What changed in WOODSIDE ENERGY GROUP LTD's 20-F — 2024 vs 2025

Item 3.D for more information on the Group’s objectives, policies and processes for managing financial risk. The below risks arise in the normal course of the Group’s business.

Risk information can be found in the following sections: Section A Commodity price risk management Page F- 13 Section A Foreign exchange risk management Page F- 13 Section C Capital risk management Page F- 40 Section C Liquidity risk management Page F- 40 Section C Interest rate risk management Page F- 40 Section D Credit risk management Page F- 46 Significant estimates and judgements In applying the Group’s accounting policies, management regularly evaluates judgements, estimates and assumptions based on experience and other factors, including expectations of future events that may have an impact on the Group.

All judgements, estimates and assumptions made are believed to be reasonable based on the most current set of circumstances known to management, and actual results may differ.

Significant judgements, estimates and assumptions made by management in the preparation of these financial statements are found in the following notes: Note A.1 Segment revenue and expenses Page F- 14 Note A.5 Taxes Page F- 19 Note B.2 Exploration and evaluation Page F- 27 Note B.3 Property, plant and equipment Page F- 28 Note B.4 Impairment of exploration and evaluation, property, plant and equipment and goodwill Page F- 30 Note B.5 Business combination Page F- 34 Note B.6 Intangible assets Page F- 36 Note B.7 Significant production and growth asset acquisitions Page F- 37 Note B.9 Transactions with equity holders of the Group Page F- 38 Note D.5 Provisions Page F- 49 Note D.6 Other financial assets and liabilities Page F- 51 Note D.7 Leases Page F- 55 Note E.6 Joint arrangements Page F- 61 F-13 Table of Contents Notes to the financial statements A.

Earnings for the period for the year ended 31 December 2025 IN THIS SECTION This section addresses financial performance of the Group for the reporting period including, where applicable, the accounting policies applied and the significant estimates and judgements made. This section also includes the tax position of the Group for and at the end of the reporting period. A.

Earnings for the period A.1 Segment revenue and expenses Page F- 14 A.2 Finance costs Page F- 18 A.3 Dividends paid and proposed Page F- 18 A.4 Earnings per share Page F- 18 A.5 Taxes Page F- 19 Key financial and capital risks in this section Commodity price risk management The Group’s revenue is exposed to commodity price fluctuations through the sale of hydrocarbons.

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

The Group’s management of commodity price risk includes the use of commodity derivatives to hedge its exposure (refer to Note D.6 ). The hedged exposure includes oil-linked revenue related to produced volumes and revenues derived from trading operations. Commodity derivatives are used to manage the Group’s price risk within its corporate and trading portfolios.

As at the reporting date, the Group held commodity hedging financial instruments with a net asset carrying value of $176 million ( 2024 : $27 million ) exposed to commodity price risk.

An increase in relevant commodity prices of 10% would decrease the instruments’ carrying value by $77 million , the effect of which would be recognised within reserves and/or the income statement in accordance with hedge accounting application. A 10% decrease would have the same but opposite effect.

This analysis assumes that all other variables remain constant (including the price on underlying physical exposures). Foreign exchange risk management Foreign exchange risk arises from future commitments, financial assets and financial liabilities that are not denominated in US dollars. The majority of the Group’s revenue is denominated in US dollars.

The Group is exposed to foreign currency risk arising from operating and capital expenditure incurred in currencies other than US dollars, particularly Australian dollars. The Group’s management of foreign exchange risk relating to capital expenditure includes the use of forward exchange contract derivatives to hedge its exposure (refer to Note D.6 ).

The Group entered into foreign exchange forward contracts to fix the Australian dollar to US dollar exchange rate in relation to a portion of the Australian dollar denominated capital expenditure incurred or expected to be incurred under the Scarborough development (refer to Note D.6 ).

Through the use of foreign exchange forward contracts, the Group managed its Australian dollar to US dollar exchange rate exposure in relation to the Australian dollar denominated dividend payments.

As at the reporting date, the Group held hedging foreign currency financial instruments with a net asset carrying value of $19 million ( 2024 : net liability carrying value of $45 million ) exposed to foreign exchange risk. Measuring the exposure to foreign exchange risk is achieved by regularly monitoring and performing sensitivity analysis on the Group’s financial position.

