EX-99.1

EX-99.1 2 d99445dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

SECOND QUARTER REPORT FOR PERIOD ENDED 30 JUNE 2025

LOGO

ASX: WDS | NYSE: WDS

Wednesday, 23 July 2025

Louisiana LNG FID unlocks future value

Operational highlights

•

Quarterly production of 50.1 MMboe (550 Mboe/d), up 2% from Q1 2025.

•

Maintained exceptional performance from Sangomar, with 101 Mbbl/d produced (100% basis, 81 Mbbl/d Woodside share), contributing $510 million revenue for the quarter.

•

Achieved a strong realised quarterly price of $62/boe for produced LNG, benefiting from diversified pricing and optimisation.

•

Sold 23.1% of produced LNG at prices linked to gas hub indices in the quarter (9.1% of total equity production).

•

Entered into two sale and purchase agreements with Uniper for the long-term supply of LNG.

Project highlights

•

The Scarborough Energy Project was 86% complete, and remains on track for first LNG cargo in the second half of 2026.

•

The Trion Project was 35% complete, and remains on track for first oil in 2028.

•

The Beaumont New Ammonia Project was 95% complete, with Phase 1 of the project targeting first ammonia production from late 2025.

Portfolio highlights

•

Outstanding production performance with full-year production guidance updated to 188-195 MMboe, incorporating Greater Angostura divestment.

•

Reduced full-year unit production cost range to $8.0-$8.5 per boe following strong production and cost performance in H1 2025.

•

Unlocked long-term future value through the final investment decision to develop the Louisiana LNG Project.

•

Completed the Greater Angostura assets divestment for $259 million subsequent to the period.¹

Capital discipline

•

Completed the sell-down of a 40% interest in Louisiana LNG Infrastructure LLC to Stonepeak, receiving approximately $1,900 million, reflecting Stonepeak’s 75% share of capital expenditure since the effective date of 1 January 2025.

•

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

•

Delivered strong liquidity of approximately $8,400 million at the end of the quarter.

Woodside CEO Meg O’Neill said the company continued to demonstrate operational excellence and world-class project execution over the second quarter, with a focus on driving future growth and value.

“We delivered strong production of 50 million barrels of oil equivalent for the quarter from our diverse portfolio of high-quality assets. At the same time, ongoing focus on cost control has enabled us to lower our unit production cost guidance for 2025.

“As we marked the anniversary in June of first oil from Sangomar, the project’s exceptional performance continued to make a strong contribution to quarterly results, with gross production reaching 101 thousand barrels per day at close to 100% reliability. Our outstanding safety record at Sangomar continued, with no recordable injuries during the project’s first year of operations.

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


1				Second quarter report for period ended 30 June 2025

“Our announcement in April of a final investment decision to develop the Louisiana LNG Project positions Woodside as a global LNG powerhouse, complementing our established Australian LNG business and enabling us to meet growing global demand from a broader range of customers.

“Louisiana LNG’s strategic advantages and value-generating potential were demonstrated by key infrastructure, offtake and gas supply agreements entered into during the quarter.

“In June, we completed the sell-down of a 40% interest in Louisiana LNG Infrastructure LLC to Stonepeak for $5.7 billion, with Stonepeak to contribute 75% of the project capital expenditure in both 2025 and 2026.

“We continue to receive strong interest from high-quality potential partners as we explore further sell-downs. With both the final investment decision and capital expenditure risk reduced through our transaction with Stonepeak, we will evaluate the most value-accretive opportunities and remain disciplined in our selection of strategic partners.

“Our collaboration agreement with Aramco signed in May also includes potential acquisition of an equity interest in, and LNG offtake from, Louisiana LNG. The agreement includes exploring potential collaboration opportunities in lower-carbon ammonia from our Beaumont New Ammonia Project.

“We remain focused on delivering our Scarborough and Trion projects on schedule and budget. In May, we connected the floating production unit hull and topsides for our Scarborough Energy Project, which is now 86% complete and on track for first LNG cargo in the second half of 2026.

“Our Trion Project offshore Mexico is now 35% complete and targeting first oil in 2028. Construction of the floating production unit is progressing well, and we are preparing for construction of the floating storage and offloading vessel to commence in the second half of 2025.

“This demonstrates that Woodside continues to deliver on our commitments, executing multiple major projects with strong safety performance and cost control.

“We are maintaining financial discipline during our current phase of capital expenditure and proactively managing our balance sheet. We issued $3.5 billion of unsecured bonds in the US market in an offering that was heavily oversubscribed, reaffirming the debt market’s view of Woodside.

“The $1.9 billion closing payment received from Stonepeak in June, plus proceeds from the divestment of our Greater Angostura assets in Trinidad and Tobago, further de-risks our balance sheet and strengthens our ability to both fund our growth projects and provide shareholder returns. We have made the decision to exit the H2OK Project, demonstrating our disciplined approach to portfolio management.

“We are also executing multiple, complex decommissioning activities offshore Australia. We successfully completed the plugging of the Minerva and Stybarrow wells. Removal of other equipment at the legacy Minerva, Stybarrow and Griffin assets has been impacted by unexpected challenges, with further engineering and alternative solutions required. Whilst this has had some cost impacts, we are applying learnings to improve planning and execution.

“We are pleased to have received the Australian Government’s proposed decision to grant environmental approval for the North West Shelf Project Extension. We are continuing constructive consultation with the Government.

