Woodside Energy Group (ASX: WDS) (NYSE:WDS):

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Disciplined execution

Operational excellence and project delivery

Recorded operating revenue of $7,446 million, up 13% from H1 2025.
Delivered production of 478 Mboe/d (86.5 MMboe) and unit production costs of $8.8/boe.¹
Progressed major projects with Scarborough 98%, Trion 64%, and Louisiana LNG 28% complete.
Maintained high asset reliability, with operated LNG facilities achieving 98.7% reliability, Sangomar 99.5%, and Shenzi 99.1%.
Safely executed the Pluto planned turnaround campaign on schedule and within budget, including key integration activities supporting the Scarborough Energy Project, with more than 400,000 hours worked and zero lost-time injuries.

Delivering value

Determined a fully franked interim dividend of 57 US cents per share (cps).
Achieved net profit after tax (NPAT) of $1,672 million (underlying NPAT $1,334 million).¹
Delivered EBITDA of $4,647 million from underlying base business.¹
Delivered operating cash flow of $3,013 million and free cash flow of $352 million.
Disciplined capital management resulted in strong liquidity of $8,189 million.¹
Gearing of 20.6%, marginally outside the target range of 10 - 20%, impacted by $655 million of new lease liabilities, a $419 million net cash outflow from hedge settlements, and a $101 million increase in trade receivables.¹

Comparative performance

		H1 2026	H1 2025	Change %
Operating revenue	$ million	7,446	6,590	13%
Underlying NPAT¹	$ million	1,334	1,247	7%
Free cash flow^1,2	$ million	352	136	159%
Average realised price^1,3	$/boe	74.0	61.7	20%
					2026 full-year guidance
					Prior	Current
Total production volumes⁴⁵	MMboe	86.5	99.2	(13%)	172 - 186	174-185
Gas hub exposure⁶	%	38.7%	24.2%	15%	~30	No change
Capital expenditure^1,78	$ million	1,637	2,558	(36%)	4,000 - 4,500	No change
Abandonment expenditure	$ million	255	517	(51%)	500 - 800	No change
Exploration expenditure¹	$ million	119	84	42%	~200	No change
Production costs	$ million	749	667	12%	1,500 - 1,800	No change
Feed gas, services and processing costs	$ million	238	92	159%	500 - 600	No change
Property, plant and equipment depreciation and amortisation	$ million	2,209	2,541	(13%)	4,200 - 4,700	No change

This page and the following 66 pages comprise the half-year information given to the ASX under Listing Rule 4.2A and should be read in conjunction with Woodside’s Annual Report 2025.

Summary

Woodside delivered strong half-year production of 478 thousand barrels oil equivalent per day (86.5 million barrels of oil equivalent total) and reported a half-year net profit after tax (NPAT) of $1,672 million. Underlying NPAT was $1,334 million, compared to $1,247 million in the corresponding period in 2025. Operating revenue rose 13% year-on-year to $7,446 million.

During the half, the Middle East conflict disrupted the global supply of LNG and oil resulting in strengthening commodity prices and an increase in customer demand for products. Woodside’s Marketing and Trading division continued to optimise the portfolio to manage risk and maximise value while fulfilling customer commitments.

The directors have determined a fully franked interim dividend of 57 US cents per share (cps), representing an 80% payout ratio of underlying NPAT, and an annualised yield of 5.9%.⁹

Woodside CEO Liz Westcott said the company delivered a resilient first half performance, remaining a secure and reliable supplier to customers throughout a period of global volatility.

"We once again delivered strong production, cash flow and shareholder returns, while continuing to execute the next phase of growth.

"Keeping our people safe remains our highest priority. We recorded one high consequence injury during the period while undertaking over 11 million work hours. This reinforces the need for ongoing focus on critical risk management, strong safety leadership and disciplined execution of safe work practices across our operations.

"We maintained operational excellence at our assets. Operated LNG reliability was more than 98% and the planned turnaround at Pluto LNG was completed on budget and schedule, derisking the Scarborough Energy Project schedule in the process. We achieved exceptional performance at Sangomar, which produced at near nameplate capacity with 99.5% reliability.

"The Scarborough Energy Project is now 98% complete and remains on track to deliver first LNG cargo in the fourth quarter of 2026. During the half, we completed all upstream infrastructure, and subsequent to the period, achieved ready for start-up and first gas at the floating production unit. Our focus remains on disciplined commissioning and start-up of all facilities to ensure safe and reliable operations from day one.

"The Trion Project offshore Mexico also made strong progress and is now 64% complete, targeting first oil in 2028. Key construction and drilling milestones achieved in the first half included completion of the topsides lift onto the floating production unit and drilling of the first three of 24 subsea wells.

"At Louisiana LNG, key milestones were achieved relating to the LNG tanks and marine infrastructure. The project’s foundation development was 28% complete at the end of the half, with first LNG targeted for 2029.

"In July, Woodside assumed operatorship of the Gippsland Basin assets, creating greater flexibility for future development opportunities while reinforcing our commitment to supporting energy security in the eastern Australian domestic market.

"We continued to deliver on our sustainability commitments during the half, taking forward biodiversity initiatives in Western Australia and Louisiana, and enhancing methane emissions reporting across the Sangomar and North West Shelf operations.

"As we focus on Woodside’s next phase of disciplined delivery, we have announced a series of actions to lift performance and sharpen our focus on value. We have set an annual cost savings target of $350 million from 2028 to be delivered through the structured review of our business."

Financial summary

Key metrics
		H1	H1	Change
		2026	2025	%
Operating revenue	$ million	7,446	6,590	13%
EBITDA excluding impairment¹⁰	$ million	4,647	4,600	1%
EBIT¹⁰	$ million	2,157	1,817	19%
Net profit after tax (NPAT)¹¹¹²	$ million	1,672	1,316	27%
Underlying NPAT¹⁰	$ million	1,334	1,247	7%
Net cash from operating activities	$ million	3,013	3,339	(10%)
Capital expenditure^10,13	$ million	1,637	2,558	(36%)
Exploration expenditure^10,14	$ million	119	84	42%
Free cash flow^10,15	$ million	352	136	159%
Average realised price^10,18	US$/boe	74.0	61.7	20%
Dividends distributed	$ million	1,122	1,006	12%
Interim dividend determined	US cps	57	53	8%

Key ratios
Earnings per share	US cps	88.2	69.4	27%
Gearing¹⁰	%	20.6	19.5	1%

Production volumes^16,17
Gas	MMboe	46.1	58.2	(21%)
Liquids	MMboe	39.4	41.0	(4%)
Ammonia	MMboe	1.0	-	N/A
Total	MMboe	86.5	99.2	(13%)

Production volumes per day¹⁷
Gas	MMscf/d	1,451	1,833	(21%)
Liquids	Mbbl/d	217	226	(4%)
Ammonia	kT/d	1.5	-	N/A
Total	Mboe/d	478	548	(13%)

Sales volumes¹⁷
Gas¹⁸	MMboe	58.5	63.9	(8%)
Liquids	MMboe	40.3	40.9	(1%)
Ammonia	MMboe	1.0	-	N/A
Total	MMboe	99.8	104.8	(5%)

Sales volumes per day¹⁷
Gas¹⁸	MMscf/d	1,843	2,012	(8%)
Liquids	Mbbl/d	223	226	(1%)
Ammonia	kT/d	1.4	-	N/A
	Mboe/d	551	579	(5%)

Appendix 4D

Results for announcement to the market

More information is available on page 48.

				US$ million
Revenue from ordinary activities	Increased	13%¹⁹	to	7,446
Profit from ordinary activities after tax attributable to members	Increased	27%¹⁹	to	1,672
Net profit for the period attributable to members	Increased	27%¹⁹	to	1,672

Interim dividend - fully franked		57 US cps H1 2026
Record date for determining entitlements to the dividend		4 September 2026

Net profit after tax reconciliation

The following table summarises the variance between the H1 2025 and H1 2026 results for the contribution of each line item to NPAT.

	US$m	Primary reasons for variance
2025 H1 reported NPAT	1,316
Revenue from sale of products
Produced - price impact	755	Higher average realised prices.
Produced - volume impact	(307)	Lower production due to cyclone impacts, Pluto planned turnaround and divestment of the Greater Angostura assets offset by first ammonia sales.
Purchased - price and volume impact	440	Higher third-party LNG trading activity.
Cost of sales	(559)	Higher third-party LNG trading activity, first ammonia production and Pluto planned turnaround.
Perdaman embedded derivative	(297)	A non-cash unrealised loss of $135 million in H1 2026 compared to an unrealised gain of $162 million in H1 2025.
Hedging	(106)	Pre-tax hedge losses of $64 million in H1 2026 compared to pre-tax hedge gains of $42 million in H1 2025.
Restoration movement	450	Restoration provision updates primarily due to Stybarrow, Griffin and Minerva in 2025.
Impairment losses	(35)	Pre-tax impairment for the Calypso Project offset by lower pre-tax impairment for the H2OK Project compared with H1 2025.
Income tax and PRRT expense	62	Recognition of the Pluto PRRT and US income tax DTA in 2026 offset by higher taxable profits and recognition of the Louisiana LNG DTA in 2025.
Other	(47)
2026 H1 reported NPAT	1,672
Underlying adjustments	(338)	Adjusted for the recognition of the Pluto PRRT and US income tax DTA benefits and the post-tax impairment of the Calypso and H2OK Projects.
2026 H1 underlying NPAT²⁰	1,334

Capital management

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

Interim dividend and dividend reinvestment plan

A 2026 fully franked interim dividend of 57 US cps has been determined, representing an annualised dividend yield of 5.9% .²¹ The total amount of the interim dividend payment is $1,084 million which represents 80% of underlying NPAT for the first half of 2026.²²

The dividend reinvestment plan remains suspended.

Liquidity and balance sheet

In H1 2026, Woodside generated $3,013 million of cash flow from operating activities and delivered positive free cash flow of $352 million, which includes the $1,725 million in capital contributions received from Stonepeak and Williams for the development of Louisiana LNG.^22,23

During this period, Woodside repaid a $600 million Syndicated Term Loan approximately 6 months prior to maturity.

At the end of the period, Woodside had cash and cash equivalents of $4,339 million, liquidity of $8,189 million, and drawn debt of $11,450 million, including $800 million of ten-year bonds due in September 2026.²²

Woodside’s gearing as at 30 June 2026 was 20.6%, marginally outside the target range of 10 to 20%.²²Woodside’s gearing may at times fall outside the target range as the balance sheet is managed through the investment cycle.

Net debt and gearing were impacted by:

$655 million of lease liabilities recognised in the first half of 2026, for the Woodside Bilangara LNG vessel and Trion construction related vessels.²⁴
Net cash outflow of $419 million for hedge settlements.
Higher pricing driving a $101 million increase in trade receivables that were received in July 2026.

Woodside’s commitment to an investment-grade credit rating remains unchanged and supports the aim of providing sustainable returns to shareholders, both now from the strong existing business and in the future from the growth opportunities, in accordance with Woodside’s capital management framework.