A reasonably possible change in the exchange rate of the US dollar to the Australian dollar ( +7.0% / -7.0% ( 2024 : +10.0% / -10.0% )), with all other variables held constant, would not have a material impact on the Group’s equity or the income statement.

Refer to Notes C.1 , C.2 , D.2 , D.4 and D.7 for details of the denominations of cash and cash equivalents, interest-bearing liabilities, receivables, payables and lease liabilities held at 31 December 2025 . F-14 Table of Contents Notes to the financial statements A.

Earnings for the period for the year ended 31 December 2025 A.1 Segment revenue and expenses Operating segment information The Group’s operating segments have been determined based on the internal reports reviewed by the Chief Executive Officer, who is the Chief Operating Decision Maker. These reports are used to assess performance and allocate resources within the business.

As the Group continues to invest in new energy and integrate these activities across its operations, changes have been made to the way financial information is presented. New energy projects that have reached a final investment decision (FID) are now reported within either the Australia or International segments, depending on their geographical location.

The Group’s disclosed operating segments have been updated to reflect this change, and the comparative information for 2024 and 2023 has been restated to ensure consistency of presentation.

The Group’s reportable operating segments are as follows: Australia: Exploration, evaluation, development, production and sale of liquefied natural gas (LNG), pipeline gas, crude oil, condensate and natural gas liquids, as well as the development, production and sale of new energy products from Australian assets that have achieved FID.

International: Exploration, evaluation, development, production and sale of LNG, pipeline gas, crude oil, condensate and natural gas liquids, and the development, production and sale of new energy products from assets located outside Australia that have achieved FID. Marketing: Marketing, shipping and trading of the Group’s oil and gas portfolio (including purchased volumes) and optimisation activities that generate incremental value.

Corporate: Comprises new energy projects that have not yet reached FID and corporate items that are not allocated to operating segments. Corporate items include revenues, expenses, assets and liabilities that are not considered part of the core operations of any segment.

Customer concentration The Group has two major customers which each respectively account for 8% and 7% of the Group’s external revenue.

The sales are generated by the Australia and Marketing operating segments ( 2024 : two major customers ; 7% and 6% generated by the Australia and Marketing operating segments and 2023 : two major customers ; 8% and 7% generated by the Australia and Marketing operating segments).

Geographical information Geographical information Revenue from external customers 1 2025 2024 2023 US$m US$m US$m Asia Pacific 7,335 8,445 9,823 Americas 2,241 2,462 2,564 Europe 3,122 2,272 1,607 Other 286 — — Consolidated 12,984 13,179 13,994 1. Revenue is attributable to geographic location based on the location of the customers.

Recognition and measurement Revenue from contracts with customers Revenue is recognised when or as the Group transfers control of products or provides services to a customer at the amount to which the Group expects to be entitled. If the consideration includes a variable component, the Group estimates the amount of the expected consideration receivable.

Variable consideration is estimated throughout the contract and is recognised to the extent that it is highly probable a significant reversal will not occur. • Revenue from sale of hydrocarbons – Revenue from the sale of hydrocarbons is recognised at a point in time when control of the product is transferred to the customer.

Revenue from take or pay contracts is recorded as unearned revenue until the product has been drawn by the customer (transfer of control), at which time it is recognised in earnings. • Other operating revenue – Revenue earned from LNG processing and other services is recognised over time as the services are rendered.

Expenses • Royalties, excise and levies – Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group’s entitlement to physical production. • Depreciation and amortisation - Refer to Note B.3 . • Impairment and impairment reversals - Refer to Note B.4 . • Leases - Refer to Note D.7 . • Employee benefits - Refer to Note E.2 .

F-15 Table of Contents Notes to the financial statements A. Earnings for the period for the year ended 31 December 2025 Significant estimates and judgements (a) Revenue from contracts with customers The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices.

Judgement is also used to determine if it is highly probable that a significant reversal will not occur in relation to revenue recognised during open pricing periods in LNG contracts. The Group estimates variable consideration based on available information from contract negotiations and market indicators.

