EX-99.1 2 d18162dex991.htm EX-99.1

Exhibit 99.1

HALF-YEAR REPORT FOR PERIOD ENDED 30 JUNE 2025

ASX: WDS | NYSE: WDS

Tuesday, 19 August 2025

Strong global portfolio delivers value and growth

Strong first half performance

| • |  | Determined a fully franked interim dividend of 53 US cents per share (cps).

| • |  | Delivered production of 548 Mboe/d (99.2 MMboe) and reduced unit production costs to $7.7/boe.1

| • |  | Achieved strong progress on major projects with Scarborough 86%, Trion 35%, and Beaumont New Ammonia 95% complete.

| • |  | Positioned to unlock future value through the final investment decision (FID) to develop the Louisiana LNG Project.

| • |  | Completed the sell-down of a 40% interest in Louisiana LNG Infrastructure LLC to Stonepeak.

| • |  | On track to meet Woodside’s net equity Scope 1 and 2 greenhouse gas emissions reduction target of 15% by 2025.2

Achieving operational excellence

| • |  | Recorded over one million work hours in Sangomar’s first year with no recordable injuries.

| • |  | Maintained exceptional performance from Sangomar with 100 Mbbl/d produced (100% basis, 80 Mbbl/d Woodside share).

| • |  | Achieved strong operated LNG plant performance with combined reliability of 96%.

| • |  | Contributed approximately 8% of EBIT from our marketing and trading capability.

Strong financial outcomes and capital discipline

| • |  | Achieved net profit after tax of $1,316 million.

| • |  | Delivered strong EBITDA of $4,600 million from underlying base business.1

| • |  | Delivered operating cash flow of $3,339 million.

| • |  | Disciplined capital management resulted in strong liquidity of $8,430 million and gearing of 19.5%, within the target range.1

| • |  | Issued $3,500 million of senior unsecured bonds in the US market, with the book heavily oversubscribed.

Comparative performance

|  |  |  |  | H1 2025 |  |  | H1 2024 |  |  | Change % |  |  |  |
Operating revenue |  |  | $ million |  |  |  | 6,590 |  |  |  | 5,988 |  |  |  | 10% |  |  |  |  |
Underlying NPAT1 |  |  | $ million |  |  |  | 1,247 |  |  |  | 1,632 |  |  |  | (24%) |  |  |  |  |
Free cash flow1,3 |  |  | $ million |  |  |  | 272 |  |  |  | 740 |  |  |  | (63%) |  |  |  |  |
Average realised price1 |  |  | US$/boe |  |  |  | 61.8 |  |  |  | 62.6 |  |  |  | (1%) |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  | 2025 full-year guidance |
|  |  |  |  |  |  |  |  |  |  |  |  |  | Prior |  |  | Current |
Production4 |  |  | MMboe |  |  |  | 99.2 |  |  |  | 89.3 |  |  |  | 11% |  |  |  | 186 - 196 |  |  |  | 188 - 195 |
Gas hub exposure5 |  |  | % of produced |  |  |  | 24.2 | % |  |  | 34.0 | % |  |  | (9.8%) |  |  |  | 28 - 35 |  |  |  | No change |
Unit production cost1 |  |  | $/boe |  |  |  | 7.7 |  |  |  | 8.3 |  |  |  | (7%) |  |  |  | 8.5 - 9.2 |  |  |  | 8.0 - 8.5 |
Property, plant and equipment depreciation and amortisation |  |  | $ million |  |  |  | 2,541 |  |  |  | 1,893 |  |  |  | 34% |  |  |  | 4,500 - 5,000 |  |  |  | 4,700 - 5,000 |
Exploration expenditure1 |  |  | $ million |  |  |  | 86 |  |  |  | 112 |  |  |  | (23%) |  |  |  | 200 |  |  |  | No change |
Payments for restoration |  |  | $ million |  |  |  | 565 |  |  |  | 325 |  |  |  | 74% |  |  |  | 700 - 1,000 |  |  |  | No change |
Capital expenditure (excluding Louisiana LNG)1 |  |  | $ million |  |  |  | 1,773 |  |  |  | 2,365 |  |  |  | (25%) |  |  |  | 4,500 - 5,000 |  |  |  | 4,000 - 4,500 |
Net capital expenditure on Louisiana LNG1,6 |  |  | $ million |  |  |  | 785 |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  |  |

This page and the following 70 pages comprise the half year end information given to the ASX under Listing Rule 4.2A and should be read in conjunction with Woodside’s Annual Report 2024.

1 | These are alternative performance measures which are non-IFRS measures that are unaudited. Refer to Alternative Performance Measures on pages 55 – 57 and Non-IFRS Measures on page 63 for more information.

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

3 | Cash flow from operating activities less cash flow from investing activities, adjusted for the capital contribution from Stonepeak for the development of Louisiana LNG.

4 | Includes production of 98.6 MMboe from Woodside reserves and 0.6 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

5 | Gas hub indices include Japan Korea Marker (JKM), TTF and National Balancing Point (NBP). It excludes Henry Hub.

6 | Capital additions on Louisiana LNG adjusted for the cash contribution from Stonepeak.

1 | Half-Year Report 2025 |  |

Summary

Woodside delivered strong half-year production of 548 thousand barrels oil equivalent per day (99.2 million barrels of oil equivalent total) and reported a half-year net profit after tax (NPAT) of $1,316 million. Underlying NPAT was $1,247 million, compared to $1,632 million in the corresponding period in 2024. Operating revenue rose 10% year-on-year to $6,590 million.

The directors have determined a fully franked interim dividend of 53 US cents per share (cps), representing an 80% payout ratio of underlying NPAT, and an annualised yield of 6.9%.7

CEO Meg O’Neill said the results demonstrate Woodside’s world-class business is rewarding shareholders with strong dividends today, while ensuring the balance sheet strength to deliver major growth projects.

“Strong underlying performance of our assets, our robust financial performance, and a focus on disciplined capital management have enabled us to maintain our interim dividend payout ratio at the top end of the payout range.

“The outstanding performance of our high-quality assets over the first half has continued to support safe, reliable operations. This has been complemented by a strong focus on cost management, resulting in a reduction in our unit production costs. We have also taken a disciplined approach to future growth and reduced spend on new energy and exploration as we prioritise delivering sanctioned projects.

“A highlight was the ongoing exceptional performance of our Senegal Project, which marked one year since first oil in June 2024. In just the first half of 2025, Sangomar has generated revenue nearing $1 billion, with gross production of 100 thousand barrels per day. Proved reserves have also been added, following positive early field performance. Sangomar’s success has showcased Woodside’s world-class project execution and operational capabilities.

“Our excellence in project delivery was further demonstrated in the first half. The Scarborough Energy Project in Western Australia is 86% complete and targeting first LNG cargo in the second half of 2026. Our Trion Project offshore Mexico is 35% complete and targeting first oil in 2028.

“In April we took a final investment decision on Louisiana LNG, positioning Woodside as a global LNG powerhouse able to meet growing customer demand in the Pacific and Atlantic Basins. The Project’s compelling value proposition was reinforced with key infrastructure, offtake, and gas supply agreements signed with high-quality partners. This included completion of the sell-down of a 40% interest in Louisiana LNG Infrastructure LLC to Stonepeak for $5.7 billion, which will see Stonepeak contribute 75% of the expected Project capital expenditure over both 2025 and 2026.

“We continue to receive strong interest from high-quality potential partners as we explore further sell-downs of Louisiana LNG. This highlights the distinct value Woodside offers, with our business model well positioned to deliver compelling long-term value in the US LNG market, further differentiated by our extensive LNG experience, portfolio marketing capabilities, and balance sheet strength.

“Further strengthening our operational capabilities and subsequent to the period, we agreed to assume operatorship of the Bass Strait assets offshore Victoria from ExxonMobil. This agreement creates flexibility for future development opportunities through existing infrastructure.

“Safety remains at the forefront of everything we do. We marked significant safety milestones across our global portfolio over the period including 100,000 hours worked across two major turnarounds at the North West Shelf Project in Western Australia with no lost-time injuries. Our outstanding safety record at Sangomar continued, with no recordable injuries during the Project’s first year of operations.”

7 | Calculated based on Woodside’s closing share price on 30 June 2025 of A$23.63 ($15.45) and a USD:AUD exchange rate of 0.6537.

2 | Half-Year Report 2025 |  |

Financial summary

Key metrics

|  |  |  |  | H1 2025 |  |  | H1 2024 |  |  | Change % |
Operating revenue |  | $ | million |  |  |  | 6,590 |  |  |  | 5,988 |  |  |  | 10% |
EBITDA excluding impairment8 |  | $ | million |  |  |  | 4,600 |  |  |  | 4,371 |  |  |  | 5% |
EBIT8 |  | $ | million |  |  |  | 1,817 |  |  |  | 2,362 |  |  |  | (23%) |
Net profit after tax (NPAT)9,10 |  | $ | million |  |  |  | 1,316 |  |  |  | 1,937 |  |  |  | (32%) |
Underlying NPAT8 |  | $ | million |  |  |  | 1,247 |  |  |  | 1,632 |  |  |  | (24%) |
Net cash from operating activities |  | $ | million |  |  |  | 3,339 |  |  |  | 2,393 |  |  |  | 40% |
Capital expenditure8,11 |  | $ | million |  |  |  | 2,558 |  |  |  | 2,365 |  |  |  | 8% |
Exploration expenditure8,12 |  | $ | million |  |  |  | 86 |  |  |  | 112 |  |  |  | (23%) |
Free cash flow8,13 |  | $ | million |  |  |  | 272 |  |  |  | 740 |  |  |  | (63%) |
Average realised price8 |  |  | US$/boe |  |  |  | 61.8 |  |  |  | 62.6 |  |  |  | (1%) |
Dividends distributed |  | $ | million |  |  |  | 1,006 |  |  |  | 1,310 |  |  |  | (23%) |
Interim dividend declared |  |  | US cps |  |  |  | 53 |  |  |  | 69 |  |  |  | (23%) |
Key ratios |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Earnings |  |  | US cps |  |  |  | 69.4 |  |  |  | 102.2 |  |  |  | (32%) |
Gearing8 |  |  |  | % |  |  | 19.5 |  |  |  | 13.3 |  |  |  | 6.2% |
Production volumes14,15 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas |  |  | MMboe |  |  |  | 58.2 |  |  |  | 60.9 |  |  |  | (4%) |
Liquids |  |  | MMboe |  |  |  | 41.0 |  |  |  | 28.4 |  |  |  | 44% |
Total |  |  | MMboe |  |  |  | 99.2 |  |  |  | 89.3 |  |  |  | 11% |
Production volumes per day15 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas |  |  | MMscf/d |  |  |  | 1,833 |  |  |  | 1,907 |  |  |  | (4%) |
Liquids |  |  | Mbbl/d |  |  |  | 226 |  |  |  | 156 |  |  |  | 45% |
Total |  |  | Mboe/d |  |  |  | 548 |  |  |  | 491 |  |  |  | 12% |
Sales volumes15 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas16 |  |  | MMboe |  |  |  | 63.7 |  |  |  | 64.9 |  |  |  | (2%) |
Liquids |  |  | MMboe |  |  |  | 40.9 |  |  |  | 28.9 |  |  |  | 42% |
Total |  |  | MMboe |  |  |  | 104.6 |  |  |  | 93.8 |  |  |  | 12% |
Sales volumes per day15 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas16 |  |  | MMscf/d |  |  |  | 2,006 |  |  |  | 2,032 |  |  |  | (1%) |
Liquids |  |  | Mbbl/d |  |  |  | 226 |  |  |  | 159 |  |  |  | 42% |
Total |  |  | Mboe/d |  |  |  | 578 |  |  |  | 516 |  |  |  | 12% |

8 | This is an alternative performance measure which is a non-IFRS measure that is unaudited. Refer to Alternative Performance Measures on pages 55 – 57 for a reconciliation for these measures to Woodside’s financial statements and Non-IFRS Measures on page 63 for more information.

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

10 | The global operations effective income tax rate (EITR) of 21.0% (2024: 6.9%) is calculated as the Group’s income tax expense divided by profit before income tax. The underlying EITR is 30.9% when excluding the recognition of a $182 million deferred tax asset as a result of the Louisiana LNG FID and the $113 million post-tax H2OK impairment loss.

11 | Capital additions on property, plant and equipment and evaluation capitalised. Excludes exploration capitalised and adjusted for the capital contribution received from Stonepeak for the development of Louisiana LNG.

12 | Exploration and evaluation expenditure less amortisation costs and prior year exploration expense written off.

13 | Cash flow from operating activities less cash flow from investing activities, adjusted for the capital contribution from Stonepeak for the development of Louisiana LNG.

14 | Includes production of 98.6 MMboe from Woodside reserves and 0.6 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

15 | The conversion factors used throughout this report are set out on page 60, unless otherwise stated. Sales volumes differ from production volumes primarily due to the timing of liftings and the exclusion of third-party purchased volumes.

16 | Sales volumes exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales. The 2024 comparative sales volumes and sales volumes per day have been restated by 0.1 MMboe and 3 MMscf/d respectively to exclude the periodic adjustments.

3 | Half-Year Report 2025 |  |

Appendix 4D

Results for announcement to the market

More information is available on page 54.

|  |  |  |  |  |  |  |  |  |  | US$ million |
Revenue from ordinary activities |  |  | Increased |  |  |  | 10 | %17 |  |  | to |  |  |  | 6,590 |
Profit from ordinary activities after tax attributable to members |  |  | Decreased |  |  |  | 32 | %17 |  |  | to |  |  |  | 1,316 |
Net profit for the period attributable to members |  |  | Decreased |  |  |  | 32 | %17 |  |  | to |  |  |  | 1,316 |
Interim dividend - fully franked |  |  | 53 US cps H1 2025 |
Record date for determining entitlements to the dividend |  |  | 29 August 2025 |

Net profit after tax reconciliation

The following table summarises the variance between the H1 2024 and H1 2025 results for the contribution of each line item to NPAT.

|  |  | US$m |  |  | Primary reasons for variance
2024 H1 reported NPAT |  |  | 1,937 |  |  |
Revenue from sale of hydrocarbons |  |  |  |  |  |
Price |  |  | (154) |  |  | Lower average realised prices.
Volume |  |  | 754 |  |  | Full period of Sangomar production primarily offset by NWS and Pluto production.
Cost of sales |  |  | (773) |  |  | Full period of Sangomar production costs, depreciation and amortisation.
Perdaman embedded derivative |  |  | 315 |  |  | Remeasurement of the Perdaman embedded derivative at fair value and accretion on contract liability.
Scarborough sell-down |  |  | (121) |  |  | Profit on 10% Scarborough sell-down to LNG Japan in 2024.
Restoration movement |  |  | (430) |  |  | Restoration provision updates primarily due to Stybarrow, Griffin and Minerva.
Impairment losses |  |  | (143) |  |  | Pre-tax impairment on the H2OK Project, following the decision to exit the Project.
Income tax and PRRT expense |  |  | (86) |  |  | Recognition of the Sangomar deferred tax asset (DTA) in 2024 offset by recognition of the Louisiana LNG DTA in 2025.
Other |  |  | 17 |  |  |
2025 H1 reported NPAT |  |  | 1,316 |  |  |
2025 H1 NPAT adjustments |  |  | (69) |  |  | Adjusted for the recognition of the Louisiana LNG DTA and the post-tax impairment on the H2OK Project.
2025 H1 underlying NPAT |  |  | 1,247 |  |  |

17 | Comparisons are to half-year ended 30 June 2024.

4 | Half-Year Report 2025 |  |

Capital management

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

Interim dividend and dividend reinvestment plan

A 2025 fully franked interim dividend of 53 US cps has been determined, representing an annualised dividend yield of 6.9%.18 The total amount of the interim dividend payment is $1,006 million which represents 80% of underlying NPAT for the first half of 2025.19

The dividend reinvestment plan remains suspended.

Liquidity and balance sheet

In H1 2025, Woodside generated $3,339 million of cash flow from operating activities and delivered positive free cash flow of $272 million, which includes the $1,870 million in proceeds received from the sell-down of Louisiana LNG Infrastructure LLC.19,20

During this period, Woodside undertook the following financing activities:

| • |  | Raised $3,500 million in the US market through a multi-tranche SEC-registered bonds issue in May 2025, consisting of $500 million three-year bonds, $1,250 million five-year bonds, $500 million seven-year bonds, and $1,250 million ten-year bonds.

| • |  | Refinanced $1,200 million of syndicated revolving facilities, with $600 million now maturing in June 2028 and the remaining $600 million in June 2030.

| • |  | Repaid a $1,000 million ten-year US bond that matured.

At the end of the period, Woodside had cash and cash equivalents of $4,880 million, liquidity of $8,430 million, and drawn debt of $12,050 million, including $800 million of ten-year bonds due in September 2026.19

Woodside’s gearing at the end of the first half was 19.5%, within our target range of 10 to 20%.19 Woodside’s gearing may at times fall outside this target range 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, both now from our strong existing business and in the future from our growth opportunities, in accordance with Woodside’s capital allocation framework.

Commodity price risk management

As at 30 June 2025, Woodside has placed oil price hedges for:

| • |  | Approximately 30 MMboe of 2025 production at an average price of $78.7 per barrel, of which approximately 58% has been delivered.

| • |  | A total of 10 MMboe of 2026 production at an average price of approximately $70.1 per barrel.

Woodside has also placed a number of hedges for Corpus Christi LNG volumes. These hedges are Henry Hub and Title Transfer Facility (TTF) commodity swaps. Approximately 94% of Corpus Christi volumes for the remainder of 2025 and 87% of 2026 volumes have been hedged.

Embedded commodity derivative

In 2023, Woodside entered a revised long-term gas sale and purchase agreement with Perdaman. A component of the selling price is linked to the price of urea, creating an embedded commodity derivative in the contract. The fair value of the embedded derivative is estimated using a Monte Carlo simulation model.

18 | Calculated based on Woodside’s closing share price on 30 June 2025 of A$23.63 ($15.45) and a USD:AUD exchange rate of 0.6537.

19 | These are alternative performance measures which are non-IFRS measures that are unaudited. Refer to Alternative Performance Measures on pages 55 – 57 and Non-IFRS Measures on page 63 for more information.

20 | Cash flow from operating activities less cash flow from investing activities, adjusted for the capital contribution from Stonepeak for the development of Louisiana LNG.

5 | Half-Year Report 2025 |  |

During the period, Woodside reassessed the embedded derivative calculation to factor in current market conditions and pricing inputs that reflect the long-term nature of the contract and associated market. Updates to the valuation model inputs include:

| • |  | 30-day average pricing assumptions and longer-term external pricing forecasts to reflect the long-term nature of the contract; and

| • |  | longer-term historical data excluding extreme volatility periods, to reflect typical market conditions.

As there is no long-term urea forward curve, TTF continues to be used as a proxy to simulate the value of the derivative over the life of the contract. For the half-year ended 30 June 2025, an unrealised gain of $162 million has been recognised through other income.

6 | Half-Year Report 2025 |  |

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 2025 was 25.5 MMboe. This was a 5.2% decrease compared with H1 2024 due to unplanned outages. This decrease was partially offset by production through the Pluto-Karratha Gas Plant Interconnector, with 5.6 MMboe of Pluto production processed at Karratha Gas Plant through the Interconnector.