Commodity price risk management

As at 30 June 2026, approximately 62% of the 30 MMboe of 2026 oil-linked production previously hedged (at an average price of $74.23 per barrel) had been cash settled and 10 MMboe of 2027 oil-linked production was hedged at an average price of $76.76 per barrel.

Commodity swaps were used to continue managing risk associated with the Corpus Christi LNG volumes.

For the period ended 30 June 2026, pre-tax hedge losses of $64 million primarily relating to Corpus Christi LNG hedges and foreign exchange hedges were recognised, and hedge settlements resulted in a net cash outflow of $419 million. The hedge settlement net cash outflow in H1 2026 is primarily due to timing with oil-linked hedge losses cash settled ahead of the related revenue recognition, and expected to be offset by higher revenue from Q2 price lag realisation in H2 2026.

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.

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 2026, an unrealised loss of $135 million has been recognised through other expenses.

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 2026 was 20.6 MMboe. This was an 18% decrease compared with 25.0 MMboe in H1 2025, primarily due to the impact of a planned turnaround and Severe Tropical Cyclone Mitchell in the reporting period. H1 2026 production included 3.9 MMboe of Pluto gas processed at Karratha Gas Plant through the Interconnector.

Pluto LNG achieved reliability of 98.7% in H1 2026, reflecting the asset's strong operating performance.

In H1 2026, drilling of the XNA-03 infill well was completed and preparations continue for start-up targeted for H2 2026.

The planned turnaround in May 2026 was successfully delivered safely, on schedule and within budget, including critical integration scopes supporting the Scarborough Energy Project. The turnaround involved over 1,500 personnel on site to deliver a safe lost time injury-free campaign with more than 400,000 hours worked.

Woodside is operator and holds a 90% participating interest.

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 onshore LNG processing trains and two domestic gas trains.

Woodside’s share of production in H1 2026 was 14.0 MMboe. This was a 7% decrease compared with H1 2025 due to natural reservoir decline and impacts from Severe Tropical Cyclone Narelle.

Despite these impacts, the NWS achieved LNG reliability of 98.7% in H1 2026, highlighting the continued dependability and efficiency of the integrated facilities.

In H1 2026, the NWS Joint Venture approved the drilling rig contract for the Greater Western Flank Phase 4 Project with drilling targeted to commence in 2027, and targeting first production in 2028.

Preparations are continuing for a planned turnaround for a single LNG Train targeted to commence in September 2026.

The NWS is continuing with infrastructure retirement planning at KGP while maintaining the capacity to provide processing services for third-party gas.

During H1 2026, three legal proceedings continued in the Federal Court of Australia, and one in the Western Australian Supreme Court, associated with the NWS Project Extension Commonwealth and State environmental approvals. Subsequent to the period, hearings on the three Federal Court proceedings took place in July 2026, and the Western Australian Supreme Court proceeding is currently scheduled in Q4 2026.

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 targeted for completion in Q4 2026.²⁵

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 2026 was 4.4 MMboe. This was a 30% decrease compared with H1 2025 due to the impacts of Severe Tropical Cyclone Narelle.

The Julimar Phase 3 Project, a subsea tie-back to the existing Julimar field production system, completed its subsea construction and drilling campaign in H1 2026 and remains targeted for start-up in H2 2026.

In parallel, decommissioning of three Julimar–Brunello exploration wells commenced in H1 2026. Completion of both activities are condition precedents to the Chevron asset swap.

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 remains targeted for completion in Q4 2026.²⁶

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 8.4 MMboe in H1 2026, an 8% decrease from H1 2025 predominantly due to reduced available capacity through scheduled maintenance programs and domestic gas demand.

In H1 2026, drilling of the five wells under the Turrum Phase 3 Project was completed. The Turrum Phase 3 Project is targeting delivery of gas to the eastern Australian domestic gas market by H1 2027 from the Turrum and North Turrum fields with topsides modifications to the Marlin B platform.

Subsequent to the period, on 1 July 2026, the transfer of operatorship of the Bass Strait assets from ExxonMobil to Woodside occurred, following the satisfaction of the conditions precedent to the transaction.²⁷

Woodside continues to progress technical maturation of four potential development wells that could deliver up to 200 PJ of sales gas to the market. Technical maturity and the impact of the Federal Government’s new domestic gas reservation scheme will influence whether these opportunities are progressed to a final investment decision. Subject to a final investment decision, these would be developed solely by Woodside through the Bass Strait infrastructure.

Woodside became operator on 1 July 2026 and holds a 50% participating interest in the GBJV and a 32.5% participating interest in the KUJV.

Other Australian oil and gas assets

Woodside operates three floating production storage and offloading (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%).

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 remains targeted for completion in Q4 2026.²⁶

Woodside’s share of production from the FPSO assets was 2.2 MMboe in H1 2026. This was a 39% decrease from H1 2025 primarily due to the planned shipyard maintenance and a subsea mooring system defect for the Okha FPSO and Severe Tropical Cyclone Narelle impacting in-field infrastructure at Pyrenees FPSO.

Woodside also operates Macedon (Woodside participating interest: 71.4%), 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 4.0 MMboe, a 5% decrease from H1 2025 primarily reflecting natural field decline. The Macedon facility delivered approximately 16% of the Western Australian domestic gas market supply in H1 2026.

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 continued activities to progress the proposed Woodside Solar Project, including arrangements to secure access to new and existing common-user transmission infrastructure required to transmit renewable energy to Pluto LNG. Development of this infrastructure is being led by the Western Australian Government and APA Group.

International operations

Sangomar

The Sangomar Field Development Phase 1 is a deepwater project with a stand-alone FPSO facility moored approximately 100 km offshore Senegal.

Woodside’s share of production was 15.0 MMboe in H1 2026, a 4% increase from H1 2025 due to continued strong reservoir performance, high reliability and optimisation of wells, flow lines and system hydraulics.

In H1 2026, Sangomar continued to deliver strong operational performance, averaging 99 Mbbl/d (100% basis, 83 Mbbl/d Woodside share) at 99.5% production reliability.²⁸ Reservoir performance continues to exceed expectations, particularly in the S500 reservoirs. Greater-than-anticipated aquifer pressure support, combined with well and network optimisation has enabled an extended initial production plateau and reduced the impact of reservoir decline. Although ongoing optimisation activities continue to moderate decline rates, production is expected to increasingly reflect the underlying reservoir decline profile.

H1 2026 sales of Sangomar crude oil were directed to Europe and South Asia during the Middle East conflict, attracting strong premiums.

Evaluation of future development opportunities is ongoing. A potential Phase 2 development leveraging existing installed capacity would include wells targeting the upper S400 reservoirs. Engagements are ongoing with Petrosen (18% participating interest) and the Senegalese Government for Phase 2.

Woodside is operator and has an 82% participating interest.

Shenzi

Shenzi is a conventional offshore oil and gas field developed through a tension leg platform located offshore in the Gulf of America.

Woodside’s share of production in H1 2026 was 4.1 MMboe at 99.1% reliability. This was a 12.8% decrease compared with H1 2025 due to natural field decline and reduced pressure support from a major water injector.

Woodside is operator and holds a 72% participating interest.

Atlantis

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

In H1 2026, water injection commenced on a new well, and the Atlantis Major Facility Expansion Project progressed. Subsequent to the period, the Major Facility Expansion project achieved start-up. The project added subsea infrastructure and upgraded water injection equipment.

Woodside’s share of production in H1 2026 was 6.3 MMboe. This was a 5% increase compared with H1 2025 due to high reliability and production from the Drill Center 1 Expansion which started production in H2 2025.

Woodside holds a 44% non-operating participating interest.

Mad Dog

Mad Dog is an offshore conventional oil and gas field located in the Gulf of America and is currently producing from two offshore facilities, 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.

The third and final Mad Dog Southwest Extension well was brought online in Q1 2026, completing the project that began with production from the first production well in August 2025.

Woodside’s share of production in H1 2026 was 5.8 MMboe. This was a 9% increase compared with H1 2025 due to five new producing wells starting production over the last 12 months.

Woodside holds a 23.9% non-operating participating interest.

Beaumont New Ammonia

Beaumont New Ammonia (BNA) is a 1.1 Mtpa ammonia synthesis plant located in Beaumont, Texas. First production of ammonia commenced in December 2025 and Woodside assumed operational control of BNA in March 2026 following successful completion of performance testing and handover from OCI Global.

Woodside's production in H1 2026 was 279 kT with reliability of 87.6% including the start-up and commissioning period.²⁹ Production remained below capacity due to feedstock constraints arising from construction delays at third-party suppliers, with Q2 production averaging 69% of capacity. These constraints are expected to continue into 2027. Lower-carbon ammonia production remains targeted for 2027, subject to commissioning of Linde’s low-carbon hydrogen facilities and startup of ExxonMobil’s CCS infrastructure, including approval of the relevant CCS permitting process.³⁰

Woodside is operator and holds a 100% participating interest.

Marketing and Trading

Revenue and trading

Revenue increased 13% to $7,446 million in H1 2026, reflecting higher average realised prices. Stronger commodity prices amid global supply disruptions, together with realisation of premiums increased the average realised price to $74.0/boe, up 20% compared with H1 2025.

Portfolio optimisation activities captured higher value opportunities across multiple trades, including redirecting Woodside cargoes to higher price markets, and using third-party purchases to meet long-term customer commitments. The value from these activities are realised as cargoes are delivered, resulting in fluctuations in earnings between reporting periods. Further value from trading activities in H1 2026 is expected to be realised in H2 2026.

The marketing segment delivered EBIT of $54 million in H1 2026, representing approximately 3% of total EBIT.³¹ Pre-tax hedge losses of $62 million were recognised in the segment, primarily relating to Corpus Christi LNG hedges, reducing EBIT.

In H1 2026, approximately 39% of LNG sold was linked to gas hub indices impacted by lower volumes available due to the Pluto planned turnaround.

Shipping

Woodside has signed five long-term time charter parties for LNG vessels all commencing in 2029, and added the Woodside Bilangara to Woodside’s fleet of LNG vessels during the period to support the start-up of the Scarborough Energy Project, bringing Woodside’s total number of long-term chartered vessels on the water to nine.

Pipeline gas

Throughout H1 2026, Western Australia domestic gas spot volume pricing held steady at approximately A$5.50/GJ, not impacted by fluctuations in global markets.

Woodside executed incremental pipeline gas sales agreements for 58.6 PJ to be delivered to the Western Australian market from 2026 to 2029, including an agreement for the supply of 31.1 PJ with Alcoa.

Woodside also executed incremental pipeline gas sales agreements for 47 PJ to be delivered to the east coast of Australia across 2026, 2027 and 2028.

On the east coast of Australia, Woodside commenced an expression of interest for 20 PJ of Bass Strait supply across 2027 and 2028 and is progressing in line with its obligations under its Ministerial Exemption to the Gas Market Code. Interest has been received from a wide variety of gas users including power generators, retailers and manufacturers with final offers expected in Q3 2026.