For the year ended 31 December 2025 Australia International Marketing Corporate Consolidated 2025 2025 2025 2025 2025 US$m US$m US$m US$m US$m Liquified natural gas 4,800 - 1,160 - 5,960 Pipeline gas 1,160 164 - - 1,324 Crude oil and condensate 1,313 3,872 72 - 5,257 Natural gas liquids 171 33 37 - 241 Revenue from sale of hydrocarbons 7,444 4,069 1,269 - 12,782 Intersegment revenue 1 (120) - 120 - - Processing and services revenue 177 - - - 177 Shipping and other revenue - - 25 - 25 Other revenue 57 - 145 - 202 Operating revenue 2 7,501 4,069 1,414 - 12,984 Production costs (1,030) (523) - - (1,553) Royalties, excise and levies (251) (50) - - (301) Insurance (37) (19) - (23) (79) Inventory movement 44 (11) - - 33 Costs of production (1,274) (603) - (23) (1,900) Property, plant and equipment depreciation (2,405) (2,570) - (68) (5,043) Shipping and direct sales costs (75) (87) (103) - (265) Trading costs 3 (217) - (928) - (1,145) Other hydrocarbon costs (29) - - - (29) Other (22) (44) - - (66) Other cost of sales (343) (131) (1,031) - (1,505) Cost of sales (4,022) (3,304) (1,031) (91) (8,448) Gross profit/(loss) 3,479 765 383 (91) 4,536 Other income 4 207 364 18 359 948 Exploration and evaluation expenditure 5 (34) (145) - - (179) Amortisation of permit acquisitions - (5) - - (5) Write-offs - (4) - - (4) Exploration and evaluation (34) (154) - - (188) General, administration and other costs (62) (67) (3) (350) (482) Amortisation of intangible assets - - - (22) (22) Depreciation of lease assets (33) (16) (78) (48) (175) Restoration movement 6 (379) 34 - 5 (340) Other 7 (60) (90) (12) (83) (245) Other costs (534) (139) (93) (498) (1,264) Other expenses (568) (293) (93) (498) (1,452) Impairment losses - - - (143) (143) Profit/(loss) before tax and net finance costs 3,118 836 308 (373) 3,889 1.

Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment’s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 2. Operating revenue includes revenue from contracts with customers of $12,959 million and sub-lease income of $25 million disclosed within shipping and other revenue. 3.

In 2025 traded LNG and condensate purchased from Australia operations Joint Venture Partners have been presented in the Australia segment with the corresponding trading revenue presented in the Australia segment, whereas in 2024 this was presented in the Marketing segment. 4.

Includes a $137 million unrealised fair value gain on embedded derivatives, $204 million of net gains on hedging activities, fees a nd recoveries and other income not associated with the ongoing operations of the business. The International segment includes $161 million from the gain on the sale of the Greater Angostura assets to Perenco. 5.

Includes seismic and general permit activities and other exploration costs. Exploration and evaluation expenditure includes $ 17 million of evaluation expenditure. 6. Includes updated closure cost estimates and economic assumptions at closed sites. 7. Includes items not associated with the ongoing operations of the business including foreign exchange losses. F-16 Table of Contents Notes to the financial statements A.