“Conducting our business sustainably remains core to Woodside’s success and we remain firmly on track to meet our target of reducing net equity Scope 1 and 2 greenhouse gas emissions by 15% by 2025.”


2				Second quarter report for period ended 30 June 2025

Comparative performance at a glance

2025

Q1
2025

Change

Q2
2024

Change

YTD

2025

YTD

2024

Change

Revenue²

$ million

3,275

3,315

(1%)

3,043

6,590

5,988

10%

Production³

MMboe

50.1

49.1

44.4

13%

99.2

89.3

11%

Gas

MMscf/d

1,825

1,841

(1%)

1,885

(3%)

1,833

1,907

(4%)

Liquids

Mbbl/d

230

223

157

46%

226

156

45%

Total

Mboe/d

550

546

488

13%

548

491

12%

Sales⁴

MMboe

54.4

50.2

48.2

13%

104.6

93.8

12%

Gas

MMscf/d

2,050

1,962

2,115

(3%)

2,006

2,032

(1%)

Liquids

Mbbl/d

238

213

12%

159

50%

226

159

42%

Total

Mboe/d

598

558

530

13%

578

516

12%

Average realised price

$/boe

(9%)

(5%)

(2%)

Capital expenditure

$ million

752

1,806

(58%)

1,232

(39%)

2,558

2,390

Capex excl. Louisiana LNG⁵

$ million

868

905

(4%)

1,232

(30%)

1,773

2,390

(26%)

Louisiana LNG⁶

$ million

(116)

901

(113%)

—

785

—

Operations

Pluto LNG

•

Achieved quarterly LNG reliability of 94.9%.

•

Commenced production from the PLA-08 subsea well, enhancing deliverability and extending plateau production.

•

Secured secondary environmental approval enabling development of the XNA-03 well through existing infrastructure to support sustained production.

North West Shelf (NWS) Project

•

Achieved strong quarterly LNG reliability of 97.4%.

•

Received the proposed approval from the Australian Government on the North West Shelf Project Extension and continued consultation on proposed conditions.

•

Successfully completed planned maintenance offshore at Goodwyn Alpha and onshore at Karratha Gas Plant (KGP), with production recommencing as planned.

Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of $10 million in Q2 2024 and -$14 million in YTD 2024. These amounts will be included within other income/(expenses) in the Financial Statements. Restatement allows for revenue presented in this quarterly report to reconcile to operating revenue, the IFRS measure presented in Woodside Financial Statements.

³	Q2 2025 includes 0.28 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

⁴

Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of 0.19 MMboe in Q2 2024 and -0.09 MMboe in YTD 2024. Restatement allows for revenue presented in this quarterly report to reconcile to operating revenue, the IFRS measure presented in Woodside Financial Statements.

⁵	Includes capital additions on property plant and equipment, evaluation capitalised and other corporate spend. Exploration capitalised has been reclassified from capital expenditure to other expenditure.

⁶	Capital expenditure for Louisiana LNG is presented as a net figure inclusive of cash contributions received from Stonepeak representing their share of the project’s capital expenditure to date. Q2 2025 includes a $1,870 million cash contribution.


3				Second quarter report for period ended 30 June 2025

•

Successfully drilled the Lambert West development well, with installation of the subsea infrastructure and startup expected in Q3 2025. The project will sustain production from the Angel platform.

•

Completed the permanent retirement of LNG Train 2, resulting in a reduction of KGP’s capacity from 16.9 Mtpa to 14.3 Mtpa.

Wheatstone and Julimar-Brunello

•

Progressed the Julimar Phase 3 Project, a four-well tieback to the existing Julimar field production system. Subsea construction commenced ahead of the drilling campaign scheduled for Q3 2025, with project startup expected in 2026.

•

Completion of the asset swap with Chevron remains on track for 2026.⁷

Bass Strait

•

Completed preparatory activities and secured regulatory approvals for the Kipper 1B Project, with drilling expected to commence in Q3 2025.

•

Progressed the Turrum Phase 3 Project with work commencing on the Marlin-B platform ahead of the drilling campaign, expected to commence in the second half of 2025.

•

Through these projects, Woodside is expected to add more than 100 PJs (Woodside share) to the south-eastern Australian domestic gas market.

Sangomar

•

Achieved exceptional production of 101 Mbbl/d (100% basis, 81 Mbbl/d Woodside share) at 99.6% reliability.

•

Production from the Sangomar field remained on plateau for the quarter, with the field expected to come off plateau in Q3 2025.

•

Continuing to assess production performance to inform further development.

United States of America

•

Achieved strong quarterly production at Shenzi, supported by 97.7% reliability.

•

Approved a final investment decision on the Atlantis Major Facility Expansion Project, which is expected to increase water injection capacity. First water injection is targeted for 2027.

Greater Angostura

•

Completed the divestment of the Greater Angostura assets to Perenco for $259 million, subsequent to the period.⁸ The divestment includes Woodside’s interest in the shallow water Angostura and Ruby offshore oil and gas fields, associated production facilities, and onshore terminal.

•

Delivered safe and reliable operations while undertaking divestment transition activities.

Marketing

•

Supplied 23.1% of produced LNG at prices linked to gas hub indices in the quarter, realising a 14% premium compared to oil-linked pricing. This represents 9.1% of Woodside’s total equity production. Full-year gas hub guidance remains unchanged.

