Woodside Energy Half-Year Report for Period Ended 30 June 2026

About this update from Woodside Energy Group Ltd

[{"type":"text","content":" \nWoodside Energy Group (ASX: WDS) (NYSE: WDS):\n\n This press release features multimedia. View the full release here: https://www.businesswire.com/news/home/20260824865396/en/ \nDisciplined execution \nOperational excellence and project delivery \n\nRecorded operating revenue of $7,446 million, up 13% from H1 2025.\n\n \n\nDelivered production of 478 Mboe/d (86.5 MMboe) and unit production costs of $8.8/boe. 1 \nProgressed major projects with Scarborough 98%, Trion 64%, and Louisiana LNG 28% complete.\n\n \n\nMaintained high asset reliability, with operated LNG facilities achieving 98.7% reliability, Sangomar 99.5%, and Shenzi 99.1%.\n\n \n\nSafely 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.\n\n \nDelivering value \n\nDetermined a fully franked interim dividend of 57 US cents per share (cps).\n\n \n\nAchieved net profit after tax (NPAT) of $1,672 million (underlying NPAT $1,334 million). 1 \nDelivered EBITDA of $4,647 million from underlying base business. 1 \nDelivered operating cash flow of $3,013 million and free cash flow of $352 million.\n\n \n\nDisciplined capital management resulted in strong liquidity of $8,189 million. 1 \nGearing 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 $101 million increase in trade receivables. 1 \nComparative performance \n \n\n \n \n\n \nH1 \n2026 \nH1 \n2025 \nChange \n% \n \n\n \nOperating revenue\n\n \n$ million\n\n \n7,446\n\n \n6,590\n\n \n13%\n\n \n \n\n \nUnderlying NPAT 1 \n$ million\n\n \n1,334\n\n \n1,247\n\n \n7%\n\n \n \n\n \nFree cash flow 1,2 \n$ million\n\n \n352\n\n \n136\n\n \n159%\n\n \n \n\n \nAverage realised price 1,3 \n$/boe\n\n \n74.0\n\n \n61.7\n\n \n20%\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \n2026 full-year guidance \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nPrior \nCurrent \nTotal production volumes 45 \nMMboe\n\n \n86.5\n\n \n99.2\n\n \n(13%)\n\n \n172 - 186\n\n \n174-185\n\n \nGas hub exposure 6 \n%\n\n \n38.7%\n\n \n24.2%\n\n \n15%\n\n \n~30\n\n \nNo change\n\n \nCapital expenditure 1,78 \n$ million\n\n \n1,637\n\n \n2,558\n\n \n(36%)\n\n \n4,000 - 4,500\n\n \nNo change\n\n \nAbandonment expenditure\n\n \n$ million\n\n \n255\n\n \n517\n\n \n(51%)\n\n \n500 - 800\n\n \nNo change\n\n \nExploration expenditure 1 \n$ million\n\n \n119\n\n \n84\n\n \n42%\n\n \n~200\n\n \nNo change\n\n \nProduction costs\n\n \n$ million\n\n \n749\n\n \n667\n\n \n12%\n\n \n1,500 - 1,800\n\n \nNo change\n\n \nFeed gas, services and processing costs\n\n \n$ million\n\n \n238\n\n \n92\n\n \n159%\n\n \n500 - 600\n\n \nNo change\n\n \nProperty, plant and equipment depreciation and amortisation\n\n \n$ million\n\n \n2,209\n\n \n2,541\n\n \n(13%)\n\n \n4,200 - 4,700\n\n \nNo change\n\n \nThis 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.\n\n \nSummary \nWoodside 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.\n\n \nDuring 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.\n\n \nThe 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 \nWoodside 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.\n\n \n“We once again delivered strong production, cash flow and shareholder returns, while continuing to execute the next phase of growth.\n\n \n“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.\n\n \n“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.\n\n \n“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.\n\n \n“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.\n\n \n“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.\n\n \n“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.\n\n \n“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.\n\n \n“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 $350 million from 2028 to be delivered through the structured review of our business.”