Earnings for the period for the year ended 31 December 2025 For the year ended 31 December 2024 Australia International Marketing Corporate Consolidated 2024 2024 2024 2024 2024 US$m US$m US$m US$m US$m Liquified natural gas 5,361 - 1,040 - 6,401 Pipeline gas 1,119 230 - - 1,349 Crude oil and condensate 1,668 3,143 76 - 4,887 Natural gas liquids 196 39 71 - 306 Revenue from sale of hydrocarbons 8,344 3,412 1,187 - 12,943 Intersegment revenue 1 (23) (7) 30 - - Processing and services revenue 220 - - - 220 Shipping and other revenue - - 16 - 16 Other revenue 197 (7) 46 - 236 Operating revenue 2 8,541 3,405 1,233 - 13,179 Production costs (1,051) (528) - - (1,579) Royalties, excise and levies (349) (23) - - (372) Insurance (27) (9) - 11 (25) Inventory movement 55 29 - - 84 Costs of production (1,372) (531) - 11 (1,892) Property, plant and equipment depreciation (2,621) (1,848) - (54) (4,523) Shipping and direct sales costs (89) (86) (130) - (305) Trading costs (4) - (691) - (695) Other hydrocarbon costs (51) - - - (51) Other (22) (7) - (6) (35) Other cost of sales (166) (93) (821) (6) (1,086) Cost of sales (4,159) (2,472) (821) (49) (7,501) Gross profit/(loss) 4,382 933 412 (49) 5,678 Other income 3 568 50 23 (17) 624 Exploration and evaluation expenditure 4 (44) (276) - - (320) Amortisation of permit acquisitions - (8) - - (8) Write-offs (3) (6) - - (9) Exploration and evaluation (47) (290) - - (337) General, administration and other costs - - - (445) (445) Amortisation of intangible assets - - - (21) (21) Depreciation of lease assets (58) (1) (101) (50) (210) Restoration movement (176) 6 - (29) (199) Other 5 (55) (97) 93 (517) (576) Other costs (289) (92) (8) (1,062) (1,451) Other expenses (336) (382) (8) (1,062) (1,788) Impairment losses - - - - - Profit/(loss) before tax and net finance costs 4,614 601 427 (1,128) 4,514 1.

Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment’s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs. 2. Operating revenue includes revenue from contracts with customers of $13,163 million and sub-lease income of $16 million disclosed within shipping and other revenue. 3.

Item 5.A Operating Results ” of this 2025 Form 20-F.

Disclosures regarding oil and gas operations The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference: • Drilling and other exploratory and development activities in Section 6.3: Additional disclosures on page 257 • Present development activities continuing as of 31 December 2025 in Section 6.3: Additional disclosures on page 257 • Oil and gas properties, wells, operations and acreage in Section 6.3: Additional disclosures on pages 258 • Delivery commitments in Section 6.3: Additional disclosures on page 258 • Production in Section 6.3: Additional disclosures on page 259.

RESERVES STATEMENT About the Reserves Statement This Reserves Statement presents Woodside’s proved oil and gas reserves, as of 31 December 2025 , in accordance with the regulations of the United States Securities and Exchange Commission (SEC). 1 Unless stated otherwise, the following apply to this Reserves Statement: The effective date for reserves estimates is 31 December 2025 .

Estimates have been prepared in accordance with the reserves definitions of Rules 4-10(a) of SEC Regulations S-X and are calculated using SEC-compliant economic assumptions and pricing. Production is reported for the period from 1 January 2025 to 31 December 2025 . Reserves and production stated are Woodside’s net share and inclusive of fuel consumed in operations. See “Methodology” below.

All numbers are internal estimates produced by Woodside. Estimates of reserves should be regarded only as estimates that may change over time as additional information and production history becomes available.

See “Forward-Looking Statements”. 2025 proved reserves Woodside produced a total of 211.4 MMboe in 2025 , including 197.7 MMboe produced for sale and 13.7 MMboe of production consumed as fuel in operations. 2 At 31 December 2025 , Woodside’s proved (1P) reserves were 1,882.1 MMboe (Table 1, 2).

As a result of the divestment of the Greater Angostura assets in Trinidad and Tobago, Woodside’s proved developed reserves decreased by 16.3 MMboe (shown as acquisitions and divestments in Table 2).

In 2025 , excluding divestments and production, Woodside's proved reserves increased by 134.1 MMboe (shown as extensions and discoveries, revisions of previous estimates, and improved recovery in Table 2) .

Key drivers for these changes included: • production driven technical updates at Greater Pluto in Australia contributed to proved reserves increases of 25.6 MMboe (included as revisions of previous estimates in Table 2) • field performance, technical updates and the final investment decision on Greater Western Flank 4 (GWF4) at North West Shelf in Australia contributed to proved reserves increases of 34.6 MMboe . 3 Of these changes, the final investment decision on GWF4 resulted in proved reserves increases of 16.4 MMboe (included as extensions and discoveries, and revisions of previous estimates in Table 2) 17 Table of Contents • field performance, technical updates and the final investment decision on Turrum Phase 3 at Bass Strait in Australia resulted in proved reserves increases of 17.4 MMboe (included as extensions and discoveries, and revisions of previous estimates in Table 2) • field performance and technical updates at several Exmouth fields in Australia contributed to proved reserves increases of 12.2 MMboe • field performance and technical updates at Sangomar in Senegal contributed to proved reserves increases of 27.9 MMboe .