In H1 2025, production from the PLA-08 well commenced, enhancing deliverability and extending plateau production. Woodside also secured secondary environmental approval enabling development of the XNA-03 well through existing infrastructure to support sustained production.

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.

Woodside Solar final investment decision and first solar energy import timing depend on securing access to proposed new common-user transmission infrastructure that will be required to transmit renewable energy to Pluto LNG and the finalisation of associated commercial agreements. The development of this infrastructure is being led by the Western Australian Government and the APA Group.

North West Shelf Project

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

Woodside’s share of production in H1 2025 was 15.1 MMboe. This was a 23.0% decrease compared with H1 2024 due to reservoir decline, planned maintenance at the Goodwyn Alpha platform, and cyclone activity.

In H1 2025, the NWS Joint Venture participants approved long lead items for the Greater Western Flank Phase 4 Project, a five-well subsea tie-back to existing NWS offshore facilities, with final investment decision targeted for the second half of 2025.

After 40 years of operations, the NWS is entering a period of production decline. KGP will progressively have increased processing ullage due to natural field decline, despite the ongoing processing of third-party gas. To optimise operations, the NWS permanently retired LNG Train 2 in H1 2025. This retirement resulted in a reduction of KGP’s production capacity from 16.9 Mtpa to 14.3 Mtpa.

Subsequent to the period, the Lambert West development well was successfully drilled, subsea infrastructure was installed and startup commenced. The Project will sustain production from the Angel Platform.

The regulatory approval processes continued to progress for the NWS Project Extension, which will support long-term operations and processing of future third-party gas resources at KGP. A proposed approval was issued by the Australian Government on the NWS Project Extension. Woodside and the NWS Joint Venture are continuing to consult with the Australian Government and assess the proposed conditions as part of the proposed approval.

Woodside is operator and holds a 33.33% participating interest.

Following completion of the asset swap agreement with Chevron announced in 2024, Woodside’s participating interest will increase to 50%. The asset swap remains on track for completion in 2026.21

21 | Completion of the transaction is subject to conditions precedent. See “Woodside simplifies portfolio and unlocks long-term value” announced 19 December 2024 for details concerning the Australian asset swap.

7 | Half-Year Report 2025 |  |

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 2025 was 6.3 MMboe. This was a 8.6% increase compared with H1 2024 due to higher reliability.

The Julimar Phase 3 Project is a four-well tie-back to the existing Julimar field production system. Subsea construction began during the half, and subsequent to the period the drilling campaign commenced. The Project is expected to startup in 2026.

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.

Following completion of the asset swap agreement with Chevron announced in 2024, Woodside will no longer have an interest in Wheatstone and Julimar-Brunello. The asset swap with Chevron remains on track for completion in 2026.22

Bass Strait

Bass Strait is located in the south east of Australia and produces 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 9.1 MMboe in H1 2025, a 7.1% increase from H1 2024 predominantly due to higher domestic gas market demand.

In H1 2025, Woodside approved investment in the Kipper 1B Project and the Turrum Phase 3 Project. Through these Projects, Woodside is expected to add more than 100 PJ of gas (Woodside share) to the south eastern Australian domestic gas market.

Subsequent to the period, Woodside agreed to assume operatorship of the Bass Strait assets from ExxonMobil Australia (ExxonMobil). Woodside has identified four potential development wells that could deliver up to 200 PJ of sales gas to the market. Under the agreement with ExxonMobil, Woodside can solely develop these opportunities through the Bass Strait infrastructure, subject to further technical maturation and a final investment decision. This potential production has been identified from within the existing contingent resource opportunity set.23 The transaction is subject to conditions precedent, including obtaining regulatory approvals, and is expected to complete in 2026.24

Woodside holds a 50% non-operating participating interest in the GBJV and a 32.5% non-operating participating interest in the KUJV. Upon completion of the agreement with ExxonMobil, Woodside will become operator, but there will be no change to Woodside’s participating interests.

Other Australian oil and gas assets

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

22 | Completion of the transaction is subject to conditions precedent. See “Woodside simplifies portfolio and unlocks long-term value” announced 19 December 2024 for details concerning the Australian asset swap.

23 | Refer to Woodside’s Reserves Statement dated 17 February 2025 for the latest disclosure on the Bass Strait reserves and resources.

24 | See the announcement “Woodside strengthens its Australian operations” released 29 July 2025 for details.

8 | Half-Year Report 2025 |  |

Following completion of the asset swap agreement with Chevron announced in 2024, Woodside’s participating interest in the Okha FPSO will increase to 66.67%. The asset swap with Chevron remains on track for completion in 2026.22

Woodside’s share of production from the FPSO assets was 3.6 MMboe in H1 2025. This was a 20.0% increase from H1 2024 primarily due to the planned five-yearly Pyrenees FPSO maintenance turnaround in H1 2024 and the Pyrenees shut-in following a subsea produced-water leak at the facility in H1 2024.

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 4.2 MMboe, a 7.7% increase from H1 2024 driven by reservoir performance and strong demand. The Macedon facility delivered approximately 16% of the Western Australian domestic gas market supply in H1 2025.

International operations

Sangomar

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

Woodside’s share of production was 14.4 MMboe in H1 2025. First oil was achieved in June 2024, marking the delivery of Senegal’s first offshore oil project.

In H1 2025, Sangomar achieved exceptional production, averaging 100 Mbbl/d (100% basis, 80 Mbbl/d Woodside share) at 98.6% reliability, with production from the field remaining at plateau for the half-year. The field is expected to come off plateau in Q3 2025.

Based on a positive response observed in the S400 oil producer wells from water injection, contingent resources were migrated to developed reserves during the period. The reserve addition was 7.1 million barrels to proved (1P) reserves and 16.1 million barrels to proved plus probable (2P) reserves, Woodside share. Subsequent to the period, strong field performance in the S500 reservoirs resulted in an additional 18.4 million barrels of proved (1P) reserves being added.25 As a result, Woodside expects Sangomar’s depreciation, depletion and amortisation (DD&A) rate to further reduce in the second half of 2025.

Sales of the initial Sangomar crude cargoes are receiving strong interest from European, North American and Asian refiners. As at 30 June 2025, 36 cargoes were loaded and delivered.

Woodside has filed an action with the High Court of Dakar and a request for arbitration with the International Centre for Settlement of Investment Disputes disputing a tax assessment of approximately $75 million from the Senegalese tax authorities.26 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 offshore oil and gas field developed through a tension leg platform located in the United States.

Woodside’s share of production in H1 2025 was 4.7 MMboe. This was an 9.6% decrease compared with H1 2024 due to natural field decline and planned maintenance downtime.

25 | Refer to Notes to petroleum reserves and resources on page 64 for details of disclaimers.

26 | Under the terms of the sale agreement between Capricorn and Woodside, Capricorn is responsible for ~50% of the total amount.

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In H1 2025, reliability at Shenzi was 98.8%. Woodside is operator and holds a 72% participating interest.

Atlantis

The Atlantis conventional offshore oil and gas development includes a semi-submersible facility and is one of the largest producing fields in the United States.

Woodside’s share of production in H1 2025 was 6.0 MMboe. This was a 17.6% increase compared with H1 2024 due to no turnaround activities, uplift from planned interventions, and new production from an infill sidetrack well.

In H1 2025, a FID was taken for the Atlantis Major Facility Expansion Project, which includes two new water injection wells and upgrades to the topsides water injection system to increase water injection capacity. First water injection is targeted for 2027.

Woodside holds a 44% non-operating participating interest.

Mad Dog

Mad Dog is an offshore conventional oil and gas field located in the United States and is currently producing from two offshore facilities, the A-Spar and Argos. The Argos facility was installed as part of the Mad Dog Phase 2 Project, an ongoing development of the southern flank of the Mad Dog field.

Woodside’s share of production in H1 2025 was 5.3 MMboe. This was a 11.7% decrease compared with H1 2024 due to natural field decline.

Infill drilling and completion activities were ongoing throughout H1 2025 in support of both the Argos and A-Spar facilities. The Mad Dog Southwest Extension was brought online subsequent to the period, with first oil achieved 25 months after finishing the appraisal well. Woodside holds a 23.9% non-operating participating interest.

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 was operator and held a 45.0% participating interest in the Angostura field and a 68.5% participating interest in the Ruby field through H1 2025.

Subsequent to the period, Woodside completed the divestment of its Greater Angostura assets to Perenco for $259 million.27 The divestment is inclusive of Woodside’s interest in the shallow water Angostura and Ruby offshore oil and gas fields, associated production facilities, and onshore terminal.

Marketing and Trading

The marketing segment’s EBIT in H1 2025 was $144 million, representing approximately 8% of total EBIT. 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 volumes.

In H1 2025, Woodside signed three long-term LNG sales and purchase agreements (SPAs). This included two long-term SPAs with Uniper for the supply of 1.0 Mtpa from Louisiana LNG LLC for up to 13 years from its commercial operations date (COD) and up to 1.0 Mtpa from Woodside’s global portfolio, commencing with Louisiana LNG’s COD and extending until 2039. Woodside also signed an SPA with China Resources Gas International Limited for supply of approximately 0.6 million tonnes of LNG per year over 15 years on a delivered basis, commencing in 2027.

Woodside signed non-binding heads of agreements with JERA Co. and PETRONAS. The first with JERA Co., is for the sale and purchase of three LNG cargoes (approximately 0.2 Mtpa) on a delivered ex-ship basis during Japan’s winter months from 2027 for a period of five years. The second with PETRONAS, is for the supply of 1.0 Mtpa of LNG to Malaysia from 2028 for a period of 15 years.

27 | Includes a base purchase price of $206 million plus working capital completion adjustments and interest, based on an effective date of 1 January 2025.

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The execution of these agreements highlights sustained global demand for Woodside’s LNG and reinforces the strategic advantage of our diversified portfolio in driving long-term growth and value.

Oil sales increased in H1 2025 from H1 2024, reflecting a full six months of production from the Sangomar field in Senegal. A total of 19 Sangomar cargoes were loaded in the period (14 MMbbl Woodside share). The first cargo to be sold for domestic refining in Senegal was successfully delivered during the period.

A record quantity of trucked LNG, approximately 1,233 TJ and equivalent to 1,200 trailers, was delivered in H1 2025 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 4,400 trailers of LNG (approximately 4,400 TJ), offering a lower-carbon alternative to diesel.

On the east coast of Australia, and in accordance with its obligations under its Ministerial Exemption to the Gas Market Code, Woodside commenced an expression of interest for 30 PJ of Bass Strait supply across 2026 and 2027. Customer responses are in the process of being reviewed with initial offers to be issued in early July.

Woodside continued its marketing activities to support the offtake of lower-carbon ammonia from the Beaumont New Ammonia Project.

Woodside SPAs with Commonwealth LNG, executed in September 2022, were terminated due to the failure of Commonwealth LNG to achieve key milestones, including FID, by contractual long stop dates.

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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 field is being developed through new offshore facilities connected by a 433 km pipeline to a second LNG train at the existing Pluto LNG onshore facility. The development of the Scarborough field 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.

The expansion of the Pluto LNG facility includes the construction of a second LNG train (Pluto Train 2), installation of additional domestic gas processing facilities and supporting infrastructure and modifications to the existing Pluto Train 1 to allow it to process Scarborough gas. The Project also includes the construction of an integrated remote operations centre (IROC) at Woodside’s headquarters in Perth.

The Project was 86% complete at the end of H1 2025, excluding Pluto Train 1 modifications. First LNG cargo is targeted for the second half of 2026.

The FPU achieved significant milestones throughout the first half of 2025. The construction of both the hull and topsides was completed, and the structures were successfully loaded out and connected during the floatover activities in May 2025. Integration activities are now underway in preparation for transit from China to Australia.

Subsequent to the period, subsea installation, testing and pre-commissioning was completed, ready for the FPU arrival and final subsea hook up.

Batch drilling of the eight initial development wells continued, and subsequent to the period the third development well was drilled and completed, and the fourth well was drilled. Reservoir properties were in line with expectations, and the anticipated deliverability of the wells remains on track.

Construction activities at the Pluto Train 2 site continued with piping, cable installation and electrical commissioning progressing, with the workforce reaching peak numbers.

Civil, structural and piping works at the Pluto Train 1 modifications site are ongoing with the largest concrete pour for the modifications project completed. Construction activity at the module yard ramped up throughout the half.

Subsequent to the period, the Federal Court of Australia heard a legal challenge to the National Offshore Petroleum Safety and Environmental Management Authority’s decision to accept the Scarborough Offshore Facility and Trunkline (Operations) Environment Plan. The decision is pending.

Woodside is operator and holds a 74.9% participating interest in Scarborough, a 51% participating interest in Pluto Train 2 and a 90% participating interest in Pluto Train 1.

Trion

Trion is an offshore oil development located in Mexico, approximately 180 km off the Mexican coastline and 30 km south of the United States/Mexico maritime border. The development includes a 24 subsea well development, a semi-submersible FPU capable of producing and transferring 100,000 barrels of oil per day, and a floating storage and offloading (FSO) facility.

The Project was 35% complete at the end of H1 2025. First oil is targeted for 2028.

The FPU achieved key milestones during H1 2025 including finalising the detailed design, moving hull blocks into the dry dock, progressing construction of three topside modules and the living quarters, and completing the fabrication of FPU turbo machinery and equipment.

The FSO facility detailed engineering progressed, with fabrication scheduled to commence in H2 2025. Fabrication of the disconnectable turret mooring continued and fabrication of the FSO and FPU anchor piles commenced.

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The design, procurement and manufacturing of subsea and gathering line equipment are progressing, with all subsea equipment, trees, and topside control systems ordered and fabrication underway.

All major contract awards have been completed, including drilling and completion services, gas pipeline installation, FSO operating and maintenance contracts, and support vessels.

In February 2025, Woodside fulfilled the total contribution and carry of its PEMEX obligations. From March 2025, Project costs will be split 60% Woodside and 40% PEMEX in accordance with the terms of the joint venture agreement.

Woodside is the operator and holds a 60% participating interest in the Project.

Beaumont New Ammonia

Beaumont New Ammonia is an under-construction lower-carbon ammonia project in Beaumont, Texas with a design capacity of 1.1 Mtpa. Woodside is targeting production of first ammonia in late 2025 and lower-carbon ammonia from the second half of 2026 following commencement of carbon capture and storage (CCS) operations.28,29 The Project will position Woodside as an early mover in the lower-carbon ammonia market.

Construction on Train 1 continues to be managed by OCI and the Project is 95% complete at the end of H1 2025. Project completion and associated payment of the remaining 20% of the acquisition consideration is expected in 2026.

In H1 2025, progress included completion of storage tank construction and compressor alignment. The electrical substation was also completed with the primary transformer ready to switch from temporary to permanent power in H2 2025. Pre-commissioning activities commenced as Project construction nears completion.

Woodside is progressing marketing activities in support of ammonia sales from Train 1.

Woodside holds a 100% participating interest and upon handover of the Project from OCI will become operator.

Louisiana LNG

Louisiana LNG is a fully permitted LNG development located near Lake Charles, Louisiana. The development plan comprises five LNG trains, with a total permitted capacity of 27.6 Mtpa, and supporting infrastructure.

Woodside approved an FID to develop the initial three-train, 16.5 Mtpa Louisiana LNG Project in April 2025, targeting first LNG in 2029.

In June 2025, Woodside completed the sell-down of a 40% interest in Louisiana LNG Infrastructure LLC to Stonepeak, receiving a closing payment of $1,870 million. Under the transaction, Stonepeak will provide a total of $5,700 million in capital towards the foundation development of Louisiana LNG on an accelerated basis, contributing 75% of the expected Project capital expenditure in both 2025 and 2026.

Louisiana LNG continues to receive strong interest from high-quality potential partners and will progress sell-down discussions while retaining a controlling ownership interest.

Following FID, a full notice to proceed was issued to Bechtel for construction. All high-value orders and major purchase orders for equipment and bulk materials have been released and committed. Train 1 was 22% complete at the end of H1 2025, with activities focused on progressing the marine offloading facility, marine dry excavation, and civil works.

Louisiana LNG Gas Management LLC, a wholly-owned subsidiary of Louisiana LNG LLC, committed to purchase, on a long-term basis, up to 640 billion cubic feet of feedgas from bp with gas supply commencing in 2029.

28 | Production of lower-carbon ammonia is conditional on the supply of carbon abated hydrogen and ExxonMobil’s CCS facility becoming operational.

29 | 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).

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Woodside is building the Line 200 lateral pipeline, which will supply a significant portion of the pipeline transportation capacity requirement. Orders have been placed for long lead items for the pipeline. Woodside will continue to secure additional pipeline transportation capacity on third-party pipelines, with a continued focus on ensuring diverse and reliable feedgas sources for Louisiana LNG.

The Federal Energy Regulatory Commission approved the extension of the in-service date for the LNG terminal and Driftwood pipeline through to the end of 2029.

Woodside also submitted an application to the Department of Energy to extend the export commencement deadline for the non-free trade agreement LNG Export Authorisation through the end of 2029.

Woodside is the operator and holds a 100% participating interest in Louisiana LNG LLC and a 60% participating interest in Louisiana LNG Infrastructure LLC.

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Hydrogen Refueller @H2Perth

The Hydrogen Refueller @H2Perth is a self-contained hydrogen production, storage and refuelling station located in Perth, Western Australia.30

Construction activities commenced for the Project with major equipment packages including electrolysers and compressors installed on site. Major civil works are near complete and both electrical cable and tubing installation have commenced.

Woodside is targeting ready for startup in Q4 2025, with first hydrogen production expected in the first half of 2026.

Decommissioning

Woodside continued execution of planned decommissioning activities in H1 2025, spending approximately $565 million across its portfolio.

Woodside has progressed planned decommissioning activities across the Enfield, Griffin and Stybarrow fields, offshore north west Western Australia, as well as the Minerva field, offshore Victoria. The retrieval of the Echo Yodel umbilical is expected to commence in H2 2025.

In H1 2025, Woodside concluded the ten-well Stybarrow plugging campaign and successfully completed the plug and abandonment of the three remaining wells at the Minerva field.

In February, final infrastructure was recovered from Enfield, concluding a multi-year decommissioning program that included permanently plugging and abandoning all 18 Enfield wells, recovering and deconstructing the Nganhurra riser turret mooring and removing flexible flowlines, umbilicals and other subsea structures. Enfield is the first project that Woodside has taken from exploration through development and operations, to decommissioning.

Woodside experienced a Tier 1 process safety event when unexpected fluids were released during flushing activities of a Griffin subsea flowline. Water quality monitoring identified no impact on the environment.

Woodside is evaluating decommissioning work plans for Minerva, Stybarrow and Griffin. The as-left condition on some closed sites has continued to present challenges for safe and efficient execution of decommissioning and learnings are being applied to improve planning and execution. These challenges are the primary driver of a $445 million pre-tax ($218 million post-tax) restoration expense being recognised in the profit and loss in the half-year results.