A total of 1,271 TJ of Trucked LNG, equivalent to approximately 1,200 trailers, was delivered in H1 2026 to customers in northern Western Australia. Since the commencement of operations at the Pluto LNG Truck Loading Facility in 2019, Woodside has delivered 6,892 trailers of LNG (7,100 TJ), offering a lower-carbon alternative to diesel.

The Australian Government has released a draft framework for its proposed Domestic Gas Reservation Scheme. Woodside is participating in the consultation process and will continue engaging with government and industry on the design of the scheme. It is important that the final arrangements support national energy security, economic growth and ongoing investment in the new gas supply, helping maintain Australia’s position as a reliable energy supplier to domestic and international customers.

Projects

Scarborough Energy Project

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

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

The project includes the construction of an integrated remote operations centre (IROC) at Woodside’s headquarters. The IROC will have the capacity to operate the FPU and the Pluto LNG facility from Perth.

The project was 98% complete at the end of H1 2026, excluding Pluto Train 1 modifications. First LNG cargo is on-track for Q4 2026.

The FPU achieved significant milestones throughout the first half of 2026. All upstream infrastructure is now in place, following completion of FPU mooring and hook up to the subsea production system. Subsequent to the period, upstream commissioning and preparations for the introduction of hydrocarbons was completed, and the FPU achieved ready for start-up status and first gas.

Construction and commissioning activities at the Pluto Train 2 site continued, including completion of the gas turbine generator synchronisation with the Pluto site power grid and mechanical runs of three of the six liquefaction compressors.

Modifications which will allow processing of Scarborough gas through Pluto Train 1 have been ongoing, including successful execution of tie-ins during the Pluto Train 1 planned turnaround in the reporting period. The final module for Pluto Train 1 modifications departed the fabrication yard in Thailand and subsequent to the period, arrived at site. Civil, structural, piping and electrical works continue.

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 64% complete at the end of H1 2026. First oil is targeted for 2028.

Drilling of 24 subsea wells commenced in March 2026 with three production wells drilled during the period.

The FPU achieved key H1 2026 milestones, including completion of topsides and living quarters lifts onto the hull, and commencement of integration and pre-commissioning. FSO construction with dry mega block assembly in dry dock continue to progress in accordance with plan. Fabrication and testing of the disconnectable buoy of the FSO has been completed

Subsea equipment fabrication, including drill centre and central manifolds, three trees, static umbilicals, mooring systems and anchor piles, has been completed and delivered to Mexico ahead of installation commencing in Q3 2026. Remaining subsea production system components are progressing to plan and are in the final stages of fabrication.

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

Louisiana LNG

Louisiana LNG is a fully permitted, under-construction LNG production and export terminal located near Lake Charles, Louisiana. The project is structured as a scalable development with a total permitted capacity of 27.6 Mtpa across five LNG trains and supporting infrastructure.

In April 2025, Woodside approved an FID to develop the foundation phase of the project, comprising three LNG trains with a capacity of 16.5 Mtpa.

The foundation development was 28% complete at the end of the period, with Train 1 35% complete, Train 2 25% complete, and Train 3 18% complete. The project is targeting first LNG in 2029.

Key construction progressed during the period included structural steel erection and commencement of above-ground piping installation, advancement of LNG tanks, and marine infrastructure works, including commissioning of the material offloading facility and commencement of dredging.

Bechtel sources structural steel for Louisiana LNG from its fabrication facility in the United Arab Emirates. In response to ongoing supply chain risks associated with disruptions in the Middle East, the project is proactively assessing and implementing mitigation measures, including alternative logistics routes and fabrication sources, to support continuity of steel supply and maintain planned construction schedules beyond 2026.

Woodside completed the transition of Driftwood Pipeline LLC operatorship to Williams, with execution of the Line 200 lateral pipeline progressing under Williams as operator, including advancing engineering, procurement, and right of way activities.

With foundational transportation and storage capacity secured in 2025, Woodside continued to advance feed gas procurement in line with its gas supply strategy.

Ongoing engagement with high-quality counterparties for equity participation and LNG offtake continues to support progress on the Louisiana LNG sell-down process.

Woodside is operator with a 90% interest in Louisiana LNG LLC. Louisiana LNG LLC owns a 60% interest in Louisiana LNG Infrastructure LLC and Woodside is operator. Woodside has a 20% non-operating interest in Driftwood Pipeline LLC.

Hydrogen Refueller @H2Perth

The Hydrogen Refueller @H2Perth is a self-contained hydrogen production, storage and refuelling station located in Perth, Western Australia.³²

Commissioning activities continued on site and the facility has now been handed over to Woodside from the contractor following successful leak testing and cold commissioning. Ready for start-up is now targeted for Q3 2026 and first hydrogen production is targeted for Q4 2026.

Woodside is operator and holds a 100% participating interest.

Decommissioning

Woodside continued execution of planned decommissioning activities in H1 2026, spending approximately $274 million across its portfolio.

In H1 2026, well decommissioning activities continued across multiple assets, including commencing offshore plug and abandonment (P&A) operations for eight subsea wells across the North West Shelf and Julimar-Brunello fields, with P&A completed for two wells so far.

Offshore execution has also progressed at the Stybarrow and Griffin fields in north-west Western Australia. At Stybarrow, more than 18 km of flexible flowlines and umbilicals were removed in H1 2026, while approximately 8 km of flexible flowlines have been removed from Griffin.

Following the completion of planned infrastructure recovery from Enfield in 2025, a final seabed survey was completed in H1 2026, with results planned to be submitted to the regulator in H2 2026. Consultation with relevant persons for the development of the Environment Plan to remove the remaining Minerva infrastructure was also completed during H1 2026.

At Bass Strait, GBJV made strong progress on P&A activities during the period, completing plugging operations on the West Kingfish and Cobia platform wells and commencing platform rig operations on the Halibut and Tuna platforms. This completed all P&A activities for platforms scheduled for removal in Bass Strait Offshore Platform Removal Campaign 1, which is set to commence in Q3 2027.

Preparation for the campaign also advanced, with the National Offshore Petroleum Safety and Environmental Management Authority accepting the Environmental Plan and upgrades commencing at the onshore reception centre at Barry Beach Marine Terminal.

Developments and Exploration

Browse

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

During H1 2026, work continued to advance regulatory approvals, advance technical definition and progress commercial arrangements for processing Browse volumes through the Karratha Gas Plant. Contractors were engaged to progress pre-FEED engineering scopes for the FPSO facilities. Invitations to tender for the design and construction of the Browse FPSO facilities were issued that will provide market pricing and schedule assumptions to inform a FEED entry decision. Engineering studies commenced to assess downstream modifications required for processing Browse gas at Karratha Gas Plant with a three-train development concept.

The gas processing agreement has been progressed, and will establish the commercial framework and terms for processing Browse gas at the North West Shelf Project’s Karratha Gas Plant.

Woodside continued to engage with regulators as it progresses the primary environmental approvals for Browse. In June 2026, following a determination by the Federal Environment Minister that the Browse CCS Project can be assessed wholly under the amended Environment Protection and Biodiversity Conservation Act 1999 (Cth), Woodside submitted a revised environmental referral to the Commonwealth regulator. The resubmission does not involve any significant changes to the nature, scope or intent of the project.

In June 2026, Woodside exercised its pre-emption right to acquire CNPC's 10.67% interest in the Browse Joint Venture (BJV). The terms of the transaction include an amount payable on completion of $225 million plus reimbursement of CNPC's BJV cash call contributions from 30 June 2025 to completion. A contingent payment of $175 million is payable upon a final investment decision for the development of all of the Brecknock, Calliance and Torosa fields on or before 30 June 2032.³³

Subsequent to the period, the Browse to NWS Project was granted State Significant Project status under the Lead Agency Framework by the Western Australian State Government. State Significant Project status provides the highest level of support, helping coordinate engagement on approvals and project development.

Woodside is operator and holds a 30.6% participating interest. Woodside’s equity interest in the BJV after completion of the acquisition of CNPC’s interest will increase from 30.6% to 41.27%.

Sunrise

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

The Sunrise Joint Venture participants continued to engage with the Governments of Timor-Leste and Australia to advance the fiscal and regulatory frameworks supporting the potential development of Sunrise.

Technical and commercial activities progressed under the Timor-Leste Cooperation Agreement to support maturation of a potential Timor‑based LNG concept.

Woodside is operator and holds a 33.44% participating interest.

Calypso

Calypso is a discovered resource located approximately 220 km off the coast of Trinidad in 2,100m water depth.

Woodside is operator and holds a 70% participating interest. Subsequent to the period, Woodside entered an agreement to divest its 70% operated interest in Calypso to joint venture participant bp.³⁴

Liard

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

Woodside holds a 50% non-operating participating interest.

Exploration

Woodside’s exploration activities focused on maturing current opportunities, consistent with its disciplined exploration strategy.

In the US, Woodside was awarded 10 blocks from Gulf of America Lease Sales Big Beautiful Gulf 1 and Big Beautiful Gulf 2. Woodside also participated in the Bandit-1 well which reached total depth during H1 2026 and resulted in a Miocene discovery.³⁵ Post-well analysis continues in order to inform a potential appraisal decision. Woodside continued to actively manage its acreage position across the central and western Gulf of America.

Woodside continued to pursue disciplined portfolio optimisation, including exiting blocks no longer considered prospective. In Australia, the expiry of exploration permit WA-28-P concluded 57 years of exploration activity on the permit. Woodside also allowed its Marine XX permit to expire offshore the Republic of Congo following the completion of its permit terms.

H2Perth

The H2Perth Project is a proposal to develop Australia’s first commercial-scale liquid hydrogen production and export facility in Western Australia, located in the Rockingham Industry Zone and Kwinana.

In May 2026, the Environmental Protection Agency approved Woodside’s application under section 43A of the Environmental Protection Act 1986 (WA) to amend the proposal for the Project from its previous concept of a liquified hydrogen and ammonia production facility to a liquefied hydrogen only facility.

Woodside is operator and holds a 100% participating interest.

NeoSmelt

The NeoSmelt project aims to demonstrate a potential lower-emissions steelmaking pathway for Pilbara iron ores, involving Direct Reduced Iron and Electric Smelting Furnace (DRI-ESF) technology.³⁶

During the reporting period, work on the pilot plant continued, with the design phase now approximately 90% complete.

Woodside holds a 20% non-operating participating interest. The other participants in the project are BHP, BlueScope, Mitsui Iron Ore Development and Rio Tinto.

Carbon solutions

Carbon capture and storage (CCS)

Woodside progressed proposed CCS opportunities in Australia and the Asia-Pacific, including the operated Angel CCS (Woodside participating interest: 20%) and non-operated Bonaparte CCS opportunities (Woodside participating interest: 21%).³⁷

In H1 2026, 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.

The Bonaparte CCS Assessment Joint Venture, operated by INPEX with TotalEnergies and Woodside continues to progress pre-FEED activities.

Carbon credits portfolio

During H1 2026, 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 4,400 hectares are forecast to be planted in 2026 and these activities were 25% complete at the end of H1 2026.