Of these changes, reservoir performance supported the booking of water injection volumes in the S400 reservoirs at Sangomar, resulting in proved reserves increases of 7.7 MMboe (included as improved recovery in Table 2) • final investment decision on a water injection expansion project at Atlantis in the United States resulted in proved reserves increases of 7.6 MMboe (included as improved recovery in Table 2).

In addition, field performance and technical updates across several Gulf of America fields in the United States contributed to additional proved reserves increases of 9.1 MMboe .

The transfers of undeveloped to developed reserves associated with successful start-up of development wells in Australia and in the United States are discussed in the 2025 proved undeveloped reserves section of this Reserves Statement.

Table 1: Woodside’s proved reserves 4,5,6 overview (net Woodside share, as at 31 December 2025 ) Natural gas 7 Bcf 10 NGLs 8 MMbbl 11 Oil & condensate MMbbl Total 9 MMboe 12 Fuel included in total MMboe Proved 13 developed 14 and undeveloped 15 7,637.1 18.0 524.3 1,882.1 170.3 Proved developed 1,740.7 15.3 322.9 643.6 52.3 Proved undeveloped 5,896.4 2.7 201.4 1,238.5 118.0 Small differences are due to rounding 2024 proved reserves Woodside produced a total of 206.3 MMboe in 2024, including 192.7 MMboe produced for sale and 13.6 MMboe of production consumed as fuel in operations. 2 At 31 December 2024, Woodside’s remaining proved (1P) reserves were 1,975.7 MMboe (Table 2).

As a result of completion of the sale of 10.0% and 15.1% non-operating participating interest in the Scarborough Joint Venture in Australia, Woodside’s proved undeveloped reserves decreased by 323.0 MMboe (shown as acquisitions and divestments in Table 2, 3). In 2024, revisions of previous estimates and extensions resulted in proved reserves increases of 54 .9 MMboe .

Key drivers for these changes included: • post start-up field performance at Sangomar in Senegal contributed to a proved reserves increase of 16.2 MMboe • performance based revisions, technical updates and the final investment decision on a development opportunity in North West Shelf in Australia contributed to a proved reserves increase of 13.4 MMboe 3 • performance and technical updates at Bass Strait and multiple Exmouth fields in Australia contributed to a proved reserves increase of 20.5 MMboe • final investment decision on Xena-3 in Greater Pluto in Australia resulted in extensions of proved reserves of 7.1 MMboe • initial field performance and technical updates at Mad Dog Phase 2 in the United States contributed to a proved reserves decrease of 8.1 MMboe The transfers of undeveloped to developed reserves associated with successful start-up of Sangomar, start-up of development wells in the United States and start-up of two compression projects in Australia are discussed in the 2024 proved undeveloped reserves section of this Reserves Statement. 2023 proved reserves Woodside produced a total of 201.0 MMboe in 2023, including 186.1 MMbo e produced for sale and 15.0 MMboe o f production consumed as fuel in operations. 2 At 31 December 2023, Woodside’s remaining proved reserves were 2,450.1 MMboe (Table 2).

The first-time booking of reserves at Trion in Mexico and Mad Dog Southwest in the United States increased proved reserves by 204.1 MMboe (shown as extensions and discoveries in Table 2), of which: • final investment decision and regulatory approval of the field development plan at Trion in August 2023 increased proved reserves b y 194.8 MMboe 16 ; a nd 18 Table of Contents • approval of the Mad Dog Southwest Extension project increased proved reserves b y 9.3 MMboe.

Revisions of previous estimates in 2023 resulted in a net increase of 61.8 MMboe for proved reserves.

Key drivers for these revisions included: • asset optimisation, including injector to producer conversions, and field performance at Angostura and Ruby in Trinidad and Tobago contributed to a proved reserves increase of 13.0 MMboe • improved overall field performance and technical updates in North West Shelf increased proved reserves by 49.7 MMboe • performance based revisions at Shenzi decreased proved reserves b y 13.4 MMboe.

