1,922			1,803			35			1,838
Transfers		—		—			—			—		—			700			—			(700	)		—			—			—
Employee share plan purchases		—		(25	)		—			—		—			—			—			—			(25	)		—			(25	)
Employee share plan redemptions		—		9			(9	)		—		—			—			—			—			—			—			—
Share-based payments (net of tax)		—		—			32			—		—			—			—			—			32			—			32
Dividends paid		—		—			—			—		—			(1,139	)		—			—			(1,139	)		(47	)		(1,186	)
At 30 June 2024		29,001		(65	)		313			795		(20	)		3,679			(41	)		1,408			35,070			759			35,829
At 1 January 2023		29,001		(38	)		278			796		(586	)		3,541			2			3,342			36,336			791			37,127
Profit for the period		—		—			—			—		—			—			—			1,740			1,740			26			1,766
Other comprehensive income/(loss)		—		—			—			1		578			—			(23	)		—			556			—			556
Total comprehensive income/(loss) for the period		—		—			—			1		578			—			(23	)		1,740			2,296			26			2,322
Transfers		—		—			—			—		—			4,700			—			(4,700	)		—			—			—
Employee share plan purchases		—		(20	)		—			—		—			—			—			—			(20	)		—			(20	)
Employee share plan redemptions		—		8			(8	)		—		—			—			—			—			—			—			—
Share-based payments (net of tax)		—		—			31			—		—			—			—			—			31			—			31
Dividends paid		—		—			—			—		—			(2,734	)		—			—			(2,734	)		(42	)		(2,776	)
At 30 June 2023		29,001		(50	)		301			797		(8	)		5,507			(21	)		382			35,909			775			36,684

The accompanying notes form part of the half-year financial statements.

Woodside Energy Group Ltd | Half-Year Report 2024 F-7

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

About these statements

Woodside Energy Group Ltd (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), on the Main Market for listed securities of the London Stock Exchange (LSE) (with trades settled in the form of UK Depository Interests) and on the New York Stock Exchange (NYSE) (in the form of Woodside American Depositary Shares). The nature of the operations and principal activities of the Group are described in the Australia Operations, International Operations, Marketing and Trading, Projects, Decommissioning, Exploration and Development and New energy and Carbon solutions sections and in the segment information below.

The condensed consolidated half-year financial statements were authorised for issue in accordance with a resolution of the Directors on 27 August 2024.

Statement of compliance

The condensed consolidated half-year financial statements are condensed general purpose financial statements, which have been prepared in accordance with Australian Accounting Standard (AASB) 134 Interim Financial Reporting as issued by the Australian Accounting Standards Board and the Australian Corporations Act 2001. These condensed consolidated half-year financial statements also comply with International Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the International Accounting Standards Board.

The condensed consolidated half-year financial statements do not include all notes of the type normally included in annual financial statements. Accordingly, these condensed consolidated half-year financial statements are to be read in conjunction with the Financial Statements within the Annual Report for the year ended 31 December 2023 (2023 Financial Statements) and any public announcements made by Woodside during the period ended 30 June 2024 in accordance with the continuous disclosure requirements of the Australian Corporations Act 2001 and the relevant ASX, LSE and NYSE Listing Rules.

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. Refer to Note E.3 for more details.

The significant accounting estimates and judgements are consistent with those disclosed in the 2023 Financial Statements. Estimates have been revised, where required, to reflect current market conditions including the impact of climate change. Updated estimates used for the sell-down of the Scarborough Joint Venture and embedded commodity derivatives are disclosed in Notes B.4 and D.3 respectively; these assumptions could change in the future.

Currency

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

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 amounts contained in the condensed consolidated half-year financial statements have been rounded to the nearest million dollars under the option available to the Group under Australian Securities and Investments Commission (ASIC) Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 dated 24 March 2016, unless otherwise stated.

Woodside Energy Group Ltd | Half-Year Report 2024 F-8

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

Basis of preparation

The condensed consolidated half-year financial statements have been prepared on an 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 condensed consolidated half-year financial statements.

The condensed consolidated half-year financial statements comprise the financial results of the Group and its subsidiaries for the period ended 30 June 2024. Subsidiaries are fully consolidated from the date on which control is obtained by the Group and cease to be consolidated from the date at which the Group ceases to have control.

The material subsidiaries of the Group apply the same reporting period and accounting policies as the parent company in preparation of the condensed consolidated half-year 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; 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.

Comparative information

The condensed consolidated half-year financial statements provide comparative information in respect of the previous period. Where required, a reclassification of items in the financial statements of the previous period has been made in accordance with the classification of items in the condensed consolidated half-year financial statements of the current period.

Reporting segments

Refer to the 2023 Financial Statements for details of the Group’s operating segment information.

Woodside Energy Group Ltd | Half-Year Report 2024 F-9

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

A. Earnings for the period

A.1 Segment revenue and expenses

	Australia						International						Marketing						Corporate/Other						Consolidated
	2024 US$m			2023 US$m			2024 US$m			2023 US$m			2024 US$m			2023 US$m			2024 US$m			2023 US$m			2024 US$m			2023 US$m
Liquified natural gas		2,595			3,894			—			—			412			785			—			—			3,007			4,679
Pipeline gas		512			515			107			198			—			—			—			—			619			713
Crude oil and condensate		861			715			1,190			1,028			40			15			—			—			2,091			1,758
Natural gas liquids		87			120			24			16			40			23			—			—			151			159
Revenue from sale of hydrocarbons		4,055			5,244			1,321			1,242			492			823			—			—			5,868			7,309
Intersegment revenue1		(12	)		(120	)		(2	)		(6	)		14			126			—			—			—			—
Processing and services revenue		113			85			—			—			—			—			—			—			113			85
Shipping and other revenue		—			—			—			—			7			6			—			—			7			6
Other revenue		101			(35	)		(2	)		(6	)		21			132			—			—			120			91
Operating revenue2		4,156			5,209			1,319			1,236			513			955			—			—			5,988			7,400
Production costs		(511	)		(614	)		(234	)		(193	)		—			—			—			—			(745	)		(807	)
Royalties, excise and levies		(185	)		(285	)		(11	)		(31	)		—			—			—			—			(196	)		(316	)
Insurance		(13	)		(20	)		(2	)		(5	)		—			—			(11	)		(9	)		(26	)		(34	)
Inventory movement		15			31			47			2			—			—			—			—			62			33
Costs of production		(694	)		(888	)		(200	)		(227	)		—			—			(11	)		(9	)		(905	)		(1,124	)
Land and buildings		(26	)		(31	)		—			(2	)		—			—			(2	)		—			(28	)		(33	)
Transferred exploration and evaluation		(41	)		(51	)		(45	)		(2	)		—			—			—			—			(86	)		(53	)
Plant and equipment		(1,189	)		(1,298	)		(567	)		(543	)		—			—			(23	)		(17	)		(1,779	)		(1,858	)
Oil and gas properties depreciation and amortisation		(1,256	)		(1,380	)		(612	)		(547	)		—			—			(25	)		(17	)		(1,893	)		(1,944	)
Shipping and direct sales costs		(61	)		(107	)		(43	)		(38	)		(50	)		(30	)		—			—			(154	)		(175	)
Trading costs		—			(4	)		—			—			(273	)		(618	)		—			—			(273	)		(622	)
Other hydrocarbon costs		(26	)		(7	)		—			—			—			—			—			—			(26	)		(7	)
Other cost of sales		(17	)		—			—			—			—			—			(4	)		—			(21	)		—
Other cost of sales		(104	)		(118	)		(43	)		(38	)		(323	)		(648	)		(4	)		—			(474	)		(804	)
Cost of sales		(2,054	)		(2,386	)		(855	)		(812	)		(323	)		(648	)		(40	)		(26	)		(3,272	)		(3,872	)
Gross profit/(loss)		2,102			2,823			464			424			190			307			(40	)		(26	)		2,716			3,528
Other income3		242			106			20			—			20			1			33			27			315			134
Exploration and evaluation expenditure		(12	)		(9	)		(86	)		(123	)		—			—			—			(1	)		(98	)		(133	)
Amortisation of permit acquisitions		—			—			(5	)		(4	)		—			—			—			—			(5	)		(4	)
Write-offs		—			—			—			(1	)		—			—			—			—			—			(1	)
Exploration and evaluation		(12	)		(9	)		(91	)		(128	)		—			—			—			(1	)		(103	)		(138	)
General, administration and other costs		—			—			—			(3	)		—			(10	)		(214	)		(224	)		(214	)		(237	)
Amortisation of intangible assets		—			—			—			—			—			—			(10	)		—			(10	)		—
Depreciation of lease assets		(28	)		(22	)		(1	)		(7	)		(50	)		(34	)		(22	)		(18	)		(101	)		(81	)
Restoration movement		(14	)		(8	)		(1	)		(12	)		—			—			—			—			(15	)		(20	)
Other4		16			(27	)		—			(1	)		58			(99	)		(300	)		(200	)		(226	)		(327	)
Other costs		(26	)		(57	)		(2	)		(23	)		8			(143	)		(546	)		(442	)		(566	)		(665	)
Other expenses		(38	)		(66	)		(93	)		(151	)		8			(143	)		(546	)		(443	)		(669	)		(803	)
Impairment losses		—			(68	)		—			—			—			—			—			—			—			(68	)
Profit/(loss) before tax and net finance costs		2,306			2,795			391			273			218			165			(553	)		(442	)		2,362			2,791

1. Intersegment revenue comprises the incremental income net of all incremental associated expenses generated by the Marketing segment’s optimisation of the oil and gas portfolio.

2. Operating revenue includes revenue from contracts with customers of $5,981 million (2023: $7,394 million) and sub-lease income of $7 million (2023: $6 million) disclosed within shipping and other revenue.

3. Includes fees, recoveries and other income not associated with the ongoing operations of the business. The 2024 amount includes the gain on the Scarborough sell-down to LNG Japan of $121 million.

4. Includes gains and losses on foreign exchange and hedging activities, fair value losses on embedded derivatives and other items not associated with the ongoing operations of the business.

Woodside Energy Group Ltd | Half-Year Report 2024 F-1 0

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

A.2 Finance costs

	2024 US$m			2023 US$m
Interest on interest-bearing liabilities		125			112
Interest on lease liabilities		51			54
Accretion charge		145			134
Other finance costs		13			21
Less: Finance costs capitalised against qualifying assets		(187	)		(184	)
		147			137

A.3 Dividends paid and proposed

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

	2024 US$m		2023 US$m
(a) Dividends paid during the financial period Prior year fully franked final dividend US$0.60, paid on 4 April 2024 (2023: US$1.44, paid on 5 April 2023)		1,139		2,734
(b) Dividend declared subsequent to the reporting period (not recorded as a liability) Current year fully franked interim dividend US$0.69 to be paid on 3 October 2024 (2023: US$0.80, paid on 3 October 2023)		1,310		1,519

A.4 Earnings per share

	2024		2023
Profit attributable to equity holders of the parent (US$m)		1,937		1,740
Weighted average number of shares on issue for basic earnings per share		1,896,041,815		1,896,624,636
Effect of dilution from contingently issuable shares		14,691,983		12,981,487
Weighted average number of shares on issue adjusted for the effect of dilution		1,910,733,798		1,909,606,123
Basic earnings per share (US cents)		102.2		91.7
Diluted earnings per share (US cents)		101.4		91.1

Earnings per share is calculated by dividing the profit for the period attributable to ordinary equity holders of the parent by the weighted average number of shares on issue during the period. 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.

Woodside Energy Group Ltd | Half-Year Report 2024 F-11

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

A.5 Taxes

	2024 US$m			2023 US$m
Reconciliation of income tax expense
Profit before tax		2,310			2,828
PRRT expense		(192	)		(778	)
Profit before income tax		2,118			2,050
Income tax expense calculated at 30%		635			615
Effect of tax rate differentials		(15	)		30
Effect of deferred tax assets not recognised		35			67
Effect of tax benefits previously unrecognised1		(366	)		(340	)
Reduction in deferred tax liability due to held for sale basis1		(91	)		—
Foreign exchange impact on tax benefit		(11	)		(83	)
Adjustment to prior years		(52	)		(16	)
Other		11			11
Income tax expense		146			284

1. Subsequent to achieving first oil on the Sangomar project in June 2024, the Group has recognised a net deferred tax asset of $305 million. The remaining $61 million relates to other tax benefits previously unrecognised. The expected sale of Woodside’s 15.1% share in the Scarborough Joint Venture resulted in the recognition of a net tax benefit of $91 million. These events have resulted in a reduction of the global effective income tax rate from 25.6% to 6.9%. In the prior period, as a result of the final investment decision to develop the Trion resource, the Group recognised deferred tax assets of $319 million, resulting in a reduction of the global effective income tax rate from 29.6% to 13.9%.

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 recognising a $124 million current tax payable as at 30 June 2024.

Woodside Energy Group Ltd | Half-Year Report 2024 F-12

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

B. Production and growth assets

B.1 Exploration and evaluation

	Asia Pacific US$m			Americas US$m			Africa US$m			Total US$m
Half-year ended 30 June 2024
Carrying amount at 1 January 2024		568			76			24			668
Additions		11			52			14			77
Amortisation of licence acquisition costs		—			(5	)		—			(5	)
Transferred exploration and evaluation		(8	)		—			(18	)		(26	)
Carrying amount at 30 June 2024		571			123			20			714
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

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 oil and gas properties.

Woodside Energy Group Ltd | Half-Year Report 2024 F-13

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

B.2 Oil and gas properties

	Land and buildings US$m			Transferred exploration and evaluation US$m			Plant and equipment US$m			Projects in development1 US$m			Total US$m
Half-year ended 30 June 2024
Carrying amount at 1 January 2024		701			777			23,589			15,724			40,791
Additions2		—			—			(127	)		2,447			2,320
Disposals at written down value		(2	)		—			—			(47	)		(49	)
Depreciation and amortisation		(28	)		(86	)		(1,779	)		—			(1,893	)
Completions and transfers3		—			341			5,391			(5,706	)		26
Transfer to assets held for sale4		—			—			(4	)		(1,066	)		(1,070	)
Carrying amount at 30 June 2024		671			1,032			27,070			11,352			40,125
At 30 June 2024
Historical cost		1,743			2,320			55,533			12,072			71,668
Accumulated depreciation and impairment		(1,072	)		(1,288	)		(28,463	)		(720	)		(31,543	)
Net carrying amount		671			1,032			27,070			11,352			40,125
Year ended 31 December 2023
Carrying amount at 1 January 2023		840			481			23,057			15,541			39,919
Additions		—			—			836			5,759			6,595
Disposals at written down value		(8	)		—			(2	)		—			(10	)
Depreciation and amortisation		(67	)		(125	)		(3,764	)		—			(3,956	)
Impairment losses		(64	)		(20	)		(1,028	)		(328	)		(1,440	)
Completions and transfers		—			441			4,496			(4,633	)		304
Transfer to assets held for sale		—			—			(6	)		(615	)		(621	)
Carrying amount at 31 December 2023		701			777			23,589			15,724			40,791
At 31 December 2023
Historical cost		1,745			1,979			50,272			16,443			70,439
Accumulated depreciation and impairment		(1,044	)		(1,202	)		(26,683	)		(719	)		(29,648	)
Net carrying amount		701			777			23,589			15,724			40,791

1. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.

2. Includes $2,212 million of capital additions and $187 million of capitalised borrowing costs offset by $79 million relating to changes in restoration provision assumptions. The $127 million of additions reducing plant and equipment relates to changes in restoration provision assumptions.

3. Upon first oil in June 2024, the carrying value of the Sangomar project in projects in development has been transferred to plant and equipment.

4. Refer to Note B.4 for details of the sell-downs of the Scarborough Joint Venture.

The Group has capital expenditure commitments contracted for, but not provided for in the financial statements, of $3,017 million (31 December 2023: $4,245 million).

Woodside Energy Group Ltd | Half-Year Report 2024 F-14

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

B.3 Goodwill

	US$m
Half-year ended 30 June 2024
Carrying amount at 1 January 2024		3,995
Transfer to assets held for sale1		(298	)
Carrying amount at 30 June 2024		3,697
At 30 June 2024
Cost		4,174
Accumulated impairment		(477	)
Net carrying amount		3,697
Year ended 31 December 2023
Carrying amount at 1 January 2023		4,614
Adjustment to purchase price allocation		55
Impairment		(477	)
Transfer to assets held for sale		(197	)
Carrying amount at 31 December 2023		3,995
At 31 December 2023
Cost		4,472
Accumulated impairment		(477	)
Net carrying amount		3,995

1. Refer to Note B.4(a) for details of the sell-downs of the Scarborough Joint Venture.

B.4 Disposal of assets

(a) 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 has 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 have been reclassified to liabilities directly associated with assets held for sale. No impairment of assets occurred on reclassification to held for sale.

The following assets and liabilities were reclassified as held for sale as at 30 June 2024:

	US$m
Assets classified as held for sale
Oil and gas properties		1,070
Inventories		6
Lease assets		2
Goodwill		298
Other assets		2
Total assets held for sale		1,378
Liabilities directly associated with assets held for sale
Payables		(28	)
Deferred tax liabilities		(75	)
Lease liabilities		(8	)
Provisions		(8	)
Total liabilities directly associated with assets held for sale		(119	)

The purchase price is $740 million, subject to adjustments which includes the reimbursement to Woodside for JERA’s share of expenditure for the Scarborough project from the effective date of 1 January 2022. The total proceeds from the sale are expected to exceed the net carrying value of the assets and liabilities classified as held for sale. The transaction is expected to complete in the second half of 2024. Completion of the transaction is subject to conditions precedent including Western Australia Government approval. This has also resulted in the recognition of a net tax benefit of $91 million. After completion, the Group’s participating interest in the Scarborough Joint Venture will reduce from 90% to 74.9%.

Woodside Energy Group Ltd | Half-Year Report 2024 F-15

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

B.4 Disposal of assets (continued)

(a) Sell-down of Scarborough Joint Venture to JERA (continued)

Key estimates and judgements

Goodwill allocation on Scarborough sell-down

In accordance with AASB 136/IAS 36 Impairment of assets, if goodwill has been allocated to a CGU and the entity disposes of an operation within that unit, the goodwill associated with the operation disposed shall be included in the carrying value of the operation when determining the gain or loss on disposal and measured on the basis of the relative values of the operation disposed of and the portion of the CGU retained.

The Pluto-Scarborough CGU includes goodwill allocated from the merger with BHP Petroleum in 2022. Judgement is required to determine the amount of goodwill allocated to the 15.1% participating interest in the Scarborough assets being disposed.

The Group used fair value measurements of Pluto and Scarborough assets within the CGU as the basis to allocate goodwill between the Pluto and Scarborough assets. The goodwill associated with the participating interest of the Scarborough assets being disposed of was determined based on the percentage participating interest disposed of in proportion to the participating interest being retained.

(b) Sell-down of 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 half-year ended 30 June 2024, the Group recognised a pre-tax gain on sale of $121 million.

Woodside Energy Group Ltd | Half-Year Report 2024 F-16

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

C. Debt and capital

C.1 Contributed equity

Issued and fully paid shares

	Number of shares		US$m
Half-year ended 30 June 2024
Opening balance		1,898,749,771		29,001
Amounts as at 30 June 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

All shares are a single class with equal rights to dividends, capital distributions and voting. The Company does not have authorised capital nor par value in respect of its issued shares.

Reserved shares

Reserved shares are the Group’s own equity instruments, which are used in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity.

	Number of shares			US$m
Half-year ended 30 June 2024
Opening balance		2,140,927			(49	)
Purchases during the period		1,262,082			(25	)
Vested/allocated during the period		(424,959	)		9
Amounts as at 30 June 2024		2,978,050			(65	)
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 as at 31 December 2023		2,140,927			(49	)

C.2 Interest-bearing liabilities and financing facilities

During the period, the Group completed the drawdown of $500 million from bilateral loan facilities. In addition, the Group entered into the following facilities during the period:

• $1,000 million loan facility with Japan Bank for International Cooperation (JBIC) with a term of 10 years. Interest is based on daily Secured Overnight Financing Rate (SOFR) plus margin. This facility was fully drawn subsequent to the period on 22 July 2024.

• $450 million syndicated term loan facility with a tenor of 10 years. Interest is based on daily SOFR plus credit adjustment spread (CAS) and margin. This facility was fully drawn in June 2024.

There were no other material changes to interest-bearing liabilities and financing facilities. As at 30 June 2024, the Group had $6,500 million (31 December 2023: $6,050 million) of available undrawn facilities. Subsequent to 30 June 2024, the Group cancelled $1,550 million of undrawn facilities.

For the year ended 31 December 2023, the Group repaid $201 million of the CHF Medium Term Note and $83 million of the JBIC facility which was settled in July 2023.

Fair value

The carrying amounts of interest-bearing liabilities approximate their fair values, with the exception of the Group’s unsecured bonds and the medium-term notes. The unsecured bonds have a carrying amount of $4,087 million (31 December 2023: $4,087 million) and a fair value of $3,958 million (31 December 2023: $3,936 million). The medium-term notes have a carrying amount of $200 million (31 December 2023: $200 million) and a fair value of $188 million (31 December 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.

Woodside Energy Group Ltd | Half-Year Report 2024 F-17

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

D. Other assets and liabilities

D.1 Segment assets and liabilities

	30 June 2024 US$m		31 December 2023 US$m
(a) Segment assets
Australia		30,895		31,602
International		18,083		17,923
Marketing		798		835
Corporate/Other		5,866		5,001
		55,642		55,361

	30 June 2024 US$m		31 December 2023 US$m
(b) Segment liabilities
Australia		7,312		7,833
International		2,434		2,624
Marketing		890		751
Corporate/Other		9,177		8,983
		19,813		20,191

Corporate/Other assets mainly comprise cash and cash equivalents, lease assets and deferred tax assets. Corporate/Other liabilities mainly comprise interest-bearing liabilities, lease liabilities and deferred tax liabilities.

D.2 Provisions

	Restoration1 US$m			Employee benefits US$m			Other US$m			Total US$m
Half-year ended 30 June 2024
At 1 January 2024		7,154			522			281			7,957
Change in provision		(449	)		(31	)		55			(425	)
Unwinding of present value discount		144			—			1			145
Carrying amount at 30 June 2024		6,849			491			337			7,677
Current		698			302			223			1,223
Non-current		6,151			189			114			6,454
Net carrying amount		6,849			491			337			7,677
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 a revision of discount rates of $147 million (primarily due to an increase in risk-free rates), changes in foreign exchange rates of $84 million and provisions used of $358 million, offset by changes in estimates of $140 million.

Woodside Energy Group Ltd | Half-Year Report 2024 F-18

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

D.3 Other financial assets and liabilities

	30 June 2024 US$m		31 December 2023 US$m
Other financial assets
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		160		248
Other financial assets		100		53
Financial instruments at fair value through other comprehensive income
Other financial assets		—		28
Total other financial assets		260		329
Current		154		209
Non-current		106		120
Net carrying amount		260		329
Other financial liabilities
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		126		74
Embedded derivative		188		35
Other financial liabilities		41		—
Total other financial liabilities		355		109
Current		152		67
Non-current		203		42
Net carrying amount		355		109

Hedging activities

During the period, the following hedging activities were undertaken:

• The Group had hedged approximately 29.3 MMboe of 2024 oil production at an average price of approximately $75.6 per barrel, of which approximately 49% was delivered as at 30 June 2024.

• The Group additionally hedged approximately 15 MMboe of 2025 oil production at an average price of approximately $81.2 per barrel.

• The Group also has a hedging program for Corpus Christi LNG volumes designed to protect against downside pricing risk. These hedges are Henry Hub (HH) and Title Transfer Facility (TTF) commodity swaps. Approximately 70% of volumes for the remainder of 2024, 48% of 2025 and 9% 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.

The following table presents the Group’s derivative financial instruments designated as hedges, measured and recognised at fair value:

	30 June 2024 US$m			31 December 2023 US$m
Oil swaps (cash flow hedges)		(53	)		(14	)
HH Corpus Christi commodity swaps (cash flow hedges)		(24	)		(44	)
TTF Corpus Christi commodity swaps (cash flow hedges)		72			181
Interest rate swaps (cash flow hedges)		48			43
Foreign exchange forwards (cash flow hedges)		(9	)		8
Total derivative financial instruments asset designated as hedges		34			174

Woodside Energy Group Ltd | Half-Year Report 2024 F-19

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

D.3 Other financial assets and liabilities (continued)

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 30 June 2024 amounted to a net liability of $188 million (31 December 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 six-month period ended 30 June 2024, an unrealised loss of $153 million (30 June 2023: unrealised loss of $52 million) has been recognised through other expenses.

Fair value

Except for the other financial assets and other financial liabilities set out in this note, there are no other material financial assets or financial liabilities carried at fair value. Other financial assets and other financial liabilities set out in this note are classified as Level 2 on the fair value hierarchy with market observable inputs, with the exception of the embedded commodity derivative which has been classified as Level 3 on the fair value hierarchy with no market observable inputs. Refer to key estimates and judgements for further details. During the period, there were no reclassifications between the fair value hierarchy levels.