Climate and Sustainability

Health, safety and wellbeing

There were zero fatalities recorded in H1 2026, and zero Tier 1 or Tier 2 process safety events. One high-consequence injury was recorded during the period, across more than 11 million work hours. The year-to-date lost time injury frequency rate was 0.17, compared with 0.26 for full-year 2025, and the total recordable injury rate was 2.09, compared to 1.64 recorded for full-year 2025.

Subsequent to the period, a sustainability focus session was held on 22 July 2026 with investors on Woodside’s approach to process safety.

Indigenous Peoples cultural heritage and engagement

Woodside continued to engage with around 43 Traditional Owner representative bodies in Australia to discuss current and potential future activities. This included consultation on the Browse to North West Shelf Geophysical and Geotechnical Surveys and Minerva Field Decommissioning Environment Plans. In addition, archaeological and ethnographic surveys with some Traditional Custodians were also undertaken.

Subsequent to the period, the Global Indigenous Peoples Strategy (2025-2030) was launched and is now available on Woodside's website.

Social and economic impact

Woodside published its 2025 Social Contribution Report in April 2026. The report highlighted the positive impacts of Woodside’s A$39.8 million social contribution in 2025, which was directed through strategic partnerships, philanthropy initiatives, the value of time employees spent volunteering, and payments required by government regulations or contractual agreements with Indigenous Peoples.

Woodside paid over A$1 billion in Australian taxes, royalties and levies to the Federal and State governments in H1 2026. Additionally Woodside paid more than US$450 million in international corporate taxes, royalties and production entitlements in H1 2026 (excludes Australia).

Environment and biodiversity

In H1 2026, there were zero hydrocarbon or hazardous non-hydrocarbon spills that resulted in a moderate environmental impact.³⁸

During the half, Woodside launched the Sam Houston Jones Restoration Project, supporting restoration of threatened habitats and key wildlife species in Louisiana.

In H1 2026, the Watheroo Biodiversity Project in Western Australia was also formally launched, with the establishment of a long-term funding agreement with Department of Biodiversity, Conservation and Attractions.

Climate and the energy transition

In Q1 2026, Woodside published AASB S2 climate-related disclosures in the 2025 Annual Report.

Woodside Sustainability Briefing 2026 was held on 16 March 2026, highlighting Woodside’s 2025 sustainability performance with regards to its 2025 material topics.³⁹ This included content relevant to its 2025 material sustainability topics.

In H1 2026, Woodside submitted its second annual Oil and Gas Methane Partnership 2.0 (OGMP2.0) implementation plan to the United Nations Environment Programme (UNEP), including first-time Level 5 reporting for Léopold Sédar Senghor FPSO and Karratha Gas Plant methane emissions. Level 5 is OGMP 2.0’s highest data quality standard, requiring reconciliation of granular source-level estimates with independent site-level measurements.

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 – 15 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 2026 half-year are as follows:

Mr Richard Goyder, AO (Chair)	Ms Liz Westcott (CEO and Managing Director) ⁴⁰
Mr Larry Archibald	Mr Ashok Belani
Mr Arnaud Breuillac	Ms Swee Chen Goh
Mr Ben Wyatt, AO	Ms Angela Minas
Mr Mark Cutifani, CBE⁴¹	Ms Ann Pickard
Mr Ian Macfarlane (retired)⁴²	Mr Tony O’Neill (resigned)⁴³

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 2026/183 (ASIC Instrument 2026/183) applies. Amounts in this report have been rounded in accordance with ASIC Instrument 2026/183. 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 17 and forms part of this report.

Signed in accordance with a resolution of the directors.

R J Goyder, AO

Chair

Melbourne, Victoria

25 August 2026

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

Auditor’s Independence Declaration

As lead auditor of Woodside Energy Group Ltd's financial report for the half-year ended 30 June 2026, I declare that, to the best of my knowledge and belief, there have been:

no contraventions of the auditor independence requirements of the Corporations Act 2001 in relation to the review of the financial report; and
no contraventions of any applicable code of professional conduct in relation to the review of the financial report.

N M Henry

Partner

PricewaterhouseCoopers

Perth, Western Australia

25 August 2026

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.

HALF-YEAR FINANCIAL STATEMENTS

for the half-year ended 30 June 2026

CONTENTS

CONDENSED CONSOLIDATED INCOME STATEMENT	20
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME	21
CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION	22
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS	23
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY	24
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	25
A. Earnings for the period	27
A.1 Segment revenue and expenses	27
A.2 Finance costs	28
A.3 Dividends paid and proposed	28
A.4 Earnings per share	28
A.5 Taxes	29
B. Production and growth assets	30
B.1 Exploration and evaluation assets	30
B.2 Property, plant and equipment	31
B.3 Impairment of exploration and evaluation assets, property, plant and equipment and goodwill	32
B.4 Intangible assets	33
B.5 Transactions with equity holders of the Group	34
C. Debt and capital	35
C.1 Interest-bearing liabilities and financing facilities	35
C.2 Contributed equity	36
D. Other assets and liabilities	37
D.1 Segment assets and liabilities	37
D.2 Provisions	38
D.3 Other financial assets and liabilities	39
E. Other items	41
E.1 Contingent liabilities and assets	41
E.2 New standards and interpretations	41
E.3 Events after the end of the reporting period	41
E.4 Subsidiaries	42
DIRECTORS’ DECLARATION	44
INDEPENDENT AUDITOR’S REVIEW REPORT	45

Significant changes in the current reporting period

The financial performance and position of the Group were affected by the following:

Geopolitical developments in the Middle East contributed to increased volatility in oil and LNG prices and broader market uncertainty during the period. The full impact of higher LNG prices has not yet been realised due to lagged pricing mechanisms.
In July 2025, the Group completed the disposal of the Greater Angostura assets in Trinidad and Tobago to Perenco Energies International Limited (Perenco), which impacted revenue for the first half of 2026 relative to the comparative period, when the assets contributed $145m of revenue.
The Group recognised an additional $596 million in Pluto PRRT deferred tax assets and a $90 million income tax deferred tax asset relating to heritage Woodside US net operating loss carryforwards (Refer to Note A.5).
As at 30 June 2026, the Group recognised impairment losses of $178 million, comprising $135 million on the Calypso exploration and evaluation asset following the decision to divest its 70% operated interest in the Calypso Project, and $43 million on the H2OK Project following the decision to retire the assets (Refer to Note B.3).
The Group recognised $138 million of other income from the release of deferred income associated with the Pluto Train 2 Global Infrastructure Partners (Pluto Train 2 GIP) transaction, reflecting updated expectations that potential construction cost overruns and liquidated damages will not crystallise.
The Group recognised approximately $655 million of new lease liabilities, primarily relating to the three-year leases for the Trion drilling campaign and the Woodside Bilangara vessel.

CONDENSED CONSOLIDATED INCOME STATEMENT for the half-year ended 30 June 2026

		2026	2025
	Notes	US$m	US$m
Operating revenue	A.1	7,446	6,590
Cost of sales	A.1	(4,604)	(4,045)
Gross profit		2,842	2,545
Other income	A.1	264	379
Other expenses	A.1	(771)	(964)
Impairment losses	A.1	(178)	(143)
Profit before tax and net finance costs		2,157	1,817
Finance income		123	106
Finance costs	A.2	(245)	(169)
Profit before tax		2,035	1,754
Petroleum resource rent tax (PRRT) benefit/(expense)	A.5	305	(71)
Income tax expense	A.5	(667)	(353)
Profit after tax		1,673	1,330
Profit attributable to:
Equity holders of the parent		1,672	1,316
Non-controlling interest	E.4	1	14
Profit for the period		1,673	1,330
Basic earnings per share attributable to equity holders of the parent (US cents)	A.4	88.2	69.4
Diluted earnings per share attributable to equity holders of the parent (US cents)	A.4	87.3	68.8

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

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME for the half-year ended 30 June 2026

	2026	2025
	US$m	US$m
Profit for the period	1,673	1,330
Other comprehensive (loss)/income
Items that may be reclassified to the income statement in subsequent periods:
(Losses)/gains on cash flow hedges	(526)	289
Gains on cash flow hedges reclassified to the income statement	(72)	(16)
Tax recognised within other comprehensive income	149	(57)
Items that will not be reclassified to the income statement in subsequent periods:
Remeasurement gain on defined benefit plan	3	2
Net loss on financial instruments at fair value through other comprehensive income	—	(33)
Other comprehensive (loss)/income for the period, net of tax	(446)	185
Total comprehensive income for the period	1,227	1,515
Total comprehensive income attributable to:
Equity holders of the parent	1,226	1,501
Non-controlling interest	1	14
Total comprehensive income for the period	1,227	1,515

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

CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION as at 30 June 2026

		30 June 2026	31 December 2025
	Notes	US$m	US$m
Current assets
Cash and cash equivalents		4,339	5,712
Receivables		1,928	1,751
Inventories		579	693
Other financial assets	D.3	119	229
Tax receivable		184	114
Other assets		47	123
Total current assets		7,196	8,622
Non-current assets
Receivables		771	823
Inventories		371	288
Other financial assets	D.3	109	64
Exploration and evaluation assets	B.1	710	790
Property, plant and equipment	B.2	47,797	46,555
Deferred tax assets		3,288	2,658
Lease assets		1,795	1,428
Investments accounted for using the equity method		272	260
Intangible assets	B.4	4,856	4,853
Other assets		516	160
Total non-current assets		60,485	57,879
Total assets		67,681	66,501
Current liabilities
Payables		1,779	1,841
Interest-bearing liabilities	C.1	983	782
Other financial liabilities	D.3	148	8
Provisions	D.2	1,238	1,212
Tax payable		500	539
Lease liabilities		303	159
Other liabilities		229	876
Total current liabilities		5,180	5,417
Non-current liabilities
Interest-bearing liabilities	C.1	10,387	11,181
Deferred tax liabilities		1,273	1,182
Other financial liabilities	D.3	363	212
Provisions	D.2	6,397	6,655
Tax payable		10	10
Lease liabilities		1,995	1,600
Other liabilities		352	401
Total non-current liabilities		20,777	21,241
Total liabilities		25,957	26,658
Net assets		41,724	39,843
Equity
Issued and fully paid shares	C.2	29,036	29,036
Shares reserved for employee share plans	C.2	(72)	(82)
Other reserves		6,034	6,382
Retained earnings		1,053	578
Equity attributable to equity holders of the parent		36,051	35,914
Non-controlling interest	E.4	5,673	3,929
Total equity		41,724	39,843

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

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS for the half-year ended 30 June 2026