The transfers of undeveloped reserves to developed reserves are discussed in the 2023 proved undeveloped reserves section of this Reserves Statement. Methodology Reserves estimates have not been adjusted for risk.

Proved reserves are estimated and reported on a net interest basis, excluding royalties owned by others, in accordance with the SEC regulations, and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X.

As defined by the SEC, proved reserves are those quantities of crude oil, condensate, natural gas, and natural gas liquids that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, operating contracts, and government regulations.

Unless evidence indicates that renewal of existing operating contracts is reasonably certain, estimates of economically producible reserves reflect only the period before the contracts expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time.

Proved reserves are estimated by reference to available well and reservoir information, including but not limited to well logs, well test data, core data, production and pressure data, geologic data, seismic data and, in some cases, similar data from analogous, producing reservoirs.

A wide range of engineering and geoscience methods, including performance analysis, numerical simulation, well analogues and geologic studies, have been used to develop high confidence in estimated quantities. Governance and assurance Woodside has several processes designed to provide assurance for reserves reporting, including its Reserves and Resources Policy and Standards, reserves estimation guidance, annual staff training, and minimum experience levels.

In addition, Woodside has a dedicated and independent Corporate Reserves Team (CRT) that provides oversight and assurance of the reserves assessments and reporting processes. Reserves are estimated by staff in teams directly responsible for development and production activities. These individuals are trained in the fundamentals of reserves reporting and are approved by the CRT on an annual basis.

Reserves estimates are reviewed annually by the CRT to ensure technical quality, adherence to Woodside’s Reserves and Resources Policy and Standards and compliance with SEC reporting requirements. All reserves are reviewed and approved by Woodside’s Qualified Petroleum Reserves Evaluator and approved by senior management and Woodside’s Board prior to public reporting.

Qualified Petroleum Reserves Evaluator statement The estimates of petroleum reserves are based on and fairly represent information and supporting documentation prepared by, or under the supervision of Mr. Benjamin Ziker, Woodside’s Vice President Reserves and Subsurface, who is a full-time employee of the company and a member of the Society of Petroleum Engineers.

The Reserves Statement as a whole has been approved by Mr. Ziker. Mr.