⁷	Completion of the transaction is subject to conditions precedent.

⁸	Includes a base purchase price of $206 million plus working capital completion adjustments, based on an effective date of 1 January 2025.


4				Second quarter report for period ended 30 June 2025

•

Signed two LNG sale and purchase agreements with Uniper, for the supply of:

•

1.0 Mtpa from Louisiana LNG LLC for up to 13 years from its commercial operations date (COD).

•

Up to 1.0 Mtpa from Woodside’s global portfolio, commencing with Louisiana LNG’s COD over a term until 2039.

•

Signed non-binding heads of agreements with:

•

JERA Co., Inc. 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.

•

PETRONAS, through its subsidiary PETRONAS LNG Ltd, for the supply of 1.0 Mtpa of LNG to Malaysia from 2028 for a period of 15 years.

•

Woodside’s sale and purchase agreements with Commonwealth LNG, executed in September 2022, were terminated during the quarter following Commonwealth LNG’s failure to achieve key milestones, including FID, by contractual long stop dates.

•

Executed incremental Western Australian pipeline gas sales of 4.2 PJs for delivery in 2025. Woodside continues to engage with the Western Australian domestic market on additional supply requirements for 2025, 2026 and 2027.

Projects

Beaumont New Ammonia

•

The Beaumont New Ammonia Project was 95% complete at the end of the quarter, with pre-commissioning activities for Train 1 underway. Achievements include the completion of the storage tank construction, completion of compressor alignment and insertion of the ammonia converter basket.

•

First ammonia production is targeted for late 2025. Project completion and associated payment of the remaining 20% of the acquisition consideration is expected in 2026.

Scarborough Energy Project

•

The Scarborough and Pluto Train 2 projects were 86% complete at the end of the quarter (excluding Pluto Train 1 modifications).

•

Connected the floating production unit hull and topsides together in May 2025. Activities are now focused on the remaining integration and pre-commissioning scope.

•

Continued installation, testing and pre-commissioning of the subsea infrastructure, which is near completion.

•

Subsequent to the quarter, the third development well was drilled and completed. Reservoir properties and anticipated well deliverability were in line with expectations.

•

Continued installation of piping and cables and commenced electrical commissioning activities at the Pluto Train 2 site, with the construction workforce having reached peak numbers.

•

Progressed construction activity at the Pluto Train 1 modifications module yard, with civil works continuing and structural/piping works underway at the Pluto site.

•

Subsequent to the quarter, 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.

•

First LNG cargo is targeted for the second half of 2026.


5				Second quarter report for period ended 30 June 2025

Trion

•

The Trion Project was 35% complete at the end of the quarter.

•

Finalised the floating production unit detailed engineering and procured all equipment and bulk materials.

•

Progressed the floating storage and offloading vessel detailed engineering, with fabrication scheduled to commence in the second half of 2025.

•

Progressed the design, procurement and manufacturing of the subsea equipment.

•

First oil is targeted for 2028.

Louisiana LNG

•

Approved FID to develop the three-train, 16.5 Mtpa Louisiana LNG Project and issued a full notice to proceed to Bechtel.

•

Train 1 was 22% complete at the end of the quarter, with activities focused on progressing the marine offloading facility, marine dry excavation, and civil works.

•

Completed the sell-down of a 40% interest in Louisiana LNG Infrastructure LLC to Stonepeak. The closing payment of approximately $1,900 million received by Woodside reflects Stonepeak’s 75% share of capex funding incurred since the effective date of 1 January 2025.

•

Signed a long-term gas supply agreement with bp for the purchase of up to 640 billion cubic feet of feedgas commencing in 2029.

•

Received approval from the Federal Energy Regulatory Commission for the extension of the in-service date for the LNG terminal and Driftwood Mainline Pipeline to the end of 2029.

•

Submitted an application to the Department of Energy to extend to 2029 the export commencement deadline for the non-free trade agreement LNG Export Authorisation permit.

•

First LNG is targeted for 2029.

Hydrogen Refueller @H2Perth

•

Progressed construction activities with major equipment packages including electrolysers and compressors installed on site.

•

Ready for startup is targeted for Q4 2025 and first hydrogen production is expected in the first half of 2026.⁹

Decommissioning

•

Successfully completed the plug and abandonment of the three remaining wells at the Minerva field, offshore Victoria.

•

Recovered approximately 45% of the Minerva pipeline across State and Commonwealth waters. Challenges to pipeline recovery and adverse weather impeded progress, leading to the suspension of activities. Recommencement will be informed by vessel availability.

•

Continued decommissioning activities in the Bass Strait, including the submission of environmental approvals and plugging of 22 wells.

•

Successfully concluded the ten-well Stybarrow plugging campaign.

•

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

⁹	The project has received funding from the Hydrogen Fuelled Transport Project Funding Process as part of the Western Australian Government’s Renewable Hydrogen Strategy.


6				Second quarter report for period ended 30 June 2025

•

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.

•

These challenges have resulted in an increase in spend and cost estimates, and is expected to lead to an expense of $400 - 500 million pre-tax ($120 - 320 million post-tax) being recognised in the profit and loss in the half-year results.

Exploration and development

Browse

•

The Western Australian Environmental Protection Authority concluded a four-week public comment period for an amendment to the Browse to North West Shelf Project proposal. The amendment reflects changes to the development footprint and introduces new environmental measures that further reduce the potential environmental impact of the development.