		2026	2025
	Notes	US$m	US$m
Cash flows from/(used in) operating activities
Profit after tax for the period		1,673	1,330
Adjustments for:
Non-cash items
Depreciation and amortisation		2,223	2,555
Depreciation of lease assets		89	85
Change in fair value of derivative financial instruments		176	(206)
Net finance costs		122	63
Tax expense		362	424
Impairment losses	B.3	178	143
Restoration movement		(5)	445
Other		(143)	(99)
Changes in assets and liabilities
(Increase)/decrease in trade and other receivables		(65)	122
Decrease/(increase) in inventories		31	(65)
Decrease in provisions		(129)	(112)
(Decrease)/increase in other assets and liabilities		(363)	103
Decrease in trade and other payables		(62)	(186)
Cash generated from operations		4,087	4,602
Interest received		109	89
Borrowing costs relating to operating activities		(84)	(5)
Income tax and PRRT paid		(825)	(782)
Payments for restoration		(274)	(565)
Net cash from operating activities		3,013	3,339
Cash flows (used in)/from investing activities
Cash paid relating to business combination¹		(470)	—
Payments for capital and exploration expenditure		(3,673)	(4,881)
Reimbursements received from external parties for capital expenditure		181	236
Borrowing costs relating to investing activities		(297)	(330)
Deposits received from disposal of non-current assets		—	21
(Contributions to)/dividends from associates		(27)	17
Net cash used in investing activities		(4,286)	(4,937)
Cash flows (used in)/from financing activities
Proceeds from borrowings	C.1	—	4,849
Repayment of borrowings	C.1	(602)	(2,900)
Purchases of shares relating to employee share plans		—	(26)
Repayment of the principal portion of lease liabilities		(111)	(108)
Borrowing costs relating to lease liabilities		(1)	(1)
Contributions from/to non-controlling interests²		1,737	1,843
Dividends paid		(1,122)	(1,006)
Net cash (used in)/from financing activities		(99)	2,651
Net (decrease)/increase in cash held		(1,372)	1,053
Less: Cash and cash equivalents classified within assets held for sale		—	(108)
Cash and cash equivalents at the beginning of the period		5,712	3,923
Effects of exchange rate changes		(1)	12
Cash and cash equivalents at the end of the period		4,339	4,880
Relates to the final acquisition completion payment for Beaumont New Ammonia. Includes capital contribution of $1,668 million (2025: $1,870 million) from Stonepeak and $57 million (2025: nil) from Williams for the development of Louisiana LNG. Refer to Note B.5 for the transactions with equity holders of the Group.
The accompanying notes form part of the half-year financial statements.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY for the half-year ended 30 June 2026

	Issued and fully paid shares	Reserved shares	Employee benefits reserve	Non-controlling interest 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.2	C.2									E.4
	US$m	US$m	US$m	US$m	US$m	US$m	US$m	US$m	US$m	US$m	US$m	US$m
At 1 January 2026	29,036	(82)	287	(373)	795	188	5,557	(72)	578	35,914	3,929	39,843
Profit for the period	—	—	—	—	—	—	—	—	1,672	1,672	1	1,673
Other comprehensive (loss)/income	—	—	—	—	—	(449)	—	—	3	(446)	—	(446)
Total comprehensive (loss)/income for the period	—	—	—	—	—	(449)	—	—	1,675	1,226	1	1,227
Transfers	—	—	—	—	—	—	1,200	—	(1,200)	—	—	—
Transactions with non-controlling interests¹	—	—	—	(20)	—	—	—	—	—	(20)	1,754	1,734
Employee share plan redemptions	—	10	(10)	—	—	—	—	—	—	—	—	—
Share-based payments (net of tax)	—	—	53	—	—	—	—	—	—	53	—	53
Dividends paid	—	—	—	—	—	—	(1,122)	—	—	(1,122)	(11)	(1,133)
At 30 June 2026	29,036	(72)	330	(393)	795	(261)	5,635	(72)	1,053	36,051	5,673	41,724
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	(270)	795	217	5,063	(71)	666	35,639	2,868	38,507
Represents the difference between the amount of the adjustment to non-controlling interest and any consideration received. Refer to Note B.5 for the transactions with equity holders of the Group.

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

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2026

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, Developments and Exploration and Carbon Solutions sections.

The condensed consolidated half-year financial statements were authorised for issue in accordance with a resolution of the directors on 25 August 2026.

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 2025 (2025 Financial Statements).

The Group’s accounting policies are materially consistent with those disclosed in the Group’s 2025 Financial Statements. Adoption of new or amended standards and interpretations effective 1 January 2026 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 2025 Financial Statements. Estimates have been revised, where required, to reflect current market conditions including the impact of climate change.

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 condensed consolidated 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 2026/183 dated 24 March 2026, unless otherwise stated.

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 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 2026. 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. Refer to Note A.1 for more details.

Reporting segments

Refer to the 2025 Financial Statements for details of the Group’s operating segment information.

A. Earnings for the period

A.1 Segment revenue and expenses

	Australia		International		Marketing		Corporate		Consolidated
	2026	2025	2026	2025	2026	2025	2026	2025	2026	2025
	US$m	US$m	US$m	US$m	US$m	US$m	US$m	US$m	US$m	US$m
Liquified natural gas	2,189	2,417	—	—	836	522	—	—	3,025	2,939
Pipeline gas	565	564	20	141	—	—	—	—	585	705
Crude oil and condensate	784	683	2,515	2,011	142	13	—	—	3,441	2,707
Natural gas liquids	115	90	17	18	2	9	—	—	134	117
Ammonia	—	—	171	—	—	—	—	—	171	—
Revenue from sale of products	3,653	3,754	2,723	2,170	980	544	—	—	7,356	6,468
Intersegment revenue¹	(101)	(9)	—	—	101	9	—	—	—	—
Processing and services revenue	88	109	—	—	—	—	—	—	88	109
Shipping and other revenue	—	—	—	—	2	13	—	—	2	13
Other revenue	(13)	100	—	—	103	22	—	—	90	122
Operating revenue²	3,640	3,854	2,723	2,170	1,083	566	—	—	7,446	6,590
Production costs³	(539)	(399)	(210)	(268)	—	—	—	—	(749)	(667)
Feed gas, services and processing costs³	(92)	(92)	(146)	—	—	—	—	—	(238)	(92)
Royalties, excise and levies	(134)	(126)	(9)	(30)	—	—	—	—	(143)	(156)
Insurance	(16)	(19)	(11)	(8)	—	—	(6)	(10)	(33)	(37)
Inventory movement	(77)	(7)	23	6	—	—	—	—	(54)	(1)
Costs of production	(858)	(643)	(353)	(300)	—	—	(6)	(10)	(1,217)	(953)
Property, plant and equipment depreciation	(1,032)	(1,170)	(1,150)	(1,340)	—	—	(27)	(31)	(2,209)	(2,541)
Shipping and direct sales costs	(70)	(36)	(53)	(41)	(54)	(43)	—	—	(177)	(120)
Trading costs	(101)	(88)	—	—	(871)	(322)	—	—	(972)	(410)
Other hydrocarbon costs	(10)	(6)	—	—	—	—	—	—	(10)	(6)
Other	(14)	(15)	(5)	—	—	—	—	—	(19)	(15)
Other cost of sales	(195)	(145)	(58)	(41)	(925)	(365)	—	—	(1,178)	(551)
Cost of sales	(2,085)	(1,958)	(1,561)	(1,681)	(925)	(365)	(33)	(41)	(4,604)	(4,045)
Gross profit/(loss)	1,555	1,896	1,162	489	158	201	(33)	(41)	2,842	2,545
Other income⁴	230	82	8	67	12	(9)	14	239	264	379
Exploration and evaluation expenditure	(26)	(10)	(73)	(71)	—	—	—	—	(99)	(81)
Amortisation of permit acquisitions	—	—	(4)	(3)	—	—	—	—	(4)	(3)
Write-offs	—	—	(1)	—	—	—	—	—	(1)	—
Exploration and evaluation	(26)	(10)	(78)	(74)	—	—	—	—	(104)	(84)
General, administration and other costs	(28)	(15)	(46)	(8)	—	(1)	(168)	(237)	(242)	(261)
Amortisation of intangible assets	—	—	(1)	—	—	—	(9)	(11)	(10)	(11)
Depreciation of lease assets	(12)	(18)	(3)	(1)	(44)	(39)	(30)	(27)	(89)	(85)
Restoration movement	3	(443)	2	(2)	—	—	—	—	5	(445)
Other⁵	(58)	(19)	(26)	(2)	(72)	(8)	(175)	(49)	(331)	(78)
Other costs	(95)	(495)	(74)	(13)	(116)	(48)	(382)	(324)	(667)	(880)
Other expenses	(121)	(505)	(152)	(87)	(116)	(48)	(382)	(324)	(771)	(964)
Impairment losses⁶	—	—	(135)	—	—	—	(43)	(143)	(178)	(143)
Profit/(loss) before tax and net finance costs	1,664	1,473	883	469	54	144	(444)	(269)	2,157	1,817
Intersegment revenue reflects the margin recognised on products and services transferred between segments. Operating revenue includes revenue from contracts with customers of $7,444 million (2025: $6,577 million) and sub-lease income of $2 million (2025: $13 million) disclosed within shipping and other revenue. In 2026, feed gas, services and processing-related costs are presented separately to better reflect underlying activities of the Group. In the 2025 Financial Statements, these costs were included within production costs. Includes $138 million of released deferred income associated with the Pluto Train 2 GIP transaction and other income not associated with the ongoing operations of the business. The 2025 amount includes a $162 million unrealised fair value gain on the Perdaman-related embedded derivatives, $32 million net gain on hedging activities, fees, recoveries and other income not associated with the ongoing operations of the business. Includes $135 million unrealised fair value loss on the Perdaman-related embedded derivatives, $71 million net loss on hedging activities and other items not associated with the ongoing operations of the business. Includes $135 million (2025: nil) relating to the impairment of the Calypso exploration and evaluation asset and $43 million (2025: $143 million) relating to the impairment of the H2OK Project. Refer to Note B.3 for details on impairment.

A.2 Finance costs

	2026	2025
	US$m	US$m
Interest on interest-bearing liabilities	303	281
Interest on lease liabilities	65	51
Accretion charge	156	148
Other finance costs	17	29
Less: Borrowing costs capitalised against qualifying assets	(296)	(340)
Total finance costs	245	169

A.3 Dividends paid and proposed

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

	2026	2025
	US$m	US$m
(a) Dividends paid during the financial year
Prior year fully franked final dividend US$0.59, paid on 27 March 2026 (2025: US$0.53, paid on 2 April 2025)	1,122	1,006
(b) Dividend determined subsequent to the reporting period (not recorded as a liability)
Current year fully franked interim dividend US$0.57 to be paid on 25 September 2026 (2025: US$0.53 to be paid on 24 September 2025)	1,084	1,006

A.4 Earnings per share

	2026	2025
Profit attributable to equity holders of the parent (US$m)	1,672	1,316
Weighted average number of shares on issue for basic earnings per share	1,896,068,066	1,895,162,804
Effect of dilution from contingently issuable shares	19,457,286	17,049,593
Weighted average number of shares on issue adjusted for the effect of dilution	1,915,525,352	1,912,212,397
Basic earnings per share (US cents)	88.2	69.4
Diluted earnings per share (US cents)	87.3	68.8
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.