At Bass Strait, the Gippsland Basin Joint Venture has safely completed approximately A$2,500 million (100% share) of early decommissioning works, including the plug and abandonment of over 200 wells. This includes the completion of plugging the Bream B and Kingfish A platform wells in H1 2025.

Detailed engineering and execution planning, including submission of primary and secondary environmental approvals to regulators for assessment, is well advanced for the Bass Strait offshore platform removal campaign planned for 2027.

30 | The Project has received funding from the Hydrogen Fuelled Transport Project Funding Process as part of the Western Australian Government’s Renewable Hydrogen Strategy.

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Exploration and Development

Browse

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

Work continued on the Browse to North West Shelf Project to optimise the development concept, advance key regulatory approvals and progress commercial discussions to process Browse volumes through the Karratha Gas Plant.

In March 2025, Woodside applied to amend the State Browse to North West Shelf Project environmental proposal to reflect changes to the development footprint and new environmental measures designed to further reduce the potential environmental impact of the development. The original proposal was submitted in 2018. The Western Australian Environmental Protection Authority held a four-week public comment period on the proposed amendment, from 12 May to 10 June 2025.

In May 2025, Woodside applied to amend the Commonwealth Browse to NWS Project environment proposal to align with the proposed changes to the State proposal. The original proposal was submitted in 2018. The assessment of the Commonwealth proposal remains suspended while the Department of Climate Change, Energy, the Environment and Water consults with the National Offshore Petroleum Safety and Environmental Management Authority on the new Woodside information provided to both the State and Commonwealth regulators in September 2024 to support the final phase of assessment.

The Browse CCS Project was referred to the Commonwealth regulator in October 2024 and declared valid on 2 January 2025. The regulator has yet to determine if this is a controlled action under the Environment Protection and Biodiversity Conservation Act, and set a corresponding level of assessment.

Woodside is operator and holds a 30.6% 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.

Woodside continues to work with the Timor-Leste and Australian Governments and the Sunrise Joint Venture participants to assess and address technical and commercial considerations to help enable the desired commercialisation of the fields.

Woodside conducted a visit to Timor-Leste’s south coast as a potential location for processing Sunrise gas. The visit included a review of the Timor-Leste Government’s proposed site at Natarbora for a range of facilities, including an LNG plant, and a proposed site at Suai for a supply base.

Woodside is operator and holds a 33.44% participating interest.

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.

The Joint Venture continues to review development options. Concept select engineering studies and subsurface studies to mature the technical and commercial definition progressed.

Woodside is operator and holds a 70% participating interest.

Liard

The Liard field is an unconventional gas field located in British Columbia, Canada.

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Woodside is working with the asset operator to develop a strategy for full field development, as well as with its partners in Rockies LNG to potentially export LNG through the proposed Ksi Lisims Project on the west coast of Canada.

Woodside holds a 50% non-operating participating interest in Liard.

Exploration

Woodside’s exploration activities continue to prioritise disciplined portfolio optimisation, including exiting blocks that are no longer considered prospective, such as Blocks 1, 3, and 4 in the Red Sea offshore Egypt.

In Australia, Exploration Permit WA-536-P expired. Woodside also elected to not exercise its option to acquire at least a 56% interest in Petroleum Exploration License 87 offshore Namibia.

In the US, Woodside continues to actively manage its acreage position offshore United States.

New energy

NeoSmelt

The NeoSmelt Project is a proposed pilot plant aiming to prove Pilbara iron ore can be used to produce lower-carbon emissions molten iron using direct reduced iron and electric smelting furnace technology.31

In H1 2025, Woodside formally joined the NeoSmelt Project as an equal equity participant and preferred energy supplier.32 In H1 2025, the Project commenced front-end engineering design (FEED) studies supported by A$19.8 million in funding from the Australian Renewable Energy Agency (ARENA) as part of ARENA’s Industrial Transformation Stream program.33

Woodside is non-operator and holds a 20% participating interest.

H2Perth

H2Perth is a proposed commercial-scale liquid hydrogen facility to be located in Perth, Western Australia.

In H1 2025, Woodside commenced pre-FEED studies for the initial phase of the Project.

Woodside is operator and holds a 100% participating interest.

H2OK

Woodside has made the decision to exit the proposed H2OK Project in Oklahoma due to ongoing challenges facing the lower-carbon hydrogen industry, including cost escalation and lower than anticipated hydrogen demand. The exit has resulted in an impairment loss of $143 million pre-tax ($113 million post-tax) being recognised in the profit and loss in the half-year results.

H2TAS

In H1 2025, Woodside formalised its exit from H2TAS.

31 | 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 resource, process, production facility, product or service, or activity. When applied to Woodside’s strategy, please see the definition of lower-carbon portfolio in the Glossary on pages 58-60.

32 | Energy supply may include hydrogen, natural gas and/or electricity.

33 | The views expressed herein are not necessarily the views of the Australian Government, and the Australian Government does not accept responsibility for any information or advice contained herein.

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Business developments

Aramco collaboration

In May, Woodside entered into a non-binding collaboration agreement with Aramco to explore global opportunities, including Aramco’s potential acquisition of an equity interest in and LNG offtake from Louisiana LNG. Additionally, both companies are exploring opportunities for a potential collaboration in lower-carbon ammonia.34

Hyundai Engineering and Hyundai Glovis collaboration

Woodside signed a non-binding memorandum of understanding with Hyundai Engineering and Hyundai Glovis, establishing a strategic framework to collaborate on LNG project development, engineering services and shipping logistics.

34 | 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).

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Carbon solutions

Carbon capture storage (CCS)

Woodside is progressing CCS opportunities in Australia, including the operated Angel CCS (Woodside participating interest: 20%) and non-operated Bonaparte CCS opportunities (Woodside participating interest: 21%).

In H1 2025, the proposed Angel CCS Project completed engineering studies as part of pre-FEED and commenced domestic and international engagement with potential customers for CCS services. Following completion of the asset swap agreement with Chevron announced in 2024, Woodside’s participating interest will increase to 40%. The asset swap remains on track for completion in 2026.35

The Bonaparte CCS Assessment Joint Venture commenced pre-FEED and was awarded Major Project Status by the Australian Government.

Woodside continues to assess the South East Australia CCS opportunity.

Carbon credits portfolio

Woodside continues to acquire carbon credits through both market purchases and the development of its own carbon origination projects.36

During H1 2025, environmental planting activities under Woodside’s Native Reforestation Project, including site preparation and seedling installation, were carried out on Woodside-owned properties in Western Australia and New South Wales. Approximately 2 million biodiverse seedlings are forecast to be planted in Western Australia and approximately 500,000 in New South Wales in 2025. These activities were 50% complete by the end of H1 2025.

Woodside-funded international carbon origination projects in Paraguay and Senegal progressed during the period. Woodside is expected to receive approximately 2.4 million and 1.8 million carbon credits respectively over 40 years.

Climate and Sustainability

Health, personal and process safety

In H1 2025, the year-to-date lost time frequency rate was 0.26 compared with 0.47 for full-year 2024, and the total recordable injury rate was 2.02 compared to 2.44 recorded for full-year 2024. There were no fatalities or permanent injuries recorded in H1 2025.

In H1 2025, Woodside experienced a Tier 1 process safety event when unexpected fluids were released during flushing activities of a Griffin subsea flowline. Water quality monitoring identified no impact to the environment.

Woodside is focussed on embedding simplified safety processes, implementing improvements in the engineering systems to manage hardware, and promoting a learning culture through the Field Leadership Program.

Climate

Woodside is on track to meet its corporate 2025 net equity Scope 1 and 2 greenhouse gas emissions reduction target.37 During the half, achievements included the high reliability of the Sangomar gas injection system which lead to reduced flaring emissions and improvements at KGP that reduced the assist gas for the operational flares and improved the efficiency of the domestic gas compressor operating envelope.

35 | Completion of the transaction is subject to conditions precedent. See “Woodside simplifies portfolio and unlocks long-term value” announced 19 December 2024 for details concerning the Australian asset swap.

36 | Origination refers to carbon offset projects developed by Woodside or third-party project developers, characterised by (i) the provision by Woodside of up-front investment or funding; (ii) Woodside either being a majority participant in the project or a recipient of carbon credits from the project (or both); and (iii) the acceptance of risk by Woodside in relation to carbon credit delivery.

37 | Target is for net equity Scope 1 and 2 greenhouse gas emissions reduction relative to a starting base of 6.32 Mt CO2-e which is representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and which may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with a FID prior to 2021. Net equity emissions include the utilisation of carbon credits as offsets. This means net equity Scope 1 and 2 greenhouse gas emissions for the 12-month period ending 31 December 2025 are targeted to be 15% lower than the starting base.

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Woodside submitted its Oil and Gas Methane Partnership 2.0 Implementation Plan to the United Nations Environment Program. Half-year activities included initiation of a methane leak detection and reporting program at the Goodwyn A Platform, and the testing of flare monitoring equipment at the Pluto LNG facility and KGP.

First Nations cultural heritage and engagement

During H1 2025, Woodside continued to engage with multiple Traditional Owner representative bodies in Australia to discuss current and potential future activities. This included consultation on the Goodwyn Alpha Geophysical and Geotechnical Surveys and Okha Operations Environment Plans.

Woodside completed a planned annual cultural heritage audit of North West Shelf Project leases in collaboration with Traditional Custodians.

Subsequent to the period, Woodside welcomed the inscription of the Murujuga Cultural Landscape on the World Heritage List by UNESCO’s World Heritage Committee.

Environment and biodiversity

In H1 2025, there were no significant environmental impacts from our operations. Woodside continued to implement a robust and systematic approach to environmental management of our activities.

To support biodiversity positive outcomes in the regions and areas in which we undertake activities, Woodside is working closely with local partners to identify and deliver measurable positive biodiversity outcomes across a range of locations in Western Australia and the United States.38

In H1 2025, Woodside finalised Biodiversity Management Plans for Trion, Beaumont New Ammonia and Louisiana LNG.

Local content

In H1 2025, the Pluto Train 1 Modifications Project awarded 47 new contracts to Pilbara based businesses. Of the 47 new contracts awarded, 45 were with Karratha businesses and 10 were awarded to Indigenous businesses. For the same period, 9 new local subcontracts were awarded in the Pilbara region for Pluto Train 2.

Woodside also extended its agreement with North West Alliance for the management of waste from Woodside’s onshore and offshore facilities. The Pilbara-based joint venture is 50% Indigenous owned, and Woodside is one of its longest contracting customers in Karratha (more than a decade).

In Senegal, operational insurance valued at $13 million was successfully placed with local insurance companies, in partnership with international reinsurers.

A contracting plan has been put in place to support operations planning for Trion. The plan includes strategies for compliance with local content requirements, including a framework to support local companies through specialised supplier development programs, networking, and integration. A key element of the strategy for local content is collaboration with Project participants to leverage potential suppliers and share synergies.

Social contribution

Woodside published its 2024 Social Investment Impact Report in May 2025. The report highlights the positive impacts of Woodside’s A$35.4 million social contribution in 2024, which was directed through strategic partnerships, philanthropy initiatives, employee volunteering, and payments required by government and First Nations agreements.

38 | Woodside defines biodiversity positive as a project or investment that has measurable benefits to 1) threatened or keystone species; or 2) restores or regenerates natural habitat; or 3) removes threatening processes or enhances ecological function. A keystone species is a species that has a disproportionately large effect on its natural environment relative to its abundance.

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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 1 - 20 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 2025 half-year are as follows:

Mr Richard Goyder, AO (Chair) |  | Ms Meg O’Neill (CEO and Managing Director)
Mr Larry Archibald |  | Mr Ashok Belani
Mr Arnaud Breuillac |  | Ms Swee Chen Goh
Mr Ian Macfarlane |  | Ms Angela Minas
Mr Tony O’Neill |  | Ms Ann Pickard
Mr Ben Wyatt |  |

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.

Auditor’s Independence Declaration

The Auditor’s Independence Declaration, as required under section 307C of the Corporations Act 2001, is set out on page 22 and forms part of this report.

Signed in accordance with a resolution of the directors.

R J Goyder, AO

Chair

Perth, Western Australia

19 August 2025

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Auditor’s Independence Declaration to the Directors of Woodside Energy Group Ltd

Auditor’s Independence Declaration

As lead auditor for the review of Woodside Energy Group Ltd for the half-year ended 30 June 2025, I declare that to the best of my knowledge and belief, there have been:

a. | no contraventions of the auditor independence requirements of the Corporations Act 2001 in relation to the review; and

b. | no contraventions of any applicable code of professional conduct in relation to the review.

This declaration is in respect of Woodside Energy Group Ltd and the entities it controlled during the period.

N M Henry |  | Perth
Partner PricewaterhouseCoopers |  | 19 August 2025

pwc.com.au |  | PricewaterhouseCoopers, ABN 52 780 433 757 Brookfield Place, Level 15, 125 St Georges Terrace, PERTH WA 6000, GPO Box D198, PERTH WA 6840 T: +61 8 9238 3000, F: +61 8 9238 3999, www.pwc.com.au Liability limited by a scheme approved under Professional Standards Legislation.

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HALF-YEAR FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

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HALF-YEAR FINANCIAL STATEMENTS

CONTENTS

CONDENSED CONSOLIDATED INCOME STATEMENT |  |  | 25 |
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME |  |  | 26 |
CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION |  |  | 27 |
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS |  |  | 28 |
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY |  |  | 29 |
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS |  |  | 30 |
A. |  | Earnings for the period |  |  | 32 |
|  | A.1 Segment revenue and expenses |  |  | 32 |
|  | A.2 Finance costs |  |  | 33 |
|  | A.3 Dividends paid and proposed |  |  | 33 |
|  | A.4 Earnings per share |  |  | 33 |
|  | A.5 Taxes |  |  | 34 |
B. |  | Production and growth assets |  |  | 35 |
|  | B.1 Exploration and evaluation |  |  | 35 |
|  | B.2 Property, plant and equipment |  |  | 36 |
|  | B.3 Intangible assets |  |  | 37 |
|  | B.4 Business combination |  |  | 38 |
|  | B.5 Disposal and sell-down of assets |  |  | 40 |
|  | B.6 Impairment of exploration and evaluation, property, plant and equipment and goodwill |  |  | 41 |
C. |  | Debt and capital |  |  | 42 |
|  | C.1 Contributed equity |  |  | 42 |
|  | C.2 Interest-bearing liabilities and financing facilities |  |  | 43 |
D. |  | Other assets and liabilities |  |  | 45 |
|  | D.1 Segment assets and liabilities |  |  | 45 |
|  | D.2 Provisions |  |  | 46 |
|  | D.3 Other financial assets and liabilities |  |  | 47 |
E. |  | Other items |  |  | 49 |
|  | E.1 Contingent liabilities and assets |  |  | 49 |
|  | E.2 New standards and interpretations |  |  | 49 |
|  | E.3 Events after the end of the reporting period |  |  | 49 |
DIRECTORS’ DECLARATION |  |  | 50 |
INDEPENDENT AUDITOR’S REVIEW REPORT |  |  | 51 |

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 28 March 2025, the Group and Perenco Energies International Limited (Perenco) entered into an agreement for Perenco to acquire the Greater Angostura assets in Trinidad and Tobago. The divestment includes Woodside’s 45% interest in the Angostura field and 68.46% interest in the Ruby field. The transaction completed on 11 July 2025, with an effective date of 1 January 2025. As a result, as at 30 June 2025 $447 million of assets have been reclassified as assets held for sale and $416 million of liabilities have been reclassified as liabilities directly associated with assets held for sale (refer to Note B.5).

| • |  | On 7 April 2025, the Group and Stonepeak Wallaby I Acquiror LP (Stonepeak) entered into an agreement for Stonepeak to acquire a 40% interest in Louisiana LNG Infrastructure LLC, a subsidiary within the Group. The transaction completed on 25 June 2025 with the Group continuing to retain control of Louisiana LNG Infrastructure LLC. As at 30 June 2025, $2,140 million has been recognised as non-controlling interest within equity based on Stonepeak’s proportionate share of total capital contributions made to date, and $270 million has been recognised in other reserves for the difference in proceeds received and the non-controlling interest recognised (refer to Note B.5).

| • |  | On 29 April 2025, the Group approved an FID to develop the Louisiana LNG Project. Upon FID, the Group recognised a deferred tax asset of $182 million (refer to Note A.5).

| • |  | In March and April 2025, the Group repaid, renewed and drew down on various debt facilities. In May 2025, the Group issued unsecured SEC-registered bonds amounting to $3,500 million (refer to Note C.2).

| • |  | As at 30 June 2025, an impairment indicator was identified on the H2OK Project following the Group’s decision to exit the Project. As a result, the Group recognised an impairment loss before tax of $143 million (refer to Note B.6).

| • |  | During the period, the Group recognised a restoration expense of $445 million primarily due to updated closure cost estimates and economic assumptions for Minerva, Stybarrow and Griffin (refer to Note A.1).