•

The Browse CCS Project was referred to the Commonwealth regulator in October 2024 and declared valid in 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.

Calypso

•

The Calypso joint venture continues to review development options. Concept select engineering studies and subsurface studies to mature the technical and commercial definition progressed in the quarter.

Exploration

•

There were no substantive exploration activities during the quarter.

New energy and carbon solutions

New energy

•

Woodside formally joined the NeoSmelt Project as an equal equity participant and preferred energy supplier.¹⁰ The proposed project is a 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.¹¹

•

Woodside 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 is expected to result in an impairment loss of approximately $140 million pre-tax (approximately $110 million post-tax) being recognised in the profit and loss in the half-year results.

Carbon capture and storage (CCS) opportunities

•

The Bonaparte CCS Assessment Joint Venture commenced pre-front end engineering design and, subsequent to the quarter, was awarded Major Project Status by the Australian Government.¹²

¹⁰	Energy supply may include hydrogen, natural gas and/or electricity.

¹¹

Woodside uses this term to describe the characteristic of having lower levels of associated potential greenhouse gas emissions when compared to historical and/or current conventions or analogues, for example relating to an otherwise similar resource, process, production facility, product or service, or activity. When applied to Woodside’s strategy, please see the definition of lower-carbon portfolio in Woodside’s 2024 Annual Report.

¹²	Major Project Status is the Australian Government’s recognition of a project’s national significance through its contribution to strategic priorities, economic growth, employment, or to regional Australia.


7				Second quarter report for period ended 30 June 2025

Corporate activities

Business development

•

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 the Louisiana LNG Project and opportunities for a potential collaboration in lower-carbon ammonia.

Climate and sustainability

•

On track to meet Woodside’s target of reducing net equity Scope 1 and 2 greenhouse gas emissions by 15% by 2025.¹³ ¹⁴

•

Submitted the Oil and Gas Methane Partnership 2.0 Implementation Plan to the United Nations Environment Program. Quarterly activities include the initiation of a methane leak detection and reporting program at Goodwyn Alpha.

•

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

Hedging

•

Delivered as of 30 June 2025 approximately 58% of the 30 MMboe of 2025 oil production that was previously hedged at an average price of $78.7 per barrel.

•

Hedged 10 MMboe of 2026 oil production at an average price of $70.1 per barrel.

•

Continued hedging program for Corpus Christi LNG volumes involving Henry Hub (HH) and Title Transfer Facility (TTF) commodity swaps. Approximately 94% of 2025 and 87% of 2026 volumes have been hedged.

•

The realised value of all hedged positions for the half-year ended 30 June 2025 is expected to be a pre-tax profit of $42 million, with a $58 million profit related to oil price hedges offset by a $18 million loss related to Corpus Christi hedges, and a $2 million profit related to other hedge positions. Hedging profits will be included in ‘other income’ except hedging profits related to interest rate swaps which will be included in ‘finance income’ in the half-year financial statements.

Funding and liquidity

•

Raised $3,500 million in the US market through multi-tranche SEC-registered bonds 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.

•

Cancelled two $1,500 million short-term liquidity facilities and repaid $1,900 million of drawn bi-lateral facilities.

•

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

•

As at 30 June 2025, Woodside had liquidity of approximately $8,400 million.

¹³

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

¹⁴	This means net equity for the 12-month period ending 31 December 2025 are targeted to be 15% lower than the starting base.


8				Second quarter report for period ended 30 June 2025

Embedded commodity derivative

•

In 2023, Woodside entered into a revised long-term gas sale and purchase contract 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.

•

During the quarter, 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 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 approximately $160 million is expected to be recognised through other income.

2025 half-year results and teleconference

•

Woodside’s Half-Year Report 2025 and associated investor briefing will be released to the market on Tuesday, 19 August 2025. These will also be available on Woodside’s website at http://www.woodside.com/

•

A teleconference providing an overview of the half-year 2025 results and a question and answer session will be hosted by Woodside CEO and Managing Director, Meg O’Neill, and Chief Financial Officer, Graham Tiver, on Tuesday, 19 August 2025 at 10:00 AEDT / 08:00 AWST / 19:00 CDT (Monday, 18 August 2025).

•

We recommend participants pre-register 5 to 10 minutes prior to the event with one of the following links:

•

https://webcast.openbriefing.com/wds-hyr-2025/ to view the presentation and listen to a live stream of the question and answer session.

•

https://s1.c-conf.com/diamondpass/10048280-l4hu3r.html to participate in the question and answer session. Following pre-registration, participants will receive the teleconference details and a unique passcode.

Upcoming events 2025



August	19	Half-Year 2025 results

October	22	Third quarter 2025 report


9				Second quarter report for period ended 30 June 2025

2025 full-year guidance



		Prior	Current	Comments

Production	MMboe	186 - 196	188 - 195	Includes the Greater Angostura assets divestment.

Gas hub exposure¹⁵	% of produced LNG	28 - 35	No change

Unit production cost	$/boe	8.5 - 9.2	8.0 - 8.5	Strong production and cost performance in H1 2025.

Property, plant and equipment depreciation and amortisation	$ million	4,500 - 5,000	4,700 - 5,000

Exploration expense	$ million	200	No change

Payments for restoration	$ million	700 - 1,000	No change

Capital expenditure¹⁶	$ million	4,500 - 5,000	4,000 - 4,500	Beaumont New Ammonia Project completion payment is expected in 2026, first ammonia production is planned for late 2025.