There were no changes to the Group’s valuation processes, valuation techniques and types of inputs used in the fair value measurements during the period.

Financial risk factors

The Group’s activities expose its financial instruments to a variety of market risks, including foreign exchange, commodity price and interest rate risk. The half-year financial report does not include all financial risk management information and disclosures required in the Annual Report and, as such, should be read in conjunction with the Group’s 2023 Financial Statements. There have been no significant changes in risk management policies since 31 December 2023. Refer to the embedded commodity derivative key estimates and judgements section for the sensitivity assessment on discount rates and pricing.

Key estimates and judgements

Embedded commodity derivative

The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast cash flows, discount rate, credit risk and volatility. These assumptions require significant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions. The present value of the embedded derivative was estimated using the assumptions set out below.

• Inflation rate – 2.5%.

• Discount rate – a pre-tax interest rate curve (range: 5.8% to 6.95%).

• Domestic gas pricing – forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (TTF) prices available in the market 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. 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%		137
Urea sales price: decrease of 10%		(137	)
Discount rate: increase of 1.5%2		(186	)
Discount rate: decrease of 1.5%2		230

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.

Woodside Energy Group Ltd | Half-Year Report 2024 F-20

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

E. Other items

E.1 Contingent liabilities and assets

	30 June 2024 US$m		31 December 2023 US$m
Contingent liabilities at reporting date
Not otherwise provided for in the financial statements:
Contingent liabilities		226		260
Guarantees		3		2
		229		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 $56 million as at 30 June 2024 (31 December 2023: $47 million).

E.2 Changes to the composition of the Group

Since the last annual reporting, Koolbardi Pte Ltd, a wholly owned subsidiary, was incorporated in Singapore on 21 February 2024.

E.3 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 half-year 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 30 June 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 with the exception of AASB 18/ IFRS 18 Presentation and Disclosure in Financial Statements and the amendments to AASB 112/ IAS 12 Income Taxes where the impact is under assessment.

Pillar Two tax reform

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

• aim to ensure that large multinational groups pay a minimum amount of tax on income arising in each jurisdiction in which they operate; and

• would achieve a minimum effective tax rate in each jurisdiction of 15% from the reporting period commencing1 January 2024.

For the half-year ended 30 June 2024, the Group paid $1,700 million of income tax and PRRT.

The Group’s impact assessment will depend on the extent to which the Pillar Two legislation has been enacted in the various jurisdictions the Group operates in and when it comes into effect. As at reporting date, Australia has not enacted the Pillar Two legislation. The Group will continue to monitor and assess the expected impact of the Pillar Two reform.

Woodside Energy Group Ltd | Half-Year Report 2024 F-21

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2024

E.4 Events after the end of the reporting period

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 (Tellurian) for a cash payment of approximately $900 million (the transaction). As part of the agreement, the Group has provided a loan facility of up to $230 million to Tellurian to ensure site activity maintains momentum prior to the completion of the transaction. The loan is secured by a first priority lien over the Tellurian assets, subject to customary exclusions. The latest maturity date of the loan is 15 December 2024 or the date of transaction completion.

The transaction is subject to Tellurian shareholder approval, satisfaction of customary conditions precedent, and is expected to complete in the fourth quarter of 2024. The financial effect of the transaction is still being assessed.

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 Clean Ammonia Project for an all-cash consideration of approximately $2.35 billion. The project is under construction and is subject to cost, schedule, and performance guarantees from OCI. 

The transaction is subject to OCI shareholder approval, satisfaction of customary conditions precedent, and is expected to complete in the second half of 2024. The financial effect of the transaction is still being assessed.

Woodside Energy Group Ltd | Half-Year Report 2024 F-22

Appendix 4D

Dividends

Ex-dividend date	5 September 2024
Record date for the interim dividend	6 September 2024
Date the dividend is payable	3 October 2024
		Current period	Previous corresponding period1
Interim dividend – fully franked	US cents per share	69	80

None of these dividends are foreign sourced.

Woodside dividends are determined and declared in US dollars. However, shareholders will receive their dividend in Australian dollars unless their registered address is in the United Kingdom (in which case they will receive their dividend in British pounds), in the United States of America (in which case they will receive their dividend in US dollars) or in New Zealand (in which case they will receive their dividend in NZ dollars).

Shareholders who reside outside of the United States can elect to receive their dividend electronically in US dollars, payable into a US financial institution account. Shareholders who reside outside of the United States, the United Kingdom, New Zealand and Australia may elect to receive their dividend electronically in their local currency using Global Wire Payment Service from the Company’s share registry, Computershare Investor Services Pty Ltd.

Shareholders should contact the Company’s share registry if they wish to alter their dividend currency for future dividend payments. Contact details are available on Woodside’s website on the Shareholder Information section of the Investors page. Shareholders must make an election to alter their dividend currency on or before 5.00pm AWST on 9 September 2024.

Details of Associates and Joint Venture Entities

	Percentage of ownership interest held at end of period or date of disposal
Name of entity	Current period	Previous corresponding period1
North West Shelf Gas Pty Ltd	33.33%	33.33%
North West Shelf Liaison Company Pty Ltd	33.33%	33.33%
China Administration Company Pty Ltd	33.33%	33.33%
International Gas Transportation Company Limited	33.33%	33.33%
North West Shelf Shipping Service Company Pty Ltd	33.33%	33.33%
North West Shelf Lifting Coordinator Pty Ltd	33.33%	33.33%
Blue Ocean Seismic Services Limited	16.17%	28.50%
Iwilei District Participating Parties, LLC	14.96%	14.96%
Caesar Oil Pipeline Company, LLC	25.00%	25.00%
Cleopatra Gas Gathering Company LLC	22.00%	22.00%
Marine Well Containment Company LLC	10.00%	10.00%

¹  Comparisons are to half-year ended 30 June 2023.

Woodside Energy Group Ltd | Half-Year Report 2024 A-1

Shareholder information

Key announcements 2024

January	Fourth quarter 2023 report
	Appointment of Director and changes to Committee Membership
February	Woodside concludes discussions with Santos
	Woodside releases Reserves Statement and financial updates
	Woodside to sell 15.1% Scarborough interest to JERA
	Full-year 2023 results and briefing
	Annual Report 2023 and US Annual Report 2023 (Form 20-F)
	Climate Transition Action Plan and 2023 Progress Report
March	Thriving through the energy transition investor presentation
	Woodside completes sale of 10% Scarborough interest
April	Chair’s letter to shareholders
	First quarter 2024 report
	2024 Annual General Meeting
June	Appointment of Director to Woodside Board
	Woodside achieves first oil at Sangomar field in Senegal
	Report on payments to governments 2023
July	Woodside to acquire Tellurian and Driftwood LNG
	Second quarter 2024 report
August	Woodside to acquire OCI’s Clean Ammonia Project
	Half-Year 2024 line-item guidance
	Half-Year 2024 results

Events calendar 2024-2025

Key calendar dates for Woodside shareholders in 2024-25. Please note dates are subject to review.

August	27	Half-year 2024 results
September	5	Ex-dividend date for interim dividend (Australian Securities Exchange and London Stock Exchange)
	6	Ex-dividend date for interim dividend (New York Stock Exchange)
	6	Record date for interim dividend
	16	US investor event
October	3	Payment date for interim dividend
	16	Third quarter 2024 report
December	31	Year-end 2024
January		Fourth quarter 2024 report

Business directory

Registered office:	Postal address:
Woodside Energy Group Ltd Mia Yellagonga 11 Mount Street Perth WA 6000 Australia	GPO Box D188 Perth WA 6840 Australia T:   +61 8 9348 4000

Woodside Energy Group Ltd | Half-Year Report 2024 A-2

Investor enquiries

Investors seeking information on the company should contact Investor Relations at:

Postal address:
Investor Relations GPO Box D188 Perth WA 6840 Australia	T:   +61 8 9348 4000 E:   investor@woodside.com W:  woodside.com

Share registry enquiries

Investors seeking information about their shareholdings should contact the company’s share registry:

Registered office:	Postal address:
Computershare Investor Services Pty Limited Level 11 172 St Georges Terrace Perth WA 6000	GPO Box D182 Perth WA 6840 T:   1300 558 507 (within Australia) +61 3 9415 4632 (outside Australia) E:   web.queries@computershare.com.au W:  investorcentre.com/wds

The share registry can assist with queries on share transfers, dividend payments, the dividend reinvestment plan, notification of tax file numbers and changes of name, address or bank account details.

Details of shareholdings can be checked by visiting the share registry website at www.investorcentre.com/wds.

Details of our registrar in the United Kingdom and our authorised depositary bank for Woodside’s American Depositary Receipt programme can be found on our website.

Assets

Producing facilities

Australia

Asset	Role	Equity		Product
Pluto LNG	Operator		90%	LNG, pipeline gas and condensate
North West Shelf1	Operator		33.33%	LNG, pipeline gas, condensate and NGLs
Wheatstone	Non-operator		13%	LNG, pipeline gas and condensate
Julimar-Brunello	Operator		65%
Okha FPSO	Operator		50%	Crude oil
Ngujima-Yin FPSO	Operator		60%	Crude oil
Bass Strait	Non-operator		32.5-50%	Crude oil, pipeline gas, condensate and NGLs
Pyrenees FPSO	Operator		40-71.4%	Crude oil
Macedon	Operator		71.4%	Pipeline gas

  Interest JVs is 31.567%.

Woodside Energy Group Ltd | Half-Year Report 2024 A-3

International

Asset	Role	Equity		Product
Sangomar	Operator		82%	Crude oil
Greater Angostura	Operator		45-68.46%	Crude oil and pipeline gas
Greater Shenzi	Operator		72%	Crude oil, pipeline gas, condensate and NGLs
Atlantis	Non-operator		44%	Crude oil, pipeline gas, condensate and NGLs
Mad Dog	Non-operator		23.9%	Crude oil, pipeline gas, condensate and NGLs

Projects¹

Post FID

Asset	Role	Equity			Product
Scarborough	Operator		90%	2	LNG, pipeline gas and condensate
Trion	Operator		60%		Crude oil

1. Excludes acquisitions subsequent to the period.

2. On completion of the transaction to sell a 15.1% interest in the Scarborough Joint Venture to JERA, Woodside will hold a 74.9% interest and remain as operator. Completion is expected in the second half of 2024.

Developments

Asset	Role	Equity		Product
Calypso	Operator		70%	Gas
Browse	Operator		30.6%	LNG, pipeline gas and condensate
Greater Scarborough1	Operator		100%	Gas
Liard	Non-operator		50%	Gas
Sunrise	Operator		33.44%	LNG, pipeline gas and condensate

1. “Greater Scarborough” includes the Jupiter and Thebe fields.

Woodside Energy Group Ltd | Half-Year Report 2024 A-4

New energy opportunities^1,2

Asset	Role	Equity		Product
H2OK	Operator		100%	Hydrogen
H2Perth	Operator		100%	Hydrogen
Hydrogen Refueller@H2Perth	Operator		100%	Hydrogen
H2TAS	Operator		100%	Hydrogen and ammonia
Woodside Solar	Proponent2		100%	Solar energy
Southern Green Hydrogen3	Preferred partner		—	Hydrogen and ammonia
Capella	Non-operating participant		N/A	Solar energy

1. Subject to FID and regulatory approvals. Excludes acquisitions subsequent to the period.

2. Solar generation, battery services and transmission access and services will be supplied to Woodside under contracts with third parties.

3. Subsequent to the period, Woodside ceased discussions on a potential Southern Green Hydrogen collaboration.

Greenhouse gas assessment permits

Country	Permit	Role	Joint venture	Comment
Australia	G-7-AP	Non-operator	Bonaparte CCS Assessment Joint Venture	Located in the Bonaparte basin off the north western coast of the Northern Territory
	G-8-AP	Operator	Browse Joint Venture	For carbon capture and storage evaluation for Browse
	G-10-AP	Operator	Angel CCS Joint Venture	Located in the Northern Carnarvon basin off the north west coast of Western Australia

Woodside Energy Group Ltd | Half-Year Report 2024 A-5

Exploration

Country	Permit	Role	Equity	Product
Asia – Pacific
Australia	WA-404-P	Operator	100%	Gas prone basin
	WA-536-P	Operator	65%	Gas prone basin
	WA-550-P	Operator	100%	Gas prone basin
	NT/P86	Operator	100%	Gas prone basin
	WA-28-P	Operator	15.78%-33.3%	Oil and gas prone basin
	WA-93-R	Operator	70%	Gas prone basin
	WA-94-R	Operator	70%	Gas prone basin
Europe
Ireland	FEL 5/13	Operator	Exit initiated	Oil or gas prone basin
Africa
Senegal	Rufisque, Sangomar and Sangomar Deep (RSSD)	Operator	Exit initiated	Oil prone basin
Congo	Marine XX	Non-operator	22.5%	Oil or gas prone basin
Egypt	Red Sea Block 1	Non-operator	45%	Oil or gas prone basin
	Red Sea Block 3	Non-operator	30%	Oil and gas prone basin
	Red Sea Block 4	Non-operator	25%	Oil and gas prone basin
	North El Dabaa Offshore (Block 4)	Non-operator	27%	Oil and gas prone basin
Caribbean
Barbados	Bimshire Bay	Operator	60% - Exit initiated	Oil or gas prone basin

Woodside Energy Group Ltd | Half-Year Report 2024 A-6

Country	Permit	Role	Equity	Product
North America
US Gulf of Mexico	GB 780, GB 824, GB 825, GB 821, GB 866, EB 636, EB 637, EB 550, EB 594, EB 638, KC 859, KC 903, KC 904, KC 905, KC 948, KC 949, WR 795, WR 796	Operator	100%	Oil prone basin
	GB 640, GB 641, GB 685, GB 555, GB 726, GB 770, GB 771, GB 604, GB 605, GB 647, GB 648, GB 772, GB 728, GB 729, GB 773, GB 774, GB 421, GB 464, GB 465, GB 508, GB 509, GC 598	Non-operator	40%	Oil prone basin
	GB 574, GB 575, GB 619, GB 529, GB 530, GB 531	Operator	40%	Oil prone basin
	GC 436, GC 480	Non-operator	44%	Oil prone basin
	GB 501, GB 502, GB 545, GB 630, GB 672, GB 676, GB 677, GB 716, GB 719, GB 720, GB 721, GB 760, GB 762, GB 763, GB 805, GB 806, GB 807, GB 851, GB 852, GB 895	Operator	60%	Oil prone basin
	GC 282, GC 237	Non-operator	50%	Oil prone basin
	GB 663, GB 664, GB 678, GC 210, GC 211	Operator	100%	Oil prone basin
	EB 655, EB 656, EB 699, EB 700, EB 701, EB 566, EB 567, EB 610, EB 611, AC 34, AC 36, AC 78, AC 80, EB 914	Operator	70%	Oil prone basin
	MC 798, MC 842	Non-operator	45%	Oil prone basin
	AC 125, AC 126, AC 81, AC 82	Operator	45%	Oil prone basin
	GC 679, GC 768	Non-operator	31.9%	Oil prone basin
	MC 368, MC 369, MC 411, MC 412, MC 455, MC 456	Non-operator	25%	Oil prone basin
	GC 80, GC 123, GC 124, GC 168	Operator	75%	Oil prone basin
	GC 870	Non-operator	23.9%	Oil prone basin
	AT 228, AT 273, AT 274, AT 409, AT 452, AT 453, AT 454, AT 424, AT 425, AT 469, AT 470	Non-operator	30%	Oil prone basin

Woodside Energy Group Ltd | Half-Year Report 2024 A-7

Alternative Performance Measures

Woodside uses various alternative performance measures (APM) which are non-IFRS measures that are unaudited but derived from our Half-Year Financial Statements. Although certain non-IFRS data has been extracted or derived from the Half-Year financial statements, this data has not been audited or reviewed by Woodside’s independent auditors. These measures are presented to provide further insight into Woodside’s performance. See Non-IFRS Measures on page 2 for more information.

APMs and their nearest respective IFRS measure.

APMs derived from the condensed consolidated income statement	30 June 2024 US$m			30 June 2023 US$m
EBIT/EBITDA excluding impairment
Net profit after tax		1,972			1,766
Adjusted for:
Finance income		(95	)		(174	)
Finance costs		147			137
PRRT expense		192			778
Income tax expense		146			284
EBIT		2,362			2,791
Adjusted for:
Oil and gas properties depreciation and amortisation		1,893			1,944
Amortisation of licence acquisition costs		5			4
Amortisation of intangible assets		10			—
Depreciation of lease assets		101			81
Impairment losses		—			68
EBITDA excluding impairment		4,371			4,888
Underlying NPAT
Net profit after tax attributable to equity holders of the parent		1,937			1,740
Adjusted for the following exceptional items:
Add: Derecognition of Pluto PRRT (post-tax)		—			446
Add: Impairment losses (post-tax)		—			29
Less: Sangomar DTA recognition		(305	)		—
Less: Trion DTA recognition		—			(319	)
Underlying NPAT		1,632			1,896

APMs derived from the condensed consolidated statement of cash flows and other notes	30 June 2024 US$m			30 June 2023 US$m
Capital expenditure
Capital additions on evaluation		42			76
Capital additions on oil and gas properties		2,212			2,555
Capital additions on other1		111			138
Capital expenditure		2,365			2,769
Exploration expenditure
Exploration and evaluation expenditure		103			138
Adjusted for:
Amortisation expense		(5	)		(4	)
Prior year expense written off		—			(1	)
Exploration capitalised		14			54
Exploration expenditure		112			187
Capital and exploration expenditure		2,477			2,956
Free cash flow
Cash flow from operating activities2		2,393			2,951
Cash flow used in investing activities		(1,653	)		(2,637	)
Free cash flow		740			314
Liquidity
Cash and cash equivalents		1,979			3,469
Add: Available undrawn facilities		6,500			4,050
Less: Restricted cash		—			(10	)
Liquidity		8,479			7,509

1. Includes capital additions on other corporate spend. The 2023 amounts have been restated to be presented on the same basis.

2. Purchases of shares relating to employee share plans, which were previously classified within cash flows used in operating activities, has been classified within cash flows used in financing activities for the half-year ended 2024. The 2023 amounts have been restated to be presented on the same basis.

Woodside Energy Group Ltd | Half-Year Report 2024 A-8

APMs derived from the condensed consolidated statement of financial position	30 June 2024 US$m			30 June 2023 US$m
Net tangible assets per ordinary security
Net assets		35,829			36,684
Adjusted for:
Goodwill		(3,697	)		(4,669	)
Non-controlling interest		(759	)		(775	)
Intangible assets		(205	)		(103	)
Net tangible assets		31,168			31,137
Number of issued and fully paid shares		1,898,749,771			1,898,749,771
Net tangible assets per ordinary security		16.42			16.40
Gearing
Interest-bearing liabilities (Current and non-current)		5,822			5,109
Lease liabilities (Current and non-current)		1,545			1,570
Adjusted for:
Cash and cash equivalents		(1,979	)		(3,469	)
Add: Restricted cash		—			10
Net debt		5,388			3,220
Equity attributable to equity holders of the parent		35,070			35,909
Total net debt and equity attributable to equity holders of the parent		40,458			39,129
Gearing (%)		13.3			8.2

APMs derived from the condensed consolidated income statement and statement of financial position	30 June 2024 US$m		30 June 2023 US$m
Return on equity
Net profit after tax attributable to equity holders of the parent		1,937		1,740
Equity attributable to equity holders of the parent		35,070		35,909
Return on equity (%)		5.5		4.8
Return on average capital employed
Profit before tax and net finance costs		2,362		2,791
Opening non-current liabilities		15,209		15,586
Closing non-current liabilities		14,932		15,109
Average non-current liabilities		15,071		15,348
Opening equity attributable to equity holders of the parent		34,399		36,336
Closing equity attributable to equity holders of the parent		35,070		35,909
Average equity attributable to equity holders of the parent		34,735		36,123
Total average non-current liabilities and equity attributable to equity holders of the parent		49,806		51,471
Return on average capital employed (%)		4.7		5.4

APMs derived from other notes	30 June 2024 US$m			30 June 2023 US$m
Revenue from sale of hydrocarbons (excluding marketing segment)		5,376			6,486
Cash margin (excluding marketing segment)
Gross profit/(loss)		2,526			3,221
Adjusted for:
Other cost of sales		21			—
Trading costs		—			4
Oil and gas properties depreciation and amortisation		1,893			1,944
Other revenue		(99	)		41
Cash margin (excluding marketing segment)		4,341			5,210
Cash margin %		81	%		80	%
Production costs (excluding marketing segment)		745			807
Production cost margin %		14	%		13	%
Other cash costs (excluding marketing segment):
Royalties, excise and levies		196			316
Insurance		26			34
Inventory movement		(62	)		(33	)
Shipping and direct sales costs		104			145
Other hydrocarbon costs		26			7
Total other cash costs (excluding marketing segment)		290			469
Other cash cost margin %		5	%		7	%

Woodside Energy Group Ltd | Half-Year Report 2024 A-9

Notes

Glossary

Term	Definition
$, $m	US dollars unless otherwise stated, millions of dollars
1P	Proved reserves
2C	Best Estimate of Contingent resources
2P	Proved plus Probable reserves
Abate/abatement	Avoidance, reduction or removal of an amount of carbon dioxide or equivalent.
ASX	Australian Securities Exchange
A$, AUD	Australian dollars
BHP Petroleum	Woodside Energy Global Holdings Pty Ltd ACN 006 923 897 (formerly known as BHP Petroleum International Pty Ltd) and, unless context otherwise requires, its subsidiaries. References to “Woodside Energy Global Holdings Pty Ltd” or “BHP Petroleum International Pty Ltd” are references to Woodside Energy Global Holdings Pty Ltd ACN 006 923 897 (formerly known as BHP Petroleum International Pty Ltd) excluding its subsidiaries.
Biodiversity	Biological diversity means the variability among living organisms from all sources including, inter alia, terrestrial, marine and other aquatic ecosystems and the ecological complexes of which they are a part; this includes diversity within species, between species and of ecosystems.1
Board	The Board of Directors of Woodside Energy Group Ltd
Brent	Intercontinental Exchange (ICE) Brent Crude deliverable futures contract (oil price)
Capital expenditure	Includes capital additions on oil and gas properties and evaluation capitalised.
Carbon credit	A tradeable financial instrument that is issued by a carbon-crediting program. A carbon credit represents a greenhouse gas emission reduction to, or removal from, the atmosphere equivalent to 1 tCO2-e, calculated as the difference in emissions from a baseline scenario to a project scenario. Carbon credits are uniquely serialised, issued, tracked and retired or administratively cancelled by means of an electronic registry operated by an administrative body, such as a carbon-crediting program.
Cash margin	Gross profit/loss adjusted for other cost of sales, trading costs, oil and gas properties depreciation and amortisation and other revenue. Excludes the marketing segment. Cash margin % is calculated as cash margin divided by revenue from sale of hydrocarbons (excluding marketing segment).
CCS	Carbon capture and storage
CCUS	Carbon capture utilisation and storage
CHF	Swiss francs
CO2	Carbon dioxide
CO2-e	CO2 equivalent. The universal unit of measurement to indicate the global warming potential of each of the seven greenhouse gases, expressed in terms of the global warming potential of one unit of carbon dioxide. It is used to evaluate releasing (or avoiding releasing) any greenhouse gas against a common basis.2
Condensate	Hydrocarbons that are gaseous in a reservoir but that condense to form liquids as they rise to the surface.
cps	Cents per share
Decarbonisation	Woodside uses this term to describe activities or pathways that have the effect of moving towards a state that is lower carbon, as defined in this glossary.
DRP	Dividend reinvestment plan
EBIT	Calculated as profit before income tax, PRRT and net finance costs
EBITDA excluding impairment	Calculated as profit before income tax, PRRT, net finance costs, depreciation and amortisation, impairment losses, impairment reversals
Emissions	Emissions refers to emissions of greenhouse gases unless otherwise stated.
EPS	Earnings per share
Exploration expenditure	Includes exploration and evaluation expenditure less amortisation of licence acquisition costs and prior year exploration expense written off.
Extended Interest Joint Ventures or Extended Interest JVs	The Extended Interest Joint Ventures commenced on 1 August 2020 and cover the relevant joint venturers’ production entitlement for equity lifted LNG and pipeline gas from the North West Shelf Project. Woodside’ participating interest in the Extended Interest Joint Ventures is 31.567%.