24 | Half-Year Report 2025 |  |

CONDENSED CONSOLIDATED INCOME STATEMENT

for the half-year ended 30 June 2025

|  | Notes |  |  | 2025 US$m |  |  | 2024 US$m |
Operating revenue |  |  | A.1 |  |  |  | 6,590 |  |  |  | 5,988 |
Cost of sales |  |  | A.1 |  |  |  | (4,045 | ) |  |  | (3,272 | )
Gross profit |  |  |  |  |  |  | 2,545 |  |  |  | 2,716 |
Other income |  |  | A.1 |  |  |  | 379 |  |  |  | 315 |
Other expenses |  |  | A.1 |  |  |  | (964 | ) |  |  | (669 | )
Impairment losses |  |  | A.1 |  |  |  | (143 | ) |  |  | — |
Profit before tax and net finance costs |  |  |  |  |  |  | 1,817 |  |  |  | 2,362 |
Finance income |  |  |  |  |  |  | 106 |  |  |  | 95 |
Finance costs |  |  | A.2 |  |  |  | (169 | ) |  |  | (147 | )
Profit before tax |  |  |  |  |  |  | 1,754 |  |  |  | 2,310 |
Petroleum resource rent tax (PRRT) expense |  |  |  |  |  |  | (71 | ) |  |  | (192 | )
Income tax expense |  |  | A.5 |  |  |  | (353 | ) |  |  | (146 | )
Profit after tax |  |  |  |  |  |  | 1,330 |  |  |  | 1,972 |
Profit attributable to: |  |  |  |  |  |  |  |  |  |  |  |
Equity holders of the parent |  |  |  |  |  |  | 1,316 |  |  |  | 1,937 |
Non-controlling interest |  |  |  |  |  |  | 14 |  |  |  | 35 |
Profit for the period |  |  |  |  |  |  | 1,330 |  |  |  | 1,972 |
Basic earnings per share attributable to equity holders of the parent (US cents) |  |  | A.4 |  |  |  | 69.4 |  |  |  | 102.2 |
Diluted earnings per share attributable to equity holders of the parent (US cents) |  |  | A.4 |  |  |  | 68.8 |  |  |  | 101.4 |

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

25 | Half-Year Report 2025 |  |

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

for the half-year ended 30 June 2025

|  | 2025 US$m |  |  | 2024 US$m |
Profit for the period |  |  | 1,330 |  |  |  | 1,972 |
Other comprehensive income |  |  |  |  |  |  |  |
Items that may be reclassified to the income statement in subsequent periods: |  |  |  |  |  |  |  |
Gains/(losses) on cash flow hedges |  |  | 289 |  |  |  | (165 | )
(Gains)/losses on cash flow hedges reclassified to the income statement |  |  | (16 | ) |  |  | 38 |
Tax recognised within other comprehensive income |  |  | (57 | ) |  |  | 19 |
Items that will not be reclassified to the income statement in subsequent periods: |  |  |  |  |  |  |  |
Remeasurement gain/(loss) on defined benefit plan |  |  | 2 |  |  |  | (15 | )
Net loss on financial instruments at fair value through other comprehensive income |  |  | (33 | ) |  |  | (11 | )
Other comprehensive income/(loss) for the period, net of tax |  |  | 185 |  |  |  | (134 | )
Total comprehensive income for the period |  |  | 1,515 |  |  |  | 1,838 |
Total comprehensive income attributable to: |  |  |  |  |  |  |  |
Equity holders of the parent |  |  | 1,501 |  |  |  | 1,803 |
Non-controlling interest |  |  | 14 |  |  |  | 35 |
Total comprehensive income for the period |  |  | 1,515 |  |  |  | 1,838 |

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

26 | Half-Year Report 2025 |  |

CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

as at 30 June 2025

|  | Notes |  |  | 30 June 2025 US$m |  |  | 31 December 2024 US$m |
Current assets |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  |  |  |  |  |  | 4,880 |  |  |  | 3,923 |
Receivables |  |  |  |  |  |  | 1,813 |  |  |  | 2,390 |
Inventories |  |  |  |  |  |  | 711 |  |  |  | 684 |
Other financial assets |  |  | D.3 |  |  |  | 274 |  |  |  | 185 |
Assets held for sale |  |  | B.5 |  |  |  | 447 |  |  |  | — |
Tax receivable |  |  |  |  |  |  | 413 |  |  |  | 288 |
Other assets |  |  |  |  |  |  | 92 |  |  |  | 93 |
Total current assets |  |  |  |  |  |  | 8,630 |  |  |  | 7,563 |
Non-current assets |  |  |  |  |  |  |  |  |  |  |  |
Receivables |  |  |  |  |  |  | 898 |  |  |  | 876 |
Inventories |  |  |  |  |  |  | 232 |  |  |  | 213 |
Other financial assets |  |  | D.3 |  |  |  | 88 |  |  |  | 118 |
Exploration and evaluation assets |  |  | B.1 |  |  |  | 746 |  |  |  | 721 |
Property, plant and equipment |  |  | B.2 |  |  |  | 45,067 |  |  |  | 42,636 |
Deferred tax assets |  |  |  |  |  |  | 2,616 |  |  |  | 2,393 |
Lease assets |  |  |  |  |  |  | 1,234 |  |  |  | 1,291 |
Investments accounted for using the equity method |  |  |  |  |  |  | 232 |  |  |  | 249 |
Intangible assets |  |  | B.3 |  |  |  | 4,891 |  |  |  | 4,826 |
Other assets |  |  |  |  |  |  | 243 |  |  |  | 378 |
Total non-current assets |  |  |  |  |  |  | 56,247 |  |  |  | 53,701 |
Total assets |  |  |  |  |  |  | 64,877 |  |  |  | 61,264 |
Current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Payables |  |  |  |  |  |  | 1,604 |  |  |  | 2,185 |
Interest-bearing liabilities |  |  | C.2 |  |  |  | — |  |  |  | 990 |
Other financial liabilities |  |  | D.3 |  |  |  | 35 |  |  |  | 139 |
Liabilities directly associated with assets held for sale |  |  | B.5 |  |  |  | 416 |  |  |  | — |
Provisions |  |  | D.2 |  |  |  | 1,172 |  |  |  | 1,322 |
Tax payable |  |  |  |  |  |  | 356 |  |  |  | 308 |
Lease liabilities |  |  |  |  |  |  | 177 |  |  |  | 189 |
Other liabilities |  |  |  |  |  |  | 782 |  |  |  | 724 |
Total current liabilities |  |  |  |  |  |  | 4,542 |  |  |  | 5,857 |
Non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Interest-bearing liabilities |  |  | C.2 |  |  |  | 11,972 |  |  |  | 9,007 |
Deferred tax liabilities |  |  |  |  |  |  | 1,343 |  |  |  | 1,497 |
Other financial liabilities |  |  | D.3 |  |  |  | 194 |  |  |  | 379 |
Provisions |  |  | D.2 |  |  |  | 6,252 |  |  |  | 6,225 |
Tax payable |  |  |  |  |  |  | 17 |  |  |  | 28 |
Lease liabilities |  |  |  |  |  |  | 1,406 |  |  |  | 1,434 |
Other liabilities |  |  |  |  |  |  | 644 |  |  |  | 684 |
Total non-current liabilities |  |  |  |  |  |  | 21,828 |  |  |  | 19,254 |
Total liabilities |  |  |  |  |  |  | 26,370 |  |  |  | 25,111 |
Net assets |  |  |  |  |  |  | 38,507 |  |  |  | 36,153 |
Equity |  |  |  |  |  |  |  |  |  |  |  |
Issued and fully paid shares |  |  | C.1 |  |  |  | 29,001 |  |  |  | 29,001 |
Shares reserved for employee share plans |  |  | C.1 |  |  |  | (71 | ) |  |  | (58 | )
Other reserves |  |  |  |  |  |  | 6,043 |  |  |  | 4,108 |
Retained earnings |  |  |  |  |  |  | 666 |  |  |  | 2,348 |
Equity attributable to equity holders of the parent |  |  |  |  |  |  | 35,639 |  |  |  | 35,399 |
Non-controlling interest |  |  |  |  |  |  | 2,868 |  |  |  | 754 |
Total equity |  |  |  |  |  |  | 38,507 |  |  |  | 36,153 |

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

27 | Half-Year Report 2025 |  |

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

for the half-year ended 30 June 2025

|  | Notes |  |  | 2025 US$m |  |  | 2024 US$m |
Cash flows from operating activities |  |  |  |  |  |  |  |  |  |  |  |
Profit after tax for the period |  |  |  |  |  |  | 1,330 |  |  |  | 1,972 |
Adjustments for: |  |  |  |  |  |  |  |  |  |  |  |
Non-cash items |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortisation |  |  |  |  |  |  | 2,555 |  |  |  | 1,908 |
Depreciation of lease assets |  |  |  |  |  |  | 85 |  |  |  | 101 |
Change in fair value of derivative financial instruments |  |  |  |  |  |  | (206 | ) |  |  | 205 |
Net finance costs |  |  |  |  |  |  | 63 |  |  |  | 52 |
Tax expense |  |  |  |  |  |  | 424 |  |  |  | 338 |
Impairment losses |  |  |  |  |  |  | 143 |  |  |  | — |
Restoration movement |  |  |  |  |  |  | 445 |  |  |  | 15 |
Loss/(gain) on disposal of property, plant and equipment |  |  |  |  |  |  | 2 |  |  |  | (143 | )
Other |  |  |  |  |  |  | (101 | ) |  |  | (66 | )
Changes in assets and liabilities |  |  |  |  |  |  |  |  |  |  |  |
Decrease in trade and other receivables |  |  |  |  |  |  | 122 |  |  |  | 113 |
Increase in inventories |  |  |  |  |  |  | (65 | ) |  |  | (166 | )
Decrease in provisions |  |  |  |  |  |  | (112 | ) |  |  | (31 | )
Decrease in other assets and liabilities |  |  |  |  |  |  | 103 |  |  |  | 39 |
(Decrease)/increase in trade and other payables |  |  |  |  |  |  | (186 | ) |  |  | 6 |
Cash generated from operations |  |  |  |  |  |  | 4,602 |  |  |  | 4,343 |
Interest received |  |  |  |  |  |  | 89 |  |  |  | 77 |
Borrowing costs relating to operating activities |  |  |  |  |  |  | (5 | ) |  |  | (2 | )
Income tax and PRRT paid |  |  |  |  |  |  | (782 | ) |  |  | (1,700 | )
Payments for restoration |  |  |  |  |  |  | (565 | ) |  |  | (325 | )
Net cash from operating activities |  |  |  |  |  |  | 3,339 |  |  |  | 2,393 |
Cash flows used in investing activities |  |  |  |  |  |  |  |  |  |  |  |
Payments for capital and exploration expenditure |  |  |  |  |  |  | (4,881 | ) |  |  | (2,418 | )
Reimbursements received from external parties for capital expenditure |  |  |  |  |  |  | 236 |  |  |  | — |
Borrowing costs relating to investing activities |  |  |  |  |  |  | (330 | ) |  |  | (155 | )
Deposits/proceeds received from disposal of non-current assets |  |  |  |  |  |  | 21 |  |  |  | 920 |
Dividends received from associates |  |  |  |  |  |  | 17 |  |  |  | — |
Net cash used in investing activities |  |  |  |  |  |  | (4,937 | ) |  |  | (1,653 | )
Cash flows used in financing activities |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from borrowings |  |  |  |  |  |  | 4,849 |  |  |  | 950 |
Repayment of borrowings |  |  | C.2 |  |  |  | (2,900 | ) |  |  | — |
Purchases of shares relating to employee share plans |  |  |  |  |  |  | (26 | ) |  |  | (25 | )
Repayment of the principal portion of lease liabilities |  |  |  |  |  |  | (108 | ) |  |  | (213 | )
Borrowing costs relating to lease liabilities |  |  |  |  |  |  | (1 | ) |  |  | (21 | )
Contributions from/(distributions to) non-controlling interests1 |  |  |  |  |  |  | 1,843 |  |  |  | (48 | )
Dividends paid |  |  |  |  |  |  | (1,006 | ) |  |  | (1,139 | )
Net cash from/(used in) financing activities |  |  |  |  |  |  | 2,651 |  |  |  | (496 | )
Net increase in cash held |  |  |  |  |  |  | 1,053 |  |  |  | 244 |
Less: Cash and cash equivalents classified within assets held for sale |  |  | B.5 |  |  |  | (108 | ) |  |  | — |
Cash and cash equivalents at the beginning of the period |  |  |  |  |  |  | 3,923 |  |  |  | 1,740 |
Effects of exchange rate changes |  |  |  |  |  |  | 12 |  |  |  | (5 | )
Cash and cash equivalents at the end of the period |  |  |  |  |  |  | 4,880 |  |  |  | 1,979 |

1. | Includes Stonepeak’s capital contribution of $1,870 million for the development of Louisiana LNG. Refer to Note B.5 for the sell-down of Louisiana LNG Infrastructure LLC to Stonepeak.

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

28 | Half-Year Report 2025 |  |

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

for the half-year ended 30 June 2025

|  | 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 2025 |  |  | 29,001 |  |  |  | (58 | ) |  |  | 281 |  |  |  | 795 |  |  |  | 1 |  |  |  | 3,069 |  |  |  | (38 | ) |  |  | 2,348 |  |  |  | 35,399 |  |  |  | 754 |  |  |  | 36,153 |
Profit for the period |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,316 |  |  |  | 1,316 |  |  |  | 14 |  |  |  | 1,330 |
Other comprehensive income/(loss) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 216 |  |  |  | — |  |  |  | (33 | ) |  |  | 2 |  |  |  | 185 |  |  |  | — |  |  |  | 185 |
Total comprehensive income/(loss) for the period |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 216 |  |  |  | — |  |  |  | (33 | ) |  |  | 1,318 |  |  |  | 1,501 |  |  |  | 14 |  |  |  | 1,515 |
Transfers |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3,000 |  |  |  | — |  |  |  | (3,000 | ) |  |  | — |  |  |  | — |  |  |  | — |
Transactions with non-controlling interests1 |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (270 | ) |  |  | — |  |  |  | (270 | ) |  |  | 2,140 |  |  |  | 1,870 |
Employee share plan purchases |  |  | — |  |  |  | (26 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (26 | ) |  |  | — |  |  |  | (26 | )
Employee share plan redemptions |  |  | — |  |  |  | 13 |  |  |  | (13 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Share-based payments (net of tax) |  |  | — |  |  |  | — |  |  |  | 41 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 41 |  |  |  | — |  |  |  | 41 |
Dividends paid |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1,006 | ) |  |  | — |  |  |  | — |  |  |  | (1,006 | ) |  |  | (40 | ) |  |  | (1,046 | )
At 30 June 2025 |  |  | 29,001 |  |  |  | (71 | ) |  |  | 309 |  |  |  | 795 |  |  |  | 217 |  |  |  | 5,063 |  |  |  | (341 | ) |  |  | 666 |  |  |  | 35,639 |  |  |  | 2,868 |  |  |  | 38,507 |
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 |

1. | Relates to the non-controlling interest contribution reserve which represents the difference between the amount of the adjustment to non-controlling interest and any consideration received. Refer to Note B.5 for the sell-down of Louisiana LNG Infrastructure LLC to Stonepeak.

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

29 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

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) 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.

The condensed consolidated half-year financial statements were authorised for issue in accordance with a resolution of the directors on 19 August 2025.

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 2024 (2024 Financial Statements) and any public announcements made by Woodside during the period ended 30 June 2025 in accordance with the continuous disclosure requirements of the Australian Corporations Act 2001 and the relevant ASX and NYSE Listing Rules.

The Group’s accounting policies are materially consistent with those disclosed in the Group’s 2024 Financial Statements. Adoption of new or amended standards and interpretations effective 1 January 2025 did not result in any significant changes to the Group’s accounting policies. Refer to Note E.2 for more details.

The significant accounting estimates and judgements are consistent with those disclosed in the 2024 Financial Statements. Estimates have been revised, where required, to reflect current market conditions including the impact of climate change. Updated estimates used for business combination, restoration provision and embedded commodity derivatives are disclosed in Notes B.4, D.2 and D.3 respectively; these assumptions could change in the future. New estimates and judgements relating to the disposal and sell-down of assets are disclosed in Note B.5.

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.

30 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

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 for the period ended 30 June 2025. 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 condensed consolidated income statement; their share of other comprehensive income, net of tax, in the condensed consolidated statement of comprehensive income; and are presented within equity in the condensed 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 2024 Financial Statements for details of the Group’s operating segment information.

31 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

A. Earnings for the period

A.1 Segment revenue and expenses

|  | Australia |  |  | International |  |  | Marketing |  |  | New energy/ Corporate |  |  | Consolidated |
|  | 2025 US$m |  |  | 2024 US$m |  |  | 2025 US$m |  |  | 2024 US$m |  |  | 2025 US$m |  |  | 2024 US$m |  |  | 2025 US$m |  |  | 2024 US$m |  |  | 2025 US$m |  |  | 2024 US$m |
Liquified natural gas |  |  | 2,417 |  |  |  | 2,595 |  |  |  | — |  |  |  | — |  |  |  | 522 |  |  |  | 412 |  |  |  | — |  |  |  | — |  |  |  | 2,939 |  |  |  | 3,007 |
Pipeline gas |  |  | 564 |  |  |  | 512 |  |  |  | 141 |  |  |  | 107 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 705 |  |  |  | 619 |
Crude oil and condensate |  |  | 683 |  |  |  | 861 |  |  |  | 2,011 |  |  |  | 1,190 |  |  |  | 13 |  |  |  | 40 |  |  |  | — |  |  |  | — |  |  |  | 2,707 |  |  |  | 2,091 |
Natural gas liquids |  |  | 90 |  |  |  | 87 |  |  |  | 18 |  |  |  | 24 |  |  |  | 9 |  |  |  | 40 |  |  |  | — |  |  |  | — |  |  |  | 117 |  |  |  | 151 |
Revenue from sale of hydrocarbons |  |  | 3,754 |  |  |  | 4,055 |  |  |  | 2,170 |  |  |  | 1,321 |  |  |  | 544 |  |  |  | 492 |  |  |  | — |  |  |  | — |  |  |  | 6,468 |  |  |  | 5,868 |
Intersegment revenue1 |  |  | (9 | ) |  |  | (12 | ) |  |  | — |  |  |  | (2 | ) |  |  | 9 |  |  |  | 14 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Processing and services revenue |  |  | 109 |  |  |  | 113 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 109 |  |  |  | 113 |
Shipping and other revenue |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 13 |  |  |  | 7 |  |  |  | — |  |  |  | — |  |  |  | 13 |  |  |  | 7 |
Other revenue |  |  | 100 |  |  |  | 101 |  |  |  | — |  |  |  | (2 | ) |  |  | 22 |  |  |  | 21 |  |  |  | — |  |  |  | — |  |  |  | 122 |  |  |  | 120 |
Operating revenue2 |  |  | 3,854 |  |  |  | 4,156 |  |  |  | 2,170 |  |  |  | 1,319 |  |  |  | 566 |  |  |  | 513 |  |  |  | — |  |  |  | — |  |  |  | 6,590 |  |  |  | 5,988 |
Production costs |  |  | (491 | ) |  |  | (511 | ) |  |  | (268 | ) |  |  | (234 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (759 | ) |  |  | (745 | )
Royalties, excise and levies |  |  | (126 | ) |  |  | (185 | ) |  |  | (30 | ) |  |  | (11 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (156 | ) |  |  | (196 | )
Insurance |  |  | (19 | ) |  |  | (13 | ) |  |  | (8 | ) |  |  | (2 | ) |  |  | — |  |  |  | — |  |  |  | (10 | ) |  |  | (11 | ) |  |  | (37 | ) |  |  | (26 | )
Inventory movement |  |  | (7 | ) |  |  | 15 |  |  |  | 6 |  |  |  | 47 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1 | ) |  |  | 62 |
Costs of production |  |  | (643 | ) |  |  | (694 | ) |  |  | (300 | ) |  |  | (200 | ) |  |  | — |  |  |  | — |  |  |  | (10 | ) |  |  | (11 | ) |  |  | (953 | ) |  |  | (905 | )
Property, plant and equipment depreciation and amortisation |  |  | (1,170 | ) |  |  | (1,256 | ) |  |  | (1,340 | ) |  |  | (612 | ) |  |  | — |  |  |  | — |  |  |  | (31 | ) |  |  | (25 | ) |  |  | (2,541 | ) |  |  | (1,893 | )
Shipping and direct sales costs |  |  | (36 | ) |  |  | (61 | ) |  |  | (41 | ) |  |  | (43 | ) |  |  | (43 | ) |  |  | (50 | ) |  |  | — |  |  |  | — |  |  |  | (120 | ) |  |  | (154 | )
Trading costs |  |  | (88 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (322 | ) |  |  | (273 | ) |  |  | — |  |  |  | — |  |  |  | (410 | ) |  |  | (273 | )
Other hydrocarbon costs |  |  | (6 | ) |  |  | (26 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (6 | ) |  |  | (26 | )
Other |  |  | (15 | ) |  |  | (17 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (4 | ) |  |  | (15 | ) |  |  | (21 | )
Other cost of sales |  |  | (145 | ) |  |  | (104 | ) |  |  | (41 | ) |  |  | (43 | ) |  |  | (365 | ) |  |  | (323 | ) |  |  | — |  |  |  | (4 | ) |  |  | (551 | ) |  |  | (474 | )
Cost of sales |  |  | (1,958 | ) |  |  | (2,054 | ) |  |  | (1,681 | ) |  |  | (855 | ) |  |  | (365 | ) |  |  | (323 | ) |  |  | (41 | ) |  |  | (40 | ) |  |  | (4,045 | ) |  |  | (3,272 | )
Gross profit/(loss) |  |  | 1,896 |  |  |  | 2,102 |  |  |  | 489 |  |  |  | 464 |  |  |  | 201 |  |  |  | 190 |  |  |  | (41 | ) |  |  | (40 | ) |  |  | 2,545 |  |  |  | 2,716 |
Other income3 |  |  | 82 |  |  |  | 242 |  |  |  | 67 |  |  |  | 20 |  |  |  | (9 | ) |  |  | 20 |  |  |  | 239 |  |  |  | 33 |  |  |  | 379 |  |  |  | 315 |
Exploration and evaluation expenditure |  |  | (10 | ) |  |  | (12 | ) |  |  | (71 | ) |  |  | (86 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (81 | ) |  |  | (98 | )
Amortisation of permit acquisitions |  |  | — |  |  |  | — |  |  |  | (3 | ) |  |  | (5 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (3 | ) |  |  | (5 | )
Write-offs |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Exploration and evaluation |  |  | (10 | ) |  |  | (12 | ) |  |  | (74 | ) |  |  | (91 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (84 | ) |  |  | (103 | )
General, administration and other costs |  |  | (15 | ) |  |  | — |  |  |  | (8 | ) |  |  | — |  |  |  | (1 | ) |  |  | — |  |  |  | (237 | ) |  |  | (214 | ) |  |  | (261 | ) |  |  | (214 | )
Amortisation of intangible assets |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (11 | ) |  |  | (10 | ) |  |  | (11 | ) |  |  | (10 | )
Depreciation of lease assets |  |  | (18 | ) |  |  | (28 | ) |  |  | (1 | ) |  |  | (1 | ) |  |  | (39 | ) |  |  | (50 | ) |  |  | (27 | ) |  |  | (22 | ) |  |  | (85 | ) |  |  | (101 | )
Restoration movement4 |  |  | (443 | ) |  |  | (14 | ) |  |  | (2 | ) |  |  | (1 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (445 | ) |  |  | (15 | )
Other5 |  |  | (19 | ) |  |  | 16 |  |  |  | (2 | ) |  |  | — |  |  |  | (8 | ) |  |  | 58 |  |  |  | (49 | ) |  |  | (300 | ) |  |  | (78 | ) |  |  | (226 | )
Other costs |  |  | (495 | ) |  |  | (26 | ) |  |  | (13 | ) |  |  | (2 | ) |  |  | (48 | ) |  |  | 8 |  |  |  | (324 | ) |  |  | (546 | ) |  |  | (880 | ) |  |  | (566 | )
Other expenses |  |  | (505 | ) |  |  | (38 | ) |  |  | (87 | ) |  |  | (93 | ) |  |  | (48 | ) |  |  | 8 |  |  |  | (324 | ) |  |  | (546 | ) |  |  | (964 | ) |  |  | (669 | )
Impairment losses |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (143 | ) |  |  | — |  |  |  | (143 | ) |  |  | — |
Impairment reversals |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Profit/(loss) before tax and net finance costs |  |  | 1,473 |  |  |  | 2,306 |  |  |  | 469 |  |  |  | 391 |  |  |  | 144 |  |  |  | 218 |  |  |  | (269) |  |  |  | (553) |  |  |  | 1,817 |  |  |  | 2,362 |