\n\n \nFinancial summary \nKey metrics \n \n\n \n \n\n \nH1 \nH1 \nChange \n \n\n \n \n\n \n2026 \n2025 \n% \nOperating revenue\n\n \n$ million\n\n \n7,446\n\n \n6,590\n\n \n13%\n\n \nEBITDA excluding impairment 10 \n$ million\n\n \n4,647\n\n \n4,600\n\n \n1%\n\n \nEBIT 10 \n$ million\n\n \n2,157\n\n \n1,817\n\n \n19%\n\n \nNet profit after tax (NPAT) 1112 \n$ million\n\n \n1,672\n\n \n1,316\n\n \n27%\n\n \nUnderlying NPAT 10 \n$ million\n\n \n1,334\n\n \n1,247\n\n \n7%\n\n \nNet cash from operating activities\n\n \n$ million\n\n \n3,013\n\n \n3,339\n\n \n(10%)\n\n \nCapital expenditure 10,13 \n$ million\n\n \n1,637\n\n \n2,558\n\n \n(36%)\n\n \nExploration expenditure 10,14 \n$ million\n\n \n119\n\n \n84\n\n \n42%\n\n \nFree cash flow 10,15 \n$ million\n\n \n352\n\n \n136\n\n \n159%\n\n \nAverage realised price 10,18 \nUS$/boe\n\n \n74.0\n\n \n61.7\n\n \n20%\n\n \nDividends distributed\n\n \n$ million\n\n \n1,122 \n1,006 \n12%\n\n \nInterim dividend determined\n\n \nUS cps\n\n \n57\n\n \n53\n\n \n8%\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nKey ratios \n \n\n \n \n\n \n \n\n \n \n\n \nEarnings per share\n\n \nUS cps\n\n \n88.2\n\n \n69.4\n\n \n27%\n\n \nGearing 10 \n%\n\n \n20.6\n\n \n19.5\n\n \n1%\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nProduction volumes 16,17 \n \n\n \n \n\n \n \n\n \n \n\n \nGas\n\n \nMMboe\n\n \n46.1\n\n \n58.2\n\n \n(21%)\n\n \nLiquids\n\n \nMMboe\n\n \n39.4\n\n \n41.0\n\n \n(4%)\n\n \nAmmonia\n\n \nMMboe\n\n \n1.0\n\n \n-\n\n \nN/A\n\n \nTotal\n\n \nMMboe\n\n \n86.5\n\n \n99.2\n\n \n(13%)\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nProduction volumes per day 17 \n \n\n \n \n\n \n \n\n \n \n\n \nGas\n\n \nMMscf/d\n\n \n1,451\n\n \n1,833\n\n \n(21%)\n\n \nLiquids\n\n \nMbbl/d\n\n \n217\n\n \n226\n\n \n(4%)\n\n \nAmmonia\n\n \nkT/d\n\n \n1.5\n\n \n-\n\n \nN/A\n\n \nTotal\n\n \nMboe/d\n\n \n478\n\n \n548\n\n \n(13%)\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nSales volumes 17 \n \n\n \n \n\n \n \n\n \n \n\n \nGas 18 \nMMboe\n\n \n58.5\n\n \n63.9\n\n \n(8%)\n\n \nLiquids\n\n \nMMboe\n\n \n40.3\n\n \n40.9\n\n \n(1%)\n\n \nAmmonia\n\n \nMMboe\n\n \n1.0\n\n \n-\n\n \nN/A\n\n \nTotal\n\n \nMMboe \n99.8\n\n \n104.8\n\n \n(5%)\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nSales volumes per day 17 \n \n\n \n \n\n \n \n\n \n \n\n \nGas 18 \nMMscf/d\n\n \n1,843\n\n \n2,012\n\n \n(8%)\n\n \nLiquids\n\n \nMbbl/d\n\n \n223\n\n \n226\n\n \n(1%)\n\n \nAmmonia\n\n \nkT/d\n\n \n1.4\n\n \n-\n\n \nN/A\n\n \n \n\n \nMboe/d \n551\n\n \n579\n\n \n(5%)\n\n \nAppendix 4D \nResults for announcement to the market \nMore information is available on page 48.\n\n \n \n\n \n \n\n \n \n\n \n \n\n \nUS$ million \nRevenue from ordinary activities\n\n \nIncreased\n\n \n13% 19 \nto\n\n \n7,446\n\n \nProfit from ordinary activities after tax attributable to members\n\n \nIncreased\n\n \n27% 19 \nto\n\n \n1,672\n\n \nNet profit for the period attributable to members\n\n \nIncreased\n\n \n27% 19 \nto\n\n \n1,672\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nInterim dividend - fully franked\n\n \n \n\n \n57 US cps H1 2026\n\n \n \n\n \nRecord date for determining entitlements to the dividend\n\n \n \n\n \n4 September 2026\n\n \n \n\n \nNet profit after tax reconciliation \nThe following table summarises the variance between the H1 2025 and H1 2026 results for the contribution of each line item to NPAT.\n\n \n \n\n \nUS$m \nPrimary reasons for variance \n2025 H1 reported NPAT \n1,316 \n \n\n \nRevenue from sale of products\n\n \n \n\n \n \n\n \nProduced - price impact\n\n \n755\n\n \nHigher average realised prices.\n\n \nProduced - volume impact\n\n \n(307)\n\n \nLower production due to cyclone impacts, Pluto planned turnaround and divestment of the Greater Angostura assets offset by first ammonia sales.\n\n \nPurchased - price and volume impact\n\n \n440\n\n \nHigher third-party LNG trading activity.\n\n \nCost of sales\n\n \n(559)\n\n \nHigher third-party LNG trading activity, first ammonia production and Pluto planned turnaround.