¹⁵	Gas hub indices include Japan Korea Marker (JKM), TTF and National Balancing Point (NBP). It excludes Henry Hub.

¹⁶

Capital expenditure includes the following participating interests; Scarborough (74.9%), Pluto Train 2 (51%) and Trion (60%). It excludes the remaining Beaumont New Ammonia acquisition expenditure and Louisiana LNG expenditure. This guidance assumes no change to these participating interests in 2025. This excludes the impact of any subsequent asset sell-downs, future acquisitions or other changes in equity.


10				Second quarter report for period ended 30 June 2025

2025 half-year line-item guidance



		Statutory	Underlying	Comments

Production costs	$ million	740 - 780

Other income	$ million	340 - 420		Includes approximately $160 million non-cash benefit for the Perdaman embedded derivative and approximately $30 million in hedging gains.

Restoration movement expense (other expense)	$ million	400 - 500		Includes decommissioning cost updates to Stybarrow, Griffin and Minerva. There is no change to the payments for restoration 2025 full-year guidance.

Impairment losses	$ million	~140	—	Impairment loss of approximately $140 million pre-tax (approximately $110 million post-tax) on the H2OK Project, following the decision to exit the project. Excluded from underlying NPAT.

Net finance costs	$ million	50 - 80		Includes approximately $10 million in hedging gains relating to interest rate swaps.

PRRT expense	$ million	40 - 100

Income tax expense	$ million	280 - 480	490 - 690	2025 half-year statutory income tax includes a deferred tax asset (DTA) of approximately $180 million for the Louisiana LNG Project recognised on FID. The Louisiana LNG DTA and tax impact of the H2OK impairment loss are excluded from underlying NPAT. Woodside’s 2025 half-year statutory and underlying effective income tax rate is expected to be higher than 2024 full-year.

The presentation of these line-item aligns to the consolidated income statement (page 146) or note A.1 segment revenue and expenses note (pages 157-160) within the 2024 Annual Report. The line-item guidance provided above is indicative and subject to external auditor review process.


11				Second quarter report for period ended 30 June 2025


Contacts:

INVESTORS	MEDIA	REGISTERED ADDRESS

		Woodside Energy Group Ltd
		ACN 004 898 962
Vanessa Martin	Christine Forster	Mia Yellagonga
M: +61 477 397 961	M: +61 484 112 469	11 Mount Street
E: investor@woodside.com	E: chris.forster@woodside.com	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.


12				Second quarter report for period ended 30 June 2025

Production summary


		Q2 2025		Q1 2025		Q2 2024		YTD 2025		YTD 2024
Gas	MMscf/d		1,825		1,841		1,885		1,833		1,907
Liquids	Mbbl/d		230		223		157		226		156
Total	Mboe/d		550		546		488		548		491


		Q2 2025		Q1 2025		Q2 2024		YTD 2025		YTD 2024
AUSTRALIA
LNG
North West Shelf	Mboe		5,375		6,395		7,088		11,770		15,280
Pluto¹⁷	Mboe		11,097		10,430		11,726		21,527		23,480
Wheatstone	Mboe		2,424		2,422		1,959		4,846		4,316
Total	Mboe		18,896		19,247		20,773		38,143		43,076

Pipeline gas
Bass Strait	Mboe		3,653		3,192		3,410		6,845		5,769
Other¹⁸	Mboe		3,975		3,807		3,848		7,782		7,126
Total	Mboe		7,628		6,999		7,258		14,627		12,895

Crude oil and condensate
North West Shelf	Mbbl		912		1,106		1,260		2,018		2,672
Pluto¹⁷	Mbbl		899		857		933		1,756		1,864
Wheatstone	Mbbl		419		441		380		860		842
Bass Strait	Mbbl		457		402		503		859		995
Macedon & Pyrenees	Mbbl		558		369		107		927		216
Ngujima-Yin	Mbbl		1,084		725		974		1,809		1,860
Okha	Mbbl		587		312		491		899		957
Total	Mboe		4,916		4,212		4,648		9,128		9,406

NGL
North West Shelf	Mbbl		207		230		279		437		569
Pluto¹⁷	Mbbl		52		52		59		104		113
Bass Strait	Mbbl		753		668		941		1,421		1,773
Total	Mboe		1,012		950		1,279		1,962		2,455


Total Australia ¹⁹	Mboe		32,452		31,408		33,958		63,860		67,832

	Mboe/d		357		349		373		353		373

¹⁷	Q2 2025 includes 1.69 MMboe of LNG, 0.09 MMboe of condensate and 0.05 MMboe of NGL processed at the Karratha Gas Plant (KGP) through the Pluto-KGP Interconnector.

¹⁸	Includes the aggregate Woodside equity domestic gas production from all Western Australian projects.

¹⁹	Q2 2025 includes 0.28 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.