A.5 Taxes

	2026	2025
	US$m	US$m
Reconciliation of income tax expense/(benefit)
Profit before tax	2,035	1,754
PRRT benefit/(expense)	305	(71)
Profit before income tax	2,340	1,683
Income tax expense calculated at 30%	702	505
Effect of tax rate differentials	41	42
Effect of deferred tax assets not recognised	50	12
Effect of tax benefits previously unrecognised	(90)	(193)
Foreign exchange impact on tax expense/(benefit)	28	(35)
Adjustment to prior years	(41)	4
Other	(23)	18
Income tax expense	667	353

The global operations effective income tax rate (EITR) of 28.5% (2025: 21.0%) is calculated as the Group’s income tax expense divided by profit before income tax. The underlying EITR is 29.6% when excluding the recognition of additional Pluto PRRT deferred tax asset, income tax deferred tax asset relating to US net operating losses and impairment losses. During the period, the Group recognised an additional PRRT deferred tax asset of $596 million ($417 million post tax) for the Pluto project, reflecting increased expected utilisation of available PRRT deductions driven by the higher pricing environment. The Group also recognised a $90 million income tax deferred tax asset in respect of heritage Woodside US net operating loss carryforwards, as utilisation of those losses is now considered probable.

B. Production and growth assets

B.1 Exploration and evaluation assets

	Asia Pacific	Americas	Africa	Total
	US$m	US$m	US$m	US$m
Half-year ended 30 June 2026
Carrying amount at 1 January 2026	582	207	1	790
Additions	18	47	—	65
Amortisation of licence acquisition costs	—	(4)	—	(4)
Expensed	—	(1)	—	(1)
Impairment¹	—	(135)	—	(135)
Transferred exploration and evaluation	(5)	—	—	(5)
Carrying amount at 30 June 2026	595	114	1	710

Year ended 31 December 2025
Carrying amount at 1 January 2025	571	149	1	721
Additions	17	67	—	84
Amortisation of licence acquisition costs	—	(5)	—	(5)
Expensed	—	(4)	—	(4)
Transferred exploration and evaluation	(6)	—	—	(6)
Carrying amount at 31 December 2025	582	207	1	790
Refer to Note B.3 for details of impairment of the Calypso exploration and evaluation asset.

B.2 Property, plant and equipment

	Land and buildings	Oil and gas properties	Projects in development¹	Other plant and equipment	Total
	US$m	US$m	US$m	US$m	US$m
Half-year ended 30 June 2026
Carrying amount at 1 January 2026	744	23,091	22,437	283	46,555
Additions²	—	9	3,492	—	3,501
Disposals at written down value	—	—	(12)	—	(12)
Impairment loss³	—	—	(43)	—	(43)
Completions and transfers⁴	136	398	(2,010)	1,481	5
Depreciation	(32)	(2,135)	—	(42)	(2,209)
Carrying amount at 30 June 2026	848	21,363	23,864	1,722	47,797
At 30 June 2026
Historical cost	2,035	59,227	24,389	2,201	87,852
Accumulated depreciation and impairment	(1,187)	(37,864)	(525)	(479)	(40,055)
Carrying amount	848	21,363	23,864	1,722	47,797
Year ended 31 December 2025
Carrying amount at 1 January 2025	734	25,787	15,926	189	42,636
Adjustment to purchase price allocation	(21)	—	(9)	—	(30)
Additions	—	657	8,658	10	9,325
Disposals at written down value	(6)	(44)	(143)	(3)	(196)
Impairment loss	—	—	(143)	—	(143)
Completions and transfers	98	1,609	(1,852)	151	6
Depreciation	(61)	(4,918)	—	(64)	(5,043)
Carrying amount at 31 December 2025	744	23,091	22,437	283	46,555
At 31 December 2025
Historical cost	1,899	58,820	22,919	720	84,358
Accumulated depreciation and impairment	(1,155)	(35,729)	(482)	(437)	(37,803)
Carrying amount	744	23,091	22,437	283	46,555
Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations. Includes $3,243 million of capital additions, $296 million of capitalised borrowing costs, and $26 million relating to changes in restoration provision assumptions. Included within capital additions is $1,595 million relating to the Louisiana LNG Project. Refer to Note B.3 for details of impairment of the H2OK Project. Primarily reflects the transfer of the Beaumont New Ammonia (BNA) Project carrying amount from projects in development to other plant and equipment following completion in March 2026.
The Group has capital commitments contracted for, but not provided for in the financial statements, of $9,699 million (31 December 2025: $11,957 million). Capital commitments relate predominantly to the Louisiana LNG and Trion Projects (31 December 2025: Louisiana LNG, Trion and Scarborough Energy Projects). Capital commitments for Louisiana LNG totalling $8,170 million (31 December 2025: $9,986 million) are shared between the Group, Stonepeak and Williams based on their respective interests in the project. Under the transaction arrangements, Stonepeak has committed up to $5,700 million to fund its share of the capital expenditure associated with the foundation development of Louisiana LNG. Refer to Note B.5 for details of the sell-down arrangement with Stonepeak and the contributions made by Stonepeak to date.

B.3 Impairment of exploration and evaluation assets, property, plant and equipment and goodwill

Impairment of Calypso exploration and evaluation asset

As at 30 June 2026, the Calypso exploration and evaluation asset was assessed as not fully recoverable following the Group's decision to pursue a divestment of its 70% operated interest in the Calypso Project. Consequently, an impairment loss of $135 million (2025: nil) was recognised in the International segment of Note A.1 for the half-year ended 30 June 2026. Refer to Note E.3 for details of the subsequent agreement to sell the Group's interest in the Calypso Project.

Impairment of H2OK Project

As at 30 June 2026, the remaining H2OK Project assets were assessed as not recoverable following the decision to retire the assets. Consequently, an impairment loss before tax of $43 million (2025: $143 million) was recognised in the Corporate segment of Note A.1 for the half-year ended 30 June 2026 reducing the carrying value of the assets to nil.

B.4 Intangible assets

	Goodwill	Contract assets	Software	Total
	US$m	US$m	US$m	US$m
Half-year ended 30 June 2026
Carrying amount at 1 January 2026	3,952	714	187	4,853
Additions	–	–	18	18
Amortisation	–	(2)	(8)	(10)
Disposals	–	(5)	–	(5)
Carrying amount at 30 June 2026	3,952	707	197	4,856
At 30 June 2026
Cost	4,429	796	238	5,463
Accumulated amortisation and impairment	(477)	(89)	(41)	(607)
Carrying amount	3,952	707	197	4,856
Year ended 31 December 2025
Carrying amount at 1 January 2025	3,866	757	203	4,826
Adjustment to purchase price allocation	86	30	–	116
Additions	–	–	2	2
Amortisation	–	(73)	(18)	(91)
Carrying amount at 31 December 2025	3,952	714	187	4,853
At 31 December 2025
Cost	4,429	814	220	5,463
Accumulated amortisation and impairment	(477)	(100)	(33)	(610)
Carrying amount	3,952	714	187	4,853

B.5 Transactions with equity holders of the Group

Sell-down arrangement with Stonepeak

During 2025, the Group and Stonepeak entered into an agreement for Stonepeak to acquire a 40% interest in Louisiana LNG Infrastructure LLC, a subsidiary within the Group. Stonepeak will provide up to $5,700 million 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. As at 30 June 2026, total payment of $4,262 million was received.

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 will to revert to 40% when the project starts generating revenue. Refer to Note E.4 Subsidiaries.

C. Debt and capital

C.1 Interest-bearing liabilities and financing facilities

	Bilateral facilities	Syndicated facilities	JBIC facility	US bonds	Medium term notes	Total
	US$m	US$m	US$m	US$m	US$m	US$m
Half-year ended 30 June 2026
At 1 January 2026	(4)	2,232	1,000	8,535	200	11,963
Repayments¹	—	(600)	—	—	—	(600)
Transaction costs capitalised and amortised	(1)	2	—	6	—	7
Carrying amount at 30 June 2026	(5)	1,634	1,000	8,541	200	11,370
Current	(2)	(4)	—	789	200	983
Non-current	(3)	1,638	1,000	7,752	—	10,387
Carrying amount at 30 June 2026	(5)	1,634	1,000	8,541	200	11,370
Undrawn balance at 30 June 2026	2,650	1,200	—	—	—	3,850
Year ended 31 December 2025
At 1 January 2025	495	2,233	1,000	6,069	200	9,997
Drawdowns	1,400	—	—	3,500	—	4,900
Repayments	(1,900)	—	—	(1,000)	—	(2,900)
Transaction costs capitalised and amortised	1	(1)	—	(34)	—	(34)
Carrying amount at 31 December 2025	(4)	2,232	1,000	8,535	200	11,963
Current	(2)	(5)	—	789	—	782
Non-current	(2)	2,237	1,000	7,746	200	11,181
Carrying amount at 31 December 2025	(4)	2,232	1,000	8,535	200	11,963
Undrawn balance at 31 December 2025	2,350	1,200	—	—	—	3,550
In June 2026, the Group settled the $600 million syndicated facility that was executed on 17 January 2020.

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

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 $8,541 million (31 December 2025: $8,535 million) and a fair value of $8,636 million (31 December 2025: $8,665 million). The medium-term notes have a carrying amount of $200 million (31 December 2025: $200 million) and a fair value of $198 million (31 December 2025: $197 million). Fair value is determined by reference to quoted market prices for these instruments and is classified as Level 1 within the fair value hierarchy.

C.2 Contributed equity

Issued and fully paid shares

	Number of shares	US$m
Half-year ended 30 June 2026
Opening balance	1,901,100,143	29,036
Amounts as at 30 June 2026	1,901,100,143	29,036
Year ended 31 December 2025
Opening balance	1,898,749,771	29,001
Shares issued	2,350,372	35
Amounts as at 31 December 2025	1,901,100,143	29,036

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 2026
Opening balance	5,283,450	(82)
Vested/allocated during the half-year	(644,610)	10
Amounts as at 30 June 2026	4,638,840	(72)
Year ended 31 December 2025
Opening balance	3,080,842	(58)
Purchases during the year	5,700,372	(88)
Vested/allocated during the year	(3,497,764)	64
Amounts as at 31 December 2025	5,283,450	(82)

D. Other assets and liabilities

D.1 Segment assets and liabilities

	30 June 2026	31 December 2025
	US$m	US$m
(a) Segment assets
Australia	30,569	30,541
International	26,885	24,773
Marketing	1,094	965
Corporate	9,133	10,222
	67,681	66,501

	30 June 2026	31 December 2025
	US$m	US$m
(b) Segment liabilities
Australia	6,899	7,252
International	2,856	2,531
Marketing	1,297	1,054
Corporate	14,905	15,821
	25,957	26,658
Corporate assets mainly comprise cash and cash equivalents, deferred tax assets, new energy assets in development and lease assets. Corporate liabilities mainly comprise interest-bearing liabilities, deferred tax liabilities and lease liabilities.