\n\n \nPerdaman embedded derivative\n\n \n(297)\n\n \nA non-cash unrealised loss of $135 million in H1 2026 compared to an unrealised gain of $162 million in H1 2025.\n\n \nHedging\n\n \n(106)\n\n \nPre-tax hedge losses of $64 million in H1 2026 compared to pre-tax hedge gains of $42 million in H1 2025.\n\n \nRestoration movement\n\n \n450\n\n \nRestoration provision updates primarily due to Stybarrow, Griffin and Minerva in 2025.\n\n \nImpairment losses\n\n \n(35)\n\n \nPre-tax impairment for the Calypso Project offset by lower pre-tax impairment for the H2OK Project compared with H1 2025.\n\n \nIncome tax and PRRT expense\n\n \n62\n\n \nRecognition 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.\n\n \nOther\n\n \n(47)\n\n \n \n\n \n2026 H1 reported NPAT \n1,672 \n \n\n \nUnderlying adjustments\n\n \n(338) \nAdjusted for the recognition of the Pluto PRRT and US income tax DTA benefits and the post-tax impairment of the Calypso and H2OK Projects.\n\n \n2026 H1 underlying NPAT 20 \n1,334 \n \n\n \nCapital management \nWoodside’s capital management framework provides us with the flexibility to optimise value and shareholder returns delivered from the portfolio of opportunities.\n\n \nInterim dividend and dividend reinvestment plan \nA 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 \nThe dividend reinvestment plan remains suspended.\n\n \nLiquidity and balance sheet \nIn 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 \nDuring this period, Woodside repaid a $600 million Syndicated Term Loan approximately 6 months prior to maturity.\n\n \nAt 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 \nWoodside’s gearing as at 30 June 2026 was 20.6%, marginally outside the target range of 10 to 20%. 22 Woodside’s gearing may at times fall outside the target range as the balance sheet is managed through the investment cycle.\n\n \nNet debt and gearing were impacted by:\n\n \n\n$655 million of lease liabilities recognised in the first half of 2026, for the Woodside Bilangara LNG vessel and Trion construction related vessels. 24 \nNet cash outflow of $419 million for hedge settlements.\n\n \n\nHigher pricing driving a $101 million increase in trade receivables that were received in July 2026.\n\n \nWoodside’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.\n\n \nCommodity price risk management \nAs 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.\n\n \nCommodity swaps were used to continue managing risk associated with the Corpus Christi LNG volumes.\n\n \nFor 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.\n\n \nEmbedded commodity derivative \nIn 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.\n\n \nAs 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.\n\n \nAustralian operations \nPluto LNG \nPluto LNG is a gas processing facility in the Pilbara region of Western Australia, comprising an offshore platform and one onshore LNG processing train.\n\n \nWoodside’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.\n\n \nPluto LNG achieved reliability of 98.7% in H1 2026, reflecting the asset's strong operating performance.\n\n \nIn H1 2026, drilling of the XNA-03 infill well was completed and preparations continue for start-up targeted for H2 2026.\n\n \nThe 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.\n\n \nWoodside is operator and holds a 90% participating interest.\n\n \nNorth West Shelf Project \nThe 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.\n\n \nWoodside’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.\n\n \nDespite these impacts, the NWS achieved LNG reliability of 98.7% in H1 2026, highlighting the continued dependability and efficiency of the integrated facilities.\n\n \nIn 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.\n\n \nPreparations are continuing for a planned turnaround for a single LNG Train targeted to commence in September 2026.\n\n \nThe NWS is continuing with infrastructure retirement planning at KGP while maintaining the capacity to provide processing services for third-party gas.