13				Second quarter report for period ended 30 June 2025



		Q2 2025		Q1 2025		Q2 2024		YTD 2025		YTD 2024

INTERNATIONAL

Pipeline gas

USA	Mboe		409		378		324		787		684

Trinidad & Tobago	Mboe		2,205		2,416		1,736		4,621		4,239

Other²⁰	Mboe		5		23		-		28		-

Total	Mboe		2,619		2,817		2,060		5,436		4,923

Crude oil and condensate

Atlantis	Mbbl		2,604		2,472		2,019		5,076		4,460

Mad Dog	Mbbl		2,470		2,577		2,944		5,047		5,709

Shenzi	Mbbl		2,021		2,322		2,333		4,343		4,738

Trinidad & Tobago	Mbbl		93		99		94		192		220

Sangomar	Mbbl		7,396		7,010		540		14,406		540

Other²⁰	Mbbl		-		-		81		-		162

Total	Mboe		14,584		14,480		8,011		29,064		15,829

NGL

USA	Mbbl		398		398		355		796		748

Other²⁰	Mbbl		3		12		-		15		-

Total	Mboe		401		410		355		811		748



Total International	Mboe		17,604		17,707		10,426		35,311		21,500
Total International	Mboe/d		193		197		115		195		118



Total Production	Mboe		50,056		49,115		44,384		99,171		89,332
Total Production	Mboe/d		550		546		488		548		491

²⁰	Overriding royalty interests held in the USA for several producing wells.


14				Second quarter report for period ended 30 June 2025

Product sales



		Q2 2025		Q1 2025		Q2 2024		YTD 2025		YTD 2024
Gas	MMscf/d		2,050		1,962		2,115		2,006		2,032
Liquids	Mbbl/d		238		213		159		226		159

Total	Mboe/d		598		558		530		578		516



		Q2 2025		Q1 2025		Q2 2024		YTD 2025		YTD 2024
AUSTRALIA
LNG
North West Shelf	Mboe		5,059		6,887		7,081		11,946		15,089
Pluto	Mboe		11,969		9,676		12,749		21,645		23,262
Wheatstone²¹	Mboe		3,346		2,217		2,451		5,563		4,759

Total	Mboe		20,374		18,780		22,281		39,154		43,110

Pipeline gas
Bass Strait	Mboe		3,620		3,299		3,508		6,919		6,078
Other²²	Mboe		3,833		3,584		3,435		7,417		6,329

Total	Mboe		7,453		6,883		6,943		14,336		12,407

Crude oil and condensate
North West Shelf	Mbbl		616		1,229		1,904		1,845		3,118
Pluto	Mbbl		650		705		1,283		1,355		1,923
Wheatstone	Mbbl		651		334		666		985		995
Bass Strait	Mbbl		599		534		271		1,133		868
Ngujima-Yin	Mbbl		1,151		663		1,018		1,814		2,017
Okha	Mbbl		1,256		-		572		1,256		1,190
Macedon & Pyrenees	Mbbl		498		499		-		997		496

Total	Mboe		5,421		3,964		5,714		9,385		10,607

NGL
North West Shelf	Mbbl		-		477		266		477		521
Pluto	Mbbl		-		110		49		110		104
Bass Strait	Mbbl		1,010		226		361		1,236		1,146

Total	Mboe		1,010		813		676		1,823		1,771



Total Australia	Mboe		34,258		30,440		35,614		64,698		67,895
Total Australia	Mboe/d		376		338		391		357		373

²¹

²²	Includes the aggregate Woodside equity domestic gas production from all Western Australian projects.


15				Second quarter report for period ended 30 June 2025



		Q2 2025		Q1 2025		Q2 2024		YTD 2025		YTD 2024
INTERNATIONAL
Pipeline gas
USA	Mboe		324		294		336		618		622
Trinidad & Tobago	Mboe		2,233		2,274		1,606		4,507		4,063
Other²³	Mboe		4		4		5		8		11

Total	Mboe		2,561		2,572		1,947		5,133		4,696

Crude oil and condensate
Atlantis	Mbbl		2,606		2,494		2,013		5,100		4,439
Mad Dog	Mbbl		2,485		2,620		3,043		5,105		5,669
Shenzi	Mbbl		2,030		2,202		2,430		4,232		4,782
Trinidad & Tobago	Mbbl		133		43		19		176		71
Sangomar	Mbbl		7,505		6,521		-		14,026		-
Other²³	Mbbl		47		57		59		104		119

Total	Mboe		14,806		13,937		7,564		28,743		15,080

NGL
USA	Mbbl		385		371		454		756		867
Other²³	Mbbl		2		2		3		4		6

Total	Mboe		387		373		457		760		873



Total International	Mboe		17,754		16,882		9,968		34,636		20,649
Total International	Mboe/d		195		188		110		191		113

MARKETING²⁴

LNG	Mboe		2,337		2,750		2,593		5,087		4,679
Liquids	Mboe		64		104		37		168		608

Total	Mboe		2,401		2,854		2,630		5,255		5,287



Total Marketing	Mboe		2,401		2,854		2,630		5,255		5,287



Total sales	Mboe		54,413		50,176		48,212		104,589		93,831
Total sales	Mboe/d		598		558		530		578		516

²³	Overriding royalty interests held in the USA for several producing wells.

²⁴	Purchased volumes sourced from third parties.