Woodside Energy Group Ltd | Half-Year Report 2024 A-10

FEED	Front-end engineering design
FID	Final investment decision
FPSO	Floating production storage and offloading
FPU	Floating production unit
Free cash flow	Cash flow from operating activities and cash flow used in investing activities
GAAP	Generally Accepted Accounting Principles
Gearing	Net debt divided by the total of net debt and equity attributable to equity holders of the parent.
GHG or greenhouse gas	The seven greenhouse gases listed in the Kyoto Protocol are: carbon dioxide (CO2); methane (CH4); nitrous oxide (N2O); hydrofluorocarbons (HFCs); nitrogen trifluoride (NF3); perfluorocarbons (PFCs); and sulphur hexafluoride (SF6).2
Goal	Woodside uses this term to broadly encompass its targets and aspirations.
Gross margin	Gross profit divided by operating revenue. Gross profit excludes income tax, PRRT, net finance costs, other income and other expenses.
H1, H2	Halves of the calendar year (H1 is 1 January to 30 June and H2 is 1 July to 31 December).
HSE	Health, safety and environment
IFRS	International Financial Reporting Standards
JV	Joint venture
KGP	Karratha Gas Plant
Liquidity	Total cash and cash equivalents and available undrawn debt facilities less restricted cash.
LNG	Liquified natural gas
Lower carbon	Woodside uses this term to describe the characteristic of having lower levels of associated potential GHG emissions when compared to historical and/or current conventions or analogues, for example relating to an otherwise similar resource, process, production facility, product or service, or activity.
Lower carbon ammonia	Lower carbon ammonia is characterised here by the use of hydrogen with emissions abated by carbon, capture, and storage (CCS), with an expected ammonia lifecycle (Scope 1, 2 and 3) carbon emissions intensity of 0.8 tCO2/tNH3 (based on contracted intensity threshold with Linde) relative to unabated ammonia with a lifecycle (Scope 1, 2 and 3) carbon emissions intensity of 2.3 tCO2/tNH3 (Hydrogen Europe, 2023).
Lower carbon portfolio	For Woodside, a lower carbon portfolio is one from which the net equity Scope 1 and 2 greenhouse gas emissions, which includes the use of offsets, are being reduced towards targets, and into which new energy products and lower carbon services are planned to be introduced as a complement to existing and new investments in oil and gas. Our Climate Policy sets out the principles that we believe will assist us achieve this aim.
Lower carbon services	Woodside uses this term to describe technologies, such as CCUS or offsets that could be used by customers to reduce their net greenhouse gas emissions.
LSE	London Stock Exchange
Net debt	Interest-bearing liabilities and lease liabilities less cash and cash equivalents.
Net profit attributable to equity holders of the parent	Net profit after tax excluding non-controlling interests from the Group’s operations.
Net tangible assets	The Group’s net assets less goodwill, non-controlling interest and intangible assets.
Net tangible assets per ordinary security	Net tangible assets divided by the number of issued and fully paid shares.
New energy	Woodside uses this term to describe energy technologies, such as hydrogen or ammonia, that are emerging in scale but which are expected to grow during the energy transition due to having lower greenhouse gas emissions at the point of use than conventional fossil fuels.
NGLs	Natural gas liquids
NPAT	Net profit after tax attributable to equity holders of the parent

Woodside Energy Group Ltd | Half-Year Report 2024 A-11

NWS	North West Shelf
NYSE	New York Stock Exchange
Offsets	The compensation for an entity’s greenhouse gas emissions within its scope by achieving an equivalent amount of emission reductions or removals outside the boundary or value chain of that entity.
Other cash cost margin	Other cash costs include royalties, excise and levies, insurance, inventory movement, shipping and direct sales costs and other hydrocarbon costs. Excludes the marketing segment. Other cash cost margin  % is calculated as other cash costs divided by revenue from sale of hydrocarbons (excluding marketing segment).
Production cost margin	Production cost margin  % is calculated as production costs divided by revenue from sale of hydrocarbons. Excludes the marketing segment.
PRRT	Petroleum resources rent tax
PSC	Production sharing contract
PSE	Process safety event
Revenue from ordinary activities	Revenue from the sale of hydrocarbons, processing and services revenue and shipping and other revenue.
RFSU	Ready for start up
RSSD	Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore.
Scope 1 GHG emissions	Direct GHG emissions. These occur from sources that are owned or controlled by the company, for example, emissions from combustion in owned or controlled boilers, furnaces, vehicles, etc.; emissions from chemical production in owned or controlled process equipment. Woodside estimates greenhouse gas emissions, energy values and global warming potentials are estimated in accordance with the relevant reporting regulations in the jurisdiction where the emissions occur (e.g. Australian national Greenhouse and Energy Reporting (nGER), US EPA Greenhouse Gas Reporting Program (GHGRP)). Australian regulatory reporting principles have been used for emissions in jurisdictions where regulations do not yet exist.3
Scope 2 GHG emissions	Electricity indirect GHG emissions. Scope 2 accounts for GHG emissions from the generation of purchased electricity consumed by the company. Purchased electricity is defined as electricity that is purchased or otherwise brought into the organisational boundary of the company. Scope 2 emissions physically occur at the facility where electricity is generated. Woodside estimates greenhouse gas emissions, energy values and global warming potentials are estimated in accordance with the relevant reporting regulations in the jurisdiction where the emissions occur (e.g. Australian national Greenhouse and Energy Reporting (nGER), US EPA Greenhouse Gas Reporting Program (GHGRP)). Australian regulatory reporting principles have been used for emissions in jurisdictions where regulations do not yet exist.3
Scope 3 GHG emissions	Other indirect GHG emissions. Scope 3 is a reporting category that allows for the treatment of all other indirect emissions. Scope 3 emissions are a consequence of the activities of the company but occur from sources not owned or controlled by the company. Some examples of Scope 3 activities are extraction and production of purchased materials; transportation of purchased fuels; and use of sold products and services.
Significant environmental event	Unplanned or undesired event resulting in a moderate, medium-term impact on ecosystem, species, habitat or physical or biological attributes.
Sustainably (including sustainable and sustainably)	References to sustainability (including sustainable and sustainably) are used with reference to Woodside’s Sustainability Committee and sustainability related Board policies, as well as in the context of Woodside’s aim to ensure its business is sustainable from a long-term perspective, considering a range of factors including economic (including being able to sustain our business in the long term by being low cost and profitable), environmental (including considering our environmental impact and striving for a lower carbon portfolio), social (including supporting our license to operate), and regulatory (including ongoing compliance with relevant legal obligations). Use of the terms ‘sustainability’, ‘sustainable’ and ‘sustainably’ is not intended to imply that Woodside will have no adverse impact on the economy, environment, or society, or that Woodside will achieve any particular economic, environmental, or social outcomes.
Target	Woodside uses this term to describe an intention to seek the achievement of an outcome, where Woodside considers that it has developed a suitably defined plan or pathway to achieve that outcome
TCFD	Taskforce on Climate-related Financial Disclosures
Tier 1 PSE	A typical Tier 1 process safety event is loss of containment of hydrocarbons greater than 500 kg (in any one-hour period).
Tier 2 PSE	A typical Tier 2 process safety event is loss of containment of hydrocarbons greater than 50 kg but less than 500 kg (in any one-hour period).
TRIR	Total recordable injury rate. The number of recordable injuries (fatalities, lost workday cases, restricted work day cases and medical treatment cases) per million work hours

Woodside Energy Group Ltd | Half-Year Report 2024 A-12

Underlying NPAT	Net profit after tax from the Group’s operations excluding any exceptional items
Unit production cost or UPC	Production costs ($    million) divided by production volume (MMboe)
US, USA	United States of America
USD	US dollars
WA	Western Australia

1. UNEP,1992. “Convention on Biological Diversity’ https://www.cbd.int/doc/legal/cbd-en.pdf.

2. See IFRS Foundation 2021: Climate Related Disclosures Prototype. Appendix A. The IFRS published a further consultation document subsequent to the 2021 prototype. As it did not contain an updated definition of Paris-Aligned scenarios Woodside has retained use of the previous edition.

3. World Resources Institute and World Business Council for Sustainable Development 2004. “GHG Protocol: a corporate accounting and reporting standard”.

Conversion factors

Product	Unit	Conversion factor
Natural gas	5,700 scf	1 boe
Condensate	1 bbl	1 boe
Oil	1 bbl	1 boe
Natural gas liquids	1 bbl	1 boe

Facility	Unit	LNG conversion factor
Karratha Gas Plant	1 tonne	8.08 boe
Pluto Gas Plant	1 tonne	8.34 boe
Wheatstone	1 tonne	8.27 boe

The LNG conversion factor from tonne to boe is specific to volumes produced at each facility and is based on gas composition which may change over time.

Units of measure

Term	Definition
bbl	barrel
bcf	billion cubic feet of gas
boe	barrel of oil equivalent
CO2-e	carbon dioxide equivalent
GJ	gigajoule
ha	hectare
Mbbl	thousand barrels
Mbbl/d	thousand barrels per day
Mboe	thousand barrels of oil equivalent
Mboe/d	thousand barrels of oil equivalent per day
Mcf	thousand cubic feet of gas
MMboe	million barrels of oil equivalent
MMBtu	million British thermal units
MMscf	million standard cubic feet of gas
MMscf/d	million standard cubic feet of gas per day
Mtpa	million tonnes per annum

Woodside Energy Group Ltd | Half-Year Report 2024 A-13

MW	megawatt
PJ	petajoules
scf	standard cubic feet of gas
TJ	terajoule
tpd	tonnes per day

Woodside Energy Group Ltd | Half-Year Report 2024 A-14

EX-99.2

Exhibit 99.2

Disclaimer and important notice

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, statements regarding outcomes of transactions, including the timing, terms and potential benefits of the proposed acquisition of Tellurian, 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, assumptions 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 include, but are not limited to, fluctuations in commodity prices, actual demand for Woodside’s 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, environmental risks, climate related risks, physical risks, legislative, fiscal and regulatory developments, changes in accounting standards, economic and financial markets conditions in various countries and regions, political risks, the actions of third parties, project delay or advancement, regulatory approvals, the impact of armed conflict and political instability (such as the ongoing conflict in Ukraine and in the Middle East) on economic activity and oil and gas supply and demand, cost estimates, the effect of future regulatory or legislative actions on Woodside or the industries in which it operates, including potential changes to tax laws, and 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 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 the “Risk” section of Woodside’s most recent Annual Report released to the Australian Securities Exchange and the London Stock Exchange and in Woodside’s most recent Annual Report on Form 20-F filed with the United States Securities and Exchange Commission and available on the Woodside website at https://www.woodside.com/investors/reports-investor-briefings. 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.

1 | Second quarter report for period ended 30 June 2024

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, Woodside does not intend to, undertake to, or assume 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, 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.

Other important information

All figures are Woodside share for the quarter ending 30 June 2024, unless otherwise stated.

All references to dollars, cents or $ in this report are to US currency, unless otherwise stated.

References to “Woodside” may be references to Woodside Energy Group Ltd and/or its applicable subsidiaries (as the context requires).

The conversion factors used throughout this report are set out under “Units of measure and conversion factors”, unless otherwise stated.

2 | Second quarter report for period ended 30 June 2024

SECOND QUARTER REPORT FOR PERIOD ENDED 30 JUNE 2024

ASX: WDS | NYSE: WDS | LSE: WDS

Tuesday, 23 July 2024

Delivering on our growth strategy

Operations

• Quarterly production of 44.4 MMboe (488 Mboe/day), down 1% from Q1 2024 due to planned maintenance activities, weather impacts at North West Shelf and unplanned outages at Wheatstone and Julimar, partly offset by higher seasonal demand at Bass Strait and first oil at Sangomar. Full year production guidance remains unchanged.

• Sold 22% of total equity production in the quarter on prices linked to gas hub indices.¹ Full year gas hub guidance remains unchanged.

Projects

• The Sangomar Project achieved first oil in June and production continues to ramp up as planned. Subsequent to the quarter, the first cargo was loaded for delivery to Europe.

• The Scarborough Energy Project was 67% complete at the end of the quarter, with first LNG cargo expected in 2026.²

• The total estimated cost of the Scarborough Energy Project has increased by 4% to US$12.5 billion (US$8.2 billion Woodside share), significantly driven by scope maturation of the Pluto Train 1 modifications project.³

• The Trion Project continued to progress engineering, procurement, and contracting activities in accordance with the execution plan.

• Secured all primary environmental approvals for the Hydrogen Refueller @H2Perth and progressed offtake discussions for the H2OK Project.

Other

• Signed a sale and purchase agreement (SPA) with CPC Corporation, Taiwan (CPC) for the long-term supply of LNG to Taiwan.

• Secured $1 billion funding from Japan Bank for International Cooperation (JBIC) for the Scarborough Energy Project.

• Subsequent to the quarter, Woodside entered into a definitive agreement to acquire Tellurian and its US Gulf Coast Driftwood LNG development opportunity for an all-cash payment of approximately $900 million.

Woodside CEO Meg O’Neill said the company is on track to achieve its full year production guidance of 185-195 million barrels of oil equivalent (MMboe), with output for the second quarter of 44.4 MMboe.

“The first oil from our Sangomar project offshore Senegal was a significant milestone, delivering against our growth strategy. Subsequent to the quarter, we achieved peak gross rate of 75,000 barrels per day and production ramp-up continues as planned.

“The addition of Sangomar to Woodside’s portfolio will deliver enduring shareholder value and significant economic benefits for Senegal.

“Work on our other major growth projects continued at pace. The Scarborough Energy Project in Western Australia is now more than two-thirds complete and we remain on target for first LNG cargo in 2026.

“We are also progressing our opportunities in new energy, securing all primary environmental approvals for the Hydrogen Refueller @H2Perth, while continuing offtake discussions for H2OK in the US.

“We see ongoing demand for Woodside’s LNG in Asian markets, as evidenced by our long-term sale and purchase agreement with CPC Corporation, Taiwan, and the $1 billion loan agreement executed with JBIC to fund Woodside’s Scarborough Energy Project.

“The recent announcement of an agreement to acquire Tellurian and Driftwood LNG positions Woodside to be a global LNG powerhouse, adding scalable US LNG development exposure to our portfolio,” she said.

¹  45% of produced LNG cargoes in the quarter were sold on prices linked to gas hub indices.

²  The completion % excludes the Pluto Train 1 modifications project.

³  The total project cost includes the cost for the Scarborough project, the Pluto Train 2 project and the Pluto Train 1 modifications project. Refer to page 5 for additional information.

3 | Second quarter report for period ended 30 June 2024

Comparative performance at a glance

		Q2 2024		Q1 2024		Change %			Q2 2023		Change %			YTD 2024		YTD 2023		Change %
Production4	MMboe		44.4		44.9		(1	%)		44.5		—			89.3		91.3		(2	%)
Gas	MMscf/d		1,885		1,929		(2	%)		1,905		(1	%)		1,907		1,999		(5	%)
Liquids	Mbbl/d		157		155		1	%		155		1	%		156		154		1	%
Total	Mboe/d		488		494		(1	%)		489		—			491		504		(3	%)
Sales	MMboe		48.0		45.9		5	%		48.4		(1	%)		93.9		98.8		(5	%)
Gas	MMscf/d		2,103		1,967		7	%		2,170		(3	%)		2,035		2,268		(10	%)
Liquids	Mbbl/d		159		159		—			151		5	%		159		148		7	%
Total	Mboe/d		528		504		5	%		532		(1	%)		516		546		(5	%)
Average realised price	$/boe		62		63		(2	%)		63		(2	%)		63		74		(15	%)

Operations

North West Shelf (NWS) Project

• Achieved strong quarterly LNG reliability of 99.7%.

• Successfully completed planned offshore maintenance at Goodwyn Alpha (GWA).

• Progressed the proposed GWA infill development for potential final investment decision (FID) in 2025, which would involve tying back several fields via existing GWA subsea infrastructure.

Pluto LNG

• Achieved quarterly LNG reliability of 97.7%.

• Successfully completed a two-day turnaround at Pluto LNG to enable integration testing of the produced water handling unit into the Pluto A platform.

• Increased Pluto domestic gas production through the Pluto-KGP interconnector at the NWS.

Wheatstone and Julimar-Brunello

• Two separate unplanned outages occurred in the quarter, impacting the Julimar subsea production system and the Wheatstone facility respectively. Full production resumed in the quarter.

Bass Strait

• Completed offshore installation of the Kipper Compression modules, with the project progressing hook-up activities for a planned start-up in Q3 2024.

• The Gippsland Basin Joint Venture (GBJV) continues to optimise its facilities through the Gippsland Asset Streamlining project with the Halibut platform ceasing production as planned following declining oil production from the facility.

Other Australia

• Successfully completed the planned five-yearly maintenance turnaround at the Pyrenees floating production storage and offloading (FPSO) facility.

• A produced-water leak identified in the subsea system at the Pyrenees facility in January was rectified and production recommenced, returning to normal rates this quarter.

⁴  Q2 2024 includes 0.30 MMboe, Q1 2024 includes 0.29 MMboe and Q2 2023 includes 0.23 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

4 | Second quarter report for period ended 30 June 2024

Gulf of Mexico

• Achieved quarterly reliability of 98.9% at Shenzi.

• Executed a planned major offshore facility turnaround at Atlantis.

• Achieved first water injection at the Argos platform in April 2024.

Trinidad & Tobago

• Safely completed a planned facility maintenance turnaround in June 2024 aimed at proactive risk and integrity management and control system upgrades.

Marketing

• Signed a long-term LNG SPA with CPC for the supply of approximately 6 million tonnes of LNG on a delivered basis over 10 years, commencing in July 2024. LNG delivered under the SPA will be sourced from volumes across Woodside’s global portfolio.

• Sold 45% of produced LNG at prices linked to gas hub indices in the quarter (34% year to date). This represents 22% of Woodside’s total equity production (16% year to date). Full year gas hub guidance remains unchanged.

• Took delivery of a new 174,000m³ long-term charter LNG vessel, the Woodside Scarlet Ibis, which will support efforts to lower the carbon intensity of Woodside’s LNG deliveries.

• Executed 14 PJ of Western Australian gas sales for delivery from May to the end of 2024. Woodside continues to support the Western Australian domestic market by offering additional supply for 2025, 2026 and 2027.

• Achieved record trucked LNG deliveries of 525 TJ during the quarter to customers in northern Western Australia. Woodside has now delivered more than 2000 trailers of LNG since commencement of operations at the Pluto LNG Truck Loading Facility, offering a lower-carbon alternative to diesel.⁵

Projects

Scarborough Energy Project

• A cost and schedule review was performed for the integrated Scarborough Energy Project. The schedule remains unchanged, with first LNG cargo targeted for 2026. The revised total project cost estimate is US$12.5 billion (US$8.2 billion Woodside share), a 4% increase from the previous cost estimate at FID of US$12 billion. The cost increase is significantly driven by scope maturation of the Pluto Train 1 modifications project.⁶

• The Scarborough and Pluto Train 2 project was 67% complete at the end of the quarter.

• 29 Pluto Train 2 modules have been delivered to site, with 25 modules set in position at the end of the quarter and site works continuing to ramp up.

• Fabrication of the floating production unit (FPU) hull and topsides progressed. The living quarters module was installed on the topsides, which has achieved structural completion.

• Trunkline installation has transitioned from the 36” to 32” pipe and is now more than 50% complete.

• Two development wells have been drilled, with one well completed and the other planned to be completed in H2 2024. Reservoir quality is aligned with pre-drill estimates.

• Installation and testing of the three flowlines was completed.

• All major engineering reviews for Pluto Train 1 modifications have been completed and approximately 80% of materials and equipment have been ordered. Mobilisation of personnel to both the module yard and Pluto site commenced.

⁵  Woodside uses this term to describe the characteristic of having lower levels of associated potential greenhouse gas emissions when compared to historical and/or current conventions or analogues, for example relating to an otherwise similar product.

⁶  The total project cost includes the cost for the Scarborough project, the Pluto Train 2 project and the Pluto Train 1 modifications project. Woodside share is based on a participating interest in the Scarborough Joint Venture (SJV) of 74.9% (compared to 73.5% at FID) and assumes completion of the sell-down of a 15.1% participating interest in the SJV to JERA. Woodside share excludes the impact of GIP’s additional contribution to Pluto Train 2 ($0.8 billion).

5 | Second quarter report for period ended 30 June 2024

Sangomar Field Development Phase 1

• Achieved first oil from the Sangomar field in June 2024, marking the delivery of Senegal’s first offshore oil project.

• Finalised sales for initial Sangomar crude cargoes loading in July 2024, receiving interest from European and Asian refiners. The first cargo was loaded subsequent to the quarter.

• The project was 98% complete at the end of the quarter.

• The development drilling program continued with 21 of 23 wells drilled and completed. An additional 24th well approved by the joint venture in May 2023 was also drilled and completed in the period.

• Commissioning activities and the safe ramp up of production are expected to continue through 2024.

Trion

• Awarded contracts for the FPU dry transportation, gas gathering line pipe and drilling equipment and consumables.

• Progressed FPU engineering, procurement and construction activities with procurement of key equipment and the integration of vendor data into the design.

• Completed floating, storage and offloading vessel (FSO) front-end engineering design (FEED).

Decommissioning

• The Griffin, Stybarrow and Enfield decommissioning campaign continued with ~50km of flexible flowlines and umbilicals recovered in the quarter.

• The final two of 18 xmas trees were removed from Enfield and wellhead severance commenced, with four completed at the end of the quarter.

• At Bass Strait, offshore execution of the plug and abandonment of two subsea wells commenced, utilising the Q7000 light well intervention vessel.

• The GBJV also progressed FEED of the facility preparation scope for removal of platforms no longer in use and continued to execute preparatory decommissioning activities.

Exploration and development

Calypso

• Continued pre-FEED engineering studies to mature the technical definition and cost estimate for the deepwater infield host.

• Continued fiscal and marketing negotiations with various counterparties to assess the commercial options to monetise the Calypso resource.

Browse

• In June 2024, a Declaration of an Identified Greenhouse Gas Storage Formation was made by the Commonwealth Government over the Calliance Storage Formation within the G-8-AP Greenhouse Gas Assessment Permit (held by Woodside as Operator of Browse). This declaration supports the proposed carbon capture and storage solution incorporated into the Browse design.

Sunrise

• The Sunrise Joint Venture participants continued to work with the Australian and Timor Leste governments to progress a new Production Sharing Contract, Petroleum Mining Code and fiscal regime.

Exploration

• In Congo, the Niamou Marine-1 well spud in May 2024 under the Marine XX joint venture operated by TotalEnergies.

6 | Second quarter report for period ended 30 June 2024

New energy and carbon solutions

H2OK

• Continued to advance discussions with potential offtakers on pricing and volumes.

• Woodside is awaiting final guidance for the 45V Clean Hydrogen Production Tax Credit.

Woodside Solar

• Working with the Western Australian Government to progress its plans to develop common user transmission infrastructure required to support the proposed project.

• FID readiness and first solar import will be subject to securing access to this new infrastructure.

Hydrogen Refueller @H2Perth

• Secured primary environmental approvals for the Hydrogen Refueller @H2Perth.

• Commenced factory acceptance testing for key project equipment packages.

• Woodside is targeting supply of hydrogen to Western Australian industrial customers in 2025.

Carbon capture and storage (CCS) opportunities

• Continued to progress engineering and marketing activities and required approvals for the Angel CCS project.

Carbon Credits Portfolio

• Subsequent to the quarter, Woodside signed an agreement to fund the reforestation of 5000 hectares of land in the Chaco region in Paraguay. The Woodside portion of the project is expected to generate approximately 1.6 million carbon credits over 40 years.

Corporate activities

Hedging

• Woodside hedged approximately 29.3 MMboe of 2024 oil production at an average price of approximately $75.6 per barrel, with approximately 49% delivered as of 30 June 2024.

• Woodside additionally hedged approximately 15 MMboe of 2025 oil production at an average price of approximately $81.2 per barrel.

• Woodside also has a hedging program for Corpus Christi LNG volumes designed to protect against downside pricing risk. These hedges are Henry Hub (HH) and Title Transfer Facility (TTF) commodity swaps. Approximately 70% of volumes for the remainder of 2024, 48% of 2025 and 9% of 2026 volumes have been hedged.

• The realised value of all hedged positions for the half-year ended 30 June 2024 is a pre-tax expense of approximately $45 million, with $111 million related to oil price hedges offset by $65 million profit related to Corpus Christi hedges and $1 million related to other hedge positions. Hedging losses will be included in “other expenses” in the full-year financial statements.

Funding

• In May 2024, Woodside secured a $1 billion, 10-year loan from JBIC to support the Scarborough Energy Project. This loan was secured at prevailing market rates associated with Woodside’s credit rating.

Climate and sustainability

• Woodside’s Annual General Meeting (AGM) took place on 24 April 2024, where all resolutions were passed except for the Climate Transition Action Plan and 2023 Progress Report (CTAP), which received a vote of 58.36% against it. Management is reflecting on the results of the CTAP vote.

• Woodside published its 2023 Social Contribution Impact Report in April 2024 and its 2023 Modern Slavery Statement in June 2024.