\n\n \nDuring 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.\n\n \nWoodside is operator and holds a 33.33% participating interest.\n\n \nFollowing 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 \nWheatstone and Julimar-Brunello \nWheatstone 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.\n\n \nWoodside’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.\n\n \nThe 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.\n\n \nIn parallel, decommissioning of three Julimar–Brunello exploration wells commenced in H1 2026. Completion of both activities are condition precedents to the Chevron asset swap.\n\n \nWoodside is operator and holds a 65% participating interest in the Julimar-Brunello fields.\n\n \nWoodside holds a 13% non-operating participating interest in the Wheatstone Project.\n\n \nFollowing 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 \nBass Strait \nBass 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).\n\n \nWoodside’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.\n\n \nIn 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.\n\n \nSubsequent 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 \nWoodside 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.\n\n \nWoodside became operator on 1 July 2026 and holds a 50% participating interest in the GBJV and a 32.5% participating interest in the KUJV.\n\n \nOther Australian oil and gas assets \nWoodside 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%).\n\n \nFollowing 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 \nWoodside’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.\n\n \nWoodside 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.\n\n \nWoodside’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.\n\n \nWoodside Solar \nWoodside 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.\n\n \nWoodside 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.\n\n \nInternational operations \nSangomar \nThe Sangomar Field Development Phase 1 is a deepwater project with a stand-alone FPSO facility moored approximately 100 km offshore Senegal.\n\n \nWoodside’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.\n\n \nIn 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.\n\n \nH1 2026 sales of Sangomar crude oil were directed to Europe and South Asia during the Middle East conflict, attracting strong premiums.\n\n \nEvaluation 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.\n\n \nWoodside is operator and has an 82% participating interest.\n\n \nShenzi \nShenzi is a conventional offshore oil and gas field developed through a tension leg platform located offshore in the Gulf of America.\n\n \nWoodside’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.\n\n \nWoodside is operator and holds a 72% participating interest.\n\n \nAtlantis \nAtlantis 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.\n\n \nIn 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.\n\n \nWoodside’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.\n\n \nWoodside holds a 44% non-operating participating interest.\n\n \nMad Dog \nMad 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.\n\n \nThe 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.\n\n \nWoodside’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.\n\n \nWoodside holds a 23.9% non-operating participating interest.\n\n \nBeaumont New Ammonia \nBeaumont 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.\n\n \nWoodside'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 \nWoodside is operator and holds a 100% participating interest.\n\n \nMarketing and Trading \nRevenue and trading \nRevenue 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.\n\n \nPortfolio 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.\n\n \nThe 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.\n\n \nIn H1 2026, approximately 39% of LNG sold was linked to gas hub indices impacted by lower volumes available due to the Pluto planned turnaround.