16				Second quarter report for period ended 30 June 2025

Revenue (US$ million)


	Q2 2025		Q1 2025		Q2 2024		YTD 2025		YTD 2024
AUSTRALIA
North West Shelf		295		535		524		830		1,116
Pluto		827		712		891		1,539		1,636
Wheatstone²⁵		255		199		212		454		411
Bass Strait		283		228		247		511		470
Macedon		52		52		48		104		99
Ngujima-Yin		86		57		91		143		183
Okha		90		-		46		90		96
Pyrenees		39		44		-		83		44
Total Australia		1,927		1,827		2,059		3,754		4,055

INTERNATIONAL
Atlantis		181		191		168		372		364
Mad Dog		161		190		249		351		453
Shenzi		138		167		205		305		395
Trinidad & Tobago²⁶		78		66		38		144		99
Sangomar		510		481		-		991		-
Other²⁷		4		3		5		7		10
Total International		1,072		1,098		665		2,170		1,321

Marketing revenue²⁸		232		312		265		544		492

Total sales revenue²⁹		3,231		3,237		2,989		6,468		5,868

Processing revenue		35		74		52		109		113
Shipping and other revenue		9		4		2		13		7
Total revenue		3,275		3,315		3,043		6,590		5,988

²⁵

Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of $10 million in Q2 2024 and -$14 million in YTD 2024. These amounts will be included within other income/(expenses) in the financial statements. Restatement allows for revenue presented in this quarterly report to reconcile to operating revenue, the IFRS measure presented in Woodside Financial Statements.

²⁶	Includes the impact of periodic adjustments related to the production sharing contract (PSC).

²⁷	Overriding royalty interests held in the USA for several producing wells.

²⁸

Values include revenue generated from purchased LNG and Liquids volumes, as well as the marketing margin on the sale of Woodside’s produced LNG and Liquids portfolio. Marketing revenue excludes hedging impacts and cargo swaps where a Woodside produced cargo is sold and repurchased from the same counterparty to optimise the portfolio. The margin for these cargo swaps is recognised net in other income.

²⁹	Referred to as ‘Revenue from sale of hydrocarbons’ in Woodside financial statements. Total sales revenue excludes all hedging impacts.


17				Second quarter report for period ended 30 June 2025

Realised prices


	Units	Q2 2025		Q1 2025		Q2 2024		Units	Q2 2025		Q1 2025		Q2 2024
LNG produced	$/MMBtu		9.8		10.6		9.6	$/boe		62		67		60
LNG traded³⁰	$/MMBtu		11.4		13.7		9.1	$/boe		72		86		58
Pipeline gas								$/boe		36		36		38
Oil and condensate	$/bbl		68		74		83	$/boe		68		74		83
NGL	$/bbl		43		47		44	$/boe		43		47		44
Liquids traded³⁰	$/bbl		68		70		79	$/boe		68		70		79
Average realised price for pipeline gas:
Western Australia	A$/GJ		6.8		6.9		6.5
East Coast Australia	A$/GJ		13.4		14.0		14.3
International	$/Mcf		4.7		5.0		3.9
Average realised price	$/boe		59		65		62
Dated Brent	$/bbl		68		76		85
JCC (lagged three months)	$/bbl		79		78		84
WTI	$/bbl		64		71		81
JKM	$/MMBtu		12.5		14.7		9.6
TTF	$/MMBtu		12.2		14.6		9.2

Average realised price decreased 9% from the prior quarter reflecting lower Dated Brent, WTI, JKM and TTF.

³⁰	Excludes any additional benefit attributed to produced volumes through third-party trading activities.


18				Second quarter report for period ended 30 June 2025

Capital expenditure (US$ million)


	Q2 2025			Q1 2025		Q2 2024		YTD 2025			YTD 2024
Evaluation capitalised³¹		17			12		37		29			54
Property plant & equipment		828			889		1,135		1,717			2,225
Other ³²		23			4		60		27			111
Sub Total (excluding Louisiana LNG)		868			905		1,232		1,773			2,390
Louisiana LNG³³		1,754			901		-		2,655			-
Cash contribution from Stonepeak³⁴		(1,870	)		-		-		(1,870	)		-
Total		752			1,806		1,232		2,558			2,390


	Q2 2025			Q1 2025		Q2 2024		YTD 2025			YTD 2024
Scarborough		333			322		563		655			1,137
Trion		92			315		137		407			234
Sangomar		10			7		206		17			416
Other		433			261		326		694			603
Sub Total (excluding Louisiana LNG)		868			905		1,232		1,773			2,390
Louisiana LNG³³		1,754			901		-		2,655			-
Cash contribution from Stonepeak³⁴		(1,870	)		-		-		(1,870	)		-
Total		752			1,806		1,232		2,558			2,390


Other expenditure (US$ million)
	Q2 2025			Q1 2025		Q2 2024		YTD 2025			YTD 2024
Exploration capitalised^31,³⁵		-			5		1		5			22
Exploration and evaluation expensed³⁶		46			35		46		81			100
Permit amortisation		-			3		3		3			6
Total		46			43		50		89			128



Trading costs		178			232		128		410			273

³¹	Project final investment decisions result in amounts of previously capitalised exploration and evaluation expense (from current and prior years) being transferred to property plant & equipment. This table does not reflect the impact of such transfers.

³²	Other primarily incorporates corporate spend including SAP build costs, other investments and other capital expenditure.

³³	Capital expenditure for Louisiana LNG is presented at 100% working interest equity.

³⁴	Cash contributions received from Stonepeak represent their share of the project’s capital expenditure since the effective date of 1 January 2025.

³⁵

Exploration capitalised has been reclassified from capital expenditure to other expenditure. Exploration capitalised represents expenditure on successful and pending wells, plus permit acquisition costs during the period and is net of well costs reclassified to expense on finalisation of well results.