1. | Intersegment revenue comprises the incremental income net of all incremental associated expenses generated by the Marketing segment. The value is incremental income net of incremental costs.

2. | Operating revenue includes revenue from contracts with customers of $6,577 million (2024: $5,981 million) and sub-lease income of $13 million (2024: $7 million) disclosed within shipping and other revenue.

3. | Includes a $162 million unrealised fair value gain on embedded derivatives, $32 million net gain on hedging activities, 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 updated closure cost estimates and economic assumptions at closed sites.

5. | Includes items not associated with the ongoing operations of the business. The 2024 amount includes a $153 million fair value loss on embedded derivatives.

32 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

A.2 Finance costs

|  | 2025 US$m |  |  | 2024 US$m |
Interest on interest-bearing liabilities |  |  | 281 |  |  |  | 125 |
Interest on lease liabilities |  |  | 51 |  |  |  | 51 |
Accretion charge |  |  | 148 |  |  |  | 145 |
Other finance costs |  |  | 29 |  |  |  | 13 |
Less: Finance costs capitalised against qualifying assets |  |  | (340 | ) |  |  | (187 | )
Total finance costs |  |  | 169 |  |  |  | 147 |

A.3 Dividends paid and proposed

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

|  | 2025 US$m |  |  | 2024 US$m |
(a) Dividends paid during the financial year Prior year fully franked final dividend US$0.53, paid on 2 April 2025 (2024: US$0.60, paid on 4 April 2024) |  |  | 1,006 |  |  |  | 1,139 |
(b) Dividend declared subsequent to the reporting period (not recorded as a liability) Current year fully franked interim dividend US$0.53, to be paid on 24 September 2025 (2024: US$0.69, paid on 3 October 2024) |  |  | 1,006 |  |  |  | 1,310 |

A.4 Earnings per share

|  | 2025 |  |  | 2024 |
Profit attributable to equity holders of the parent (US$m) |  |  | 1,316 |  |  |  | 1,937 |
Weighted average number of shares on issue for basic earnings per share |  |  | 1,895,162,804 |  |  |  | 1,896,041,815 |
Effect of dilution from contingently issuable shares |  |  | 17,049,593 |  |  |  | 14,691,983 |
Weighted average number of shares on issue adjusted for the effect of dilution |  |  | 1,912,212,397 |  |  |  | 1,910,733,798 |
Basic earnings per share (US cents) |  |  | 69.4 |  |  |  | 102.2 |
Diluted earnings per share (US cents) |  |  | 68.8 |  |  |  | 101.4 |

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.

33 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

A.5 Taxes

|  | 2025 US$m |  |  | 2024 US$m |
Reconciliation of income tax expense |  |  |  |  |  |  |  |
Profit before tax |  |  | 1,754 |  |  |  | 2,310 |
PRRT expense |  |  | (71 | ) |  |  | (192 | )
Profit before income tax |  |  | 1,683 |  |  |  | 2,118 |
Income tax expense calculated at 30% |  |  | 505 |  |  |  | 635 |
Effect of tax rate differentials |  |  | 42 |  |  |  | (15 | )
Effect of deferred tax assets not recognised |  |  | 12 |  |  |  | 35 |
Effect of tax benefits previously unrecognised |  |  | (193 | ) |  |  | (366 | )
Reduction in deferred tax liability due to held for sale basis |  |  | — |  |  |  | (91 | )
Foreign exchange impact on tax benefit |  |  | (35 | ) |  |  | (11 | )
Adjustment to prior years |  |  | 4 |  |  |  | (52 | )
Other |  |  | 18 |  |  |  | 11 |
Income tax expense |  |  | 353 |  |  |  | 146 |

The global operations effective income tax rate (EITR) of 21.0% (2024: 6.9%) is calculated as the Group’s income tax expense divided by profit before income tax. The underlying EITR is 30.9% when excluding the recognition of a $182 million deferred tax asset as a result of the Louisiana LNG FID and the $113 million post-tax H2OK impairment loss. At 30 June 2024, the Group’s normalised EITR was 25.6% when adjusting for one-off tax events.

34 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

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 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Carrying amount at 1 January 2025 |  |  | 571 |  |  |  | 149 |  |  |  | 1 |  |  |  | 721 |
Additions |  |  | 8 |  |  |  | 26 |  |  |  | — |  |  |  | 34 |
Amortisation of licence acquisition costs |  |  | — |  |  |  | (3 | ) |  |  | — |  |  |  | (3 | )
Transferred exploration and evaluation |  |  | (5 | ) |  |  | (1 | ) |  |  | — |  |  |  | (6 | )
Carrying amount at 30 June 2025 |  |  | 574 |  |  |  | 171 |  |  |  | 1 |  |  |  | 746 |
Year ended 31 December 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Carrying amount at 1 January 2024 |  |  | 568 |  |  |  | 76 |  |  |  | 24 |  |  |  | 668 |
Additions |  |  | 17 |  |  |  | 81 |  |  |  | 1 |  |  |  | 99 |
Amortisation of licence acquisition costs |  |  | — |  |  |  | (8 | ) |  |  | — |  |  |  | (8 | )
Expensed |  |  | (3 | ) |  |  | — |  |  |  | (6 | ) |  |  | (9 | )
Transferred exploration and evaluation |  |  | (11 | ) |  |  | — |  |  |  | (18 | ) |  |  | (29 | )
Carrying amount at 31 December 2024 |  |  | 571 |  |  |  | 149 |  |  |  | 1 |  |  |  | 721 |

35 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

B.2 Property, plant and equipment

|  | Land and buildings US$m |  |  | Oil and gas properties US$m |  |  | Other plant and equipment US$m |  |  | Projects in development1 US$m |  |  | Total US$m |
Half-year ended 30 June 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Carrying amount at 1 January 2025 |  |  | 734 |  |  |  | 25,787 |  |  |  | 189 |  |  |  | 15,926 |  |  |  | 42,636 |
Adjustment to purchase price allocation2 |  |  | (21 | ) |  |  | — |  |  |  | — |  |  |  | (9 | ) |  |  | (30 | )
Additions3 |  |  | — |  |  |  | 166 |  |  |  | — |  |  |  | 5,021 |  |  |  | 5,187 |
Disposals at written down value |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (3 | ) |  |  | (3 | )
Depreciation and amortisation |  |  | (30 | ) |  |  | (2,482 | ) |  |  | (29 | ) |  |  | — |  |  |  | (2,541 | )
Impairment losses4 |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (143 | ) |  |  | (143 | )
Completions and transfers |  |  | 3 |  |  |  | 851 |  |  |  | 72 |  |  |  | (920 | ) |  |  | 6 |
Transfer to assets held for sale5 |  |  | — |  |  |  | (44 | ) |  |  | — |  |  |  | (1 | ) |  |  | (45 | )
Carrying amount at 30 June 2025 |  |  | 686 |  |  |  | 24,278 |  |  |  | 232 |  |  |  | 19,871 |  |  |  | 45,067 |
At 30 June 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Historical cost |  |  | 1,812 |  |  |  | 57,974 |  |  |  | 605 |  |  |  | 20,400 |  |  |  | 80,791 |
Accumulated depreciation and impairment |  |  | (1,126 | ) |  |  | (33,696 | ) |  |  | (373 | ) |  |  | (529 | ) |  |  | (35,724 | )
Net carrying amount |  |  | 686 |  |  |  | 24,278 |  |  |  | 232 |  |  |  | 19,871 |  |  |  | 45,067 |
Year ended 31 December 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Carrying amount at 1 January 2024 |  |  | 701 |  |  |  | 24,168 |  |  |  | 198 |  |  |  | 15,724 |  |  |  | 40,791 |
Acquisitions through business combinations |  |  | 92 |  |  |  | — |  |  |  | — |  |  |  | 2,211 |  |  |  | 2,303 |
Additions |  |  | — |  |  |  | (293 | ) |  |  | — |  |  |  | 5,514 |  |  |  | 5,221 |
Disposals at written down value |  |  | (3 | ) |  |  | (4 | ) |  |  | — |  |  |  | (1,178 | ) |  |  | (1,185 | )
Depreciation and amortisation |  |  | (56 | ) |  |  | (4,419 | ) |  |  | (48 | ) |  |  | — |  |  |  | (4,523 | )
Completions and transfers |  |  | — |  |  |  | 6,335 |  |  |  | 39 |  |  |  | (6,345 | ) |  |  | 29 |
Carrying amount at 31 December 2024 |  |  | 734 |  |  |  | 25,787 |  |  |  | 189 |  |  |  | 15,926 |  |  |  | 42,636 |
At 31 December 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Historical cost |  |  | 1,830 |  |  |  | 58,303 |  |  |  | 533 |  |  |  | 16,300 |  |  |  | 76,966 |
Accumulated depreciation and impairment |  |  | (1,096 | ) |  |  | (32,516 | ) |  |  | (344 | ) |  |  | (374 | ) |  |  | (34,330 | )
Net carrying amount |  |  | 734 |  |  |  | 25,787 |  |  |  | 189 |  |  |  | 15,926 |  |  |  | 42,636 |

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

2. | Refer to Note B.4 for details on business combination.

3. | Includes $4,372 million of capital additions, $340 million of capitalised borrowing costs, $255 million relating to reimbursed capital expenditure from OCI N.V., $178 million relating to changes in restoration provision assumptions and $42 million of other additions. Included within capital additions is $2,655 million relating to Louisiana LNG at 100% working equity interest.

4. | Refer to Note B.6 for details of the impairment of the H2OK liquid hydrogen project.

5. | Refer to Note B.5 for details of the disposal of the Greater Angostura asset.

The Group has capital expenditure commitments contracted for, but not provided for in the financial statements, of $13,687 million (31 December 2024: $3,841 million). Capital expenditure commitments relate predominantly to the Louisiana LNG, Trion and Scarborough projects (31 December 2024: Trion, Scarborough and Louisiana LNG projects). Capital expenditure commitments include $10,956 million for Louisiana LNG. Stonepeak will pay for its share of the capital expenditure for Louisiana LNG up to a cap of $5.7 billion. Refer to Note B.5 for details of the sell-down of Louisiana LNG Infrastructure LLC to Stonepeak.

36 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

B.3 Intangible assets

|  | Goodwill US$m |  |  | Contract Assets US$m |  |  | Software US$m |  |  | Total US$m |
Half-year ended 30 June 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Carrying amount at 1 January 2025 |  |  | 3,866 |  |  |  | 757 |  |  |  | 203 |  |  |  | 4,826 |
Adjustment to purchase price allocation1 |  |  | 86 |  |  |  | 30 |  |  |  | — |  |  |  | 116 |
Additions |  |  | — |  |  |  | — |  |  |  | 1 |  |  |  | 1 |
Amortisation |  |  | — |  |  |  | (43 | ) |  |  | (9 | ) |  |  | (52 | )
Carrying amount at 30 June 2025 |  |  | 3,952 |  |  |  | 744 |  |  |  | 195 |  |  |  | 4,891 |
At 30 June 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cost |  |  | 4,429 |  |  |  | 814 |  |  |  | 219 |  |  |  | 5,462 |
Accumulated amortisation and impairment |  |  | (477 | ) |  |  | (70 | ) |  |  | (24 | ) |  |  | (571 | )
Net carrying amount |  |  | 3,952 |  |  |  | 744 |  |  |  | 195 |  |  |  | 4,891 |
Year ended 31 December 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Carrying amount at 1 January 2024 |  |  | 3,995 |  |  |  | 15 |  |  |  | 173 |  |  |  | 4,183 |
Acquisitions through business combinations and asset acquisitions |  |  | 169 |  |  |  | 766 |  |  |  | 6 |  |  |  | 941 |
Additions |  |  | — |  |  |  | 1 |  |  |  | 39 |  |  |  | 40 |
Amortisation |  |  | — |  |  |  | (25 | ) |  |  | (15 | ) |  |  | (40 | )
Goodwill disposed |  |  | (298 | ) |  |  | — |  |  |  | — |  |  |  | (298 | )
Carrying amount at 31 December 2024 |  |  | 3,866 |  |  |  | 757 |  |  |  | 203 |  |  |  | 4,826 |
At 31 December 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cost |  |  | 4,343 |  |  |  | 784 |  |  |  | 218 |  |  |  | 5,345 |
Accumulated amortisation and impairment |  |  | (477 | ) |  |  | (27 | ) |  |  | (15 | ) |  |  | (519 | )
Net carrying amount |  |  | 3,866 |  |  |  | 757 |  |  |  | 203 |  |  |  | 4,826 |

1. | Refer to Note B.4 for details on business combination.

37 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

B.4 Business combination

Acquisition of OCI Clean Ammonia Holding B.V. (OCI)

Refer to the 2024 Financial Statements for details of the acquisition of OCI Clean Ammonia Holding B.V. (subsequently renamed Beaumont New Ammonia Holding B.V.). Except for the changes noted below, the disclosures are consistent with Note B.5 of the 2024 financial statements.

On 5 August 2024, Woodside entered into a binding agreement to acquire 100% of OCI and its Beaumont New Ammonia Project for an all-cash consideration of $2,350 million. The Project is under construction and is subject to cost, schedule and performance guarantees from OCI N.V. The transaction was completed on 30 September 2024 and accounted for as a business combination.

The Group had 12 months from the transaction completion date to make adjustments to the fair value of net identifiable assets acquired and the resultant value of goodwill. As at 30 June 2025, the Group finalised the purchase price allocation based on updated information which has resulted in goodwill of $255 million, a net increase of $86 million from the amount reported at 31 December 2024.

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

Fair value of net identifiable assets and goodwill acquired, on acquisition date |  | US$m |
Cash and cash equivalents |  |  | 4 |
Receivables |  |  | 720 |
Property, plant and equipment |  |  | 906 |
Intangible assets |  |  | 796 |
Other assets |  |  | 2 |
Payables |  |  | (43 | )
Deferred tax liabilities |  |  | (154 | )
Provisions |  |  | (116 | )
Fair value of net identifiable assets acquired |  |  | 2,115 |
Goodwill arising on acquisition |  |  | 255 |
Total purchase consideration1 |  |  | 2,370 |

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

Purchase consideration |  | US$m |
Cash payment |  |  | 1,900 |
Contingent consideration2 |  |  | 470 |
Total purchase consideration |  |  | 2,370 |

2. | Contingent consideration relating to the remaining 20% of the consideration to be paid to OCI N.V. at project completion.

Analysis of cash flows on acquisition |  | US$m |
Cash payment |  |  | (1,900 | )
Cash and cash equivalents acquired |  |  | 4 |
Net cash flow on acquisition |  |  | (1,896 | )

38 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

B.4 Business combination (continued)

Key estimates and judgements

(a) | Nature of acquisition

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

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

(b) | Fair value determination for net assets acquired

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

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

(c) | Contingent consideration

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

39 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

B.5 Disposal and sell-down of assets

Sell-down of Louisiana LNG Infrastructure LLC to Stonepeak Wallaby I Acquiror LP

On 7 April 2025, the Group and Stonepeak Wallaby I Acquiror LP (Stonepeak) entered into an agreement for Stonepeak to acquire a 40% interest in Louisiana LNG Infrastructure LLC, a subsidiary within the Group. The transaction completed on 25 June 2025, with an effective date of 1 January 2025. Stonepeak will provide up to $5.7 billion towards the expected capital expenditure for the foundation development of Louisiana LNG on an accelerated basis, contributing 75% of the expected project capital expenditure in both 2025 and 2026. A payment of $1,870 million was received on the transaction completion date.

Under the agreement, the Group still controls Louisiana LNG Infrastructure LLC, while Stonepeak now holds a non-controlling interest. Transactions that do not result in the Group’s loss of control are treated as equity transactions. When ownership percentages change, the carrying amounts of both controlling and non-controlling interests are adjusted based on their relative interest in the subsidiary. Any difference between the adjustment to non-controlling interests and consideration received is recorded in a separate equity reserve. Stonepeak’s non-controlling interest percentage is based on the proportion of total contributions to date and will fluctuate during the construction phase. The non-controlling interest percentage is expected to revert to 40% when the project starts generating revenue.