\n\n \nShipping \nWoodside 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.\n\n \nPipeline gas \nThroughout H1 2026, Western Australia domestic gas spot volume pricing held steady at approximately A$5.50/GJ, not impacted by fluctuations in global markets.\n\n \nWoodside 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.\n\n \nWoodside also executed incremental pipeline gas sales agreements for 47 PJ to be delivered to the east coast of Australia across 2026, 2027 and 2028.\n\n \nOn 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.\n\n \nA 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.\n\n \nThe 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.\n\n \nProjects \nScarborough Energy Project \nThe Scarborough gas field is located in the Carnarvon Basin, approximately 375 km off the coast of Western Australia.\n\n \nThe 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.\n\n \nThe 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.\n\n \nThe project was 98% complete at the end of H1 2026, excluding Pluto Train 1 modifications. First LNG cargo is on-track for Q4 2026.\n\n \nThe 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.\n\n \nConstruction 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.\n\n \nModifications 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.\n\n \nWoodside 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.\n\n \nTrion \nTrion 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.\n\n \nThe project was 64% complete at the end of H1 2026. First oil is targeted for 2028.\n\n \nDrilling of 24 subsea wells commenced in March 2026 with three production wells drilled during the period.\n\n \nThe 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\n\n \nSubsea 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.\n\n \nWoodside is the operator and holds a 60% participating interest.\n\n \nLouisiana LNG \nLouisiana 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.\n\n \nIn 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.\n\n \nThe 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.\n\n \nKey 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.\n\n \nBechtel 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.\n\n \nWoodside 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.\n\n \nWith foundational transportation and storage capacity secured in 2025, Woodside continued to advance feed gas procurement in line with its gas supply strategy.\n\n \nOngoing engagement with high-quality counterparties for equity participation and LNG offtake continues to support progress on the Louisiana LNG sell-down process.\n\n \nWoodside 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.\n\n \nHydrogen Refueller @H2Perth \nThe Hydrogen Refueller @H2Perth is a self-contained hydrogen production, storage and refuelling station located in Perth, Western Australia. 32 \nCommissioning 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.\n\n \nWoodside is operator and holds a 100% participating interest.\n\n \nDecommissioning \nWoodside continued execution of planned decommissioning activities in H1 2026, spending approximately $274 million across its portfolio.\n\n \nIn 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.\n\n \nOffshore 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.\n\n \nFollowing 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.\n\n \nAt 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.\n\n \nPreparation 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.\n\n \nDevelopments and Exploration \nBrowse \nThe Browse development comprises the Calliance, Brecknock and Torosa gas and condensate fields located approximately 425 km north of Broome, Western Australia.\n\n \nDuring 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.\n\n \nThe 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.\n\n \nWoodside 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.