7 | Second quarter report for period ended 30 June 2024

• Woodside hosted a methane masterclass during the Australian Energy Producers (AEP) conference as part of its commitment to the decarbonisation of its activities and to share Woodside’s best practices on methane emissions reduction.

August	27	Half-Year 2024 report
September	16	US investor event
October	16	Third quarter 2024 report

2024 full-year guidance

		Prior	Current
Production	MMboe	185 – 195 (505 – 533 Mboe/day)	No change
Capital expenditure7	$ billion	5.0 – 5.5	No change
Gas hub exposure8	% of produced LNG	26 – 33	No change

⁷  Capital expenditure includes the following participating interests; Sangomar (82%); Scarborough (90% following completion of the transaction with LNG Japan in March 2024 and 74.9% following completion of the transaction with JERA, expected in the second half of 2024), Pluto Train 2 (51%) and Trion (60%). Trion capital expenditure includes Pemex carry. This guidance assumes no change to these participating interests in 2024. This excludes the impact of any future asset sell-downs, acquisitions or other changes in equity.

⁸  Gas hub indices include Japan Korea Marker (JKM), TTF and National Balancing Point (NBP). It excludes HH.

8 | Second quarter report for period ended 30 June 2024

Production summary

		Q2 2024		Q1 2024		Q2 2023		YTD 2024		YTD 2023
Gas	MMscf/d		1,885		1,929		1,905		1,907		1,999
Liquids	Mbbl/d		157		155		155		156		154
Total	Mboe/d		488		494		489		491		504
		Q2 2024		Q1 2024		Q2 2023		YTD 2024		YTD 2023
AUSTRALIA
LNG
North West Shelf	Mboe		7,088		8,192		8,746		15,280		18,419
Pluto9	Mboe		11,726		11,754		8,765		23,480		20,919
Wheatstone	Mboe		1,959		2,357		2,588		4,316		5,044
Total	Mboe		20,773		22,303		20,099		43,076		44,382
Pipeline gas
Bass Strait	Mboe		3,410		2,359		4,170		5,769		7,303
Other10	Mboe		3,848		3,278		3,080		7,126		6,117
Total	Mboe		7,258		5,637		7,250		12,895		13,420
Crude oil and condensate
North West Shelf	Mbbl		1,260		1,412		1,546		2,672		3,230
Pluto9	Mbbl		933		931		699		1,864		1,660
Wheatstone	Mbbl		380		462		425		842		833
Bass Strait	Mbbl		503		492		904		995		1,681
Macedon & Pyrenees	Mbbl		107		109		759		216		1,390
Ngujima-Yin	Mbbl		974		886		—		1,860		869
Okha	Mbbl		491		466		421		957		852
Total	Mboe		4,648		4,758		4,754		9,406		10,515
NGL
North West Shelf	Mbbl		279		290		339		569		631
Pluto10	Mbbl		59		54		45		113		95
Bass Strait	Mbbl		941		832		1,191		1,773		1,914
Total	Mboe		1,279		1,176		1,575		2,455		2,640
Total Australia11	Mboe		33,958		33,874		33,678		67,832		70,957
	Mboe/d		373		372		370		373		392

⁹  Q2 2024 includes 2.18 MMboe of LNG, 0.10 MMboe of condensate and 0.06 MMboe of NGL, Q1 2024 includes 2.60 MMboe of LNG, 0.10 MMboe of condensate and 0.05 MMboe of NGL and Q2 2023 includes 1.96 MMboe of LNG and 0.08 MMboe of condensate and 0.04 MMboe of NGL processed at the Karratha Gas Plant (KGP) through the Pluto-KGP Interconnector.

¹⁰  Includes the aggregate Woodside equity domestic gas production from all Western Australian projects.

¹¹  Q2 2024 includes 0.30 MMboe, Q1 2024 includes 0.29 MMboe and Q2 2023 includes 0.23 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

9 | Second quarter report for period ended 30 June 2024

		Q2 2024		Q1 2024		Q2 2023		YTD 2024		YTD 2023
INTERNATIONAL
Pipeline gas
Gulf of Mexico	Mboe		324		360		349		684		679
Trinidad & Tobago	Mboe		1,736		2,503		2,723		4,239		4,959
Other12	Mboe		—		—		—		—		30
Total	Mboe		2,060		2,863		3,072		4,923		5,668
Crude oil and condensate
Atlantis	Mbbl		2,019		2,441		2,792		4,460		5,488
Mad Dog	Mbbl		2,944		2,765		1,627		5,709		2,566
Shenzi	Mbbl		2,333		2,405		2,599		4,738		5,195
Trinidad & Tobago	Mbbl		94		126		294		220		591
Sangomar	Mbbl		540		—		—		540		—
Other12	Mbbl		81		81		81		162		120
Total	Mboe		8,011		7,818		7,393		15,829		13,960
NGL
Gulf of Mexico	Mbbl		355		393		350		748		681
Other12	Mbbl		—		—		—		—		17
Total	Mboe		355		393		350		748		698
Total International	Mboe		10,426		11,074		10,815		21,500		20,326
	Mboe/d		115		122		119		118		112
Total production	Mboe		44,384		44,948		44,493		89,332		91,283
	Mboe/d		488		494		489		491		504

¹²  Overriding royalty interests held in the GoM for several producing wells.

10 | Second quarter report for period ended 30 June 2024

Product sales

		Q2 2024		Q1 2024		Q2 2023		YTD 2024		YTD 2023
Gas	MMscf/d		2,103		1,967		2,170		2,035		2,268
Liquids	Mbbl/d		159		159		151		159		148
Total	Mboe/d		528		504		532		516		546
		Q2 2024		Q1 2024		Q2 2023		YTD 2024		YTD 2023
AUSTRALIA
LNG
North West Shelf	Mboe		7,081		8,008		9,003		15,089		19,567
Pluto	Mboe		12,749		10,513		9,592		23,262		20,902
Wheatstone13	Mboe		2,264		2,589		2,312		4,853		4,662
Total	Mboe		22,094		21,110		20,907		43,204		45,131
Pipeline gas
Bass Strait	Mboe		3,508		2,570		4,113		6,078		7,195
Other14	Mboe		3,435		2,894		3,040		6,329		5,979
Total	Mboe		6,943		5,464		7,153		12,407		13,174
Crude oil and condensate
North West Shelf15	Mbbl		1,904		1,214		1,595		3,118		2,684
Pluto	Mbbl		1,283		640		614		1,923		1,228
Wheatstone	Mbbl		666		329		309		995		659
Bass Strait	Mbbl		271		597		1,035		868		1,117
Ngujima-Yin	Mbbl		1,018		999		—		2,017		1,141
Okha	Mbbl		572		618		—		1,190		653
Macedon & Pyrenees	Mbbl		—		496		1,032		496		1,550
Total	Mboe		5,714		4,893		4,585		10,607		9,032
NGL
North West Shelf	Mbbl		266		255		255		521		425
Pluto	Mbbl		49		55		73		104		255
Bass Strait	Mbbl		361		785		903		1,146		2,012
Total	Mboe		676		1,095		1,231		1,771		2,692
Total Australia	Mboe		35,427		32,562		33,876		67,989		70,029
	Mboe/d		389		358		372		374		387

¹³  Includes periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of 0.19 MMboe in Q2 2024, 0.28 MMboe in Q1 2024 and 0.15 MMboe in Q2 2023.

¹⁴  Includes the aggregate Woodside equity domestic gas production from all Western Australian projects.

¹⁵  Includes reclassification of purchased condensate volumes from NWS JV Participants to Marketing liquids of 0.26 MMboe in Q2 2023.

11 | Second quarter report for period ended 30 June 2024

		Q2 2024		Q1 2024		Q2 2023		YTD 2024		YTD 2023
INTERNATIONAL
Pipeline gas
Gulf of Mexico	Mboe		336		286		341		622		684
Trinidad & Tobago	Mboe		1,606		2,457		2,700		4,063		4,995
Other16	Mboe		5		6		6		11		13
Total	Mboe		1,947		2,749		3,047		4,696		5,692
Crude oil and condensate
Atlantis	Mbbl		2,013		2,426		2,710		4,439		5,378
Mad Dog	Mbbl		3,043		2,626		1,628		5,669		2,569
Shenzi	Mbbl		2,430		2,352		2,652		4,782		5,325
Trinidad & Tobago	Mbbl		19		52		248		71		661
Sangomar	Mbbl		—		—		—		—		—
Other16	Mbbl		59		60		65		119		128
Total	Mboe		7,564		7,516		7,303		15,080		14,061
NGL
Gulf of Mexico	Mbbl		454		413		363		867		705
Other16	Mbbl		3		3		3		6		7
Total	Mboe		457		416		366		873		712
Total International	Mboe		9,968		10,681		10,716		20,649		20,465
	Mboe/d		110		117		118		113		113
MARKETING17
LNG	Mboe		2,593		2,086		3,532		4,679		8,015
Liquids18	Mboe		37		571		260		608		260
Total	Mboe		2,630		2,657		3,792		5,287		8,275
Total Marketing	Mboe		2,630		2,657		3,792		5,287		8,275
Total sales	Mboe		48,025		45,900		48,384		93,925		98,769
	Mboe/d		528		504		532		516		546

¹⁶  Overriding royalty interests held in the GoM for several producing wells.

¹⁷  Purchased volumes sourced from third parties.

¹⁸  Includes reclassification of purchased condensate volumes from NWS JV Participants of 0.26 MMboe in Q2 2023.

12 | Second quarter report for period ended 30 June 2024

Realised prices

	Units	Q2 2024		Q1 2024		Q2 2023		Units	Q2 2024		Q1 2024		Q2 2023
LNG produced19	$/MMBtu		9.6		10.4		10.9	$/boe		60		67		69
LNG traded20	$/MMBtu		9.1		9.1		11.0	$/boe		58		59		70
Pipeline gas								$/boe		38		34		37
Oil and condensate	$/bbl		83		79		75	$/boe		83		79		75
NGL	$/bbl		44		47		41	$/boe		44		47		41
Liquids traded20	$/bbl		79		60		70	$/boe		79		60		70
Average realised price for pipeline gas:
Western Australia								A$/GJ		6.5		6.4		6.1
East coast Australia								A$/GJ		14.3		13.7		12.6
International								$/Mcf		3.9		4.6		6.7
Average realised price								$/boe		62		63		63
Dated Brent								$/bbl		85		83		78
JCC (lagged three months)								$/bbl		84		92		87
WTI								$/bbl		81		77		74
JKM								$/MMBtu		9.6		11.9		12.6
TTF								$/MMBtu		9.2		9.8		12.6

Average realised price decreased 2% from the prior quarter reflecting lower JKM, TTF and JCC.

¹⁹  Realised prices include the impact of periodic adjustments reflecting the arrangements governing Wheatstone LNG sales.

²⁰  Excludes any additional benefit attributed to produced volumes through third-party trading activities.

13 | Second quarter report for period ended 30 June 2024

Exploration or appraisal wells drilled

Region	Permit Area	Well	Target	Interest (%)	Spud Date	Water depth (m)		Planned well depth (m)21		Remarks
Congo	Marine XX	Niamou Marine 1	Oil	22.5% Non-Operator	24 May 2024		2,094		7,015	Drilling

Permits and licences

Key changes to permit and licence holdings during the quarter ended 30 June 2024 are noted below.

Region	Permits or licence areas	Change in interest (%)			Current interest (%)		Remarks
Australia	WA-356-P		(65	%)		0	License exit as part of portfolio optimisation
Gulf of Mexico	GC 738		(23.9	%)		0	License expiry
Egypt – Herodotus Basin	North Sidi Barani Offshore (Block 2)		(27	%)		0	License expiry

²¹  Well depths are referenced to the rig rotary table.

14 | Second quarter report for period ended 30 June 2024

Production rates

Average daily production rates (100% project) for the quarter ended 30 June 2024:

	Woodside share22			Production rate (100% project, Mboe/d)				Remarks
				June 2024		Mar 2024
AUSTRALIA
NWS Project
LNG		30.37	%		256		293	Production was lower due to weather event impacts and planned offshore maintenance at Goodwyn Alpha.
Crude oil and condensate		30.21	%		46		56
NGL		30.44	%		10		10
Pluto LNG
LNG		90.00	%		116		112	Production was higher primarily due to improved reliability.
Crude oil and condensate		90.00	%		10		10
Pluto-KGP Interconnector
LNG		100.00	%		24		29	LNG production lower due to increased domestic gas production.
Crude oil and condensate		100.00	%		1		1
NGL		100.00	%		1		1

²²  Woodside share reflects the net realised interest for the period.

15 | Second quarter report for period ended 30 June 2024

Wheatstone23
LNG Crude oil and condensate	10.18 13.85	%  %	212 30	224 31	Production was lower due to two separate unplanned outages, impacting the Julimar subsea system and the Wheatstone facility respectively.
Bass Strait
Pipeline gas	43.70	%	86	61	Production was higher due to increased seasonal domestic gas demand.
Crude oil and condensate	46.17	%	12	12
NGL	47.13	%	23	19
Australia Oil
Ngujima-Yin	60.00	%	18	13	Production at Ngujima-Yin and Okha was higher due to less weather downtime.
Okha	50.00	%	11	8
Pyrenees	62.90	%	2	2	Production at Pyrenees was low due to a subsea produced-water leak and the planned turnaround.
Other
Pipeline gas24			42	33	Production was higher due to increased pipeline gas deliveries from KGP, including from Pluto via the Pluto-KGP Interconnector.

²³  The Wheatstone asset processes gas from several offshore gas fields, including the Julimar and Brunello fields, for which Woodside has 65% participating interest and is the operator.

²⁴  Includes the aggregate Woodside equity domestic gas production from all Western Australian projects.

16 | Second quarter report for period ended 30 June 2024

	Woodside share25			Production rate (100% project, Mboe/d)				Remarks
				June 2024		Mar 2024
INTERNATIONAL
Atlantis
Crude oil and condensate		38.50	%		58		70	Production was lower due to the planned turnaround.
NGL		38.50	%		4		4
Pipeline Gas		38.50	%		5		6
Mad Dog
Crude oil and condensate		20.86	%		155		146
NGL		20.86	%		5		5
Pipeline Gas		20.86	%		3		3
Shenzi
Crude oil and condensate		65.09	%		39		41
NGL		65.20	%		2		2
Pipeline Gas		65.19	%		1		2
Trinidad & Tobago
Crude oil and condensate		58.75	%26		2		2	Production was lower due to planned maintenance activities.
Pipeline gas		48.90	%26		39		54
Sangomar
Crude Oil27		78.74	%		8		—	Field achieved first oil in June.

²⁵  Woodside share reflects the net realised interest for the period.

²⁶  Operations governed by production sharing contracts, Woodside share changes monthly.

²⁷  Sangomar production rate per day reflects total production in Q2 2024 divided by total number of days in the quarter.

17 | Second quarter report for period ended 30 June 2024

Units of measure and conversion factors

Product	Unit		Conversion factor
Natural gas		5,700 scf		1 boe
Condensate		1 bbl		1 boe
Oil		1 bbl		1 boe
Natural gas liquids		1 bbl		1 boe
Facility	Unit		LNG conversion factor
Karratha Gas Plant		1 tonne		8.08 boe
Pluto Gas Plant		1 tonne		8.34 boe
Wheatstone		1 tonne		8.27 boe

The LNG conversion factor from tonne to boe is specific to volumes produced at each facility and is based on gas composition which may change over time.

Term	Definition
bbl	barrel
bcf	billion cubic feet of gas
boe	barrel of oil equivalent
GJ	gigajoule
Mbbl	thousand barrels
Mbbl/d	thousand barrels per day
Mboe	thousand barrels of oil equivalent
Mboe/d	thousand barrels of oil equivalent per day
Mcf	thousand cubic feet of gas
MMboe	million barrels of oil equivalent
MMBtu	million British thermal units
MMscf/d	million standard cubic feet of gas per day
PJ	petajoules
scf	standard cubic feet of gas
TJ	terajoule

18 | Second quarter report for period ended 30 June 2024

EX-99.3

Exhibit 99.3

About this document

This document contains summary information concerning the industry, operations, activities and financial position of Woodside Energy Group Ltd that Woodside intends to refer in certain investor meetings or related interactions in September 2024. The information contained in this document is extracted or derived from information that Woodside has previously published.

Woodside Energy Group Ltd (ABN 55 004 898 962) is the parent company of the Woodside group of companies. In this document, unless otherwise stated, references to ‘Woodside’, ‘the company’, ‘the Group’, ‘we’, ‘us’ and ‘our’ refer to Woodside Energy Group Ltd and its controlled entities as a whole. The text does not distinguish between the activities of the parent company and those of its controlled entities.

All dollar figures are expressed in US currency unless otherwise stated. Production and sales volumes, reserves and resources are quoted as Woodside share. A glossary of key terms, units of measure and conversion factors is on pages A-10 to A-14 of Woodside’s 2024 Half Year Report, attached as Exhibit 99.1 to the Form 6-K to which this document is filed (the “2024 Half-Year Report”).

Forward looking statements

This document 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, statements regarding 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 document 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, assumptions 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 include, but are not limited to, fluctuations in commodity prices, actual demand for Woodside’s 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, environmental risks, climate related risks, physical risks, legislative, fiscal and regulatory developments, changes in accounting standards, economic and financial markets conditions in various countries and regions, political risks, the actions of third parties, project delay or advancement, regulatory approvals, the impact of armed conflict and political instability (such as the ongoing conflict in Ukraine and in the Middle East) on economic activity and oil and gas supply and demand, cost estimates, 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 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 the “Risk” section of Woodside’s most recent Annual Report on Form 20-F filed with the United States Securities and Exchange Commission. You should review and have regard to these risks when considering the information contained in this document.

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 document.

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 document or involved in the preparation of the information in this document, 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 document.

All forward-looking statements contained in this document reflect Woodside’s views held as at the date of this document and, except as required by applicable law, Woodside does not intend to, undertake to, or assume any obligation to, provide any additional information or update or revise any of these statements after the date of this document, either to make them conform to actual results or as a result of new information, future events, 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.

Non-IFRS Measures

Throughout this document, a range of financial and non-financial measures are used to assess Woodside’s performance, including a number of financial measures that are not defined in, and have not been prepared in accordance with, International Financial Reporting Standards (IFRS) and are not recognised measures of financial performance or liquidity under IFRS (Non-IFRS Financial Measures). These measures include Capital expenditure, Cash margin, Production cost margin and Other cash cost margin. These Non-IFRS Financial Measures are defined in the glossary on pages A-10 to A-13 of the 2024 Half-Year Report. A quantitative reconciliation of these measures to the most directly comparable financial measure calculated and presented in accordance with IFRS can be found in the following disclosures: (i) in respect of Cash Margins, under “Non-IFRS Financial Measures” below; (ii) in respect non-IFRS measures presented in the 2024 Half-Year Report, in the Alternative Performance Measures section of the 2024 Half-Year Report on pages A-8 to A-9, and (iii) in respect of non-IFRS measures presented in the 2024 Form 20-F, section 6.6 of the 2024 Form 20-F beginning on page A-42 therein.

Woodside’s management uses these measures to monitor Woodside’s financial performance alongside IFRS measures to improve the comparability of information between reporting periods and business units and Woodside believes that the Non-IFRS Financial Measures it presents provide a useful means through which to examine the underlying performance of its business.

Undue reliance should not be placed on the Non-IFRS Financial Measures contained in this report and these Non-IFRS Financial Measures should be considered in addition to, and not as a substitute for, or as superior to, measures of financial performance, financial position or cash flows reported in accordance with IFRS. Non-IFRS Financial Measures are not uniformly defined by all companies, including those in Woodside’s industry. Accordingly, they may not be comparable with similarly titled measures and disclosures by other companies.

Climate strategy and emissions data

All greenhouse gas emissions data in this document 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 emissions, Scope 2 greenhouse emissions, and/or Scope 3 greenhouse emissions, unless otherwise stated.

No express or implied prices

This report does not include any express or implied prices at which Woodside will buy or sell financial products.

* *  *

About Woodside — Strategy

Woodside’s strategy is to thrive through this transition by developing a low cost, lower carbon, profitable, resilient and diversified portfolio.¹ There are three goals which drive this strategic direction.

• First, we strive to have the right portfolio to provide the energy required for future demand.

• Secondly, we want to create and return value to our shareholders.

• Finally, we aim to conduct our business sustainably.

We strive to have the right portfolio to provide the energy required for future demand.

Well-positioned portfolio — Wood Mackenzie forecasts in its base case scenario that global LNG demand will grow 53% to 2033, supported by growth in Europe (until 2029), China, and emerging Asian markets.² This expected demand growth follows an increase of more than 60% increase in LNG demand from 2015 to 2022, according to Wood Mackenzie.

Source: Base case scenario. Wood Mackenzie LNG Tool (1Q24).

¹  Please see Woodside’s Annual Report on Form 20-F for the year ended December 31, 2023, Section 6.7 — Glossary, units of measure and conversion factors for a definition of how Woodside uses the term lower carbon portfolio.

²  Wood Mackenzie, October 2023. “Global Gas Investment Horizon Outlook”.

Woodside is well-positioned to meet LNG demand in Asia.

Woodside has entered into agreements supporting its ability to service a number of markets, including those summarized below. For further information, refer to ‘Section 3.3 Our business — Marketing and trading’ in Woodside’s annual report on Form 20-F for the year ended December 31, 2023.

• In H1 2024, Woodside signed sale and purchase agreements (“SPAs”) with Korea Gas Corporation (“KOGAS”) and CPC Corporation, Taiwan (“CPC”) for the long-term supply of LNG to Korea and Taiwan, respectively. The KOGAS SPA is for the supply of approximately 0.5 Mtpa of LNG from 2026, for a period of 10.5 years. The CPC SPA is for the supply of approximately 6 million tonnes of LNG over 10 years, from July 2024. Under the CPC SPA, Woodside may also deliver approximately 8.4 million tonnes of LNG for a further 10 years, from 2034 to 2043.³

• In December 2023, Woodside signed an SPA with Mexico Pacific Limited (“Mexico Pacific”) for the purchase of 1.3 Mtpa of LNG over 20 years from Mexico Pacific’s Saguaro Energia LNG project on the Pacific coast of Mexico. The SPA is subject to Mexico Pacific taking a FID on the proposed third train, which is expected in the second half of 2024. Commercial operations are targeted to commence in 2029.

Following our merger with BHP’s petroleum business in 2022, we have become a larger supplier of energy to the world through an expanded global portfolio. Our expanded portfolio allowed us to achieve record production in 2023 and assisted Woodside to offset lower commodity prices.

³  Subject to conditions and agreements on terms for this period.

The graphic below sets out Woodside’s average realized oil and gas prices for the six months ended June 30, 2024, and the financial years ended December 31, 2023, 2022 and 2021:

Quality Customers – Woodside has contracted with a large number of quality customers in order to achieve revenue diversification. Based on their respective year-end 2023 debt ratings, approximately 92% of Woodside’s revenues were from companies who were investment grade rated.

Price Index Diversification – Woodside’s revenues are primarily derived from sales of LNG, crude oil, condensate, pipeline gas and natural gas liquids (“NGLs”). For the year ended December 31, 2023, the majority (approximately 72%) of Woodside’s production was attributed to natural gas, comprising LNG, NGLs and pipeline gas (47%, 4% and 21%, respectively), and the remaining portion (approximately 28%) of Woodside’s production was attributed to oil and condensate. In the 2024 Half-Year Report, Woodside reiterated its 2024 full-year expectation that approximately 26% to 33% of Woodside’s total LNG production would be linked to gas hub indices.⁴ The table below sets out additional detail as to the manner in which Woodside expects to maximize its portfolio value through contractual flexibility.

WOODSIDE PRODUCTION	LNG PORTFOLIO				TOTAL PORTFOLIO
	Near-Term (2024 – 2025)		Longer-Term (2027+)		Near-Term (2024 – 2025)		Longer-Term (2027+)
GAS HUB INDICES		25% to 30%		30% to 35%		10%		20%
OIL PRICE INDICES		60%		55%		70%		60%
FIXED OR LOW VOLATILITY PRICING MECHANISMS		10%		10%		20%		20%

Refers to Woodside’s exposure to different pricing indices for produced hydrocarbons and does not reflect the potential impact of the Tellurian and OCI transactions. The information in the table above are management estimates and are not guidance. The allocations are rounded to the nearest 5%.

⁴  Gas hub indices include Japan Korea Marker (“JKM”), Title Transfer Facility (“TTF”) and National Balancing Point (“NBP”). It excludes Henry Hub.

We want to create and return value to our shareholders. Our capital management framework aims to optimize value, balance strong shareholder returns and invest in quality opportunities.

Woodside’s high margin portfolio is made up of quality assets which have the scale and resilience to deliver ongoing value. For a presentation of Woodside’s cash margins for the half year ended June 30, 2024, and the years ended December 31, 2023, 2022 and 2021, including a reconciliation of these measures to the most directly comparable financial measure calculated and presented in accordance with IFRS in Woodside’s Financial Statements, refer to pages “Non-IFRS Financial Measures” below.