The proceeds of $1,870 million received from Stonepeak are included in contributions from non-controlling interests in the condensed consolidated statement of cash flows as at 30 June 2025. As at 30 June 2025, $2,140 million has been recognised as non-controlling interest, and $270 million has been recognised in other reserves for the difference in proceeds received and the non-controlling interest recognised.

Key estimates and judgements

(a) | Control

Under AASB/IFRS 10 Consolidated Financial Statements, consolidation is required when an investor controls an investee. If a parent loses control of a subsidiary, the parent is required to derecognise the assets and liabilities of the former subsidiary at their carrying amounts at the date when control is lost. Judgement is required to determine if the Group continues to control Louisiana LNG Infrastructure LLC after the sell-down.

The Group continues to control and consolidate Louisiana LNG Infrastructure LLC as it has the power to direct the relevant activities and decisions requiring majority approval through its roles as operator, construction manager, and majority interest.

(b) | Classification of non-controlling interest as equity or liability

Judgement is required to determine if the classification of the non-controlling interest is either equity or liability based on the Group’s contractual obligation to deliver cash or another financial asset.

Louisiana LNG Infrastructure LLC is not required to distribute dividends unless Woodside Energy Group Ltd declares dividends. As the Group can indefinitely defer payment of the Louisiana LNG Infrastructure LLC dividend based on the terms in the agreement, the non-controlling interest in Louisiana LNG Infrastructure LLC is classified as equity in the Group’s condensed consolidated financial statements. While the terms grant the Group discretion to avoid distributing dividends from Louisiana LNG Infrastructure LLC, the exercise of this discretion may increase the non-controlling interest’s entitlement to future discretionary distributions.

40 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

B.5 Disposal and sell-down of assets (continued)

Disposal of Greater Angostura assets to Perenco Energies International Limited

On 28 March 2025, the Group and Perenco Energies International Limited (Perenco) entered into an agreement for Perenco to acquire the Greater Angostura assets in Trinidad and Tobago for $259 million, which is made up of a base purchase price of $206 million plus completion adjustments for working capital and interest. The divestment includes Woodside’s 45% interest in the Angostura field and 68.46% in the Ruby field along with the associated production facilities and onshore terminal.

As at 30 June 2025, the Group has reclassified $447 million of assets, being the carrying value of the Angostura and Ruby fields within the International segment, to assets held for sale. Liabilities of $416 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 2025:

|  | 30 June 2025 US$m |
Assets classified as held for sale |  |  |  |
Cash and cash equivalents |  |  | 108 |
Receivables |  |  | 194 |
Property, plant and equipment |  |  | 45 |
Inventories |  |  | 17 |
Lease assets |  |  | 1 |
Other assets |  |  | 82 |
Total assets held for sale |  |  | 447 |
Liabilities directly associated with assets held for sale |  |  |  |
Payables |  |  | (199 | )
Deferred tax liabilities |  |  | (20 | )
Lease liabilities |  |  | (1 | )
Provisions |  |  | (196 | )
Total liabilities directly associated with assets held for sale |  |  | (416 | )

The transaction completed on 11 July 2025 (refer to Note E.3), with an effective date of 1 January 2025. The Group no longer holds any interest in the Angostura and Ruby fields. The full financial effect of the transaction is under assessment.

B.6 Impairment of exploration and evaluation, property, plant and equipment and goodwill

Impairment of H2OK liquid hydrogen project

As at 30 June 2025, an impairment indicator was identified on the H2OK Project following the Group’s decision to exit the Project. Based on management’s judgement, the estimated recoverable value of the project’s inventory and property, plant and equipment are expected to be less than the carrying value. As a result, an impairment loss before tax of $143 million was recognised in the New energy/Corporate segment of Note A.1 for the half-year ended 30 June 2025.

41 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

C. Debt and capital

C.1 Contributed equity

Issued and fully paid shares |  | Number of Shares |  |  | US$m |
Half-year ended 30 June 2025 |  |  |  |  |  |  |  |
Opening balance |  |  | 1,898,749,771 |  |  |  | 29,001 |
Amounts as at 30 June 2025 |  |  | 1,898,749,771 |  |  |  | 29,001 |
Year ended 31 December 2024 |  |  |  |  |  |  |  |
Opening balance |  |  | 1,898,749,771 |  |  |  | 29,001 |
Amounts as at 31 December 2024 |  |  | 1,898,749,771 |  |  |  | 29,001 |

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 Company’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 2025 |  |  |  |  |  |  |  |
Opening balance as at 1 January 2025 |  |  | 3,080,842 |  |  |  | (58) |
Purchases during the year |  |  | 1,650,000 |  |  |  | (26) |
Vested during the year |  |  | (664,915) |  |  |  | 13 |
Amounts as at 30 June 2025 |  |  | 4,065,927 |  |  |  | (71) |
Year ended 31 December 2024 |  |  |  |  |  |  |  |
Opening balance as at 1 January 2024 |  |  | 2,140,927 |  |  |  | (49) |
Purchases during the year |  |  | 4,293,699 |  |  |  | (81) |
Vested during the year |  |  | (3,353,784) |  |  |  | 72 |
Amounts as at 31 December 2024 |  |  | 3,080,842 |  |  |  | (58) |

42 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

C.2 Interest-bearing liabilities and financing facilities

|  | Liquidity Facilities US$m |  |  | Bilateral Facilities US$m |  |  | Syndicated Facilities US$m |  |  | JBIC Facility US$m |  |  | US Bonds US$m |  |  | Medium Term Notes US$m |  |  | Other US$m |  |  | Total US$m |
Half-year ended 30 June 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
At 1 January 2025 |  |  | — |  |  |  | 495 |  |  |  | 2,233 |  |  |  | 1,000 |  |  |  | 6,069 |  |  |  | 200 |  |  |  | — |  |  |  | 9,997 |
Drawdowns1 |  |  | — |  |  |  | 1,400 |  |  |  | — |  |  |  | — |  |  |  | 3,500 |  |  |  | — |  |  |  | — |  |  |  | 4,900 |
Repayments1 |  |  | — |  |  |  | (1,900 | ) |  |  | — |  |  |  | — |  |  |  | (1,000 | ) |  |  | — |  |  |  | — |  |  |  | (2,900 | )
Transaction costs capitalised and amortised |  |  | — |  |  |  | (1 | ) |  |  | (3 | ) |  |  | — |  |  |  | (39 | ) |  |  | — |  |  |  | — |  |  |  | (43 | )
Carrying amount at 30 June 2025 |  |  | — |  |  |  | (6 | ) |  |  | 2,230 |  |  |  | 1,000 |  |  |  | 8,530 |  |  |  | 200 |  |  |  | — |  |  |  | 11,954 |
Current2 |  |  | — |  |  |  | (3 | ) |  |  | (4 | ) |  |  | — |  |  |  | (11 | ) |  |  | — |  |  |  | — |  |  |  | (18 | )
Non-current |  |  | — |  |  |  | (3 | ) |  |  | 2,234 |  |  |  | 1,000 |  |  |  | 8,541 |  |  |  | 200 |  |  |  | — |  |  |  | 11,972 |
Carrying amount at 30 June 2025 |  |  | — |  |  |  | (6 | ) |  |  | 2,230 |  |  |  | 1,000 |  |  |  | 8,530 |  |  |  | 200 |  |  |  | — |  |  |  | 11,954 |
Undrawn balance at 30 June 2025 |  |  | — |  |  |  | 2,350 |  |  |  | 1,200 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3,550 |
Year ended 31 December 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
At 1 January 2024 |  |  | (1 | ) |  |  | (6 | ) |  |  | 594 |  |  |  | — |  |  |  | 4,087 |  |  |  | 200 |  |  |  | — |  |  |  | 4,874 |
Debt acquired through asset acquisitions |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 169 |  |  |  | 169 |
Drawdowns1 |  |  | — |  |  |  | 500 |  |  |  | 1,650 |  |  |  | 1,000 |  |  |  | 2,000 |  |  |  | — |  |  |  | — |  |  |  | 5,150 |
Repayments1 |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (169 | ) |  |  | (169 | )
Transaction costs capitalised and amortised |  |  | 1 |  |  |  | 1 |  |  |  | (11 | ) |  |  | — |  |  |  | (18 | ) |  |  | — |  |  |  | — |  |  |  | (27 | )
Carrying amount at 31 December 2024 |  |  | — |  |  |  | 495 |  |  |  | 2,233 |  |  |  | 1,000 |  |  |  | 6,069 |  |  |  | 200 |  |  |  | — |  |  |  | 9,997 |
Current |  |  | — |  |  |  | (2 | ) |  |  | (4 | ) |  |  | — |  |  |  | 996 |  |  |  | — |  |  |  | — |  |  |  | 990 |
Non-current |  |  | — |  |  |  | 497 |  |  |  | 2,237 |  |  |  | 1,000 |  |  |  | 5,073 |  |  |  | 200 |  |  |  | — |  |  |  | 9,007 |
Carrying amount at 31 December 2024 |  |  | — |  |  |  | 495 |  |  |  | 2,233 |  |  |  | 1,000 |  |  |  | 6,069 |  |  |  | 200 |  |  |  | — |  |  |  | 9,997 |
Undrawn balance at 31 December 2024 |  |  | — |  |  |  | 1,600 |  |  |  | 1,200 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2,800 |

1. | Included in cash flows classified within financing activities in the condensed consolidated statement of cash flows.

2. | The balance relates to capitalised costs to be amortised within the next 12 months. This balance has been reclassified to other assets (current) for presentation on the condensed consolidated statement of financial position.

During the period, the Group:

| • |  | Repaid $1,000 million of US bonds in March 2025.

| • |  | Renewed a $100 million bilateral facility and executed two bilateral facilities amounting to $250 million in March 2025.

| • |  | Drew down on four bilateral facilities amounting to $800 million in March 2025.

| • |  | Entered into two 12-month liquidity facilities of $1,500 million each in March 2025. Interest rates are based on daily Secured Overnight Financing Rate (SOFR) plus margin, fixed at the commencement of the drawdown period. These facilities were cancelled upon receiving the cash from the unsecured bonds in May 2025.

| • |  | Drew down on four bilateral facilities amounting to $600 million in April 2025.

| • |  | Issued the following unsecured bonds in accordance with the registration requirements of the US Securities Act of 1933 (SEC-registered bonds) in May 2025:

| • |  | $500 million of 3-year bonds with a nominal interest rate of 4.9%

| • |  | $1,250 million of 5-year bonds with a nominal interest rate of 5.4%

| • |  | $500 million of 7-year bonds with a nominal interest rate of 5.7%

| • |  | $1,250 million of 10-year bonds with a nominal interest rate of 6.0%.

| • |  | Repaid $1,900 million of bilateral facilities in June 2025.

There were no new covenants or other material changes to interest-bearing liabilities and financing facilities.

43 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

C.2 Interest-bearing liabilities and financing facilities (continued)

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 $8,530 million (31 December 2024: $6,069 million) and a fair value of $8,489 million (31 December 2024: $5,879 million). The medium-term notes have a carrying amount of $200 million (31 December 2024: $200 million) and a fair value of $195 million (31 December 2024: $191 million). Fair value is calculated based on the present value of future principal and interest cash flows, discounted at the market rate of interest at the reporting date and classified as Level 1 on the fair value hierarchy.

44 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

D. Other assets and liabilities

D.1 Segment assets and liabilities

|  | 30 June 2025 US$m |  |  | 31 December 2024 US$m |
(a) Segment assets |  |  |  |  |  |  |  |
Australia |  |  | 29,779 |  |  |  | 29,678 |
International |  |  | 21,666 |  |  |  | 19,556 |
Marketing |  |  | 734 |  |  |  | 754 |
New energy/Corporate |  |  | 12,698 |  |  |  | 11,276 |
|  |  | 64,877 |  |  |  | 61,264 |

|  | 30 June 2025 US$m |  |  | 31 December 2024 US$m |
(b) Segment liabilities |  |  |  |  |  |  |  |
Australia |  |  | 6,959 |  |  |  | 6,953 |
International |  |  | 2,447 |  |  |  | 2,616 |
Marketing |  |  | 833 |  |  |  | 1,115 |
New energy/Corporate |  |  | 16,131 |  |  |  | 14,427 |
|  |  | 26,370 |  |  |  | 25,111 |

New energy/Corporate assets mainly comprise cash and cash equivalents, deferred tax assets, new energy assets in development and lease assets. New energy/Corporate liabilities mainly comprise interest-bearing liabilities, deferred tax liabilities and lease liabilities.

45 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

D.2 Provisions

|  | Restoration1 US$m |  |  | Employee benefits US$m |  |  | Other US$m |  |  | Total US$m |
Half-year ended 30 June 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
At 1 January 2025 |  |  | 6,526 |  |  |  | 654 |  |  |  | 367 |  |  |  | 7,547 |
Adjustment to purchase price allocation2 |  |  | — |  |  |  | — |  |  |  | 100 |  |  |  | 100 |
Change in provision |  |  | 123 |  |  |  | (114) |  |  |  | (184) |  |  |  | (175) |
Unwinding of present value discount |  |  | 145 |  |  |  | 3 |  |  |  | — |  |  |  | 148 |
Transfer to liabilities held for sale3 |  |  | (177) |  |  |  | (2) |  |  |  | (17) |  |  |  | (196) |
Carrying amount at 30 June 2025 |  |  | 6,617 |  |  |  | 541 |  |  |  | 266 |  |  |  | 7,424 |
Current |  |  | 683 |  |  |  | 316 |  |  |  | 173 |  |  |  | 1,172 |
Non-current |  |  | 5,934 |  |  |  | 225 |  |  |  | 93 |  |  |  | 6,252 |
Net carrying amount |  |  | 6,617 |  |  |  | 541 |  |  |  | 266 |  |  |  | 7,424 |
Year ended 31 December 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
At 1 January 2024 |  |  | 7,154 |  |  |  | 522 |  |  |  | 281 |  |  |  | 7,957 |
Acquisitions through business combinations and asset acquisitions |  |  | 16 |  |  |  | 104 |  |  |  | 48 |  |  |  | 168 |
Change in provision |  |  | (936) |  |  |  | 28 |  |  |  | 37 |  |  |  | (871) |
Unwinding of present value discount |  |  | 292 |  |  |  | — |  |  |  | 1 |  |  |  | 293 |
Carrying amount at 31 December 2024 |  |  | 6,526 |  |  |  | 654 |  |  |  | 367 |  |  |  | 7,547 |
Current |  |  | 753 |  |  |  | 402 |  |  |  | 167 |  |  |  | 1,322 |
Non-current |  |  | 5,773 |  |  |  | 252 |  |  |  | 200 |  |  |  | 6,225 |
Net carrying amount |  |  | 6,526 |  |  |  | 654 |  |  |  | 367 |  |  |  | 7,547 |

1. | 2025 change in provision is due to changes in estimates of $445 million, changes in foreign exchange rates of $152 million and a revision of discount rates of $43 million, offset by provisions used of $517 million.

2. | Refer to Note B.4 for details on business combination.

3. | Refer to Note B.5 for details of the disposal of the Greater Angostura asset.

46 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

D.3 Other financial assets and liabilities

|  | 30 June 2025 US$m |  |  | 31 December 2024 US$m |
Other financial assets |  |  |  |  |  |  |  |
Financial instruments at fair value through profit and loss |  |  |  |  |  |  |  |
Derivative financial instruments designated as hedges |  |  | 271 |  |  |  | 186 |
Other financial assets |  |  | 34 |  |  |  | 28 |
Financial instruments at fair value through other comprehensive income |  |  |  |  |  |  |  |
Other financial assets |  |  | 57 |  |  |  | 89 |
Total other financial assets |  |  | 362 |  |  |  | 303 |
Current |  |  | 274 |  |  |  | 185 |
Non-current |  |  | 88 |  |  |  | 118 |
Total other financial assets |  |  | 362 |  |  |  | 303 |
Other financial liabilities |  |  |  |  |  |  |  |
Financial instruments at fair value through profit and loss |  |  |  |  |  |  |  |
Derivative financial instruments designated as hedges |  |  | 33 |  |  |  | 169 |
Embedded derivative |  |  | 187 |  |  |  | 349 |
Other financial liabilities |  |  | 9 |  |  |  | — |
Total other financial liabilities |  |  | 229 |  |  |  | 518 |
Current |  |  | 35 |  |  |  | 139 |
Non-current |  |  | 194 |  |  |  | 379 |
Total other financial liabilities |  |  | 229 |  |  |  | 518 |

Hedging activities

During the period, the following hedging activities were undertaken:

| • |  | Of the 30 MMboe of 2025 oil production previously hedged at an average price of $78.7 per barrel, approximately 58% was delivered by 30 June 2025. A total of 10 MMboe of 2026 oil production was hedged at an average price of approximately $70.1 per barrel.

| • |  | The Group also has a hedging program for Corpus Christi LNG volumes. These hedges are Henry Hub (HH) and Title Transfer Facility (TTF) commodity swaps. Approximately 94% of Corpus Christi volumes for the remainder of 2025 and 87% 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 Energy Project development.

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

|  | 30 June 2025 US$m |  |  | 31 December 2024 US$m |
Brent commodity swaps (cash flow hedges) |  |  | 191 |  |  |  | 137 |
HH natural gas commodity swaps (cash flow hedges) |  |  | 21 |  |  |  | 8 |
TTF LNG commodity swaps (cash flow hedges) |  |  | (6) |  |  |  | (118) |
Interest rate swaps (cash flow hedges) |  |  | 23 |  |  |  | 35 |
Foreign exchange forwards (cash flow hedges) |  |  | 9 |  |  |  | (45) |
Total derivative financial instruments asset designated as hedges |  |  | 238 |  |  |  | 17 |

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 2025 amounted to a net liability of $187 million (31 December 2024: net liability of $349 million). The derivative is remeasured to fair value at each reporting date. For the six-month period ended 30 June 2025, an unrealised gain of $162 million has been recognised through other income (30 June 2024: unrealised loss of $153 million through other expenses).

47 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

D.3 Other financial assets and liabilities (continued)

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 reclassification between the fair value hierarchy levels.

Except for the revised valuation inputs for the embedded commodity derivative, there were no changes to the Group’s valuation processes, valuation techniques and types of inputs used in the fair value measurements during the period.

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 2024 Financial Statements. There have been no significant changes in risk management policies since 31 December 2024. Refer to the embedded commodity derivative key estimates and judgements section below for the sensitivity assessment on discount rates and pricing.

Key estimates and judgements

(a) Change in embedded commodity derivative valuation inputs

The Group has reassessed the valuation inputs of the Perdaman embedded derivative factoring current market conditions and as a result revised pricing inputs that reflect the long-term nature of the contract and external market data. The change has been applied from 1 January 2025, resulting in an increase in fair value gains of $18 million for the half-year ended 30 June 2025. The effect in future periods is not disclosed because estimating it is impracticable.

(b) 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 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: 5.02% to 6.88%).

| - | Domestic gas pricing – forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (TTF) prices available in the market.