\n\n \nIn 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 \nSubsequent 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.\n\n \nWoodside 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%.\n\n \nSunrise \nThe 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.\n\n \nThe 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.\n\n \nTechnical and commercial activities progressed under the Timor-Leste Cooperation Agreement to support maturation of a potential Timor‑based LNG concept.\n\n \nWoodside is operator and holds a 33.44% participating interest.\n\n \nCalypso \nCalypso is a discovered resource located approximately 220 km off the coast of Trinidad in 2,100m water depth.\n\n \nWoodside 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 \nLiard \nThe Liard field is an unconventional gas field located in British Columbia, Canada.\n\n \nWoodside holds a 50% non-operating participating interest.\n\n \nExploration \nWoodside’s exploration activities focused on maturing current opportunities, consistent with its disciplined exploration strategy.\n\n \nIn 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.\n\n \nWoodside 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.\n\n \nH2Perth \nThe 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.\n\n \nIn 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.\n\n \nWoodside is operator and holds a 100% participating interest.\n\n \nNeoSmelt \nThe 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 \nDuring the reporting period, work on the pilot plant continued, with the design phase now approximately 90% complete.\n\n \nWoodside holds a 20% non-operating participating interest. The other participants in the project are BHP, BlueScope, Mitsui Iron Ore Development and Rio Tinto.\n\n \nCarbon solutions \nCarbon capture and storage (CCS) \nWoodside 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 \nIn 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.\n\n \nThe Bonaparte CCS Assessment Joint Venture, operated by INPEX with TotalEnergies and Woodside continues to progress pre-FEED activities.\n\n \nCarbon credits portfolio \nDuring 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.\n\n \nClimate and Sustainability \nHealth, safety and wellbeing \nThere 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.\n\n \nSubsequent to the period, a sustainability focus session was held on 22 July 2026 with investors on Woodside’s approach to process safety.\n\n \nIndigenous Peoples cultural heritage and engagement \nWoodside 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.\n\n \nSubsequent to the period, the Global Indigenous Peoples Strategy (2025-2030) was launched and is now available on Woodside's website.\n\n \nSocial and economic impact \nWoodside 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.\n\n \nWoodside 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).\n\n \nEnvironment and biodiversity \nIn H1 2026, there were zero hydrocarbon or hazardous non-hydrocarbon spills that resulted in a moderate environmental impact. 38 \nDuring the half, Woodside launched the Sam Houston Jones Restoration Project, supporting restoration of threatened habitats and key wildlife species in Louisiana.\n\n \nIn 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.\n\n \nClimate and the energy transition \nIn Q1 2026, Woodside published AASB S2 climate-related disclosures in the 2025 Annual Report.\n\n \nWoodside 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.\n\n \nIn 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.\n\n \nDirectors’ Report \nThe 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.\n\n \nBoard of directors \nThe names of directors in office during or since the end of the 2026 half-year are as follows:\n\n \nMr Richard Goyder, AO (Chair)\n\n \nMs Liz Westcott (CEO and Managing Director) 40 \nMr Larry Archibald\n\n \nMr Ashok Belani\n\n \nMr Arnaud Breuillac\n\n \nMs Swee Chen Goh\n\n \nMr Ben Wyatt, AO\n\n \nMs Angela Minas\n\n \nMr Mark Cutifani, CBE 41 \nMs Ann Pickard\n\n \nMr Ian Macfarlane (retired) 42 \nMr Tony O’Neill (resigned) 43 \nRounding of amounts \nWoodside 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.