Woodside’s business does not generally require significant sustaining capital in order to maintain production. Woodside’s capital expenditure for 2024 is expected to be between $5,000 million and $5,500 million, primarily due to Sangomar, Scarborough and Trion project expenditure. This excludes the impact of any subsequent asset sell-downs, acquisitions or other changes in equity.

	2023 US$m		2022 US$m		2021 US$m
Capital expenditure
Capital additions on evaluation		163		119		453
Capital additions on oil and gas properties		5,317		3,904		2,178
Capital additions on other(1)		256		92		—
Capital expenditure(2)		5,736		4,115		2,631

(1) Includes capital additions on other corporate spend. The 2023 amounts have been restated to be presented on the same basis.

(2) Capital expenditure includes capital expenditure for the following projects: Trion (2023: $0.3 billion), Scarborough (2023: $2.5 billion; 2022: $1.8 billion; 2021: $1.0 billion), and Sangomar (2023: $1.1 billion; 2022: $1.0 billion; 2021: $1.0 billion). The Scarborough Energy Project was 67% complete at the end of H1 2024 (excluding Pluto Train 1 modifications), with a forecast total estimated cost of $12.5 billion. The forecast total capital expenditure for Trion is $7.2 billion.

We aim to conduct our business sustainably. To achieve this, we need to manage our impact on people, communities and the environment in which we operate. The safety of our people and a strong focus on managing our net equity Scope 1 and 2 emissions to meet our targets is critical to the longevity of our business.

We have also continued to focus on maintaining meaningful relationships with communities. In 1H 2024, Woodside made Australian tax and royalty payments of A$2,682 million. In the State of Western Australia, Woodside had more than A$1.46 billion of expenditures at the North West Shelf Project and more than A$989 million of contracts awarded to Western Australia businesses in 2023. For further information, refer to “Communities” in our 2024 Half-Year Report.

Non-IFRS Financial Measures

Cash margin is a measure that is not defined in, and has not been prepared in accordance with, International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”) and is not a recognised measure of financial performance or liquidity under IFRS.

Cash margin is among the measures that Woodside’s management uses to monitor its financial performance alongside IFRS measures to improve the comparability of information between reporting periods and business units and Woodside believes that the non-IFRS financial measures it presents provide a useful means through which to examine the underlying performance of its business. Undue reliance should not be placed on non-IFRS financial measures, including cash margin, and these non-IFRS financial measures should be considered in addition to, and not as a substitute for, or as superior to, measures of financial performance, financial position or cash flows reported in accordance with IFRS. Non-IFRS financial measures, including cash margin, are not uniformly defined by all companies, including those in Woodside’s industry. Accordingly, they may not be comparable with similarly titled measures and disclosures by other companies.

Cash margin is calculated as revenue from sale of produced hydrocarbons less production costs, royalties, excise and levies, insurance, inventory movement, shipping and direct sales costs and other hydrocarbon costs; divided by revenue from the sale of produced hydrocarbons (sales volume). Excludes exploration and evaluation, general administrative and other costs, depreciation and amortization, petroleum resource rent tax and income tax.

Reconciliation of cash margin, production costs and other cash costs

	Six months ended June 30,
	2024			2023
Revenue from sale of hydrocarbons (excluding marketing segment)		5,376			6,486
Cash margin (excluding marketing segment)
Gross profit/(loss)		2,526			3,221
Adjusted for:
Other cost of sales		21			—
Trading costs		—			4
Oil and gas properties depreciation and amortisation		1,893			1,944
Other revenue		(99	)		41
Cash margin (excluding marketing segment)		4,341			5,210
Cash margin %		81	%		80	%
Production costs (excluding marketing segment)		745			807
Production cost margin %		14	%		13	%
Other cash costs (excluding marketing segment):
Royalties, excise and levies		196			316
Insurance		26			34
Inventory movement		(62	)		(33	)
Shipping and direct sales costs		104			145
Other hydrocarbon costs		26			7
Total other cash costs (excluding marketing segment)		290			469
Other cash cost margin %		5	%		7	%

	Year ended December 31,
APMs derived from other notes	2023			2022			2021
Revenue from sale of hydrocarbons (excluding marketing segment)		12,348			14,154			5,329
Cash margin (excluding marketing segment)
Gross profit/(loss)		5,942			8,949			2792
Adjusted for:
Other cost of sales		7			4			12
Trading costs		12			14			3
Oil and gas properties depreciation and amortisation		3,956			2,798			1549
Other revenue		(3	)		285			89
Cash margin (excluding marketing segment)		9,914			12,050			4,445
Cash margin %		80	%		85	%		83	%
Production costs (excluding marketing segment)		1,562			1281			481
Production cost margin %		13	%		9	%		9	%
Other cash costs (excluding marketing segment):
Royalties, excise and levies		503			596			218
Insurance		60			43			31
Inventory movement		37			(41	)		(17	)
Shipping and direct sales costs		265			206			165
Other hydrocarbon costs		7			19			6
Total other cash costs (excluding marketing segment)		872			823			403
Other cash cost margin %		7	%		6	%		8	%

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Cover Page	6 Months Ended
	Jun. 30, 2024
Document Information [Line Items]
Document Type	6-K
Amendment Flag	false
Document Period End Date	Jun. 30, 2024
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	Q2
Entity Registrant Name	Woodside Energy Group Ltd
Entity Central Index Key	0000844551
Current Fiscal Year End Date	--12-31

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Condensed Consolidated Income Statement - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Profit or loss [abstract]
Operating revenue	$ 5,988	$ 7,400
Cost of sales	(3,272)	(3,872)
Gross profit	2,716	3,528
Other income	315	134
Other expenses	(669)	(803)
Impairment losses	0	(68)
Profit before tax and net finance costs	2,362	2,791
Finance income	95	174
Finance costs	(147)	(137)
Profit before tax	2,310	2,828
Petroleum resource rent tax (PRRT) expense	(192)	(778)
Income tax expense	(146)	(284)
Profit after tax	1,972	1,766
Profit attributable to:
Equity holders of the parent	1,937	1,740
Non-controlling interest	35	26
Profit for the period	$ 1,972	$ 1,766
Basic earnings per share attributable to equity holders of the parent	$ 1.022	$ 0.917
Diluted earnings per share attributable to equity holders of the parent	$ 1.014	$ 0.911

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Condensed Consolidated Statement Of Comprehensive Income - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Statement of comprehensive income [abstract]
Profit for the period	$ 1,972	$ 1,766
Items that may be reclassified to the income statement in subsequent periods:
(Losses)/gains on cash flow hedges	(165)	413
Losses on cash flow hedges reclassified to the income statement	38	241
Tax recognised within other comprehensive income	19	(76)
Exchange fluctuations on translation of foreign operations taken to equity	0	1
Items that will not be reclassified to the income statement in subsequent periods:
Remeasurement loss on defined benefit plan	(15)	0
Net loss on financial instruments at fair value through other comprehensive income	(11)	(23)
Other comprehensive (loss)/income for the period, net of tax	(134)	556
Total comprehensive income for the period	1,838	2,322
Total comprehensive income attributable to:
Equity holders of the parent	1,803	2,296
Non-controlling interest	35	26
Total comprehensive income for the period	$ 1,838	$ 2,322

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Condensed Consolidated Statement Of Financial Position - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Current assets
Cash and cash equivalents	$ 1,979	$ 1,740
Receivables	1,459	1,517
Inventories	719	616
Other financial assets	154	209
Assets held for sale	1,378	826
Tax receivable	306	118
Other assets	57	92
Total current assets	6,052	5,118
Non-current assets
Receivables	790	839
Inventories	183	120
Other financial assets	106	120
Exploration and evaluation assets	714	668
Oil and gas properties	40,125	40,791
Deferred tax assets	1,969	1,717
Lease assets	1,187	1,230
Investments accounted for using the equity method	248	249
Goodwill	3,697	3,995
Other assets	571	514
Total non-current assets	49,590	50,243
Total assets	55,642	55,361
Current liabilities
Payables	1,597	1,724
Interest-bearing liabilities	992	0
Other financial liabilities	152	67
Liabilities directly associated with assets held for sale	119	94
Provisions	1,223	1,506
Tax payable	416	1,108
Lease liabilities	217	298
Other liabilities	165	185
Total current liabilities	4,881	4,982
Non-current liabilities
Interest-bearing liabilities	4,830	4,883
Deferred tax liabilities	1,312	1,627
Other financial liabilities	203	42
Provisions	6,454	6,451
Tax payable	39	40
Lease liabilities	1,328	1,317
Other liabilities	766	849
Total non-current liabilities	14,932	15,209
Total liabilities	19,813	20,191
Net assets	35,829	35,170
Equity
Issued and fully paid shares	29,001	29,001
Shares reserved for employee share plans	(65)	(49)
Other reserves	4,726	5,261
Retained earnings	1,408	186
Equity attributable to equity holders of the parent	35,070	34,399
Non-controlling interest	759	771
Total equity	$ 35,829	$ 35,170

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Condensed Consolidated Statement Of Cash Flows - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2024	Jun. 30, 2023
Cash flows from operating activities
Profit after tax for the period		$ 1,972	$ 1,766
Non-cash items
Depreciation and amortisation		1,908	1,948
Depreciation of lease assets		101	81
Change in fair value of derivative financial instruments		205	269
Net finance costs/(income)		52	(37)
Tax expense		338	1,062
Exploration and evaluation written off			1
Impairment losses			68
Restoration movement		15	20
Gain on disposal of oil and gas properties		(143)
Other		(66)	(180)
Changes in assets and liabilities
Decrease in trade and other receivables		113	488
Increase in inventories		(166)	(72)
Decrease in provisions		(31)	(110)
Decrease in lease liabilities			(8)
Decrease/(increase) in other assets and liabilities		39	(234)
Increase/(decrease) in trade and other payables		6	(220)
Cash generated from operations		4,343	4,842
Interest received		77	174
Dividends received			6
Borrowing costs relating to operating activities		(2)	(8)
Income tax and PRRT paid		(1,700)	(2,233)
Payments for restoration		(325)	(162)
Receipts from hedge collateral			332
Net cash from operating activities	[1]	2,393	2,951
Cash flows used in investing activities
Payments for capital and exploration expenditure		(2,418)	(2,457)
Borrowing costs relating to investing activities		(155)	(181)
Proceeds from disposal of non-current assets		920	3
Funding of equity accounted investments			(2)
Net cash used in investing activities		(1,653)	(2,637)
Cash flows used in financing activities
Proceeds from borrowings		950
Repayment of borrowings			(41)
Purchases of shares relating to employee share plans	[1]	(25)	(20)
Repayment of the principal portion of lease liabilities		(213)	(168)
Borrowing costs relating to lease liabilities		(21)	(3)
Contributions to non-controlling interests		(48)	(51)
Dividends paid		(1,139)	(2,738)
Net cash used in financing activities	[1]	(496)	(3,021)
Net increase/(decrease) in cash held		244	(2,707)
Cash and cash equivalents at the beginning of the period		1,740	6,201
Effects of exchange rate changes		(5)	(25)
Cash and cash equivalents at the end of the period		$ 1,979	$ 3,469

[1] Purchases of shares relating to employee share plans, which were previously classified within cash flows used in operating activities, has been classified within cash flows used in financing activities for the half-year ended 2024. The 2023 comparatives have been reclassified to be presented on the same basis.

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Condensed Consolidated Statement Of Changes In Equity - USD ($) $ in Millions	Total	Issued and fully paid shares [member]	Shares reserved for employee share plans [member]	Employee benefits reserve [member]	Foreign currency translation reserve [member]	Hedging reserve [member]	Distributable profits reserve [member]	Other reserve [member]	Retained earnings [member]	Equity holders of the parent [member]	Non-controlling interest [member]
Beginning balance at Dec. 31, 2022	$ 37,127	$ 29,001	$ (38)	$ 278	$ 796	$ (586)	$ 3,541	$ 2	$ 3,342	$ 36,336	$ 791
Profit for the period	1,766								1,740	1,740	26
Other comprehensive income/(loss)	556				1	578		(23)		556
Total comprehensive income/(loss) for the period	2,322				1	578		(23)	1,740	2,296	26
Transfers							4,700		(4,700)
Employee share plan purchases	(20)		(20)	0						(20)
Employee share plan redemptions			8	(8)
Share-based payments (net of tax)	31			31						31
Dividends paid	(2,776)						(2,734)			(2,734)	(42)
Ending balance at Jun. 30, 2023	36,684	29,001	(50)	301	797	(8)	5,507	(21)	382	35,909	775
Beginning balance at Dec. 31, 2023	35,170	29,001	(49)	290	795	88	4,118	(30)	186	34,399	771
Profit for the period	1,972								1,937	1,937	35
Other comprehensive income/(loss)	(134)					(108)		(11)	(15)	(134)
Total comprehensive income/(loss) for the period	1,838					(108)		(11)	1,922	1,803	35
Transfers							700		(700)
Employee share plan purchases	(25)		(25)							(25)
Employee share plan redemptions			9	(9)
Share-based payments (net of tax)	32			32						32
Dividends paid	(1,186)			0			(1,139)			(1,139)	(47)
Ending balance at Jun. 30, 2024	$ 35,829	$ 29,001	$ (65)	$ 313	$ 795	$ (20)	$ 3,679	$ (41)	$ 1,408	$ 35,070	$ 759

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Segment Revenue and Expenses

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Segment revenue and expenses

A.1 Segment revenue and expenses

	Australia						International						Marketing						Corporate/Other						Consolidated
	2024 US$m			2023 US$m			2024 US$m			2023 US$m			2024 US$m			2023 US$m			2024 US$m			2023 US$m			2024 US$m			2023 US$m
Liquified natural gas		2,595			3,894			—			—			412			785			—			—			3,007			4,679
Pipeline gas		512			515			107			198			—			—			—			—			619			713
Crude oil and condensate		861			715			1,190			1,028			40			15			—			—			2,091			1,758
Natural gas liquids		87			120			24			16			40			23			—			—			151			159
Revenue from sale of hydrocarbons		4,055			5,244			1,321			1,242			492			823			—			—			5,868			7,309
Intersegment revenue1		(12	)		(120	)		(2	)		(6	)		14			126			—			—			—			—
Processing and services revenue		113			85			—			—			—			—			—			—			113			85
Shipping and other revenue		—			—			—			—			7			6			—			—			7			6
Other revenue		101			(35	)		(2	)		(6	)		21			132			—			—			120			91
Operating revenue2		4,156			5,209			1,319			1,236			513			955			—			—			5,988			7,400
Production costs		(511	)		(614	)		(234	)		(193	)		—			—			—			—			(745	)		(807	)
Royalties, excise and levies		(185	)		(285	)		(11	)		(31	)		—			—			—			—			(196	)		(316	)
Insurance		(13	)		(20	)		(2	)		(5	)		—			—			(11	)		(9	)		(26	)		(34	)
Inventory movement		15			31			47			2			—			—			—			—			62			33
Costs of production		(694	)		(888	)		(200	)		(227	)		—			—			(11	)		(9	)		(905	)		(1,124	)
Land and buildings		(26	)		(31	)		—			(2	)		—			—			(2	)		—			(28	)		(33	)
Transferred exploration and evaluation		(41	)		(51	)		(45	)		(2	)		—			—			—			—			(86	)		(53	)
Plant and equipment		(1,189	)		(1,298	)		(567	)		(543	)		—			—			(23	)		(17	)		(1,779	)		(1,858	)
Oil and gas properties depreciation and amortisation		(1,256	)		(1,380	)		(612	)		(547	)		—			—			(25	)		(17	)		(1,893	)		(1,944	)
Shipping and direct sales costs		(61	)		(107	)		(43	)		(38	)		(50	)		(30	)		—			—			(154	)		(175	)
Trading costs		—			(4	)		—			—			(273	)		(618	)		—			—			(273	)		(622	)
Other hydrocarbon costs		(26	)		(7	)		—			—			—			—			—			—			(26	)		(7	)
Other cost of sales		(17	)		—			—			—			—			—			(4	)		—			(21	)		—
Other cost of sales		(104	)		(118	)		(43	)		(38	)		(323	)		(648	)		(4	)		—			(474	)		(804	)
Cost of sales		(2,054	)		(2,386	)		(855	)		(812	)		(323	)		(648	)		(40	)		(26	)		(3,272	)		(3,872	)
Gross profit/(loss)		2,102			2,823			464			424			190			307			(40	)		(26	)		2,716			3,528
Other income3		242			106			20			—			20			1			33			27			315			134
Exploration and evaluation expenditure		(12	)		(9	)		(86	)		(123	)		—			—			—			(1	)		(98	)		(133	)
Amortisation of permit acquisitions		—			—			(5	)		(4	)		—			—			—			—			(5	)		(4	)
Write-offs		—			—			—			(1	)		—			—			—			—			—			(1	)
Exploration and evaluation		(12	)		(9	)		(91	)		(128	)		—			—			—			(1	)		(103	)		(138	)
General, administration and other costs		—			—			—			(3	)		—			(10	)		(214	)		(224	)		(214	)		(237	)
Amortisation of intangible assets		—			—			—			—			—			—			(10	)		—			(10	)		—
Depreciation of lease assets		(28	)		(22	)		(1	)		(7	)		(50	)		(34	)		(22	)		(18	)		(101	)		(81	)
Restoration movement		(14	)		(8	)		(1	)		(12	)		—			—			—			—			(15	)		(20	)
Other4		16			(27	)		—			(1	)		58			(99	)		(300	)		(200	)		(226	)		(327	)
Other costs		(26	)		(57	)		(2	)		(23	)		8			(143	)		(546	)		(442	)		(566	)		(665	)
Other expenses		(38	)		(66	)		(93	)		(151	)		8			(143	)		(546	)		(443	)		(669	)		(803	)
Impairment losses		—			(68	)		—			—			—			—			—			—			—			(68	)
Profit/(loss) before tax and net finance costs		2,306			2,795			391			273			218			165			(553	)		(442	)		2,362			2,791

1. Intersegment revenue comprises the incremental income net of all incremental associated expenses generated by the Marketing segment’s optimisation of the oil and gas portfolio.

2. Operating revenue includes revenue from contracts with customers of $5,981 million (2023: $7,394 million) and sub-lease income of $7 million (2023: $6 million) disclosed within shipping and other revenue.

3. Includes fees, recoveries and other income not associated with the ongoing operations of the business. The 2024 amount includes the gain on the Scarborough sell-down to LNG Japan of $121 million.

4. Includes gains and losses on foreign exchange and hedging activities, fair value losses on embedded derivatives and other items not associated with the ongoing operations of the business.

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Finance Costs

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Finance costs

A.2 Finance costs

	2024 US$m			2023 US$m
Interest on interest-bearing liabilities		125			112
Interest on lease liabilities		51			54
Accretion charge		145			134
Other finance costs		13			21
Less: Finance costs capitalised against qualifying assets		(187	)		(184	)
		147			137

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Dividends Paid and Proposed

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Dividends paid and proposed

A.3 Dividends paid and proposed

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

	2024 US$m		2023 US$m
(a) Dividends paid during the financial period Prior year fully franked final dividend US$0.60, paid on 4 April 2024 (2023: US$1.44, paid on 5 April 2023)		1,139		2,734
(b) Dividend declared subsequent to the reporting period (not recorded as a liability) Current year fully franked interim dividend US$0.69 to be paid on 3 October 2024 (2023: US$0.80, paid on 3 October 2023)		1,310		1,519

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Earnings Per Share

6 Months Ended

Jun. 30, 2024

Earnings per share [abstract]

Earnings per share

A.4 Earnings per share

	2024		2023
Profit attributable to equity holders of the parent (US$m)		1,937		1,740
Weighted average number of shares on issue for basic earnings per share		1,896,041,815		1,896,624,636
Effect of dilution from contingently issuable shares		14,691,983		12,981,487
Weighted average number of shares on issue adjusted for the effect of dilution		1,910,733,798		1,909,606,123
Basic earnings per share (US cents)		102.2		91.7
Diluted earnings per share (US cents)		101.4		91.1

Earnings per share is calculated by dividing the profit for the period attributable to ordinary equity holders of the parent by the weighted average number of shares on issue during the period. 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.

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Taxes

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Taxes

A.5 Taxes

	2024 US$m			2023 US$m
Reconciliation of income tax expense
Profit before tax		2,310			2,828
PRRT expense		(192	)		(778	)
Profit before income tax		2,118			2,050
Income tax expense calculated at 30%		635			615
Effect of tax rate differentials		(15	)		30
Effect of deferred tax assets not recognised		35			67
Effect of tax benefits previously unrecognised1		(366	)		(340	)
Reduction in deferred tax liability due to held for sale basis1		(91	)		—
Foreign exchange impact on tax benefit		(11	)		(83	)
Adjustment to prior years		(52	)		(16	)
Other		11			11
Income tax expense		146			284

1. Subsequent to achieving first oil on the Sangomar project in June 2024, the Group has recognised a net deferred tax asset of $305 million. The remaining $61 million relates to other tax benefits previously unrecognised. The expected sale of Woodside’s 15.1% share in the Scarborough Joint Venture resulted in the recognition of a net tax benefit of $91 million. These events have resulted in a reduction of the global effective income tax rate from 25.6% to 6.9%. In the prior period, as a result of the final investment decision to develop the Trion resource, the Group recognised deferred tax assets of $319 million, resulting in a reduction of the global effective income tax rate from 29.6% to 13.9%.

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 recognising a $124 million current tax payable as at 30 June 2024.

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Exploration and Evaluation

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Exploration and evaluation

B.1 Exploration and evaluation

	Asia Pacific US$m			Americas US$m			Africa US$m			Total US$m
Half-year ended 30 June 2024
Carrying amount at 1 January 2024		568			76			24			668
Additions		11			52			14			77
Amortisation of licence acquisition costs		—			(5	)		—			(5	)
Transferred exploration and evaluation		(8	)		—			(18	)		(26	)
Carrying amount at 30 June 2024		571			123			20			714
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

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 oil and gas properties.

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Oil and Gas Properties

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Oil and gas properties

B.2 Oil and gas properties

	Land and buildings US$m			Transferred exploration and evaluation US$m			Plant and equipment US$m			Projects in development1 US$m			Total US$m
Half-year ended 30 June 2024
Carrying amount at 1 January 2024		701			777			23,589			15,724			40,791
Additions2		—			—			(127	)		2,447			2,320
Disposals at written down value		(2	)		—			—			(47	)		(49	)
Depreciation and amortisation		(28	)		(86	)		(1,779	)		—			(1,893	)
Completions and transfers3		—			341			5,391			(5,706	)		26
Transfer to assets held for sale4		—			—			(4	)		(1,066	)		(1,070	)
Carrying amount at 30 June 2024		671			1,032			27,070			11,352			40,125
At 30 June 2024
Historical cost		1,743			2,320			55,533			12,072			71,668
Accumulated depreciation and impairment		(1,072	)		(1,288	)		(28,463	)		(720	)		(31,543	)
Net carrying amount		671			1,032			27,070			11,352			40,125
Year ended 31 December 2023
Carrying amount at 1 January 2023		840			481			23,057			15,541			39,919
Additions		—			—			836			5,759			6,595
Disposals at written down value		(8	)		—			(2	)		—			(10	)
Depreciation and amortisation		(67	)		(125	)		(3,764	)		—			(3,956	)
Impairment losses		(64	)		(20	)		(1,028	)		(328	)		(1,440	)
Completions and transfers		—			441			4,496			(4,633	)		304
Transfer to assets held for sale		—			—			(6	)		(615	)		(621	)
Carrying amount at 31 December 2023		701			777			23,589			15,724			40,791
At 31 December 2023
Historical cost		1,745			1,979			50,272			16,443			70,439
Accumulated depreciation and impairment		(1,044	)		(1,202	)		(26,683	)		(719	)		(29,648	)
Net carrying amount		701			777			23,589			15,724			40,791

1. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.

2. Includes $2,212 million of capital additions and $187 million of capitalised borrowing costs offset by $79 million relating to changes in restoration provision assumptions. The $127 million of additions reducing plant and equipment relates to changes in restoration provision assumptions.

3. Upon first oil in June 2024, the carrying value of the Sangomar project in projects in development has been transferred to plant and equipment.

4. Refer to Note B.4 for details of the sell-downs of the Scarborough Joint Venture.

The Group has capital expenditure commitments contracted for, but not provided for in the financial statements, of $3,017 million (31 December 2023: $4,245 million).