The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses recognised in other income/expenses. The nominal impacts of the effects of changes to discount rate and long-term price assumptions are estimated as follows. The valuation is over a contract period of 20 years and the below change in assumptions applies a linear increase or decrease in inputs over the life of the contract. A spot increase is not represented by the sensitivity below.

Change in assumption1 |  | US$m |
TTF sales price: increase of 10% |  |  | 184 |
TTF sales price: decrease of 10% |  |  | (182 | )
Discount rate: increase of 1.5%2 |  |  | (206 | )
Discount rate: decrease of 1.5%2 |  |  | 255 |

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.

48 | Half-Year Report 2025 |  |

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2025

E. Other items

E.1 Contingent liabilities and assets

|  | 30 June 2025 US$m |  |  | 31 December 2024 US$m |
Contingent liabilities at reporting date |  |  |  |  |  |  |  |
Contingent liabilities |  |  | 309 |  |  |  | 281 |
Guarantees |  |  | 1 |  |  |  | 1 |
Total disclosed contingent liabilities |  |  | 310 |  |  |  | 282 |

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 $23 million as at 30 June 2025 (31 December 2024: $30 million).

E.2 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 2025 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 which is currently in progress.

E.3 Events after the end of the reporting period

Completion of the disposal of Greater Angostura assets to Perenco

On 28 March 2025, the Group and Perenco entered into an agreement for Perenco to acquire the Greater Angostura assets in Trinidad and Tobago for $259 million, which is made up of a base purchase price of $206 million plus completion adjustments for working capital and interest. The transaction completed on 11 July 2025, with an effective date of 1 January 2025. The Group no longer holds any interest in the Angostura and Ruby fields. The full financial effect of the transaction is under assessment.

Operatorship of Bass Strait assets

On 29 July 2025, the Group has agreed with ExxonMobil Australia (ExxonMobil) to assume operatorship of the Bass Strait production assets, the Longford Gas Plant, the Long Island Point gas liquids processing facility and associated pipeline infrastructure. The Group’s and ExxonMobil’s equity interest in the Joint Venture’s assets and current decommissioning plans and provisions remain unchanged. The transaction is subject to conditions precedent including obtaining regulatory approvals, and is expected to complete in 2026.

Woodside will acquire ExxonMobil’s employing entity for the Bass Strait employees which includes employee related assets and liabilities. The employee expenses continue to be funded by the Bass Strait joint venture partners based on their equity interests. The acquisition of the employing entity is expected to be treated as a business combination and the full financial impact will be determined at completion.

49 | Half-Year Report 2025 |  |

DIRECTORS’ DECLARATION

for the half-year ended 30 June 2025

In accordance with a resolution of directors of Woodside Energy Group Ltd, we state that:

In the opinion of the directors:

| a) | the financial statements and notes of the Group are in accordance with the Australian Corporations Act 2001, including:

| i. | giving a true and fair view of the Group’s financial position as at 30 June 2025 and of its performance for the half-year ended on that date; and

| ii. | complying with Australian Accounting Standard AASB 134 and International Accounting Standard IAS 34 Interim Financial Reporting and the Corporations Regulations 2001;

| b) | there are reasonable grounds to believe that Woodside Energy Group Ltd will be able to pay its debts as and when they become due and payable.

On behalf of the Board

R J Goyder, AO |  |  |  | M E O’Neill
Chair of the Board |  |  |  | Chief Executive Officer and Managing Director
Perth, Western Australia |  |  |  | Sydney, New South Wales
19 August 2025 |  |  |  | 19 August 2025

50 | Half-Year Report 2025 |  |

INDEPENDENT AUDITOR’S REVIEW REPORT

Independent auditor’s review report to the members of Woodside Energy Group Ltd

Report on the half-year financial report

Conclusion

We have reviewed the half-year financial report of Woodside Energy Group Ltd (the Company) and the entities it controlled during the half-year (together the Group), which comprises the condensed consolidated statement of financial position as at 30 June 2025, the condensed consolidated income statement, condensed consolidated statement of comprehensive income, condensed consolidated statement of cash flows, condensed consolidated statement of changes in equity for the half-year ended on that date, selected explanatory notes and the directors’ declaration.

Based on our review, which is not an audit, we have not become aware of any matter that makes us believe that the accompanying half-year financial report of Woodside Energy Group Ltd does not comply with the Corporations Act 2001 including:

1. | giving a true and fair view of the Group’s financial position as at 30 June 2025 and of its performance for the half-year ended on that date

2. | complying with Accounting Standard AASB 134 Interim Financial Reporting and the Corporations Regulations 2001.

Basis for conclusion

We conducted our review in accordance with ASRE 2410 Review of a Financial Report Performed by the Independent Auditor of the Entity (ASRE 2410). Our responsibilities are further described in the Auditor’s responsibilities for the review of the half-year financial report section of our report.

We are independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and the ethical requirements of the Accounting Professional & Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants (including Independence Standards) (the Code) that are relevant to the audit of the annual financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance with the Code.

pwc.com.au |  | PricewaterhouseCoopers, ABN 52 780 433 757 Brookfield Place, Level 15, 125 St Georges Terrace, PERTH WA 6000, GPO Box D198, PERTH WA 6840 T: +61 8 9238 3000, F: +61 8 9238 3999, www.pwc.com.au Liability limited by a scheme approved under Professional Standards Legislation.

51 | Half-Year Report 2025 |  |

Responsibilities of the directors for the half-year financial report

The directors of the Company are responsible for the preparation of the half-year financial report, in accordance with Australian Accounting Standards and the Corporations Act 2001, including giving a true and fair view, and for such internal control as the directors determine is necessary to enable the preparation of the half-year financial report that is free from material misstatement whether due to fraud or error.

Auditor’s responsibilities for the review of the half-year financial report

Our responsibility is to express a conclusion on the half-year financial report based on our review. ASRE 2410 requires us to conclude whether we have become aware of any matter that makes us believe that the half-year financial report is not in accordance with the Corporations Act 2001 including giving a true and fair view of the Group’s financial position as at 30 June 2025 and of its performance for the half-year ended on that date, and complying with Accounting Standard AASB 134 Interim Financial Reporting and the Corporations Regulations 2001.

A review of a half-year financial report consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with Australian Auditing Standards and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

PricewaterhouseCoopers

N M Henry |  | Perth
Partner |  | 19 August 2025

52 | Half-Year Report 2025 |  |

Appendix 4D

Dividends

Ex-dividend date |  | 28 August 2025 |  |  |  |
Record date for the interim dividend |  | 29 August 2025 |  |  |  |
Date the dividend is payable |  | 24 September 2025 |  |  |  |
|  |  |  | Current period |  | Previous corresponding period39
Interim dividend – fully franked |  | US cents per share |  | 53 |  | 69

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 1 September 2025.

Net Tangible Assets per ordinary security

|  | Current period US$ |  | Previous corresponding period39 US$
Net Tangible Assets (US$ per ordinary security)40 |  | 16.19 |  | 16.42

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 period39
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% |  | 16.17%
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 |  | 12.05% |  | 10.00%

39 | Comparisons are to half-year ended 30 June 2024.

40 | Includes lease assets and lease liabilities as a result of AASB 16/ IFRS 16 Leases. Net Tangible Assets per ordinary security is a non-IFRS measure. Refer to Alternative Performance Measures for a reconciliation for these measures to Woodside’s financial statements on pages 55-57.

53 | Half-Year Report 2025 |  |

Shareholder information

Key announcements 2025

January |  | Fourth quarter 2024 report
February |  | Woodside release Reserves Statement and Sangomar update
| Woodside Releases Full-Year 2024 results
| Full-Year 2024 Results Briefing Transcript
| Annual Report 2024 [and US Annual Report 2024 (Form 20-F)]
March |  | Woodside to divest Greater Angostura assets to Perenco
April |  | Sustainability Briefing 2025
| Woodside announces Louisiana LNG partnership with Stonepeak
| Woodside signs LNG supply agreements with Uniper
| First quarter 2025 report
| Woodside approves Louisiana LNG development
| Woodside signs gas supply agreement for Louisiana LNG
May |  | 2025 Annual General Meeting voting results
| Woodside prices US bond offer
| Woodside welcomes proposed NWS extension approval
June |  | Woodside completes Louisiana LNG sell-down to Stonepeak
July |  | Second quarter 2025 report
| Woodside strengthens its Australian operations
August |  | Half-Year 2025 results

Events calendar 2025-2026

Key calendar dates for Woodside shareholders in 2025-2026. Please note dates are subject to review.

August |  | 19 |  | Half-Year 2025 results
| 28 |  | Ex-dividend date for interim dividend (Australian Securities Exchange)
| 29 |  | Ex-dividend date for interim dividend (New York Stock Exchange)
| 29 |  | Record date for interim dividend
September |  | 24 |  | Payment date for interim dividend
October |  | 22 |  | Third quarter 2025 report
November |  | 5 |  | Capital Markets Day
December |  | 31 |  | Year-end 2025
January |  | 21 |  | Fourth quarter 2025 report

54 | Half-Year Report 2025 |  |

Business directory

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

Investor enquiries

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

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

Share registry enquiries

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

Registered office: |  | Postal address:
Computershare Investor Services Pty Limited |  | GPO Box D182
Level 17 |  | Perth WA 6840
221 St Georges Terrace |  |
Perth WA 6000 |  | 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 authorised depositary bank for Woodside’s American Depositary Receipt programme can be found on our website.

55 | Half-Year Report 2025 |  |

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
Wheatstone1 |  | Non-operator |  | 13% |  | LNG, pipeline gas and condensate
Julimar-Brunello |  | Operator |  | 65%
Okha FPSO1 |  | Operator |  | 50% |  | Crude oil
Ngujima-Yin FPSO |  | Operator |  | 60% |  | Crude oil
Bass Strait |  | Non-operator |  | 32.5-50% |  | Pipeline gas, condensate and NGLs
Pyrenees FPSO |  | Operator |  | 40-71.4% |  | Crude oil
Macedon |  | Operator |  | 71.4% |  | Pipeline gas

1. | In December 2024, Woodside entered into an asset swap with Chevron, refer to “Woodside simplifies portfolio and unlocks long-term value” announced 19 December 2024 for details.

International

Asset |  | Role |  | Equity |  | Product
Sangomar |  | Operator |  | 82% |  | Crude oil
Greater Angostura1 |  | 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

1. | The divestment of the Greater Angostura assets to Perenco was completed on 11 July 2025.

56 | Half-Year Report 2025 |  |

Projects

Post FID

Asset |  | Role |  | Equity |  | Product
Scarborough |  | Operator |  | 74.9% |  | LNG and pipeline gas
Pluto Train 2 |  | Operator |  | 51.0% |  | LNG
Trion |  | Operator |  | 60.0% |  | Crude oil
Beaumont New Ammonia |  | Operator |  | 100.0% |  | Ammonia
Louisiana LNG LLC |  | Operator |  | 100.0% |  | LNG
Louisiana LNG Infrastructure LLC |  | Operator |  | 60.0% |  | LNG
Hydrogen Refueller@H2Perth |  | Operator |  | 100% |  | Hydrogen

Developments

Asset |  | Role |  | Equity |  | Product
Calypso |  | Operator |  | 70% |  | Gas
Browse |  | Operator |  | 31% |  | LNG, pipeline gas and condensate
Greater Scarborough1 |  | Operator |  | 100% |  | Gas
Liard |  | Non-operator |  | 50% |  | Gas
Sunrise |  | Operator |  | 33% |  | LNG, pipeline gas and condensate

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

New energy opportunities1

Asset |  | Role |  | Equity |  | Product
H2Perth |  | Operator |  | 100% |  | Hydrogen
NeoSmelt |  | Non-operator |  | 20% |  | Iron
Woodside Solar2 |  | Proponent |  | 100% |  | Solar energy

1. | Subject to a final investment decision 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.

57 | Half-Year Report 2025 |  |

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 Venture1 |  | Located in the Northern Carnarvon basin off the north west coast of Western Australia
| G-18-AP |  | Non-operator |  | Greenhouse Gas Assessment Permit G-18-AP Joint Venture |  | Located in the Northern Carnarvon Basin off the north west coast of Western Australia
| G-19-AP |  | Non-operator |  | Gippsland Basin Joint Venture |  | Located in the Gippsland Basin off the coast of Victoria

1. | In December 2024, Woodside entered into an asset swap with Chevron, refer to “Woodside simplifies portfolio and unlocks long-term value” announced 19 December 2024 for details.

58 | Half-Year Report 2025 |  |

Exploration

Country |  | Permit |  | Role |  | Equity |  | Product
Asia – Pacific |  |  |  |  |  |  |  |
Australia |  | WA-404-P |  | Operator |  | 100% |  | Gas prone basin
| WA-550-P |  | Operator |  | 100% |  | Gas prone basin
| WA-554-P |  | Operator |  | 100% |  | Gas prone basin
| WA-28-P |  | Operator |  | 15.78%- 33% |  | Oil and gas prone basin
|  |  | Non-operator |  | 15.78%-16.67% |  | Oil and gas prone basin
Europe |  |  |  |  |  |  |  |
Ireland |  | FEL 5/13 |  | Operator |  | 100% - Exit initiated |  | Oil or gas prone basin
Africa |  |  |  |  |  |  |  |
Congo |  | Marine XX |  | Non-operator |  | 23% |  | Oil or gas prone basin
Egypt |  | Tiba Block |  | Non-operator |  | 40% |  | Oil and gas prone basin
| North EI Dabaa Offshore (Block 4) |  | Non-operator |  | 27% |  | Oil or gas prone basin
Caribbean |  |  |  |  |  |  |  |
Barbados |  | Bimshire |  |  |  | 60% - Exit initiated |  | Oil or gas prone basin
North America |  |  |  |  |  |  |  |
United States |  | GB 529, GB 530, GB 531, GB 574, GB 575, GB 619, GB 630, GB 672, GB 676, GB 677, GB 716, GB 721, GB 760, GB 762, GB 780, GB 805, GB 806, GB 821, GB 824, GB 825, GB 851, GB 852, GB 866, GB 895, EB 550, EB 594, EB 636, EB 637, EB 638, KC 859, KC 903, KC 904, KC 905, KC 948, KC 949, WR 795, WR 796, GB 663, GB 664, GB 678, GC 210, GC 211 |  | Operator |  | 100% |  | Oil prone basin
| GC 80, GC 123, GC 124, GC 168 |  | Operator |  | 75% |  | Oil prone basin
| EB 699, EB 566, EB 567, EB 610, EB 611, EB 914, AC 34, AC 36, AC 78, AC 80 |  | Operator |  | 70% |  | Oil prone basin
| GC 282, GC 237 |  | Non-operator |  | 50% |  | Oil prone basin
| AC 125, AC 126, AC 81, AC 82 |  | Operator |  | 45% |  | Oil prone basin
| MC 798, MC 842 |  | Non-operator |  | 45% |  | Oil prone basin
| GC 436, GC 480 |  | Non-operator |  | 44% |  | Oil prone basin
| GC 598 |  | Non-operator |  | 40% |  | Oil prone basin
| GC 679, GC 768 |  | Non-operator |  | 32% |  | Oil prone basin
| AT 228, AT 273, AT 274, AT 453, AT 424, AT 425, AT 469, AT 470 |  | Non-operator |  | 30% |  | Oil prone basin
| MC 368, MC 369, MC 411, MC 412, MC 455, MC 456 |  | Non-operator |  | 25% |  | Oil prone basin
| GC 870 |  | Non-operator |  | 24% |  | Oil prone basin

59 | Half-Year Report 2025 |  |

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 69 for more information.

APMs and their nearest respective IFRS measure.

APMs derived from the condensed consolidated income statement and other notes |  | 30 June 2025 US$m |  |  | 30 June 2024 US$m |
EBIT/EBITDA excluding impairment |  |  |  |  |  |  |  |
Net profit after tax |  |  | 1,330 |  |  |  | 1,972 |
Adjusted for: |  |  |  |  |  |  |  |
Finance income |  |  | (106 | ) |  |  | (95 | )
Finance costs |  |  | 169 |  |  |  | 147 |
PRRT expense |  |  | 71 |  |  |  | 192 |
Income tax expense |  |  | 353 |  |  |  | 146 |
EBIT |  |  | 1,817 |  |  |  | 2,362 |
Adjusted for: |  |  |  |  |  |  |  |
Property, plant and equipment depreciation and amortisation |  |  | 2,541 |  |  |  | 1,893 |
Amortisation of licence acquisition costs |  |  | 3 |  |  |  | 5 |
Amortisation of intangible assets |  |  | 11 |  |  |  | 10 |
Depreciation of lease assets |  |  | 85 |  |  |  | 101 |
Impairment losses |  |  | 143 |  |  |  | — |
EBITDA excluding impairment |  |  | 4,600 |  |  |  | 4,371 |
Underlying NPAT |  |  |  |  |  |  |  |
Net profit after tax attributable to equity holders of the parent |  |  | 1,316 |  |  |  | 1,937 |
Adjusted for the following exceptional items: |  |  |  |  |  |  |  |
Less: Sangomar DTA recognition |  |  | — |  |  |  | (305 | )
Less: Louisiana DTA recognition |  |  | (182 | ) |  |  | — |
Add: Impairment loss (post-tax) |  |  | 113 |  |  |  | — |
Underlying NPAT |  |  | 1,247 |  |  |  | 1,632 |
Average realised price |  |  |  |  |  |  |  |
Revenue from sale of hydrocarbons |  |  | 6,468 |  |  |  | 5,868 |
Sales volumes (MMboe) |  |  | 104.6 |  |  |  | 93.8 |
Average realised price (US$ per boe) |  |  | 61.8 |  |  |  | 62.6 |
Unit production cost |  |  |  |  |  |  |  |
Production costs |  |  | 759 |  |  |  | 745 |
Production volumes (MMboe) |  |  | 99.2 |  |  |  | 89.3 |
Unit production cost (US$ per boe) |  |  | 7.7 |  |  |  | 8.3 |
APMs derived from the condensed consolidated statement of cash flows and other notes |  | 30 June 2025 US$m |  |  | 30 June 2024 US$m |
Free cash flow |  |  |  |  |  |  |  |
Cash flow from operating activities |  |  | 3,339 |  |  |  | 2,393 |
Cash flow used in investing activities |  |  | (4,937 | ) |  |  | (1,653 | )
Add: Cash contributions from Stonepeak |  |  | 1,870 |  |  |  | — |
Free cash flow |  |  | 272 |  |  |  | 740 |
Liquidity |  |  |  |  |  |  |  |
Cash and cash equivalents |  |  | 4,880 |  |  |  | 1,979 |
Add: Available undrawn facilities |  |  | 3,550 |  |  |  | 6,500 |
Liquidity |  |  | 8,430 |  |  |  | 8,479 |

60 | Half-Year Report 2025 |  |

APMs derived from the condensed consolidated statement of financial position and other notes |  | 30 June 2025 US$m |  |  | 30 June 2024 US$m |
Capital expenditure |  |  |  |  |  |  |  |
Capital additions on evaluation |  |  | 29 |  |  |  | 42 |
Capital additions on property, plant and equipment |  |  | 4,372 |  |  |  | 2,212 |
Less: Cash contributions from Stonepeak |  |  | (1,870 | ) |  |  | — |
Capital additions on other |  |  | 27 |  |  |  | 111 |
Capital expenditure |  |  | 2,558 |  |  |  | 2,365 |
Less capital additions on Louisiana LNG |  |  | (2,655 | ) |  |  | — |
Adjusted for cash contributions from Stonepeak |  |  | 1,870 |  |  |  | — |
Less net capital expenditure on Louisiana LNG |  |  | (785 | ) |  |  | — |
Capital expenditure excluding Louisiana LNG |  |  | 1,773 |  |  |  | 2,365 |
Exploration expenditure |  |  |  |  |  |  |  |
Exploration and evaluation expenditure |  |  | 84 |  |  |  | 103 |
Adjusted for: |  |  |  |  |  |  |  |
Amortisation expense |  |  | (3 | ) |  |  | (5 | )
Exploration capitalised |  |  | 5 |  |  |  | 14 |
Exploration expenditure |  |  | 86 |  |  |  | 112 |
Capital and exploration expenditure |  |  | 2,644 |  |  |  | 2,477 |
Net tangible assets per ordinary security |  |  |  |  |  |  |  |
Net assets |  |  | 38,507 |  |  |  | 35,829 |
Adjusted for: |  |  |  |  |  |  |  |
Goodwill |  |  | (3,952 | ) |  |  | (3,697 | )
Non-controlling interest |  |  | (2,868 | ) |  |  | (759 | )
Other intangible assets |  |  | (939 | ) |  |  | (205 | )
Net tangible assets |  |  | 30,748 |  |  |  | 31,168 |
Number of issued and fully paid shares |  |  | 1,898,749,771 |  |  |  | 1,898,749,771 |
Net tangible assets per ordinary security (US$ per ordinary security) |  |  | 16.19 |  |  |  | 16.42 |
Gearing |  |  |  |  |  |  |  |
Interest-bearing liabilities (Current and non-current)1 |  |  | 11,954 |  |  |  | 5,822 |
Lease liabilities (Current and non-current) |  |  | 1,583 |  |  |  | 1,545 |
Adjusted for: |  |  |  |  |  |  |  |
Cash and cash equivalents |  |  | (4,880 | ) |  |  | (1,979 | )
Net debt |  |  | 8,657 |  |  |  | 5,388 |
Equity attributable to equity holders of the parent |  |  | 35,639 |  |  |  | 35,070 |
Total net debt and equity attributable to equity holders of the parent |  |  | 44,296 |  |  |  | 40,458 |
Gearing (%) |  |  | 19.5 | % |  |  | 13.3 | %

1. | The 30 June 2025 balance agrees to Note C.2 which includes capitalised costs to be amortised within the next 12 months.