\n\n \nAuditor’s Independence Declaration \nThe 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.\n\n \nSigned in accordance with a resolution of the directors.\n\n \nR J Goyder, AO\n Chair\n Melbourne, Victoria\n 25 August 2026\n\n \nAuditor’s Independence Declaration to the Directors of Woodside Energy Group Ltd \nAuditor’s Independence Declaration \nAs 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:\n\n \n\nno contraventions of the auditor independence requirements of the Corporations Act 2001 in relation to the review of the financial report; and\n\n \n\nno contraventions of any applicable code of professional conduct in relation to the review of the financial report.\n\n \nN M Henry\n Partner\n PricewaterhouseCoopers\n\n   \nPerth, Western Australia\n 25 August 2026\n   \n  \npwc.com.au\n\n   \nPricewaterhouseCoopers, ABN 52 780 433 757\n\n \n\n\nBrookfield Place, Level 15, 125 St Georges Terrace, PERTH WA 6000,\n\n \n\n\nGPO Box D198, PERTH WA 6840\n\n \n\n\nT: +61 8 9238 3000, F: +61 8 9238 3999, www.pwc.com.au \n \n\n \n\n\nLiability limited by a scheme approved under Professional Standards Legislation.\n\n \nHALF-YEAR FINANCIAL STATEMENTS \nfor the half-year ended 30 June 2026\n\n \nCONTENTS \nCONDENSED CONSOLIDATED INCOME STATEMENT \n20 \nCONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME \n21 \nCONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION \n22 \nCONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS \n23 \nCONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY \n24 \nNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS \n25 \nA. Earnings for the period \n27 \nA.1 Segment revenue and expenses\n\n \n27\n\n \nA.2 Finance costs\n\n \n28\n\n \nA.3 Dividends paid and proposed\n\n \n28\n\n \nA.4 Earnings per share\n\n \n28\n\n \nA.5 Taxes\n\n \n29\n\n \nB. Production and growth assets \n30 \nB.1 Exploration and evaluation assets\n\n \n30\n\n \nB.2 Property, plant and equipment\n\n \n31\n\n \nB.3 Impairment of exploration and evaluation assets, property, plant and equipment and goodwill\n\n \n32\n\n \nB.4 Intangible assets\n\n \n33\n\n \nB.5 Transactions with equity holders of the Group\n\n \n34\n\n \nC. Debt and capital \n35 \nC.1 Interest-bearing liabilities and financing facilities\n\n \n35\n\n \nC.2 Contributed equity\n\n \n36\n\n \nD. Other assets and liabilities \n37 \nD.1 Segment assets and liabilities\n\n \n37\n\n \nD.2 Provisions\n\n \n38\n\n \nD.3 Other financial assets and liabilities\n\n \n39\n\n \nE. Other items \n41 \nE.1 Contingent liabilities and assets\n\n \n41\n\n \nE.2 New standards and interpretations\n\n \n41\n\n \nE.3 Events after the end of the reporting period\n\n \n41\n\n \nE.4 Subsidiaries\n\n \n42\n\n \nDIRECTORS’ DECLARATION \n44 \nINDEPENDENT AUDITOR’S REVIEW REPORT \n45 \nSignificant changes in the current reporting period \nThe financial performance and position of the Group were affected by the following:\n\n \n\nGeopolitical 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.\n\n \n\nIn 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.\n\n \n\nThe 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).\n\n \n\nAs 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).\n\n \n\nThe 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.\n\n \n\nThe Group recognised approximately $655 million of new lease liabilities, primarily relating to the three-year leases for the Trion drilling campaign and the Woodside Bilangara vessel.