Ziker’s qualifications include a Bachelor of Science (Chemical Engineering) from Rice University (Houston, Texas, USA), and 27 years of relevant experience. 19 Table of Contents Table 2: Proved developed and undeveloped reserves reconciliation (net Woodside share, three years ending 31 December 2025 ) Australia International 17 Total Natural gas NGLs Oil & condensate Total Natural gas NGLs Oil & condensate Total Natural gas NGLs Oil & condensate Total Bcf MMbbl MMbbl MMboe Bcf MMbbl MMbbl MMboe Bcf MMbbl MMbbl MMboe Reserves as at 31 December 2022 10,455.8 17.3 79.7 1,931.4 327.8 9.0 387.3 453.8 10,783.6 26.3 467.0 2,385.2 Acquisitions and divestments 18 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Extensions and discoveries 19 0.0 0.0 0.0 0.0 177.9 0.4 172.5 204.1 177.9 0.4 172.5 204.1 Revisions of previous estimates 20 308.6 2.2 15.4 71.8 35.6 (0.6) (15.6) (9.9) 344.3 1.6 (0.2) 61.8 Production (738.4) (5.9) (22.7) (158.1) (70.6) (1.4) (29.2) (43.0) (809.0) (7.3) (51.8) (201.0) Reserves as at 31 December 2023 10,026.1 13.6 72.5 1,845.1 470.7 7.4 515.0 605.0 10,496.9 21.0 587.5 2,450.1 Acquisitions and divestments (1,841.3) 0.0 0.0 (323.0) 0.0 0.0 0.0 0.0 (1,841.3) 0.0 0.0 (323.0) Extensions and discoveries 37.7 0.0 0.5 7.1 0.0 0.0 0.0 0.0 37.7 0.0 0.5 7.1 Revisions of previous estimates 108.6 4.3 11.1 34.4 25.8 0.2 8.6 13.4 134.4 4.5 19.8 47.9 Production (714.2) (5.1) (20.7) (151.1) (63.5) (1.6) (42.5) (55.2) (777.8) (6.7) (63.2) (206.3) Reserves as at 31 December 2024 7,616.9 12.8 63.4 1,412.5 433.0 6.0 481.2 563.2 8,049.9 18.9 544.6 1,975.7 Acquisitions and divestments 0.0 0.0 0.0 0.0 (91.9) 0.0 (0.2) (16.3) (91.9) 0.0 (0.2) (16.3) Extensions and discoveries 75.6 1.1 3.4 17.7 0.0 0.0 0.0 0.0 75.6 1.1 3.4 17.7 Revisions of previous estimates 341.9 3.0 9.1 72.1 (13.4) 0.2 31.1 29.0 328.5 3.3 40.2 101.1 Improved recovery 21 0.0 0.0 0.0 0.0 3.7 0.5 14.3 15.4 3.7 0.5 14.3 15.4 Production (684.1) (4.1) (18.7) (142.8) (44.5) (1.6) (59.1) (68.5) (728.6) (5.7) (77.8) (211.4) Reserves as at 31 December 2025 22 7,350.2 12.8 57.1 1,359.5 286.9 5.1 467.2 522.7 7,637.1 18.0 524.3 1,882.1 Fuel included in 31 December 2025 reserves 843.4 0.8 0.0 148.8 122.6 0.0 0.0 21.5 966.0 0.8 0.0 170.3 Proved developed and undeveloped reserves Proved developed reserves as at 31 December 2022 2,722.6 16.7 73.3 567.6 202.5 5.9 161.0 202.4 2,925.1 22.5 234.3 770.0 as at 31 December 2023 2,361.3 12.6 67.9 494.8 220.8 6.1 198.0 242.8 2,582.1 18.7 266.0 737.7 as at 31 December 2024 1,748.5 12.4 58.4 377.6 246.5 5.0 281.0 329.2 1,995.0 17.4 339.4 706.8 as at 31 December 2025 1,641.6 11.2 51.0 350.2 99.0 4.1 272.0 293.4 1,740.7 15.3 322.9 643.6 Proved undeveloped reserves as at 31 December 2022 7,733.2 0.7 6.4 1,363.8 125.2 3.1 226.3 251.4 7,858.5 3.8 232.8 1,615.2 as at 31 December 2023 7,664.9 1.0 4.6 1,350.3 249.9 1.3 317.0 362.2 7,914.7 2.3 321.6 1,712.5 as at 31 December 2024 5,868.4 0.4 5.0 1,034.9 186.5 1.1 200.2 234.0 6,054.9 1.5 205.2 1,268.9 as at 31 December 2025 5,708.5 1.6 6.2 1,009.3 187.9 1.1 195.2 229.2 5,896.4 2.7 201.4 1,238.5 Small differences are due to rounding 2025 proved undeveloped reserves At 31 December 2025 , Woodside’s remaining proved undeveloped reserves were 1,238.5 MMboe, representing a decrease of 30.4 MMboe from the 1,268.9 MMboe as at 31 December 2024 (Table 3).

In 2025 , 67.2 MMboe of proved undeveloped reserves were transferred to proved developed reserves with the start-up of development wells at Greater Pluto ( 47.3 MMboe ), Bass Strait ( 4.1 MMboe ), North West Shelf ( 1.2 MMboe ), and Mad Dog and Atlantis ( 14.6 MMboe ).

Technical updates, performance based revisions and development plan changes in Australia and the United States resulted in revisions of previous estimates, contributing to a 11.5 MMboe increase in proved undeveloped reserves.

Compensation The information set forth under the following headings of the 2025 Ann ual Report is incorporated herein by reference: • Section 4.3: Remuneration Report from pages 146-175. See Note E.2 in “Item 18. Financial Statements” of this 2025 Form 20-F. C.

Related Party Transactions The information set forth under the following headings of the 2025 Annual Report is incorporated herein by reference: • Section 4.3: Remuneration Report from pages 146-175. See Note E.3 in “Item 18. Financial Statements” of this 2025 Form 20-F. C. Interests of Experts and Counsel Not applicable.

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS 36 A. Major shareholders 36 B. Related Party Transactions 36 C. Interests of Experts and Counsel 36 ITEM 8. FINANCIAL INFORMATION 36 A. Consolidated Statements and Other Financial Information 37 B. Significant Changes 37