61 | Half-Year Report 2025 |  |

APMs derived from the condensed consolidated income statement and statement of financial position |  | 30 June 2025 US$m |  |  | 30 June 2024 US$m |
Annualised return on equity |  |  |  |  |  |  |  |
Annualised net profit after tax attributable to equity holders of the parent |  |  | 2,632 |  |  |  | 3,874 |
Equity attributable to equity holders of the parent |  |  | 35,639 |  |  |  | 35,070 |
Annualised return on equity (%) |  |  | 7.4 | % |  |  | 11.0 | %
Annualised return on average capital employed |  |  |  |  |  |  |  |
Annualised profit before tax and net finance costs |  |  | 3,634 |  |  |  | 4,724 |
Opening non-current liabilities |  |  | 19,254 |  |  |  | 15,209 |
Closing non-current liabilities |  |  | 21,828 |  |  |  | 14,932 |
Average non-current liabilities |  |  | 20,541 |  |  |  | 15,071 |
Opening equity attributable to equity holders of the parent |  |  | 35,399 |  |  |  | 34,399 |
Closing equity attributable to equity holders of the parent |  |  | 35,639 |  |  |  | 35,070 |
Average equity attributable to equity holders of the parent |  |  | 35,519 |  |  |  | 34,735 |
Total average non-current liabilities and equity attributable to equity holders of the parent |  |  | 56,060 |  |  |  | 49,806 |
Annualised return on average capital employed (%) |  |  | 6.5 | % |  |  | 9.5 | %
APMs derived from other notes |  | 30 June 2025 US$m |  |  | 30 June 2024 US$m |
Revenue from sale of hydrocarbons (excluding marketing segment) |  |  | 5,924 |  |  |  | 5,376 |
Cash margin (excluding marketing segment) |  |  |  |  |  |  |  |
Gross profit |  |  | 2,344 |  |  |  | 2,526 |
Adjusted for: |  |  |  |  |  |  |  |
Other cost of sales |  |  | 15 |  |  |  | 21 |
Property, plant and equipment depreciation and amortisation |  |  | 2,541 |  |  |  | 1,893 |
Other revenue |  |  | (100 | ) |  |  | (99 | )
Cash margin (excluding marketing segment) |  |  | 4,800 |  |  |  | 4,341 |
Cash margin % |  |  | 81.0 | % |  |  | 80.7 | %
Production costs (excluding marketing segment) |  |  | 759 |  |  |  | 745 |
Production cost margin % |  |  | 12.8 | % |  |  | 13.9 | %
Other cash costs (excluding marketing segment): |  |  |  |  |  |  |  |
Royalties, excise and levies |  |  | 156 |  |  |  | 196 |
Insurance |  |  | 37 |  |  |  | 26 |
Inventory movement |  |  | 1 |  |  |  | (62 | )
Shipping and direct sales costs (excluding marketing segment) |  |  | 77 |  |  |  | 104 |
Trading costs |  |  | 88 |  |  |  | — |
Other hydrocarbon costs |  |  | 6 |  |  |  | 26 |
Total other cash costs (excluding marketing segment) |  |  | 365 |  |  |  | 290 |
Other cash cost margin % |  |  | 6.2 | % |  |  | 5.4 | %

62 | Half-Year Report 2025 |  |

Notes

Glossary

Term |  | Definition
$, $m |  | US dollars unless otherwise stated, millions of dollars
1P |  | Proved reserves
2C |  | Best Estimate of Contingent resources
2P |  | Proved plus Probable reserves
Abate/abatement |  | Avoidance, reduction or removal of an amount of carbon dioxide or equivalent
Aspiration |  | Woodside uses this term to describe an aspiration to seek the achievement of an outcome but where achievement of the outcome is subject to material uncertainties and contingencies such that Woodside considers there is not yet a suitable defined plan or pathway to achieve that outcome
ASX |  | Australian Securities Exchange
Average realised price |  | Revenue from sale of hydrocarbons ($ million) divided by sales volume (MMboe)
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 ecosystems1
Board |  | The Board of Directors of Woodside Energy Group Ltd
Brent |  | Intercontinental Exchange (ICE) Brent Crude deliverable futures contract (oil price)
Capital expenditure |  | Capital additions on property, plant and equipment and evaluation capitalised. Excludes exploration capitalised and adjusted for the capital contribution from Stonepeak for the development of Louisiana LNG
Capital expenditure excluding Louisiana LNG |  | Capital additions on property, plant and equipment and evaluation capitalised. Excludes exploration capitalised and capital additions on Louisiana LNG
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, property, plant and equipment 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
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 basis2
Condensate |  | Hydrocarbons that are gaseous in a reservoir but that condense to form liquids as they rise to the surface
cps |  | Cents per share
DTA |  | Deferred tax asset
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
FEED |  | Front-end engineering design
FID |  | Final investment decision
FPSO |  | Floating production storage and offloading

63 | Half-Year Report 2025 |  |

FPU |  | Floating production unit
Free cash flow |  | Cash flow from operating activities and cash flow from investing activities, adjusted for the capital contribution from Stonepeak for the development of Louisiana LNG
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)
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)
IFRS |  | International Financial Reporting Standards. For more information see www.ifrs.org.
JV |  | Joint venture
KGP |  | Karratha Gas Plant
Liquidity |  | Total cash and cash equivalents and available undrawn debt facilities less restricted cash
LNG |  | Liquefied 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
Major Project Status |  | Major Project Status is the Australian Government’s recognition of a project’s national strategic importance.
Net capital expenditure on Louisiana LNG |  | Capital additions on Louisiana LNG adjusted for the cash contribution from Stonepeak
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 other 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
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
Operator, Operated and non-operated |  | Oil and gas joint venture participants will typically appoint one company as the operator, which will hold the contractual authority to manage joint venture activities on behalf of the joint venture participants. Where Woodside is the operator of a joint venture in which it holds an equity share, this report refers to that joint venture as being operated. Where another company is the operator of a joint venture in which Woodside holds an equity share, this report refers to that joint venture as being non-operated
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
Return on average capital employed |  | Annualised profit before tax and net finance costs divided by total average non-current liabilities and equity attributable to equity holders of the parent
Return on equity |  | Annualised net profit after tax attributable to equity holder of the parent divided by equity attributable to equity holders of the parent

64 | Half-Year Report 2025 |  |

Revenue from ordinary activities |  | Revenue from the sale of hydrocarbons, processing and services revenue and shipping and other revenue
Scope 1 greenhouse gas emissions |  | Direct greenhouse gas 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 exist3
Scope 2 greenhouse gas emissions |  | Electricity indirect greenhouse gas 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 exist3
Scope 3 greenhouse gas emissions |  | Other indirect greenhouse gas 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. Please refer to the data table on page 72 of the Climate Transition Action Plan and 2023 Progress Report for further information on the Scope 3 emissions categories reported by Woodside3
Starting base |  | Woodside uses a starting base of 6.32 Mt CO2-e which is representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and which may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with a final investment decision prior to 2021. Net equity emissions include the utilisation of carbon credits as offsets
Sustainability (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
Tier 1 process safety event |  | A typical Tier 1 process safety event is loss of containment of hydrocarbons greater than 500 kg (in any one-hour period)
Tier 2 process safety event |  | 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)
TTF |  | Title transfer facility
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 LNG Gas Plant |  | 1 tonne |  | 8.34 boe
Wheatstone |  | 1 tonne |  | 8.27 boe

65 | Half-Year Report 2025 |  |

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 |  |
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 |  |
MMboe |  | million barrels of oil equivalent |  |
MMscf |  | million standard cubic feet of gas |  |
MMscf/d |  | million standard cubic feet of gas per day |  |
Mtpa |  | million tonnes per annum |  |
PJ |  | petajoules |  |
scf |  | standard cubic feet of gas |  |
TJ |  | terajoule |  |

66 | Half-Year Report 2025 |  |

About this report

This Half-Year Report 2025 is a summary of Woodside’s operations, activities and financial position as at 30 June 2025. 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 2025 and 30 June 2025. 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 64 – 67.

This report should be read in conjunction with the Annual Report 2024 and, in respect of climate and sustainability matters, the Climate Update 2024, the Climate Transition Action Plan and 2023 Progress Report available at woodside.com.

Forward looking statements

This report contains forward-looking statements with respect to Woodside’s business and operations, market conditions, results of operations and financial condition, including, for example, but not limited to, outcomes of transactions, statements regarding long-term demand for Woodside’s products, development, completion and execution of Woodside’s projects, expectations regarding future capital expenditures, the payment of future dividends and the amount thereof, future results of projects, operating activities and new energy products, expectations and plans for renewables production capacity and investments in, and development of, renewables projects expectations and guidance with respect to production, capital and exploration expenditure and gas hub exposure, and expectations regarding the achievement of Woodside’s net equity Scope 1 and 2 greenhouse gas emissions reduction and new energy investment targets and other climate and sustainability goals.

All statements, other than statements of historical or present facts, are forward-looking statements and generally may be identified by the use of forward-looking words such as ‘guidance’, ‘foresee’, ‘likely’, ‘potential’, ‘anticipate’, ‘believe’, ‘aim’, ‘aspire’, ‘estimate’, ‘expect’, ‘intend’, ‘may’, ‘target’, ‘plan’, ‘strategy’, ‘forecast’, ‘outlook’, ‘project’, ‘schedule’, ‘will’, ‘should’, ‘seek’ and other similar words or expressions. Similarly, statements that describe the objectives, plans, goals or expectations of Woodside are forward-looking statements.

Forward-looking statements in this report are not guidance, forecasts, guarantees or predictions of future events or performance, but are in the nature of future expectations that are based on management’s current expectations and assumptions.

Those statements and any assumptions on which they are based are subject to change without notice and are subject to inherent known and unknown risks, uncertainties, contingencies and other factors, many of which are beyond the control of Woodside, its related bodies corporate and their respective officers, directors, employees, advisers or representatives.

Important factors that could cause actual results to differ materially from those in the forward-looking statements and assumptions on which they are based include, but are not limited to, fluctuations in commodity prices, actual demand for Woodside’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, sustainability and environmental risks, climate related transition and, physical risks, 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 conflicts in Ukraine and in the Middle East) on economic activity and oil and gas supply and demand, cost estimates, legislative, fiscal and regulatory developments, including but not limited to those related to the imposition of tariffs and other trade restrictions, and the effect of future regulatory or legislative actions on Woodside or the industries in which it operates, including potential changes to tax laws, the impact of general economic conditions, inflationary conditions, prevailing exchange rates and interest rates and conditions in financial markets, and risks associated with acquisitions, mergers and joint ventures, including difficulties integrating or separating businesses, uncertainty associated with financial projections, restructuring, increased costs and adverse tax consequences, and uncertainties and liabilities associated with acquired and divested properties and businesses.

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A 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 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.

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, Average realised price, Unit production cost, Net debt, Liquidity, Free cash flow, Capital expenditure, Capital expenditure excluding Louisiana LNG, 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 64 – 66 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 61 – 63.

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.

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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 and 2024 Climate Update 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.

Notes to petroleum reserves and resources

1. | The petroleum resource estimates are quoted as at the effective date of 31 July 2025, net Woodside share. For details of Woodside’s year end 2024 reserves position, see the Reserves and Resources Statement included in the 2024 Annual Report. US investors should refer to “Additional information for US investors concerning reserves and resources estimates” below.

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

3. | The reference point is defined as the outlet of the floating production storage and offloading facility (FPSO).

4. | ‘Reserves’ are estimated quantities of petroleum that have been demonstrated to be producible from known accumulations in which the company has a material interest from a given date forward, at commercial rates, under presently anticipated production methods, operating conditions, prices, and costs. Woodside reports reserves inclusive of all fuel consumed in operations. Woodside estimates and reports its proved reserves in accordance with SEC regulations which are also compliant with the 2018 Society of Petroleum Engineers (SPE)/World Petroleum Council (WPC)/American Association of Petroleum Geologists (AAPG)/Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System (PRMS) (SPE-PRMS) guidelines. SEC-compliant proved reserves estimates use a more restrictive, rules-based approach and are generally lower than estimates prepared solely in accordance with SPE-PRMS guidelines due to, among other things, the requirement to use commodity prices based on the average of first of month prices during the 12-month period in the reporting company’s fiscal year. Woodside estimates and reports its proved plus probable reserves in accordance with SPE-PRMS guidelines which are not compliant with SEC regulations.

5. | Assessment of the economic value in support of an SPE-PRMS (2018) reserves and resources classification, uses Woodside Portfolio Economic Assumptions (Woodside PEAs). The Woodside PEAs are reviewed on an annual basis, or more often if required. The review is based on historical data and forecast estimates for economic variables such as product prices and exchange rates. The Woodside PEAs are approved by the Woodside Board. Specific contractual arrangements for individual projects are also taken into account.

6. | Woodside uses both deterministic and probabilistic methods for the estimation of reserves and contingent resources at the field and project levels. All proved reserves estimates have been estimated using deterministic methods and reported on a net interest basis in accordance with the SEC regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X.

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7. | ‘MMboe’ means millions (106) of barrels of oil equivalent. Natural gas volumes are converted to oil equivalent volumes via a constant conversion factor, which for Woodside is 5.7 Bcf of dry gas per 1 MMboe. All volumes are reported at standard oilfield conditions of 14.696 psi (101.325 kPa) and 60 degrees Fahrenheit (15.56 degrees Celsius).

8. | ‘Proved reserves’ are those quantities of crude oil, condensate, natural gas and NGLs that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, operating contracts, and government regulations. Proved reserves are estimated and reported on a net interest basis in accordance with the SEC regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X.

9. | ‘Undeveloped reserves’ are those reserves for which wells and facilities have not been installed or executed but are expected to be recovered through future significant investments.

10. | ‘Probable reserves’ are those reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. Proved plus probable reserves represent the best estimate of recoverable quantities. Where probabilistic methods are used, there is at least a 50% probability that the actual quantities recovered will equal or exceed the sum of estimated proved plus probable reserves. Proved plus probable reserves are estimated and reported in accordance with SPE-PRMS guidelines and are not compliant with SEC regulations.

11. | The estimates of petroleum reserves and contingent resources 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 and resources estimates included in this announcement are issued with the prior written consent of 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.

Additional information for US investors concerning reserves and resources estimates

Woodside is an Australian company with securities listed on the Australian Securities Exchange and the New York Stock Exchange. Woodside reports its proved reserves in accordance with SEC regulations, which are also compliant with SPE-PRMS guidelines, and reports its proved plus probable reserves and 2C contingent resources in accordance with SPE-PRMS guidelines. Woodside reports all petroleum resource estimates using definitions consistent with SPE-PRMS.

The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than ‘reserves’ (as that term is defined by the SEC). In this announcement, Woodside includes estimates of quantities of oil and gas using certain terms, such as ‘proved plus probable (2P) reserves’, ‘best estimate (2C) contingent resources’, ‘reserves and contingent resources’, ‘proved plus probable’, ‘developed and undeveloped’, ‘probable developed’, ‘probable undeveloped’, ‘contingent resources’ or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit Woodside from including in filings with the SEC. These types of estimates do not represent, and are not intended to represent, any category of reserves based on SEC definitions, and may differ from and may not be comparable to the same or similarly-named measures used by other companies. These estimates are by their nature more speculative than estimates of proved reserves and would require substantial capital spending over a significant number of years to implement recovery, and accordingly are subject to substantially greater risk of not being recovered by Woodside. In addition, actual locations drilled and quantities that may be ultimately recovered from Woodside’s properties may differ substantially. Woodside has made no commitment to drill, and likely will not drill, all drilling locations that have been attributable to these quantities. The Reserves Statement presenting Woodside’s proved oil and gas reserves in accordance with the regulations of the SEC is filed with the SEC as part of Woodside’s annual report on Form 20-F. US investors are urged to consider closely the disclosures in Woodside’s most recent Annual Report on Form 20-F filed with the SEC and available on the Woodside website at https://www.woodside.com/investors/reports-investor-briefings and its other filings with the SEC, which are available at www.sec.gov.

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Contacts: |  |  |  |
INVESTORS Vanessa Martin M: +61 477 397 961 E: investor@woodside.com |  | MEDIA Christine Abbott M:+61 484 112 469 E: christine.abbott@woodside.com |  | REGISTERED ADDRESS Woodside Energy Group Ltd ACN 004 898 962 Mia Yellagonga 11 Mount Street Perth WA 6000 Australia T +61 8 9348 4000 www.woodside.com

This announcement was approved and authorised for release by Woodside’s Disclosure Committee.

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