XML

Goodwill

6 Months Ended

Jun. 30, 2024

Disclosure of reconciliation of changes in goodwill [abstract]

Goodwill

B.3 Goodwill

	US$m
Half-year ended 30 June 2024
Carrying amount at 1 January 2024		3,995
Transfer to assets held for sale1		(298	)
Carrying amount at 30 June 2024		3,697
At 30 June 2024
Cost		4,174
Accumulated impairment		(477	)
Net carrying amount		3,697
Year ended 31 December 2023
Carrying amount at 1 January 2023		4,614
Adjustment to purchase price allocation		55
Impairment		(477	)
Transfer to assets held for sale		(197	)
Carrying amount at 31 December 2023		3,995
At 31 December 2023
Cost		4,472
Accumulated impairment		(477	)
Net carrying amount		3,995

1. Refer to Note B.4(a) for details of the sell-downs of the Scarborough Joint Venture.

XML

Disposal of Assets

6 Months Ended

Jun. 30, 2024

Disclosure Of Noncurrent Assets Or Disposal Groups Classified As Held For Sale [Abstract]

Disposal of assets

B.4 Disposal of assets

(a) 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 has 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 have been reclassified to liabilities directly associated with assets held for sale. No impairment of assets occurred on reclassification to held for sale.

The following assets and liabilities were reclassified as held for sale as at 30 June 2024:

	US$m
Assets classified as held for sale
Oil and gas properties		1,070
Inventories		6
Lease assets		2
Goodwill		298
Other assets		2
Total assets held for sale		1,378
Liabilities directly associated with assets held for sale
Payables		(28	)
Deferred tax liabilities		(75	)
Lease liabilities		(8	)
Provisions		(8	)
Total liabilities directly associated with assets held for sale		(119	)

The purchase price is $740 million, subject to adjustments which includes the reimbursement to Woodside for JERA’s share of expenditure for the Scarborough project from the effective date of 1 January 2022. The total proceeds from the sale are expected to exceed the net carrying value of the assets and liabilities classified as held for sale. The transaction is expected to complete in the second half of 2024. Completion of the transaction is subject to conditions precedent including Western Australia Government approval. This has also resulted in the recognition of a net tax benefit of $91 million. After completion, the Group’s participating interest in the Scarborough Joint Venture will reduce from 90% to 74.9%.

Key estimates and judgements

Goodwill allocation on Scarborough sell-down

In accordance with AASB 136/IAS 36 Impairment of assets, if goodwill has been allocated to a CGU and the entity disposes of an operation within that unit, the goodwill associated with the operation disposed shall be included in the carrying value of the operation when determining the gain or loss on disposal and measured on the basis of the relative values of the operation disposed of and the portion of the CGU retained.

The Pluto-Scarborough CGU includes goodwill allocated from the merger with BHP Petroleum in 2022. Judgement is required to determine the amount of goodwill allocated to the 15.1% participating interest in the Scarborough assets being disposed.

The Group used fair value measurements of Pluto and Scarborough assets within the CGU as the basis to allocate goodwill between the Pluto and Scarborough assets. The goodwill associated with the participating interest of the Scarborough assets being disposed of was determined based on the percentage participating interest disposed of in proportion to the participating interest being retained.

(b) Sell-down of 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 half-year ended 30 June 2024, the Group recognised a pre-tax gain on sale of $121 million.

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Debt and Capital

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Debt and Capital

C. Debt and capital

C.1 Contributed equity

Issued and fully paid shares

	Number of shares		US$m
Half-year ended 30 June 2024
Opening balance		1,898,749,771		29,001
Amounts as at 30 June 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

All shares are a single class with equal rights to dividends, capital distributions and voting. The Company does not have authorised capital nor par value in respect of its issued shares.

Reserved shares

Reserved shares are the Group’s own equity instruments, which are used in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity.

	Number of shares			US$m
Half-year ended 30 June 2024
Opening balance		2,140,927			(49	)
Purchases during the period		1,262,082			(25	)
Vested/allocated during the period		(424,959	)		9
Amounts as at 30 June 2024		2,978,050			(65	)
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 as at 31 December 2023		2,140,927			(49	)

C.2 Interest-bearing liabilities and financing facilities

During the period, the Group completed the drawdown of $500 million from bilateral loan facilities. In addition, the Group entered into the following facilities during the period:

• $1,000 million loan facility with Japan Bank for International Cooperation (JBIC) with a term of 10 years. Interest is based on daily Secured Overnight Financing Rate (SOFR) plus margin. This facility was fully drawn subsequent to the period on 22 July 2024.

• $450 million syndicated term loan facility with a tenor of 10 years. Interest is based on daily SOFR plus credit adjustment spread (CAS) and margin. This facility was fully drawn in June 2024.

There were no other material changes to interest-bearing liabilities and financing facilities. As at 30 June 2024, the Group had $6,500 million (31 December 2023: $6,050 million) of available undrawn facilities. Subsequent to 30 June 2024, the Group cancelled $1,550 million of undrawn facilities.

For the year ended 31 December 2023, the Group repaid $201 million of the CHF Medium Term Note and $83 million of the JBIC facility which was settled in July 2023.

Fair value

The carrying amounts of interest-bearing liabilities approximate their fair values, with the exception of the Group’s unsecured bonds and the medium-term notes. The unsecured bonds have a carrying amount of $4,087 million (31 December 2023: $4,087 million) and a fair value of $3,958 million (31 December 2023: $3,936 million). The medium-term notes have a carrying amount of $200 million (31 December 2023: $200 million) and a fair value of $188 million (31 December 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.

XML

Contributed Equity

6 Months Ended

Jun. 30, 2024

Equity [abstract]

Contributed equity

C.1 Contributed equity

Issued and fully paid shares

	Number of shares		US$m
Half-year ended 30 June 2024
Opening balance		1,898,749,771		29,001
Amounts as at 30 June 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

All shares are a single class with equal rights to dividends, capital distributions and voting. The Company does not have authorised capital nor par value in respect of its issued shares.

Reserved shares

Reserved shares are the Group’s own equity instruments, which are used in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity.

	Number of shares			US$m
Half-year ended 30 June 2024
Opening balance		2,140,927			(49	)
Purchases during the period		1,262,082			(25	)
Vested/allocated during the period		(424,959	)		9
Amounts as at 30 June 2024		2,978,050			(65	)
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 as at 31 December 2023		2,140,927			(49	)

XML

Interest-Bearing Liabilities and Financing Facilities

6 Months Ended

Jun. 30, 2024

Borrowings [abstract]

Interest-bearing liabilities and financing facilities

C.2 Interest-bearing liabilities and financing facilities

During the period, the Group completed the drawdown of $500 million from bilateral loan facilities. In addition, the Group entered into the following facilities during the period:

• $1,000 million loan facility with Japan Bank for International Cooperation (JBIC) with a term of 10 years. Interest is based on daily Secured Overnight Financing Rate (SOFR) plus margin. This facility was fully drawn subsequent to the period on 22 July 2024.

• $450 million syndicated term loan facility with a tenor of 10 years. Interest is based on daily SOFR plus credit adjustment spread (CAS) and margin. This facility was fully drawn in June 2024.

There were no other material changes to interest-bearing liabilities and financing facilities. As at 30 June 2024, the Group had $6,500 million (31 December 2023: $6,050 million) of available undrawn facilities. Subsequent to 30 June 2024, the Group cancelled $1,550 million of undrawn facilities.

For the year ended 31 December 2023, the Group repaid $201 million of the CHF Medium Term Note and $83 million of the JBIC facility which was settled in July 2023.

Fair value

The carrying amounts of interest-bearing liabilities approximate their fair values, with the exception of the Group’s unsecured bonds and the medium-term notes. The unsecured bonds have a carrying amount of $4,087 million (31 December 2023: $4,087 million) and a fair value of $3,958 million (31 December 2023: $3,936 million). The medium-term notes have a carrying amount of $200 million (31 December 2023: $200 million) and a fair value of $188 million (31 December 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.

XML

Other Assets and Liabilities

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Other assets and liabilities

D. Other assets and liabilities

D.1 Segment assets and liabilities

	30 June 2024 US$m		31 December 2023 US$m
(a) Segment assets
Australia		30,895		31,602
International		18,083		17,923
Marketing		798		835
Corporate/Other		5,866		5,001
		55,642		55,361

	30 June 2024 US$m		31 December 2023 US$m
(b) Segment liabilities
Australia		7,312		7,833
International		2,434		2,624
Marketing		890		751
Corporate/Other		9,177		8,983
		19,813		20,191

Corporate/Other assets mainly comprise cash and cash equivalents, lease assets and deferred tax assets. Corporate/Other liabilities mainly comprise interest-bearing liabilities, lease liabilities and deferred tax liabilities.

D.2 Provisions

	Restoration1 US$m			Employee benefits US$m			Other US$m			Total US$m
Half-year ended 30 June 2024
At 1 January 2024		7,154			522			281			7,957
Change in provision		(449	)		(31	)		55			(425	)
Unwinding of present value discount		144			—			1			145
Carrying amount at 30 June 2024		6,849			491			337			7,677
Current		698			302			223			1,223
Non-current		6,151			189			114			6,454
Net carrying amount		6,849			491			337			7,677
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 a revision of discount rates of $147 million (primarily due to an increase in risk-free rates), changes in foreign exchange rates of $84 million and provisions used of $358 million, offset by changes in estimates of $140 million.

D.3 Other financial assets and liabilities

	30 June 2024 US$m		31 December 2023 US$m
Other financial assets
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		160		248
Other financial assets		100		53
Financial instruments at fair value through other comprehensive income
Other financial assets		—		28
Total other financial assets		260		329
Current		154		209
Non-current		106		120
Net carrying amount		260		329
Other financial liabilities
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		126		74
Embedded derivative		188		35
Other financial liabilities		41		—
Total other financial liabilities		355		109
Current		152		67
Non-current		203		42
Net carrying amount		355		109

Hedging activities

During the period, the following hedging activities were undertaken:

• The Group had hedged approximately 29.3 MMboe of 2024 oil production at an average price of approximately $75.6 per barrel, of which approximately 49% was delivered as at 30 June 2024.

• The Group additionally hedged approximately 15 MMboe of 2025 oil production at an average price of approximately $81.2 per barrel.

• The Group also has a hedging program for Corpus Christi LNG volumes designed to protect against downside pricing risk. These hedges are Henry Hub (HH) and Title Transfer Facility (TTF) commodity swaps. Approximately 70% of volumes for the remainder of 2024, 48% of 2025 and 9% 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.

The following table presents the Group’s derivative financial instruments designated as hedges, measured and recognised at fair value:

	30 June 2024 US$m			31 December 2023 US$m
Oil swaps (cash flow hedges)		(53	)		(14	)
HH Corpus Christi commodity swaps (cash flow hedges)		(24	)		(44	)
TTF Corpus Christi commodity swaps (cash flow hedges)		72			181
Interest rate swaps (cash flow hedges)		48			43
Foreign exchange forwards (cash flow hedges)		(9	)		8
Total derivative financial instruments asset designated as hedges		34			174

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 30 June 2024 amounted to a net liability of $188 million (31 December 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 six-month period ended 30 June 2024, an unrealised loss of $153 million (30 June 2023: unrealised loss of $52 million) has been recognised through other expenses.

Fair value

Except for the other financial assets and other financial liabilities set out in this note, there are no other material financial assets or financial liabilities carried at fair value. Other financial assets and other financial liabilities set out in this note are classified as Level 2 on the fair value hierarchy with market observable inputs, with the exception of the embedded commodity derivative which has been classified as Level 3 on the fair value hierarchy with no market observable inputs. Refer to key estimates and judgements for further details. During the period, there were no reclassifications between the fair value hierarchy levels.

There were no changes to the Group’s valuation processes, valuation techniques and types of inputs used in the fair value measurements during the period.

Financial risk factors

The Group’s activities expose its financial instruments to a variety of market risks, including foreign exchange, commodity price and interest rate risk. The half-year financial report does not include all financial risk management information and disclosures required in the Annual Report and, as such, should be read in conjunction with the Group’s 2023 Financial Statements. There have been no significant changes in risk management policies since 31 December 2023. Refer to the embedded commodity derivative key estimates and judgements section for the sensitivity assessment on discount rates and pricing.

Key estimates and judgements

Embedded commodity derivative

The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast cash flows, discount rate, credit risk and volatility. These assumptions require significant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions. The present value of the embedded derivative was estimated using the assumptions set out below.

• Inflation rate – 2.5%.

• Discount rate – a pre-tax interest rate curve (range: 5.8% to 6.95%).

• Domestic gas pricing – forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (TTF) prices available in the market 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. 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%		137
Urea sales price: decrease of 10%		(137	)
Discount rate: increase of 1.5%2		(186	)
Discount rate: decrease of 1.5%2		230

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.

XML

Segment Assets and Liabilities

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Segment assets and liabilities

D.1 Segment assets and liabilities

	30 June 2024 US$m		31 December 2023 US$m
(a) Segment assets
Australia		30,895		31,602
International		18,083		17,923
Marketing		798		835
Corporate/Other		5,866		5,001
		55,642		55,361

	30 June 2024 US$m		31 December 2023 US$m
(b) Segment liabilities
Australia		7,312		7,833
International		2,434		2,624
Marketing		890		751
Corporate/Other		9,177		8,983
		19,813		20,191

Corporate/Other assets mainly comprise cash and cash equivalents, lease assets and deferred tax assets. Corporate/Other liabilities mainly comprise interest-bearing liabilities, lease liabilities and deferred tax liabilities.

XML

Provisions

6 Months Ended

Jun. 30, 2024

Provisions [abstract]

Provisions

D.2 Provisions

	Restoration1 US$m			Employee benefits US$m			Other US$m			Total US$m
Half-year ended 30 June 2024
At 1 January 2024		7,154			522			281			7,957
Change in provision		(449	)		(31	)		55			(425	)
Unwinding of present value discount		144			—			1			145
Carrying amount at 30 June 2024		6,849			491			337			7,677
Current		698			302			223			1,223
Non-current		6,151			189			114			6,454
Net carrying amount		6,849			491			337			7,677
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 a revision of discount rates of $147 million (primarily due to an increase in risk-free rates), changes in foreign exchange rates of $84 million and provisions used of $358 million, offset by changes in estimates of $140 million.

XML

Other Financial Assets and Liabilities

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Other financial assets and liabilities

D.3 Other financial assets and liabilities

	30 June 2024 US$m		31 December 2023 US$m
Other financial assets
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		160		248
Other financial assets		100		53
Financial instruments at fair value through other comprehensive income
Other financial assets		—		28
Total other financial assets		260		329
Current		154		209
Non-current		106		120
Net carrying amount		260		329
Other financial liabilities
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		126		74
Embedded derivative		188		35
Other financial liabilities		41		—
Total other financial liabilities		355		109
Current		152		67
Non-current		203		42
Net carrying amount		355		109

Hedging activities

During the period, the following hedging activities were undertaken:

• The Group had hedged approximately 29.3 MMboe of 2024 oil production at an average price of approximately $75.6 per barrel, of which approximately 49% was delivered as at 30 June 2024.

• The Group additionally hedged approximately 15 MMboe of 2025 oil production at an average price of approximately $81.2 per barrel.

• The Group also has a hedging program for Corpus Christi LNG volumes designed to protect against downside pricing risk. These hedges are Henry Hub (HH) and Title Transfer Facility (TTF) commodity swaps. Approximately 70% of volumes for the remainder of 2024, 48% of 2025 and 9% 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.

The following table presents the Group’s derivative financial instruments designated as hedges, measured and recognised at fair value:

	30 June 2024 US$m			31 December 2023 US$m
Oil swaps (cash flow hedges)		(53	)		(14	)
HH Corpus Christi commodity swaps (cash flow hedges)		(24	)		(44	)
TTF Corpus Christi commodity swaps (cash flow hedges)		72			181
Interest rate swaps (cash flow hedges)		48			43
Foreign exchange forwards (cash flow hedges)		(9	)		8
Total derivative financial instruments asset designated as hedges		34			174

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 30 June 2024 amounted to a net liability of $188 million (31 December 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 six-month period ended 30 June 2024, an unrealised loss of $153 million (30 June 2023: unrealised loss of $52 million) has been recognised through other expenses.

Fair value

Except for the other financial assets and other financial liabilities set out in this note, there are no other material financial assets or financial liabilities carried at fair value. Other financial assets and other financial liabilities set out in this note are classified as Level 2 on the fair value hierarchy with market observable inputs, with the exception of the embedded commodity derivative which has been classified as Level 3 on the fair value hierarchy with no market observable inputs. Refer to key estimates and judgements for further details. During the period, there were no reclassifications between the fair value hierarchy levels.

There were no changes to the Group’s valuation processes, valuation techniques and types of inputs used in the fair value measurements during the period.

Financial risk factors

The Group’s activities expose its financial instruments to a variety of market risks, including foreign exchange, commodity price and interest rate risk. The half-year financial report does not include all financial risk management information and disclosures required in the Annual Report and, as such, should be read in conjunction with the Group’s 2023 Financial Statements. There have been no significant changes in risk management policies since 31 December 2023. Refer to the embedded commodity derivative key estimates and judgements section for the sensitivity assessment on discount rates and pricing.

Key estimates and judgements

Embedded commodity derivative

The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast cash flows, discount rate, credit risk and volatility. These assumptions require significant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions. The present value of the embedded derivative was estimated using the assumptions set out below.

• Inflation rate – 2.5%.

• Discount rate – a pre-tax interest rate curve (range: 5.8% to 6.95%).

• Domestic gas pricing – forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (TTF) prices available in the market 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. 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%		137
Urea sales price: decrease of 10%		(137	)
Discount rate: increase of 1.5%2		(186	)
Discount rate: decrease of 1.5%2		230

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.

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Contingent Liabilities and Assets

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Contingent liabilities and assets

E.1 Contingent liabilities and assets

	30 June 2024 US$m		31 December 2023 US$m
Contingent liabilities at reporting date
Not otherwise provided for in the financial statements:
Contingent liabilities		226		260
Guarantees		3		2
		229		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 $56 million as at 30 June 2024 (31 December 2023: $47 million).

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Changes to the Composition of the Group

6 Months Ended

Jun. 30, 2024

Disclosure of composition of group [abstract]

Changes to the composition of the Group

E.2 Changes to the composition of the Group

Since the last annual reporting, Koolbardi Pte Ltd, a wholly owned subsidiary, was incorporated in Singapore on 21 February 2024.

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New Standards and Interpretations

6 Months Ended

Jun. 30, 2024

Disclosure of expected impact of initial application of new standards or interpretations [abstract]

 New standards and interpretations

E.3 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 half-year 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 30 June 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 with the exception of AASB 18/ IFRS 18 Presentation and Disclosure in Financial Statements and the amendments to AASB 112/ IAS 12 Income Taxes where the impact is under assessment.

Pillar Two tax reform

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

• aim to ensure that large multinational groups pay a minimum amount of tax on income arising in each jurisdiction in which they operate; and

• would achieve a minimum effective tax rate in each jurisdiction of 15% from the reporting period commencing1 January 2024.

For the half-year ended 30 June 2024, the Group paid $1,700 million of income tax and PRRT.

The Group’s impact assessment will depend on the extent to which the Pillar Two legislation has been enacted in the various jurisdictions the Group operates in and when it comes into effect. As at reporting date, Australia has not enacted the Pillar Two legislation. The Group will continue to monitor and assess the expected impact of the Pillar Two reform.

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Events After the End of the Reporting Period

6 Months Ended

Jun. 30, 2024

Disclosure of non-adjusting events after reporting period [abstract]

Events after the end of the reporting period

E.4 Events after the end of the reporting period

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 (Tellurian) for a cash payment of approximately $900 million (the transaction). As part of the agreement, the Group has provided a loan facility of up to $230 million to Tellurian to ensure site activity maintains momentum prior to the completion of the transaction. The loan is secured by a first priority lien over the Tellurian assets, subject to customary exclusions. The latest maturity date of the loan is 15 December 2024 or the date of transaction completion.

The transaction is subject to Tellurian shareholder approval, satisfaction of customary conditions precedent, and is expected to complete in the fourth quarter of 2024. The financial effect of the transaction is still being assessed.

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 Clean Ammonia Project for an all-cash consideration of approximately $2.35 billion. The project is under construction and is subject to cost, schedule, and performance guarantees from OCI. 

The transaction is subject to OCI shareholder approval, satisfaction of customary conditions precedent, and is expected to complete in the second half of 2024. The financial effect of the transaction is still being assessed.

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Segment Revenue and Expenses (Tables)

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Summary of segment assets and liabilities

	Australia						International						Marketing						Corporate/Other						Consolidated
	2024 US$m			2023 US$m			2024 US$m			2023 US$m			2024 US$m			2023 US$m			2024 US$m			2023 US$m			2024 US$m			2023 US$m
Liquified natural gas		2,595			3,894			—			—			412			785			—			—			3,007			4,679
Pipeline gas		512			515			107			198			—			—			—			—			619			713
Crude oil and condensate		861			715			1,190			1,028			40			15			—			—			2,091			1,758
Natural gas liquids		87			120			24			16			40			23			—			—			151			159
Revenue from sale of hydrocarbons		4,055			5,244			1,321			1,242			492			823			—			—			5,868			7,309
Intersegment revenue1		(12	)		(120	)		(2	)		(6	)		14			126			—			—			—			—
Processing and services revenue		113			85			—			—			—			—			—			—			113			85
Shipping and other revenue		—			—			—			—			7			6			—			—			7			6
Other revenue		101			(35	)		(2	)		(6	)		21			132			—			—			120			91
Operating revenue2		4,156			5,209			1,319			1,236			513			955			—			—			5,988			7,400
Production costs		(511	)		(614	)		(234	)		(193	)		—			—			—			—			(745	)		(807	)
Royalties, excise and levies		(185	)		(285	)		(11	)		(31	)		—			—			—			—			(196	)		(316	)
Insurance		(13	)		(20	)		(2	)		(5	)		—			—			(11	)		(9	)		(26	)		(34	)
Inventory movement		15			31			47			2			—			—			—			—			62			33
Costs of production		(694	)		(888	)		(200	)		(227	)		—			—			(11	)		(9	)		(905	)		(1,124	)
Land and buildings		(26	)		(31	)		—			(2	)		—			—			(2	)		—			(28	)		(33	)
Transferred exploration and evaluation		(41	)		(51	)		(45	)		(2	)		—			—			—			—			(86	)		(53	)
Plant and equipment		(1,189	)		(1,298	)		(567	)		(543	)		—			—			(23	)		(17	)		(1,779	)		(1,858	)
Oil and gas properties depreciation and amortisation		(1,256	)		(1,380	)		(612	)		(547	)		—			—			(25	)		(17	)		(1,893	)		(1,944	)
Shipping and direct sales costs		(61	)		(107	)		(43	)		(38	)		(50	)		(30	)		—			—			(154	)		(175	)
Trading costs		—			(4	)		—			—			(273	)		(618	)		—			—			(273	)		(622	)
Other hydrocarbon costs		(26	)		(7	)		—			—			—			—			—			—			(26	)		(7	)
Other cost of sales		(17	)		—			—			—			—			—			(4	)		—			(21	)		—
Other cost of sales		(104	)		(118	)		(43	)		(38	)		(323	)		(648	)		(4	)		—			(474	)		(804	)
Cost of sales		(2,054	)		(2,386	)		(855	)		(812	)		(323	)		(648	)		(40	)		(26	)		(3,272	)		(3,872	)
Gross profit/(loss)		2,102			2,823			464			424			190			307			(40	)		(26	)		2,716			3,528
Other income3		242			106			20			—			20			1			33			27			315			134
Exploration and evaluation expenditure		(12	)		(9	)		(86	)		(123	)		—			—			—			(1	)		(98	)		(133	)
Amortisation of permit acquisitions		—			—			(5	)		(4	)		—			—			—			—			(5	)		(4	)
Write-offs		—			—			—			(1	)		—			—			—			—			—			(1	)
Exploration and evaluation		(12	)		(9	)		(91	)		(128	)		—			—			—			(1	)		(103	)		(138	)
General, administration and other costs		—			—			—			(3	)		—			(10	)		(214	)		(224	)		(214	)		(237	)
Amortisation of intangible assets		—			—			—			—			—			—			(10	)		—			(10	)		—
Depreciation of lease assets		(28	)		(22	)		(1	)		(7	)		(50	)		(34	)		(22	)		(18	)		(101	)		(81	)
Restoration movement		(14	)		(8	)		(1	)		(12	)		—			—			—			—			(15	)		(20	)
Other4		16			(27	)		—			(1	)		58			(99	)		(300	)		(200	)		(226	)		(327	)
Other costs		(26	)		(57	)		(2	)		(23	)		8			(143	)		(546	)		(442	)		(566	)		(665	)
Other expenses		(38	)		(66	)		(93	)		(151	)		8			(143	)		(546	)		(443	)		(669	)		(803	)
Impairment losses		—			(68	)		—			—			—			—			—			—			—			(68	)
Profit/(loss) before tax and net finance costs		2,306			2,795			391			273			218			165			(553	)		(442	)		2,362			2,791

1. Intersegment revenue comprises the incremental income net of all incremental associated expenses generated by the Marketing segment’s optimisation of the oil and gas portfolio.

2. Operating revenue includes revenue from contracts with customers of $5,981 million (2023: $7,394 million) and sub-lease income of $7 million (2023: $6 million) disclosed within shipping and other revenue.