³⁶	Includes seismic and general permit activities and other exploration costs.


19				Second quarter report for period ended 30 June 2025

Exploration or appraisal wells drilled

No exploration or appraisal wells were drilled in the quarter.

Permits and licences

Key changes to permit and licence holdings during the quarter ended 30 June 2025 are noted below.


Region	Permits or licence areas	Change in interest (%)	Current interest (%)	Remarks

	GB 529, GB 530, GB 531, GB 574, GB 575, GB 619	43%	100%	Licence assignment

	AT 409, AT 452, AT 454	(30%)	—%	Licence relinquished
United States	GB 421, GB 464, GB 465, GB 508, GB 509, GB 555, GB 604, GB 605, GB 640, GB 641, GB 647, GB 648, GB 685, GB 726, GB 728, GB 770, GB 771, GB 774	(40%)	—%	Licence relinquished
	GB 501, GB 502, GB 545	(60%)	—%	Licence relinquished
	EB 655, EB 656, EB 700, EB 701	(70%)	—%	Licence relinquished


20				Second quarter report for period ended 30 June 2025

Production rates

Average daily production rates (100% project) for the quarter ended 30 June 2025:


	Woodside share³⁷			Production rate (100% project, Mboe/d)				Remarks
				Jun 2025		Mar 2025
AUSTRALIA
NWS Project
LNG		29.25	%		202		235	Production was lower due to planned maintenance.
Crude oil and condensate		29.29	%		34		40
NGL		29.45	%		8		8

Pluto LNG
LNG		90.00	%		115		104	Production was higher due to increased reliability.
Crude oil and condensate		90.00	%		10		9

Pluto-KGP Interconnector
LNG		100.00	%		19		23	Production was lower due to planned maintenance at the Karratha Gas Plant.
Crude oil and condensate		100.00	%		1		1
NGL		100.00	%		1		1

Wheatstone³⁸
LNG		11.55	%		231		224	Production was higher due to increased plant throughput.
Crude oil and condensate		14.86	%		31		31

Bass Strait
Pipeline gas		47.53	%		84		76	Production was higher due to increased seasonal demand.
Crude oil and condensate		43.88	%		11		10
NGL		45.48	%		18		16

Australia Oil
Ngujima-Yin		60.00	%		20		13	Production was higher due to weather events in Q1 2025.
Okha		50.00	%		13		7
Pyrenees		64.80	%		9		6

Other
Pipeline gas³⁹					44		42

³⁷	Woodside share reflects the net realised interest for the period.

³⁸	The Wheatstone asset processes gas from several offshore gas fields, including the Julimar and Brunello fields, for which Woodside has a 65% participating interest and is the operator.

³⁹	Includes the aggregate Woodside equity domestic gas production from all Western Australian projects.


21				Second quarter report for period ended 30 June 2025


	Woodside share⁴⁰			Production rate (100% project, Mboe/d)				Remarks
				Jun 2025		Mar 2025
INTERNATIONAL
Atlantis
Crude oil and condensate		38.50	%		74		71	Production was higher due to an infill well brought online.
NGL		38.50	%		6		4	Production was higher due to an infill well brought online.
Pipeline gas		38.50	%		8		8

Mad Dog
Crude oil and condensate		20.86	%		130		137	Production was lower due to reservoir decline.
NGL		20.86	%		4		6
Pipeline gas		20.86	%		2		3

Shenzi
Crude oil and condensate		64.71	%		34		40	Production was lower due to planned maintenance, offset by increased reliability.
NGL		64.76	%		2		2
Pipeline gas		64.76	%		1		1

Trinidad & Tobago
Crude oil and condensate		69.26	%⁴¹		1		1
Pipeline gas		47.50	%⁴¹		51		53

Sangomar
Crude oil		80.43	%⁴¹		101		99

⁴⁰	Woodside share reflects the net realised interest for the period.

⁴¹	Operations governed by production sharing contracts.


22				Second quarter report for period ended 30 June 2025

Disclaimer and important notice

Forward looking statements

This report contains forward-looking statements with respect to Woodside’s business and operations, market conditions, results of operations and financial condition, including for example, but not limited to, outcomes of transactions, statements regarding long-term demand for Woodside’s products, potential investment decisions, 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, income, expenses, costs, losses, capital and exploration expenditure and gas hub exposure. 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 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, and the impact of general economic conditions, inflationary conditions, prevailing exchange rates and interest rates and conditions in financial markets and risks associated with acquisitions, mergers, divestitures and joint ventures, including difficulties integrating or separating businesses, uncertainty associated with financial projections, restructuring, increased costs and adverse tax consequences, and uncertainties and liabilities associated with acquired and divested properties and businesses.

A more detailed summary of the key risks relating to Woodside and its business can be found in 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.


23				Second quarter report for period ended 30 June 2025

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.

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. Past performance (including historical financial and operational information) is given for illustrative purposes only. It should not be relied on as, and is not necessarily, a reliable indicator of future performance, including future security prices.

Other important information

All figures are Woodside share for the quarter ending 30 June 2025, unless otherwise stated.

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

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

Glossary, units of measure and conversion factors

Refer to the Glossary in the Annual Report 2024 for definitions, including carbon related definitions.


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


24				Second quarter report for period ended 30 June 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.


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


25				Second quarter report for period ended 30 June 2025