D.2 Provisions

	Restoration¹	Employee benefits	Other	Total
	US$m	US$m	US$m	US$m
Half-year ended 30 June 2026
At 1 January 2026	6,886	669	312	7,867
Change in provision	(229)	(86)	(73)	(388)
Unwinding of present value discount	156	—	—	156
Carrying amount at 30 June 2026	6,813	583	239	7,635
At 30 June 2026
Current	765	373	100	1,238
Non-current	6,048	210	139	6,397
Carrying amount	6,813	583	239	7,635
Year ended 31 December 2025
At 1 January 2025	6,526	654	367	7,547
Adjustment to purchase price allocation	—	—	100	100
Change in provision	254	11	(138)	127
Unwinding of present value discount	283	5	—	288
Disposals	(177)	(1)	(17)	(195)
Carrying amount at 31 December 2025	6,886	669	312	7,867
At 31 December 2025
Current	637	449	126	1,212
Non-current	6,249	220	186	6,655
Carrying amount	6,886	669	312	7,867
2026 change in provision is due to provisions used of $255 million, a revision of discount rates of $90 million offset by changes in foreign exchange rates of $92 million and changes in estimates of $24 million. 2025 change in provision is due to changes in estimates of $898 million, changes in foreign exchange rates of $233 million offset by provisions used of $823 million and a revision of discount rates of $54 million.

D.3 Other financial assets and liabilities

	30 June 2026	31 December 2025
	US$m	US$m
Other financial assets
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges	152	217
Other financial assets	18	14
Financial instruments at fair value through other comprehensive income
Other financial assets	58	62
Total other financial assets	228	293
Current	119	229
Non-current	109	64
Net carrying amount	228	293
Other financial liabilities
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges	130	7
Embedded derivative	347	212
Other financial liabilities	34	1
Total other financial liabilities	511	220
Current	148	8
Non-current	363	212
Net carrying amount	511	220

Hedging activities

As at 30 June 2026, the Group had the following principal unrealised commodity hedging positions:

36 MMboe of oil production volumes hedged at an average price of $75 per barrel through to 2027.
Corpus Christi LNG volumes hedged through Henry Hub (HH) and Title Transfer Facility (TTF) commodity swap contracts.

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

	30 June 2026	31 December 2025
	US$m	US$m
Brent commodity swaps (cash flow hedges)	103	114
HH natural gas commodity swaps (cash flow hedges)	(26)	(4)
TTF LNG commodity swaps (cash flow hedges)	(63)	66
Interest rate swaps (cash flow hedges) ¹	—	15
Foreign exchange forwards (cash flow hedges)	8	19
Total derivative financial instruments asset designated as hedges	22	210
During June 2026, the Group early settled the $600 million syndicated facility, being the underlying hedged item. Accordingly, the associated hedging instrument ceased to be designated as a hedge. Refer to Note C.1.

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 2026 amounted to a net liability of $347 million (31 December 2025: net liability of $212 million). The derivative is remeasured to fair value at each reporting date. For the half-year ended 30 June 2026, an unrealised loss of $135 million has been recognised through other expense (30 June 2025: unrealised gain of $162 million through other income).

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 reclassifications between the fair value hierarchy levels.

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

Financial risk factors

The Group’s activities expose its financial instruments to a variety of market risks, including foreign exchange, commodity price and interest rate risk. The half-year financial statements 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 2025 Financial Statements. There have been no significant changes in risk management policies since 31 December 2025. 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) 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 – 2.50%.
Discount rate – a pre-tax interest rate curve (range: 5.04% to 8.07%).
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%	179
	TTF sales price: decrease of 10%	(177)
	Discount rate: increase of 1.5%²	(182)
	Discount rate: decrease of 1.5%²	223
	Amounts shown represent the change of the present value of the contract keeping all other variables constant. A change of 1.5% represents 150 basis points.

E. Other items

E.1 Contingent liabilities and assets

	2026	2025
Contingent liabilities at reporting date	US$m	US$m
Contingent liabilities	340	322
Total disclosed contingent liabilities	340	322

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 the 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 $31 million as at 30 June 2026 (31 December 2025: $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, including the amendments to AASB/IFRS 7 and AASB/IFRS 9 disclosed in Financial Statements within the Annual Report for the year ended 31 December 2025. 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 condensed consolidated 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 2026 reporting period and have not been early adopted by the Group. Except for AASB 18/IFRS 18 Presentation and Disclosure in Financial Statements, these pronouncements are not expected to have a material impact on the Group’s consolidated financial statements in the current or future reporting periods. AASB/IFRS 18 will replace AASB 101/IAS 1 Presentation of Financial Statements, introducing new requirements that will help to achieve comparability of the financial performance of similar entities and provide more relevant information and transparency to users. Even though AASB/IFRS 18 will not impact the recognition or measurement of items in the financial statements, its impacts on presentation and disclosure are expected to be pervasive, particularly those related to the consolidated income statement and providing management-defined performance measures within the financial statements. Management is currently assessing the detailed implications of applying the new standard on the Group’s financial statements. The Group will apply the new standard from its mandatory effective date of 1 January 2027. Retrospective application is required.

E.3 Events after the end of the reporting period

Operatorship of Bass Strait assets

On 29 July 2025, the Group 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 was completed and effective on 1 July 2026, subsequent to the report date.

As part of the transaction, Woodside acquired ExxonMobil’s employing entity for the Bass Strait employees which includes employee-related assets and liabilities for the consideration of $1. The employee expenses will continue to be funded by the Bass Strait joint venture partners based on their equity interests. The acquisition of the employing entity will to be treated as a business combination and will be accounted for in the 2026 Annual Report.

E.3 Events after the end of the reporting period (continued)

Browse Joint Venture pre-emption right

On 12 June 2026, the Group exercised its pre-emption right to acquire a 10.67% participating interest in the Browse Joint Venture. The acquisition consideration comprises a payment of $225 million, reimbursement of certain joint venture cash call contributions and a contingent payment of $175 million subject to specified future conditions. The transaction is subject to customary conditions precedent, including regulatory approvals, and had not completed at the reporting date. Upon completion, the Group's participating interest in the Browse Joint Venture will increase to 41.27%.

Calypso divestment

Subsequent to the reporting date, the Group entered into an agreement to sell its 70% operated interest in the Calypso Project to bp. Completion of the transaction is subject to customary conditions precedent, including government and regulatory approvals, and is expected to occur by the end of 2026. The transaction comprises fixed and contingent consideration. As disclosed in Note B.3, an impairment loss of $135 million was recognised as at 30 June 2026 following the Group's decision to divest its interest in the Calypso Project.

E.4 Subsidiaries

Subsidiaries with non-controlling interests

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

Name of entity	Principal place of business	% held by NCI	NCI parties
Burrup Facilities Company Pty Ltd	Australia	10.00%	Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd
Burrup Train 1 Pty Ltd	Australia	10.00%	Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd
Louisiana LNG Infrastructure LLC¹	United States	62.87%	Stonepeak
Louisiana LNG LLC	United States	10.00%	Williams
1. The non-controlling interest in Louisiana LNG Infrastructure LLC is measured at its proportionate share of the subsidiary’s net assets. The proportion of net assets each member is entitled to upon liquidation varies prior to operations commencement. Prior to this milestone, entitlements are determined in proportion to the cumulative capital contributions made by each member. The NCI percentage is expected to revert to 40% when the project commences operations.

E.4 Subsidiaries (continued)

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

	Burrup Facilities Company Pty Ltd	Burrup Train 1 Pty Ltd	Louisiana LNG Infrastructure LLC	Louisiana LNG LLC	Total
	US$m	US$m	US$m	US$m	US$m
Half-year ended 30 June 2026
Current assets	379	314	678	339	1,710
Non-current assets	4,694	2,551	7,315	2,738	17,298
Current liabilities	(45)	(36)	(448)	(251)	(780)
Non-current liabilities	(542)	(299)	(84)	(31)	(956)
Net assets	4,486	2,530	7,461	2,795	17,272
Accumulated balance of NCI	449	253	4,691	280	5,673
(Loss)/Profit	(21)	19	3	(5)	(4)
(Loss)/Profit allocated to NCI	(2)	2	2	(1)	1
Dividends paid to NCI	(1)	(10)	—	—	(11)
Year ended 31 December 2025
Current assets	288	225	260	118	891
Non-current assets	4,810	2,729	5,402	2,331	15,272
Current liabilities	(38)	(39)	(318)	(143)	(538)
Non-current liabilities	(544)	(306)	(86)	(37)	(973)
Net assets	4,516	2,609	5,258	2,269	14,652
Accumulated balance of NCI	452	261	2,989	227	3,929
Profit/(Loss)	76	117	—	(2)	191
Profit allocated to NCI	8	11	—	—	19
Dividends paid to NCI	(36)	(24)	—	—	(60)

DIRECTORS’ DECLARATION

for the half-year ended 30 June 2026

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 2026 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

Chair of the Board

Melbourne, Victoria

25 August 2026

E M Westcott

Chief Executive Officer and Managing Director

Sydney, New South Wales

25 August 2026

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 2026, the condensed consolidated income statement, condensed consolidated statement of comprehensive income, condensed consolidated statement of changes in equity and condensed consolidated statement of cash flows 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:

giving a true and fair view of the Group’s financial position as at 30 June 2026 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.

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.

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 2026 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

Partner

Perth, Western Australia

25 August 2026

Appendix 4D

Dividends

Ex-dividend date	3 September 2026
Record date for the interim dividend	4 September 2026

Date the dividend is payable	25 September 2026
		Current period	Previous corresponding period⁴⁴
Interim dividend - fully franked	US cents per share	57	53
None of these dividends are foreign sourced.

Woodside dividends are determined 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 7 September 2026.

Net Tangible Assets per ordinary security

	Current period	Previous corresponding period⁴⁴
	US$	US$
Net Tangible Assets (US$ per ordinary security)⁴⁵	16.41	16.19

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 period⁴⁴
North West Shelf Gas Pty Ltd	33.33%	33.33%
North West Shelf Liaison Company Pty Ltd	—%	33.33%
China Administration Company Pty Ltd	33.33%	33.33%
International Gas Transportation Company Limited	—%	33.33%
North West Shelf Shipping Service Company Pty Ltd	—%	33.33%
North West Shelf Lifting Coordinator Pty Ltd	33.33%	33.33%
Blue Ocean Seismic Services Limited	16.17%	16.17%
Oakbio Inc	25.32%	25.32%
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	12.92%	12.05%
Driftwood Pipeline, LLC	20.00%	—%

Shareholder information

Key announcements 2026

January	Fourth quarter 2025 report
February	Woodside Releases Annual Reserves Statement
	Woodside Releases Full-Year 2025 Results
	Full-Year 2025 Results Briefing Transcript
	Annual Report 2025 [and US Annual Report 2025 (Form 20-F)]
March	Sustainability Briefing 2026
	Liz Westcott Appointed Woodside CEO
	Appointment of Director to Woodside Board
	Woodside assumes control of Beaumont New Ammonia operations
April	2026 Annual General Meeting voting results
April	First quarter 2026 report
June	Woodside exercises Browse pre-emption right
July	Second quarter 2026 report
August	Half-Year 2026 results

Events calendar 2026-2027

Key calendar dates for Woodside shareholders in 2026-2027. Please note dates are subject to review.