3. Includes fees, recoveries and other income not associated with the ongoing operations of the business. The 2024 amount includes the gain on the Scarborough sell-down to LNG Japan of $121 million.

4. Includes gains and losses on foreign exchange and hedging activities, fair value losses on embedded derivatives and other items not associated with the ongoing operations of the business.

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Finance Costs (Tables)

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Summary of finance cost

	2024 US$m			2023 US$m
Interest on interest-bearing liabilities		125			112
Interest on lease liabilities		51			54
Accretion charge		145			134
Other finance costs		13			21
Less: Finance costs capitalised against qualifying assets		(187	)		(184	)
		147			137

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Dividends Paid and Proposed (Tables)

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Summary of Woodside Energy Group Ltd, the parent entity, paid and proposed dividends

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

	2024 US$m		2023 US$m
(a) Dividends paid during the financial period Prior year fully franked final dividend US$0.60, paid on 4 April 2024 (2023: US$1.44, paid on 5 April 2023)		1,139		2,734
(b) Dividend declared subsequent to the reporting period (not recorded as a liability) Current year fully franked interim dividend US$0.69 to be paid on 3 October 2024 (2023: US$0.80, paid on 3 October 2023)		1,310		1,519

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2024

Earnings per share [abstract]

Summary of Earnings per share

	2024		2023
Profit attributable to equity holders of the parent (US$m)		1,937		1,740
Weighted average number of shares on issue for basic earnings per share		1,896,041,815		1,896,624,636
Effect of dilution from contingently issuable shares		14,691,983		12,981,487
Weighted average number of shares on issue adjusted for the effect of dilution		1,910,733,798		1,909,606,123
Basic earnings per share (US cents)		102.2		91.7
Diluted earnings per share (US cents)		101.4		91.1

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Taxes (Tables)

6 Months Ended

Jun. 30, 2024

Statements [Line Items]

Summary of reconciliation of effective and applicable income tax expenses

	2024 US$m			2023 US$m
Reconciliation of income tax expense
Profit before tax		2,310			2,828
PRRT expense		(192	)		(778	)
Profit before income tax		2,118			2,050
Income tax expense calculated at 30%		635			615
Effect of tax rate differentials		(15	)		30
Effect of deferred tax assets not recognised		35			67
Effect of tax benefits previously unrecognised1		(366	)		(340	)
Reduction in deferred tax liability due to held for sale basis1		(91	)		—
Foreign exchange impact on tax benefit		(11	)		(83	)
Adjustment to prior years		(52	)		(16	)
Other		11			11
Income tax expense		146			284

Summary of effective income tax rate

1. Subsequent to achieving first oil on the Sangomar project in June 2024, the Group has recognised a net deferred tax asset of $305 million. The remaining $61 million relates to other tax benefits previously unrecognised. The expected sale of Woodside’s 15.1% share in the Scarborough Joint Venture resulted in the recognition of a net tax benefit of $91 million. These events have resulted in a reduction of the global effective income tax rate from 25.6% to 6.9%. In the prior period, as a result of the final investment decision to develop the Trion resource, the Group recognised deferred tax assets of $319 million, resulting in a reduction of the global effective income tax rate from 29.6% to 13.9%.

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Exploration and Evaluation (Tables)

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Summary of Exploration And Evaluation

B.1 Exploration and evaluation

	Asia Pacific US$m			Americas US$m			Africa US$m			Total US$m
Half-year ended 30 June 2024
Carrying amount at 1 January 2024		568			76			24			668
Additions		11			52			14			77
Amortisation of licence acquisition costs		—			(5	)		—			(5	)
Transferred exploration and evaluation		(8	)		—			(18	)		(26	)
Carrying amount at 30 June 2024		571			123			20			714
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

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 oil and gas properties.

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Oil and Gas Properties (Tables)

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Summary of detailed information about oil and gas properties

B.2 Oil and gas properties

	Land and buildings US$m			Transferred exploration and evaluation US$m			Plant and equipment US$m			Projects in development1 US$m			Total US$m
Half-year ended 30 June 2024
Carrying amount at 1 January 2024		701			777			23,589			15,724			40,791
Additions2		—			—			(127	)		2,447			2,320
Disposals at written down value		(2	)		—			—			(47	)		(49	)
Depreciation and amortisation		(28	)		(86	)		(1,779	)		—			(1,893	)
Completions and transfers3		—			341			5,391			(5,706	)		26
Transfer to assets held for sale4		—			—			(4	)		(1,066	)		(1,070	)
Carrying amount at 30 June 2024		671			1,032			27,070			11,352			40,125
At 30 June 2024
Historical cost		1,743			2,320			55,533			12,072			71,668
Accumulated depreciation and impairment		(1,072	)		(1,288	)		(28,463	)		(720	)		(31,543	)
Net carrying amount		671			1,032			27,070			11,352			40,125
Year ended 31 December 2023
Carrying amount at 1 January 2023		840			481			23,057			15,541			39,919
Additions		—			—			836			5,759			6,595
Disposals at written down value		(8	)		—			(2	)		—			(10	)
Depreciation and amortisation		(67	)		(125	)		(3,764	)		—			(3,956	)
Impairment losses		(64	)		(20	)		(1,028	)		(328	)		(1,440	)
Completions and transfers		—			441			4,496			(4,633	)		304
Transfer to assets held for sale		—			—			(6	)		(615	)		(621	)
Carrying amount at 31 December 2023		701			777			23,589			15,724			40,791
At 31 December 2023
Historical cost		1,745			1,979			50,272			16,443			70,439
Accumulated depreciation and impairment		(1,044	)		(1,202	)		(26,683	)		(719	)		(29,648	)
Net carrying amount		701			777			23,589			15,724			40,791

1. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.

2. Includes $2,212 million of capital additions and $187 million of capitalised borrowing costs offset by $79 million relating to changes in restoration provision assumptions. The $127 million of additions reducing plant and equipment relates to changes in restoration provision assumptions.

3. Upon first oil in June 2024, the carrying value of the Sangomar project in projects in development has been transferred to plant and equipment.

4. Refer to Note B.4 for details of the sell-downs of the Scarborough Joint Venture.

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Goodwill (Tables)

6 Months Ended

Jun. 30, 2024

Disclosure of reconciliation of changes in goodwill [abstract]

Summary of goodwill

B.3 Goodwill

	US$m
Half-year ended 30 June 2024
Carrying amount at 1 January 2024		3,995
Transfer to assets held for sale1		(298	)
Carrying amount at 30 June 2024		3,697
At 30 June 2024
Cost		4,174
Accumulated impairment		(477	)
Net carrying amount		3,697
Year ended 31 December 2023
Carrying amount at 1 January 2023		4,614
Adjustment to purchase price allocation		55
Impairment		(477	)
Transfer to assets held for sale		(197	)
Carrying amount at 31 December 2023		3,995
At 31 December 2023
Cost		4,472
Accumulated impairment		(477	)
Net carrying amount		3,995

1. Refer to Note B.4(a) for details of the sell-downs of the Scarborough Joint Venture.

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Disposal of Assets (Tables)

6 Months Ended

Jun. 30, 2024

Disclosure Of Noncurrent Assets Or Disposal Groups Classified As Held For Sale [Abstract]

Summary of reclassified as held for sale

The following assets and liabilities were reclassified as held for sale as at 30 June 2024:

	US$m
Assets classified as held for sale
Oil and gas properties		1,070
Inventories		6
Lease assets		2
Goodwill		298
Other assets		2
Total assets held for sale		1,378
Liabilities directly associated with assets held for sale
Payables		(28	)
Deferred tax liabilities		(75	)
Lease liabilities		(8	)
Provisions		(8	)
Total liabilities directly associated with assets held for sale		(119	)

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Contributed Equity (Tables)

6 Months Ended

Jun. 30, 2024

Equity [abstract]

Summary of issued and fully paid shares

Issued and fully paid shares

	Number of shares		US$m
Half-year ended 30 June 2024
Opening balance		1,898,749,771		29,001
Amounts as at 30 June 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

All shares are a single class with equal rights to dividends, capital distributions and voting. The Company does not have authorised capital nor par value in respect of its issued shares.

Summary of information about shares reserved for employee share plans

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.

	Number of shares			US$m
Half-year ended 30 June 2024
Opening balance		2,140,927			(49	)
Purchases during the period		1,262,082			(25	)
Vested/allocated during the period		(424,959	)		9
Amounts as at 30 June 2024		2,978,050			(65	)
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 as at 31 December 2023		2,140,927			(49	)

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Segment Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Summary of segment assets and liabilities

	30 June 2024 US$m		31 December 2023 US$m
(a) Segment assets
Australia		30,895		31,602
International		18,083		17,923
Marketing		798		835
Corporate/Other		5,866		5,001
		55,642		55,361

	30 June 2024 US$m		31 December 2023 US$m
(b) Segment liabilities
Australia		7,312		7,833
International		2,434		2,624
Marketing		890		751
Corporate/Other		9,177		8,983
		19,813		20,191

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Provisions (Tables)

6 Months Ended

Jun. 30, 2024

Provisions [abstract]

Summary of Information About Provisions

	Restoration1 US$m			Employee benefits US$m			Other US$m			Total US$m
Half-year ended 30 June 2024
At 1 January 2024		7,154			522			281			7,957
Change in provision		(449	)		(31	)		55			(425	)
Unwinding of present value discount		144			—			1			145
Carrying amount at 30 June 2024		6,849			491			337			7,677
Current		698			302			223			1,223
Non-current		6,151			189			114			6,454
Net carrying amount		6,849			491			337			7,677
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 a revision of discount rates of $147 million (primarily due to an increase in risk-free rates), changes in foreign exchange rates of $84 million and provisions used of $358 million, offset by changes in estimates of $140 million.

XML

Other Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2024

Text Block [abstract]

Summary of information about other financial assets and liabilities

	30 June 2024 US$m		31 December 2023 US$m
Other financial assets
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		160		248
Other financial assets		100		53
Financial instruments at fair value through other comprehensive income
Other financial assets		—		28
Total other financial assets		260		329
Current		154		209
Non-current		106		120
Net carrying amount		260		329
Other financial liabilities
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		126		74
Embedded derivative		188		35
Other financial liabilities		41		—
Total other financial liabilities		355		109
Current		152		67
Non-current		203		42
Net carrying amount		355		109

Summary of detailed information about hedging activities

The following table presents the Group’s derivative financial instruments designated as hedges, measured and recognised at fair value:

	30 June 2024 US$m			31 December 2023 US$m
Oil swaps (cash flow hedges)		(53	)		(14	)
HH Corpus Christi commodity swaps (cash flow hedges)		(24	)		(44	)
TTF Corpus Christi commodity swaps (cash flow hedges)		72			181
Interest rate swaps (cash flow hedges)		48			43
Foreign exchange forwards (cash flow hedges)		(9	)		8
Total derivative financial instruments asset designated as hedges		34			174

Summary of Unrealised Gains or Losses Recognised in Other Income/Expenses

Change in assumption1	US$m
Urea sales price: increase of 10%		137
Urea sales price: decrease of 10%		(137	)
Discount rate: increase of 1.5%2		(186	)
Discount rate: decrease of 1.5%2		230

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.

XML

Contingent Liabilities and Assets (Tables)

6 Months Ended

Jun. 30, 2024

Disclosure of contingent liabilities [abstract]

Summary of contingent liabilities

	30 June 2024 US$m		31 December 2023 US$m
Contingent liabilities at reporting date
Not otherwise provided for in the financial statements:
Contingent liabilities		226		260
Guarantees		3		2
		229		262

XML

Segment Revenue and Expenses - Summary of Earnings (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Disclosure of operating segments [line items]
Impairment losses	$ 0	$ (68)
Profit/(loss) before tax and net finance costs	2,362	2,791
Operating revenue	5,988	7,400
Cost of sales	(3,272)	(3,872)
Gross profit/(loss)	2,716	3,528
Other income	315	134
Operating segments [member]
Disclosure of operating segments [line items]
Impairment losses	0	(68)
Profit/(loss) before tax and net finance costs	2,362	2,791
Other revenue	120	91
Operating revenue	5,988	7,400
Cost of sales	(3,272)	(3,872)
Insurance	(26)	(34)
Gross profit/(loss)	2,716	3,528
Other income	315	134
Exploration and evaluation expenditure	(98)	(133)
Amortisation of permit acquisition	(5)	(4)
Write-offs	0	(1)
Exploration and evaluation	(103)	(138)
General, administrative and other costs	(214)	(237)
Amortisation of intangible assets	(10)
Depreciation of lease assets	(101)	(81)
Restoration movement	(15)	(20)
Other	(226)	(327)
Other costs	(566)	(665)
Other expenses	(669)	(803)
Operating segments [member] | Oil and gas properties [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(1,893)	(1,944)
Operating segments [member] | Land and buildings [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(28)	(33)
Operating segments [member] | Transferred exploration and evaluation [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(86)	(53)
Operating segments [member] | Plant and equipment [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(1,779)	(1,858)
Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Impairment losses	0	(68)
Profit/(loss) before tax and net finance costs	2,306	2,795
Other revenue	101	(35)
Operating revenue	4,156	5,209
Cost of sales	(2,054)	(2,386)
Insurance	(13)	(20)
Gross profit/(loss)	2,102	2,823
Other income	242	106
Exploration and evaluation expenditure	(12)	(9)
Write-offs	0	0
Exploration and evaluation	(12)	(9)
Depreciation of lease assets	(28)	(22)
Restoration movement	(14)	(8)
Other	16	(27)
Other costs	(26)	(57)
Other expenses	(38)	(66)
Operating segments [member] | Australia [member] | External Customers [member]
Disclosure of operating segments [line items]
Operating revenue	(12)	(120)
Operating segments [member] | Australia [member] | Oil and gas properties [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(1,256)	(1,380)
Operating segments [member] | Australia [member] | Land and buildings [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(26)	(31)
Operating segments [member] | Australia [member] | Transferred exploration and evaluation [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(41)	(51)
Operating segments [member] | Australia [member] | Plant and equipment [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(1,189)	(1,298)
Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Impairment losses	0	0
Profit/(loss) before tax and net finance costs	391	273
Other revenue	(2)	(6)
Operating revenue	1,319	1,236
Cost of sales	(855)	(812)
Insurance	(2)	(5)
Gross profit/(loss)	464	424
Other income	20	0
Exploration and evaluation expenditure	(86)	(123)
Amortisation of permit acquisition	(5)	(4)
Write-offs	0	(1)
Exploration and evaluation	(91)	(128)
General, administrative and other costs		(3)
Depreciation of lease assets	(1)	(7)
Restoration movement	(1)	(12)
Other		(1)
Other costs	(2)	(23)
Other expenses	(93)	(151)
Operating segments [member] | International [member] | External Customers [member]
Disclosure of operating segments [line items]
Operating revenue	(2)	(6)
Operating segments [member] | International [member] | Oil and gas properties [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(612)	(547)
Operating segments [member] | International [member] | Land and buildings [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	0	(2)
Operating segments [member] | International [member] | Transferred exploration and evaluation [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(45)	(2)
Operating segments [member] | International [member] | Plant and equipment [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(567)	(543)
Operating segments [member] | Marketing [member]
Disclosure of operating segments [line items]
Impairment losses	0	0
Profit/(loss) before tax and net finance costs	218	165
Other revenue	21	132
Operating revenue	513	955
Cost of sales	(323)	(648)
Gross profit/(loss)	190	307
Other income	20	1
General, administrative and other costs		(10)
Depreciation of lease assets	(50)	(34)
Other	58	(99)
Other costs	8	(143)
Other expenses	8	(143)
Operating segments [member] | Marketing [member] | External Customers [member]
Disclosure of operating segments [line items]
Operating revenue	14	126
Operating segments [member] | Corporate/Other [member]
Disclosure of operating segments [line items]
Impairment losses	0	0
Profit/(loss) before tax and net finance costs	(553)	(442)
Cost of sales	(40)	(26)
Insurance	(11)	(9)
Gross profit/(loss)	(40)	(26)
Other income	33	27
Exploration and evaluation expenditure	0	(1)
Exploration and evaluation	0	(1)
General, administrative and other costs	(214)	(224)
Amortisation of intangible assets	(10)
Depreciation of lease assets	(22)	(18)
Other	(300)	(200)
Other costs	(546)	(442)
Other expenses	(546)	(443)
Operating segments [member] | Corporate/Other [member] | Oil and gas properties [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(25)	(17)
Operating segments [member] | Corporate/Other [member] | Land and buildings [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(2)
Operating segments [member] | Corporate/Other [member] | Plant and equipment [member]
Disclosure of operating segments [line items]
Depreciation and amortisation	(23)	(17)
Liquefied natural gas [member] | Operating segments [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	3,007	4,679
Liquefied natural gas [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	2,595	3,894
Liquefied natural gas [member] | Operating segments [member] | Marketing [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	412	785
Pipeline gas [member] | Operating segments [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	619	713
Pipeline gas [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	512	515
Pipeline gas [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	107	198
Crude oil and condensate [member] | Operating segments [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	2,091	1,758
Crude oil and condensate [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	861	715
Crude oil and condensate [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	1,190	1,028
Crude oil and condensate [member] | Operating segments [member] | Marketing [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	40	15
Natural gas liquids [member] | Operating segments [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	151	159
Natural gas liquids [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	87	120
Natural gas liquids [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	24	16
Natural gas liquids [member] | Operating segments [member] | Marketing [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	40	23
Revenue from sale of hydrocarbons [member] | Operating segments [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	5,868	7,309
Revenue from sale of hydrocarbons [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	4,055	5,244
Revenue from sale of hydrocarbons [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	1,321	1,242
Revenue from sale of hydrocarbons [member] | Operating segments [member] | Marketing [member]
Disclosure of operating segments [line items]
Revenue from sale of oil and gas products	492	823
Processing and services revenue [member] | Operating segments [member]
Disclosure of operating segments [line items]
Other revenue	113	85
Processing and services revenue [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Other revenue	113	85
Shipping and other revenue [member] | Operating segments [member]
Disclosure of operating segments [line items]
Other revenue	7	6
Shipping and other revenue [member] | Operating segments [member] | Marketing [member]
Disclosure of operating segments [line items]
Other revenue	7	6
Production costs [member] | Operating segments [member]
Disclosure of operating segments [line items]
Cost of sales	(745)	(807)
Production costs [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Cost of sales	(511)	(614)
Production costs [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Cost of sales	(234)	(193)
Royalties excise and levies [member] | Operating segments [member]
Disclosure of operating segments [line items]
Cost of sales	(196)	(316)
Royalties excise and levies [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Cost of sales	(185)	(285)
Royalties excise and levies [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Cost of sales	(11)	(31)
Inventory movement [member] | Operating segments [member]
Disclosure of operating segments [line items]
Inventory movement	62	33
Inventory movement [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Inventory movement	15	31
Inventory movement [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Inventory movement	47	2
Inventory movement [member] | Operating segments [member] | Corporate/Other [member]
Disclosure of operating segments [line items]
Inventory movement	0
Costs of production [member] | Operating segments [member]
Disclosure of operating segments [line items]
Cost of sales	(905)	(1,124)
Costs of production [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Cost of sales	(694)	(888)
Costs of production [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Cost of sales	(200)	(227)
Costs of production [member] | Operating segments [member] | Corporate/Other [member]
Disclosure of operating segments [line items]
Cost of sales	(11)	(9)
Shipping and direct sales costs [member] | Operating segments [member]
Disclosure of operating segments [line items]
Cost of sales	(154)	(175)
Shipping and direct sales costs [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Cost of sales	(61)	(107)
Shipping and direct sales costs [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Cost of sales	(43)	(38)
Shipping and direct sales costs [member] | Operating segments [member] | Marketing [member]
Disclosure of operating segments [line items]
Cost of sales	(50)	(30)
Shipping and direct sales costs [member] | Operating segments [member] | Corporate/Other [member]
Disclosure of operating segments [line items]
Cost of sales	0	0
Trading costs [member] | Operating segments [member]
Disclosure of operating segments [line items]
Cost of sales	(273)	(622)
Trading costs [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Cost of sales	0	(4)
Trading costs [member] | Operating segments [member] | Marketing [member]
Disclosure of operating segments [line items]
Cost of sales	(273)	(618)
Other hydrocarbon costs [member] | Operating segments [member]
Disclosure of operating segments [line items]
Cost of sales	(26)	(7)
Other hydrocarbon costs [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Cost of sales	(26)	(7)
Other cost of sales [member] | Operating segments [member]
Disclosure of operating segments [line items]
Cost of sales	(21)	0
Other cost of sales [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Cost of sales	(17)	0
Other cost of sales [member] | Operating segments [member] | Corporate/Other [member]
Disclosure of operating segments [line items]
Cost of sales	(4)
Total other cost of sales [member] | Operating segments [member]
Disclosure of operating segments [line items]
Cost of sales	(474)	(804)
Total other cost of sales [member] | Operating segments [member] | Australia [member]
Disclosure of operating segments [line items]
Cost of sales	(104)	(118)
Total other cost of sales [member] | Operating segments [member] | International [member]
Disclosure of operating segments [line items]
Cost of sales	(43)	(38)
Total other cost of sales [member] | Operating segments [member] | Marketing [member]
Disclosure of operating segments [line items]
Cost of sales	(323)	(648)
Total other cost of sales [member] | Operating segments [member] | Corporate/Other [member]
Disclosure of operating segments [line items]
Cost of sales	$ (4)	$ 0

XML

Segment Revenue and Expenses - Summary of Earnings (Parenthetical) (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Operating segments [member]
Disclosure of operating segments [line items]
Revenue from contracts with customers	$ 5,981	$ 7,394
Sub-lease income	7	$ 6
LNG Japan [Member] | JERA Scarborough Pty Ltd [member]
Disclosure of operating segments [line items]
Gain on sale of joint venture interest	$ 121

XML

Finance Costs - Summary of Finance Cost (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Finance Costs [abstract]
Interest on interest-bearing liabilities	$ 125	$ 112
Interest on lease liabilities	51	54
Accretion charge	145	134
Other finance costs	13	21
Less: Finance costs capitalised against qualifying assets	(187)	(184)
Finance costs	$ 147	$ 137

XML

Dividends Paid and Proposed - Summary of Woodside Energy Group Ltd the Parent Entity Paid and Proposed Dividends (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Disclosure of Detailed Information About Paid and Proposed Dividends [Line Items]
Prior year fully franked final dividend	$ 1,139	$ 2,734
Current year fully franked interim dividend	$ 1,310	$ 1,519

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Dividends Paid and Proposed - Summary of Woodside Energy Group Ltd the Parent Entity Paid and Proposed Dividends (Parenthetical) (Detail) - $ / shares	Oct. 03, 2024	Apr. 05, 2024	Apr. 04, 2024	Oct. 03, 2023
Disclosure of Detailed Information About Paid and Proposed Dividends [Line Items]
Prior year fully franked final dividend, Per share		$ 1.44	$ 0.6
Current year fully franked interim dividend, Per share	$ 0.69			$ 0.8

XML

Earnings Per Share - Summary of Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Earnings per share [abstract]
Profit attributable to equity holders of the parent	$ 1,937	$ 1,740
Weighted average number of shares on issue for basic earnings per share	1,896,041,815	1,896,624,636
Effect of dilution from contingently issuable shares	14,691,983	12,981,487
Weighted average number of shares on issue adjusted for the effect of dilution	1,910,733,798	1,909,606,123
Basic earnings per share	$ 1.022	$ 0.917
Diluted earnings per share	$ 1.014	$ 0.911

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Taxes - Summary of Reconciliation of Effective and Applicable Income Tax Expenses (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Disclosure Of Reconciliation Of Effective And Applicable Income Tax Expenses [Line Items]
Profit before tax	$ 2,310	$ 2,828
PRRT expense	192	778
Income tax expense	146	284
Income Tax [Member]
Disclosure Of Reconciliation Of Effective And Applicable Income Tax Expenses [Line Items]
Reduction in deferred tax liability due to held for sale basis	(91)	0
Profit before tax	2,310	2,828
PRRT expense	(192)	(778)
Profit before income tax	2,118	2,050
Income tax expense calculated at 30%	635	615
Effect of tax rate differentials	(15)	30
Effect of deferred tax assets not recognised	35	67
Effect of tax benefits previously unrecognised	(366)	(340)
Foreign exchange impact on tax benefit	(11)	(83)
Adjustment to prior years	(52)	(16)
Other	11	11
Income tax expense	$ 146	$ 284

XML

Taxes - Summary of Reconciliation of Effective and Applicable Income Tax Expenses (Parenthetical) (Detail)	6 Months Ended
	Jun. 30, 2024
Income Tax [Member]
Disclosure Of Reconciliation Of Effective And Applicable Income Tax Expenses [Line Items]
Applicable tax rate	30.00%

XML

Taxes - Summary of Effective Income Tax Rate (Parenthetical) (Detail) - USD ($) $ in Millions	6 Months Ended							12 Months Ended
	Jun. 30, 2030	Jun. 30, 2029	Jun. 30, 2028	Jun. 30, 2027	Jun. 30, 2026	Jun. 30, 2025	Jun. 30, 2024	Dec. 31, 2023
Disclosure Of Effective Income Tax Rate [Line Items]
Taxable Profit Percentage	10
JERA Scarborough Pty Ltd [Member]
Disclosure Of Effective Income Tax Rate [Line Items]
Tax benefit arising from previously unrecognised tax loss, tax credit or temporary difference of prior period used to reduce deferred tax expense						$ 61
Recognized tax benefit							$ 91
Bottom of range [member] | JERA Scarborough Pty Ltd [Member]
Disclosure Of Effective Income Tax Rate [Line Items]
Applicable tax rate				6.90%
Top of range [member] | JERA Scarborough Pty Ltd [Member]
Disclosure Of Effective Income Tax Rate [Line Items]
Applicable tax rate					25.60%
Pluto and Wheatstone [Member]
Disclosure Of Effective Income Tax Rate [Line Items]
Current Tax Payable							124
Trion [Member]
Disclosure Of Effective Income Tax Rate [Line Items]
Recognition of deferred tax asset			$ 319
Trion [Member] | Bottom of range [member]
Disclosure Of Effective Income Tax Rate [Line Items]
Applicable tax rate	13.90%
Trion [Member] | Top of range [member]
Disclosure Of Effective Income Tax Rate [Line Items]
Applicable tax rate		29.60%
Sangomar [Member] | JERA Scarborough Pty Ltd [Member] | Achieving First Oil On The Project [Member]
Disclosure Of Effective Income Tax Rate [Line Items]
Income tax relating to components of other comprehensive income							$ 305
Scarborough [Member]
Disclosure Of Effective Income Tax Rate [Line Items]
Percentage of Scarborough JV interest sold								10.00%
Scarborough [Member] | JERA Scarborough Pty Ltd [Member]
Disclosure Of Effective Income Tax Rate [Line Items]
Percentage of Scarborough JV interest sold							15.10%
Recognized tax benefit							$ 91

XML

Exploration And Evaluation - Summary of Exploration And Evaluation (Detail) - Exploration and evaluation assets [member] - Carrying Amounts [member] - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Asia Pacific [Member]
Disclosure of detailed information about exploration and evaluation [line items]
Carrying amount, Beginning balance	$ 568	$ 529
Additions	11	79
Expensed		(31)
Transferred exploration and evaluation	(8)	(9)	[1]
Carrying amount, Ending balance	571	568
Americas [Member]
Disclosure of detailed information about exploration and evaluation [line items]
Carrying amount, Beginning balance	76	240
Additions	52	161
Amortisation of licence acquisition costs	(5)	(2)
Expensed		(28)
Transferred exploration and evaluation	0	(295)	[1]
Carrying amount, Ending balance	123	76
Africa [Member]
Disclosure of detailed information about exploration and evaluation [line items]
Carrying amount, Beginning balance	24	38
Additions	14	6
Amortisation of licence acquisition costs	0	(2)
Expensed		(18)
Transferred exploration and evaluation	(18)
Carrying amount, Ending balance	20	24
Other [member]
Disclosure of detailed information about exploration and evaluation [line items]
Carrying amount, Beginning balance	668	807
Additions	77	246
Amortisation of licence acquisition costs	(5)	(4)
Expensed		(77)
Transferred exploration and evaluation	(26)	(304)	[1]
Carrying amount, Ending balance	$ 714	$ 668

[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 oil and gas properties.