August	25	Half-Year 2026 results
September	3	Ex-dividend date for interim dividend (Australian Securities Exchange)
	4	Ex-dividend date for interim dividend (New York Stock Exchange)
	4	Record date for interim dividend
	25	Payment date for interim dividend
October	21	Third quarter 2026 report
November	5	2026 Capital Markets Day (Australia)
November	12	2026 Capital Markets Day (United States)
December	31	Year-end 2026
January	28	Fourth quarter 2026 report
February	23	2026 Annual Report

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 the authorised depositary bank for Woodside’s American Depositary Receipt programme can be found on the website.

Assets

Producing facilities

Australia

Asset	Role	Equity	Product
Pluto LNG	Operator	90 %	LNG, pipeline gas and condensate
North West Shelf¹	Operator	33.33 %	LNG, pipeline gas, condensate and NGLs
Wheatstone¹	Non-operator	13 %	LNG, pipeline gas and condensate
Julimar-Brunello	Operator	65 %	LNG, pipeline gas and condensate
Okha FPSO¹	Operator	50 %	Crude oil
Ngujima-Yin FPSO	Operator	60 %	Crude oil
Bass Strait	Operator²	32.5—50%	Pipeline gas, condensate and NGLs
Pyrenees FPSO	Operator	40—71.4%	Crude oil
Macedon	Operator	71.4 %	Pipeline gas
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. Subsequent to the period, Woodside assumed operatorship of the Bass Strait assets. Refer to "Woodside completes Gippsland Basin operatorship transition" announced on 1 July 2026.

International

Asset	Role	Equity	Product
Sangomar	Operator	82 %	Crude oil
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
Beaumont New Ammonia	Operator	100 %	Ammonia

Projects

Post FID

Asset	Role	Equity	Product
Scarborough	Operator	74.9%	LNG and pipeline gas
Pluto Train 2	Operator	51.0%	LNG and pipeline gas
Trion	Operator	60.0%	Crude oil
Louisiana LNG LLC	Operator	90.0%	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	30.60%¹	LNG, pipeline gas and condensate
Greater Scarborough²	Operator	100%	Gas
Liard	Non-operator	50%	Gas
Sunrise	Operator	33.44%	LNG, pipeline gas and condensate
In June 2026, Woodside pre-empted the sale of CNPC’s stake in Browse. Refer to "Woodside exercises Browse pre-emption right" announced 12 June 2026 for details. "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
Subject to a final investment decision and regulatory approvals. Excludes acquisitions subsequent to the period. Solar generation, battery services and transmission access and services will be supplied to Woodside under contracts with third parties.

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-west 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	Operator²	Gippsland Basin Joint Venture	Located in the Gippsland Basin off the coast of Victoria
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. Subsequent to the period, Woodside assumed operatorship of the Bass Strait assets. Refer to "Woodside completes Gippsland Basin operatorship transition" announced on 1 July 2026.

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
Europe
Ireland	FEL 5/13	Operator	100% - Exit initiated	Oil or gas prone basin
Africa
Egypt	Tiba Block	Non-operator	40%	Oil and gas prone basin
Egypt	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	EB 550, EB 594, EB 636, EB 637, EB 638, GB 721, GB 780, GB 821, GB 824, GB 825, GB 866, KC 259, KC 297, KC 301, KC 343, KC 431, KC 859, KC 903, KC 904, KC 905, KC 948, KC 949, WR 577, WR 751, WR 795, WR 796	Operator	100%	Oil prone basin
	WR 443, WR 444, WR 488	Operator	80%	Oil prone basin
	GC 124	Operator	75%	Oil prone basin
	EB 699, AC 36, AC 80	Operator	70%	Oil prone basin
	GC 282, GC 237	Non-operator	50%	Oil prone basin
	AC 125, AC 126, AC 81	Operator	45%	Oil prone basin
	GC 598	Non-operator	40%	Oil prone basin
	AT 453	Non-operator	30%	Oil prone basin
	GC 870	Non-operator	24%	Oil prone basin
	GC 680, GC 723, GC 724, GC 679, GC 768	Non-operator	18%	Oil prone basin

Alternative Performance Measures

Woodside uses various alternative performance measures (APM) which are non-IFRS measures that are unaudited but derived from the 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 65 for more information.

APMs and their nearest respective IFRS measure.

APMs derived from the condensed consolidated income statement and other notes	30 June 2026	30 June 2025
	US$m	US$m
EBIT/EBITDA excluding impairment
Net profit after tax	1,673	1,330
Adjusted for:
Finance income	(123)	(106)
Finance costs	245	169
PRRT expense/(benefit)	(305)	71
Income tax expense	667	353
EBIT	2,157	1,817
Adjusted for:
Property, plant and equipment depreciation	2,209	2,541
Amortisation of licence acquisition costs	4	3
Amortisation of intangible assets	10	11
Depreciation of lease assets	89	85
Impairment losses	178	143
EBITDA excluding impairment	4,647	4,600

Underlying NPAT
Net profit after tax attributable to equity holders of the parent	1,672	1,316
Adjusted for the following exceptional items:
Less: Pluto DTA recognition	(417)	—
Less: USA DTA recognition	(90)	—
Add: Impairment loss (post-tax)	169	113
Less: Louisiana DTA recognition	—	(182)
Underlying NPAT	1,334	1,247

Average realised price¹
Adjusted revenue from sale of products²	7,381	6,468
Sales volumes (MMboe)	99.8	104.8
Average realised price (US$ per boe)	74.0	61.7

Unit production cost³
Production costs	749	667
Production (reserves) volumes (MMboe)⁴	85.0	98.6
Unit production cost (US$ per boe)	8.8	6.8
2025 sales volumes have been restated to include additional volumes of 0.19 MMboe to reflect pipeline gas volumes sold in MMBtu at a revised boe conversion factor, impacting realised price by ($0.1)/boe Adjusted revenue from sale of products comprises of revenue from sale of products of $7,356 million and provisional price adjustments of $25 million, which is included in other income (refer to Note A.1). The calculation has been updated to exclude feed gas, services and processing costs and processing volumes. The 2025 comparative has been restated to be presented on the same basis. 2026 Includes production volumes of 86.5 MMboe, adjusted for processing volumes of 1.5 MMboe.

APMs derived from the condensed consolidated statement of cash flows and other notes	30 June 2026	30 June 2025
	US$m	US$m
Free cash flow
Net cash from operating activities	3,013	3,339
Net cash used in investing activities	(4,286)	(4,937)
Adjusted for:
Contributions from/(to) NCI	1,737	1,843
Lease repayments	(112)	(109)
Free cash flow¹	352	136

Liquidity
Cash and cash equivalents	4,339	4,880
Add: Available undrawn facilities	3,850	3,550
Liquidity	8,189	8,430
The 2026 calculation has been updated to adjust for contributions from/(to) NCI and lease repayments. The 2025 comparative has been restated to be presented on the same basis.

APMs derived from the condensed consolidated statement of financial position and other notes	30 June 2026	30 June 2025
	US$m	US$m
Capital expenditure
Capital additions on evaluation	24	29
Capital additions on property, plant and equipment	3,243	4,372
Less: Cash contributions from participants	(1,725)	(1,870)
Capital additions on other	95	27
Capital expenditure	1,637	2,558
Acquisitions	470	—
Capital expenditure and acquisitions	2,107	2,558

Exploration expenditure
Exploration and evaluation expenditure	104	84
Adjusted for:
Evaluation expenditure	(22)	(2)
Amortisation expense	(4)	(3)
Prior year expense written off	(1)	—
Exploration capitalised	42	5
Exploration expenditure¹	119	84
Capital and exploration expenditure¹	1,756	2,642

Net tangible assets per ordinary security
Net assets	41,724	38,507
Adjusted for:
Goodwill	(3,952)	(3,952)
Non-controlling interest	(5,673)	(2,868)
Other intangible assets	(904)	(939)
Net tangible assets	31,195	30,748
Number of issued and fully paid shares	1,901,100,143	1,898,749,771
Net tangible assets per ordinary security (US$ per ordinary security)	16.41	16.19

Gearing
Interest-bearing liabilities (Current and non-current)	11,370	11,954
Lease liabilities (Current and non-current)	2,298	1,583
Adjusted for:
Cash and cash equivalents	(4,339)	(4,880)
Net debt	9,329	8,657
Equity attributable to equity holders of the parent	36,051	35,639
Total net debt and equity attributable to equity holders of the parent	45,380	44,296
Gearing (%)	20.6%	19.5%
The 2026 calculation has been updated to adjust for evaluation expenditure. The 2025 comparative has been restated to be presented on the same basis.

APMs derived from the condensed consolidated income statement and statement of financial position	30 June 2026	30 June 2025
	US$m	US$m
Annualised return on equity
Annualised net profit after tax attributable to equity holders of the parent	3,344	2,632
Equity attributable to equity holders of the parent	36,051	35,639
Annualised return on equity (%)	9.3%	7.4%

Annualised return on average capital employed
Annualised profit before tax and net finance costs	4,314	3,634
Opening non-current liabilities	21,241	19,254
Closing non-current liabilities	20,777	21,828
Average non-current liabilities	21,009	20,541
Opening equity	39,843	36,153
Closing equity	41,724	38,507
Average equity¹	40,784	37,330
Total average non-current liabilities and equity	61,793	57,871
Annualised return on average capital employed (%)	7.0%	6.3%

APMs derived from other notes	30 June 2026	30 June 2025
	US$m	US$m
Revenue from sale of products (excluding marketing segment)	6,376	5,924

Cash margin (excluding marketing segment)
Gross profit	2,684	2,344
Adjusted for:
Other	19	15
Property, plant and equipment depreciation	2,209	2,541
Other revenue	13	(100)
Cash margin (excluding marketing segment)	4,925	4,800
Cash margin %	77.2%	81.0%

Production costs (excluding marketing segment)²	749	667
Production cost margin %	11.7%	11.3%

Other cash costs (excluding marketing segment):
Feed gas, services and processing costs²	238	92
Royalties, excise and levies	143	156
Insurance	33	37
Inventory movement	54	1
Shipping and direct sales costs	123	77
Trading costs	101	88
Other hydrocarbon costs	10	6
Total other cash costs (excluding marketing segment)	702	457
Other cash cost margin %	11.0%	7.7%
The calculation has been updated to use total equity rather than equity attributable to equity holders of the parent. The 2025 comparative has been restated to be presented on the same basis. Production costs has been updated to exclude and present feed gas, services and processing costs separately. The 2025 comparative has been restated to be presented on the same basis.

Notes

Glossary

Term	Definition
$, $m	US dollars unless otherwise stated, millions of dollars
1P	Proved reserves
2C	Best Estimate of Contingent resources
2P	Proved plus Probable reserves
Abate/abatement	Avoidance, reduction or removal of an amount of carbon dioxide or equivalent
Aim	Woodside uses this term to describe a result that plans or actions are intended to achieve
Aspiration	Woodside uses this term to describe an aspiration to seek the achievement of an outcome but where achievement of the outcome is subject to material uncertainties and contingencies such that Woodside considers there is not yet a suitable defined plan or pathway to achieve that outcome
ASX	Australian Securities Exchange
Average realised price	Revenue from sale of products and provisional pricing adjustments ($ million) divided by sales volume (MMboe)
A$, AUD	Australian dollars
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 pa