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Exploration And Evaluation - Summary of Exploration And Evaluation (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Trion [member] | Oil and gas assets [member]
Disclosure of detailed information about exploration and evaluation [line items]
Exploration assets transferrred	$ 274

XML

Oil And Gas Properties - Summary of Oil And Gas Properties (Detail) - USD ($) $ in Millions		6 Months Ended		12 Months Ended
		Jun. 30, 2024		Dec. 31, 2023
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		$ 40,791
At the end of the financial year		40,125		$ 40,791
Oil and gas assets [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		40,791
At the end of the financial year		40,125		40,791
Oil and gas assets [member] | Gross carrying amount [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		40,791		39,919
Additions		2,320	[1]	6,595
Disposals at written down value		(49)		(10)
Depreciation and amortisation		(1,893)		(3,956)
Completions and transfers		26	[2]	304
Impairment losses				(1,440)
Transfer to assets held for sale		(1,070)	[3]	(621)
At the end of the financial year		40,125		40,791
Oil and gas assets [member] | Historical Cost [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		70,439
At the end of the financial year		71,668		70,439
Oil and gas assets [member] | Accumulated depreciation, amortisation and impairment [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		(29,648)
At the end of the financial year		(31,543)		(29,648)
Oil and gas assets [member] | Land and buildings [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		701
At the end of the financial year		671		701
Oil and gas assets [member] | Land and buildings [member] | Gross carrying amount [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		701		840
Disposals at written down value		(2)		(8)
Depreciation and amortisation		(28)		(67)
Completions and transfers	[2]	0
Impairment losses				(64)
At the end of the financial year		671		701
Oil and gas assets [member] | Land and buildings [member] | Historical Cost [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		1,745
At the end of the financial year		1,743		1,745
Oil and gas assets [member] | Land and buildings [member] | Accumulated depreciation, amortisation and impairment [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		(1,044)
At the end of the financial year		(1,072)		(1,044)
Oil and gas assets [member] | Transferred exploration and evaluation [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		777
At the end of the financial year		1,032		777
Oil and gas assets [member] | Transferred exploration and evaluation [member] | Gross carrying amount [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		777		481
Disposals at written down value				0
Depreciation and amortisation		(86)		(125)
Completions and transfers		341	[2]	441
Impairment losses				(20)
At the end of the financial year		1,032		777
Oil and gas assets [member] | Transferred exploration and evaluation [member] | Historical Cost [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		1,979
At the end of the financial year		2,320		1,979
Oil and gas assets [member] | Transferred exploration and evaluation [member] | Accumulated depreciation, amortisation and impairment [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		(1,202)
At the end of the financial year		(1,288)		(1,202)
Oil and gas assets [member] | Plant and equipment [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		23,589
At the end of the financial year		27,070		23,589
Oil and gas assets [member] | Plant and equipment [member] | Gross carrying amount [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		23,589		23,057
Additions		(127)	[1]	836
Disposals at written down value		0		(2)
Depreciation and amortisation		(1,779)		(3,764)
Completions and transfers		5,391	[2]	4,496
Impairment losses				(1,028)
Transfer to assets held for sale		(4)	[3]	(6)
At the end of the financial year		27,070		23,589
Oil and gas assets [member] | Plant and equipment [member] | Historical Cost [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		50,272
At the end of the financial year		55,533		50,272
Oil and gas assets [member] | Plant and equipment [member] | Accumulated depreciation, amortisation and impairment [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year		(26,683)
At the end of the financial year		(28,463)		(26,683)
Oil and gas assets [member] | Projects in development [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year	[4]	15,724
At the end of the financial year	[4]	11,352		15,724
Oil and gas assets [member] | Projects in development [member] | Gross carrying amount [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year	[4]	15,724		15,541
Additions	[4]	2,447	[1]	5,759
Disposals at written down value	[4]	(47)
Completions and transfers	[4]	(5,706)	[2]	(4,633)
Impairment losses	[4]			(328)
Transfer to assets held for sale	[4]	(1,066)	[3]	(615)
At the end of the financial year	[4]	11,352		15,724
Oil and gas assets [member] | Projects in development [member] | Historical Cost [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year	[4]	16,443
At the end of the financial year	[4]	12,072		16,443
Oil and gas assets [member] | Projects in development [member] | Accumulated depreciation, amortisation and impairment [member]
Disclosure of detailed information about oil and gas properties [line items]
At the beginning of the financial year	[4]	(719)
At the end of the financial year	[4]	$ (720)		$ (719)

[1] Includes $2,212 million of capital additions and $187 million of capitalised borrowing costs offset by $79 million relating to changes in restoration provision assumptions. The $127 million of additions reducing plant and equipment relates to changes in restoration provision assumptions.

[2] Upon first oil in June 2024, the carrying value of the Sangomar project in projects in development has been transferred to plant and equipment.

[3] Refer to Note B.4 for details of the sell-downs of the Scarborough Joint Venture.

[4] Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.

XML

Oil And Gas Properties - Summary of Detailed Information About Oil And Gas Properties (Parentheticals) (Detail) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Disclosure Of Detailed Information About Oil And Gas Properties [Line Items]
Capital additions		$ 2,212
Capitalised borrowing costs		187
Changes in revaluation of assets		$ 79
Plant And Equipment [Member]
Disclosure Of Detailed Information About Oil And Gas Properties [Line Items]
Additions to right-of-use assets	$ 127

XML

Oil And Gas Properties - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Disclosure of detailed information about property, plant and equipment [line items]
Capital commitments	$ 3,017	$ 4,245

XML

Goodwill - Summary of Goodwill (Detail) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Disclosure of reconciliation of changes in goodwill [line items]
Carrying amount beginning balance	$ 3,995	$ 3,995
Adjustment to purchase price allocation	55
Impairment		(477)
Transfer to assets held for sale	(298)	(197)
Carrying amount ending balance	3,697	3,995
Carrying amount [member]
Disclosure of reconciliation of changes in goodwill [line items]
Carrying amount beginning balance		4,472
Carrying amount ending balance	4,174
Accumulated impairment [member]
Disclosure of reconciliation of changes in goodwill [line items]
Carrying amount beginning balance		$ (477)
Carrying amount ending balance	$ (477)

XML

Disposal of Assets - Summary of Reclassified as Held for Sale (Detail) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Assets classified as held for sale
Total assets held for sale	$ 1,378	$ 826
Liabilities directly associated with assets held for sale
Total liabilities directly associated with assets held for sale	(119)	$ (94)
Assets and liabilities classified as held for sale [member] | Scarborough [Member]
Assets classified as held for sale
Oil and gas properties	1,070
Inventories	6
Lease assets	2
Goodwill	298
Other assets	2
Total assets held for sale	1,378
Liabilities directly associated with assets held for sale
Payables	(28)
Deferred tax liabilities	(75)
Lease liabilities	(8)
Provisions	(8)
Total liabilities directly associated with assets held for sale	$ (119)

XML

Disposal of Assets - Additional Information (Detail) - USD ($) $ in Millions				6 Months Ended	12 Months Ended
	Mar. 26, 2024	Feb. 23, 2024	Aug. 08, 2023	Jun. 30, 2024	Dec. 31, 2023
Disposal of assets [line item]
Assets held for sale				$ 1,378	$ 826
Liabilities directly associated with assets held for sale				119	$ 94
Impairment of assets reclassification to held for sale				0
JERA Scarborough Pty Ltd [Member]
Disposal of assets [line item]
Recognized tax benefit				91
Scarborough [Member]
Disposal of assets [line item]
Proportion of ownership interest in joint venture					10.00%
Scarborough [Member] | JERA Scarborough Pty Ltd [Member]
Disposal of assets [line item]
Recognized tax benefit				$ 91
Percentage of sale of interest sold					15.10%
Proportion of ownership interest in joint venture				15.10%
Scarborough [Member] | JERA Scarborough Pty Ltd [Member] | Bottom of range [member]
Disposal of assets [line item]
Proportion of voting rights held in joint venture				74.90%
Scarborough [Member] | JERA Scarborough Pty Ltd [Member] | Top of range [member]
Disposal of assets [line item]
Proportion of voting rights held in joint venture				90.00%
Scarborough [Member] | AUSTRALIA | JERA Scarborough Pty Ltd [Member]
Disposal of assets [line item]
Assets held for sale				$ 1,378
Liabilities directly associated with assets held for sale				119
Proportion of ownership interest in joint venture		15.10%
Scarborough [Member] | L And G Japan [Member]
Disposal of assets [line item]
Proportion of voting rights held in joint venture	90.00%		100.00%
Scarborough [Member] | L And G Japan [Member] | JERA Scarborough Pty Ltd [Member]
Disposal of assets [line item]
Disposal group including discontinued operation consideration receivable			$ 740
Scarborough [Member] | L And G Japan [Member] | AUSTRALIA
Disposal of assets [line item]
Proceeds from the sale for capital reimbursements and escalation			$ 910
Percentage of sale of interest sold			10.00%
Assets held for sale					$ 823
Liabilities directly associated with assets held for sale					$ 94
Amount payable due to cost overuns maximum			$ 50
Disposal group consideration received on sale of assets				$ 121

XML

Contributed Equity - Summary of Issued and Fully Paid Shares (Detail) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023	Jun. 30, 2023
Disclosure of classes of share capital [line items]
Beginning balance	$ 35,170	$ 36,684	$ 37,127
Ending balance	$ 35,829	$ 35,170	$ 36,684
Ordinary shares [member]
Disclosure of classes of share capital [line items]
Beginning balance, shares	1,898,749,771		1,898,749,771
Beginning balance	$ 29,001		$ 29,001
Ending balance, shares	1,898,749,771	1,898,749,771
Ending balance	$ 29,001	$ 29,001

XML

Contributed equity - Summary of Information about Shares Reserved for Employee Share Plans (Detail) - Employee Share Plans [Member] - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Disclosure of classes of share capital [line items]
Beginning balance, shares	2,140,927	1,873,777
Beginning balance	$ (49)	$ (38)
Purchases during the period, shares	1,262,082	2,332,121
Purchases during the period	$ (25)	$ (57)
Vested/allocated during the period, shares	(424,959)	(2,064,971)
Vested/allocated during the period	$ 9	$ 46
Ending balance, shares	2,978,050	2,140,927
Ending balance	$ (65)	$ (49)

XML

Interest Bearing Liabilities and Financing Facilities - Additional Information (Detail) - USD ($) $ in Millions		6 Months Ended		12 Months Ended
	Jul. 31, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023	Dec. 31, 2024
Interest bearing liabilities and financing facilities [line items]
Loan Facilities Drawdown		$ 500
Repayments of borrowings, classified as financing activities			$ 41
Undrawn borrowing facilities		6,500		$ 6,050
Cancellation of undrawn borrowing facilities		1,550
Syndicate Term Loan [Member]
Interest bearing liabilities and financing facilities [line items]
Borrowings		$ 450
CHF Medium Term Note [Member]
Interest bearing liabilities and financing facilities [line items]
Repayments of borrowings, classified as financing activities				201
Syndicated facility [member]
Interest bearing liabilities and financing facilities [line items]
Borrowings maturity		10 years
JBIC facility [member]
Interest bearing liabilities and financing facilities [line items]
Borrowings maturity		10 years
JBIC facility [member] | Loan commitments [member]
Interest bearing liabilities and financing facilities [line items]
Borrowings		$ 1,000
JBIC facility [member]
Interest bearing liabilities and financing facilities [line items]
Repayments of borrowings, classified as financing activities	$ 83
Unsecured bonds [member]
Interest bearing liabilities and financing facilities [line items]
Financial liabilities carrying amount				4,087	$ 4,087
Financial liabilities at fair value				3,936	3,958
Medium Term Notes [member]
Interest bearing liabilities and financing facilities [line items]
Financial liabilities carrying amount				200	200
Financial liabilities at fair value				$ 188	$ 188

XML

Segment Assets and Liabilities - Summary of Segment Assets and Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Disclosure of operating segments [line items]
Segment assets	$ 55,642	$ 55,361
Segment liabilities	19,813	20,191
Australia [member]
Disclosure of operating segments [line items]
Segment assets	30,895	31,602
Segment liabilities	7,312	7,833
International [member]
Disclosure of operating segments [line items]
Segment assets	18,083	17,923
Segment liabilities	2,434	2,624
Marketing [member]
Disclosure of operating segments [line items]
Segment assets	798	835
Segment liabilities	890	751
Corporate/Other [member]
Disclosure of operating segments [line items]
Segment assets	5,866	5,001
Segment liabilities	$ 9,177	$ 8,983

XML

Provisions - Summary of Provisions (Detail) - USD ($) $ in Millions		6 Months Ended	12 Months Ended
		Jun. 30, 2024	Dec. 31, 2023
Disclosure of detailed information about provisions [line items]
Beginning Balance		$ 7,957	$ 7,179
Change in provision		(425)	541
Unwinding of present value discount		145	237
Ending Balance		7,677	7,957
Current		1,223	1,506
Non-current		6,454	6,451
Net carrying amount		7,677	7,957
Restoration [member]
Disclosure of detailed information about provisions [line items]
Beginning Balance	[1]	7,154	6,253
Change in provision	[1]	(449)	664
Unwinding of present value discount	[1]	144	237
Ending Balance	[1]	6,849	7,154
Current	[1]	698	1,011
Non-current	[1]	6,151	6,143
Net carrying amount	[1]	6,849	7,154
Employee benefits [member]
Disclosure of detailed information about provisions [line items]
Beginning Balance		522	517
Change in provision		(31)	5
Unwinding of present value discount		0	0
Ending Balance		491	522
Current		302	351
Non-current		189	171
Net carrying amount		491	522
Other [member]
Disclosure of detailed information about provisions [line items]
Beginning Balance		281	409
Change in provision		55	(128)
Unwinding of present value discount		1	0
Ending Balance		337	281
Current		223	144
Non-current		114	137
Net carrying amount		$ 337	$ 281

[1] 2024 change in provision is due to a revision of discount rates of $147 million (primarily due to an increase in risk-free rates), changes in foreign exchange rates of $84 million and provisions used of $358 million, offset by changes in estimates of $140 million.

XML

Provisions - Summary Of Information About Provisions (Parenthetical) (Detail) - Restoration [member] $ in Millions	6 Months Ended
	Jun. 30, 2024 USD ($)
Disclosure of detailed information about provisions [line items]
Increase (decrease) in accounting estimate	$ 147
Provision used, other provisions	358
Change of provision due to foreign exchange	84
Change of provision due to estimates	$ 140

XML

Other Financial Assets and Liabilities - Summary of Other Financial Assets and Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Other financial assets
Derivative financial instruments designated as hedges	$ 160	$ 248
Other financial assets	100	53
Financial instruments at fair value through other comprehensive income
Other financial assets	0	28
Total other financial assets	260	329
Current	154	209
Non-current	106	120
Other financial liabilities
Derivative financial instruments designated as hedges	126	74
Embedded derivative	188	35
Other financial liabilities	41	0
Total other financial liabilities	355	109
Current	152	67
Non-current	$ 203	$ 42

XML

Other Financial Assets and Liabilities - Summary of Hedging Activities (Detail) - Cash flow hedges [member] - Designated As Hedging Instruments [Member] - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Disclosure of detailed information about hedging instruments [line items]
Financial assets at fair value	$ 34	$ 174
Oil Swaps [member]
Disclosure of detailed information about hedging instruments [line items]
Financial liabilities at fair value	(53)	(14)
HH Corpus Christi commodity Swaps [member]
Disclosure of detailed information about hedging instruments [line items]
Financial liabilities at fair value	(24)	(44)
TTF Corpus Christi Commodity Swaps [member]
Disclosure of detailed information about hedging instruments [line items]
Financial assets at fair value	72	181
Interest rate swap contract [member]
Disclosure of detailed information about hedging instruments [line items]
Financial assets at fair value	48	43
Foreign Exchange Forward [member]
Disclosure of detailed information about hedging instruments [line items]
Financial liabilities at fair value	$ (9)
Financial assets at fair value		$ 8

XML

Other Financial Assets and Liabilities - Additional Information (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2024 USD ($) bbl	Jun. 30, 2023 USD ($)	Dec. 31, 2023 USD ($)
Other financial assets and liabilities [line items]
Percentage of oil delivered	49.00%
Hedging instrument, assets	$ 29.3
2026 [member]
Other financial assets and liabilities [line items]
Percentage of hedged pricing risk	9.00%
2025 [member]
Other financial assets and liabilities [line items]
Percentage of hedged pricing risk	48.00%
Hedging instrument, assets	$ 15.0
2024 [member]
Other financial assets and liabilities [line items]
Percentage of hedged pricing risk	70.00%
Oil Swaps [Member]
Other financial assets and liabilities [line items]
Oil and gas sale price | bbl	75.6
Oil Swaps [Member] | 2025 [member]
Other financial assets and liabilities [line items]
Oil and gas sale price | bbl	81.2
Embedded Derivatives [Member] | Financial liabilities at fair value through profit or loss, category [member] | Long Term Sale And Gas Purchase Contract With Perdman [Member]
Other financial assets and liabilities [line items]
Gain loss on financial liabilities at fair value through profit or loss	$ 153.0	$ 52.0
Derivative financial liabilities	$ 188.0		$ 35.0
Discount rate, measurement input [member] | Top of range [member] | Embedded Derivatives [Member] | Financial liabilities at fair value through profit or loss, category [member] | Long Term Sale And Gas Purchase Contract With Perdman [Member]
Other financial assets and liabilities [line items]
Discount rate pre tax	6.95
Discount rate, measurement input [member] | Bottom of range [member] | Embedded Derivatives [Member] | Financial liabilities at fair value through profit or loss, category [member] | Long Term Sale And Gas Purchase Contract With Perdman [Member]
Other financial assets and liabilities [line items]
Discount rate pre tax	5.8
Inflation Rate [Member] | Embedded Derivatives [Member] | Financial liabilities at fair value through profit or loss, category [member] | Long Term Sale And Gas Purchase Contract With Perdman [Member]
Other financial assets and liabilities [line items]
Inflation rate	2.50%

XML

Other Financial Assets and Liabilities - Summary of Unrealised Gains or Losses Recognised in Other Income/Expenses (Detail) - Embedded Derivatives [Member] - Financial liabilities at fair value through profit or loss, category [member] $ in Millions	6 Months Ended
	Jun. 30, 2024 USD ($)	[1]
Urea Sales Price [Member]
Disclosure In Tabular Form Of Sensitivity Analysis Used In The Fair Value Measurement Of Embedded Derivative Liabilities [Line Items]
Change in assumption increase	$ 137
Change in assumption decrease	(137)
Discount rate, measurement input [member]
Disclosure In Tabular Form Of Sensitivity Analysis Used In The Fair Value Measurement Of Embedded Derivative Liabilities [Line Items]
Change in assumption increase	(186)	[2]
Change in assumption decrease	$ 230	[2]

[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.

XML

Other Financial Assets and Liabilities - Summary of Unrealised Gains or Losses Recognised in Other Income/Expenses (Parenthetical) (Detail) - Financial liabilities at fair value through profit or loss, category [member] - Embedded Derivatives [Member]	Jun. 30, 2024
Urea Sales Price [Member]
Disclosure In Tabular Form Of Sensitivity Analysis Used In The Fair Value Measurement Of Embedded Derivative Liabilities [Line Items]
Percentage of reasonably possible increase in unobservable input liabilities	10.00%
Percentage of reasonably possible decrease in unobservable input liabilities	10.00%
Discount rate, measurement input [member]
Disclosure In Tabular Form Of Sensitivity Analysis Used In The Fair Value Measurement Of Embedded Derivative Liabilities [Line Items]
Percentage of reasonably possible increase in unobservable input liabilities	1.50%
Percentage of reasonably possible decrease in unobservable input liabilities	1.50%

XML

Contingent Liabilities and Assets - Summary of Contingent Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Disclosure of contingent liabilities [line items]
Contingent liabilities and assets	$ 229	$ 262
Contingent liabilities [member]
Disclosure of contingent liabilities [line items]
Contingent liabilities and assets	226	260
Guarantees [member]
Disclosure of contingent liabilities [line items]
Contingent liabilities and assets	$ 3	$ 2

XML

Contingent Liabilities and Assets - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Disclosure of contingent liabilities [abstract]
Contingent assets	$ 56	$ 47

XML

Changes to the Composition of the Group - Additional Information (Detail)	Feb. 21, 2024
Disclosure of composition of group [abstract]
Country of incorporation	Singapore

XML

New Standards and Interpretations - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Disclosure of expected impact of initial application of new standards or interpretations [line items]
Income tax and PRRT paid	$ 1,700	$ 2,233
With Effect from 1 January 2024 [member] | Pillar two model rules for organization for economic cooperation and development [member]
Disclosure of expected impact of initial application of new standards or interpretations [line items]
Minimum effective tax rate percentage	15.00%

XML

Events After the End of the Reporting Period - Additional Information (Detail) - USD ($) $ in Millions	Aug. 05, 2024	Jul. 22, 2024
Agreement to Acquire the Common Stock [member] | Tellurian Inc [member]
Disclosure of non-adjusting events after reporting period [line items]
Payments to acquire or redeem entity's shares		$ 900
Gross loan commitments		$ 230
Borrowings, maturity		15 December 2024
Agreement to Acquire Entity [member] | OCI Clean Ammonia Holding B.V. [member]
Disclosure of non-adjusting events after reporting period [line items]
Percentage of voting equity interests acquired	100.00%
Cash consideration paid	$ 2,350