\n\n \nCONDENSED CONSOLIDATED INCOME STATEMENT \n \n\n \n\n\nfor the half-year ended 30 June 2026\n\n   \n \n\n \n \n\n \n2026 \n2025\n\n \n \n\n \nNotes\n\n \nUS$m \nUS$m\n\n \nOperating revenue\n\n \nA.1\n\n \n7,446 \n6,590\n\n \nCost of sales \nA.1\n\n \n(4,604) \n(4,045)\n\n \nGross profit\n\n \n \n\n \n2,842 \n2,545\n\n \nOther income\n\n \nA.1\n\n \n264 \n379\n\n \nOther expenses\n\n \nA.1\n\n \n(771) \n(964)\n\n \nImpairment losses\n\n \nA.1\n\n \n(178) \n(143)\n\n \nProfit before tax and net finance costs \n \n\n \n2,157 \n1,817\n\n \nFinance income\n\n \n \n\n \n123 \n106\n\n \nFinance costs\n\n \nA.2\n\n \n(245) \n(169)\n\n \nProfit before tax \n \n\n \n2,035 \n1,754\n\n \nPetroleum resource rent tax (PRRT) benefit/(expense)\n\n \nA.5\n\n \n305 \n(71)\n\n \nIncome tax expense\n\n \nA.5\n\n \n(667) \n(353)\n\n \nProfit after tax \n \n\n \n1,673 \n1,330\n\n \nProfit attributable to: \n \n\n \n \n\n \n \n\n \nEquity holders of the parent\n\n \n \n\n \n1,672 \n1,316\n\n \nNon-controlling interest\n\n \nE.4\n\n \n1 \n14\n\n \nProfit for the period \n \n\n \n1,673 \n1,330\n\n \nBasic earnings per share attributable to equity holders of the parent (US cents)\n\n \nA.4\n\n \n88.2 \n69.4\n\n \nDiluted earnings per share attributable to equity holders of the parent (US cents)\n\n \nA.4\n\n \n87.3 \n68.8\n\n \n  \nThe accompanying notes form part of the half-year financial statements.\n\n \nCONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME \n \n\n \n\n\nfor the half-year ended 30 June 2026\n\n   \n \n\n \n2026 \n2025\n\n \n \n\n \nUS$m \nUS$m\n\n \nProfit for the period \n1,673 \n1,330\n\n \nOther comprehensive (loss)/income \n \n\n \n \n\n \nItems that may be reclassified to the income statement in subsequent periods: \n \n\n \n \n\n \n(Losses)/gains on cash flow hedges\n\n \n(526) \n289\n\n \nGains on cash flow hedges reclassified to the income statement\n\n \n(72) \n(16)\n\n \nTax recognised within other comprehensive income\n\n \n149 \n(57)\n\n \nItems that will not be reclassified to the income statement in subsequent periods: \n \n\n \n \n\n \nRemeasurement gain on defined benefit plan\n\n \n3 \n2\n\n \nNet loss on financial instruments at fair value through other comprehensive income\n\n \n— \n(33)\n\n \nOther comprehensive (loss)/income for the period, net of tax \n(446) \n185\n\n \nTotal comprehensive income for the period \n1,227 \n1,515\n\n \nTotal comprehensive income attributable to: \n \n\n \n \n\n \nEquity holders of the parent\n\n \n1,226 \n1,501\n\n \nNon-controlling interest\n\n \n1 \n14\n\n \nTotal comprehensive income for the period \n1,227 \n1,515\n\n   \nThe accompanying notes form part of the half-year financial statements.\n\n \nCONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION \n \n\n \n\n\nas at 30 June 2026\n\n \n  \n \n\n \n \n\n \n30 June 2026 \n31 December 2025\n\n \n \n\n \nNotes\n\n \nUS$m \nUS$m\n\n \nCurrent assets \n \n\n \n \n\n \n \n\n \nCash and cash equivalents\n\n \n \n\n \n4,339 \n5,712\n\n \nReceivables\n\n \n \n\n \n1,928 \n1,751\n\n \nInventories\n\n \n \n\n \n579 \n693\n\n \nOther financial assets\n\n \nD.3\n\n \n119 \n229\n\n \nTax receivable\n\n \n \n\n \n184 \n114\n\n \nOther assets\n\n \n \n\n \n47 \n123\n\n \nTotal current assets \n \n\n \n7,196 \n8,622\n\n \nNon-current assets \n \n\n \n \n\n \n \n\n \nReceivables\n\n \n \n\n \n771 \n823\n\n \nInventories\n\n \n \n\n \n371 \n288\n\n \nOther financial assets\n\n \nD.3\n\n \n109 \n64\n\n \nExploration and evaluation assets\n\n \nB.1\n\n \n710 \n790\n\n \nProperty, plant and equipment\n\n \nB.2\n\n \n47,797 \n46,555\n\n \nDeferred tax assets\n\n \n \n\n \n3,288 \n2,658\n\n \nLease assets\n\n \n \n\n \n1,795 \n1,428\n\n \nInvestments accounted for using the equity method\n\n \n \n\n \n272 \n260\n\n \nIntangible assets\n\n \nB.4\n\n \n4,856 \n4,853\n\n \nOther assets\n\n \n \n\n \n516 \n160\n\n \nTotal non-current assets \n \n\n \n60,485 \n57,879\n\n \nTotal assets \n \n\n \n67,681 \n66,501\n\n \nCurrent liabilities \n \n\n \n \n\n \n \n\n \nPayables\n\n \n \n\n \n1,779 \n1,841\n\n \nInterest-bearing liabilities\n\n \nC.1\n\n \n983 \n782\n\n \nOther financial liabilities\n\n \nD.3\n\n \n148 \n8\n\n \nProvisions\n\n \nD.2\n\n \n1,238 \n1,212\n\n \nTax payable\n\n \n \n\n \n500 \n539\n\n \nLease liabilities\n\n \n \n\n \n303 \n159\n\n \nOther liabilities\n\n \n \n\n \n229 \n876\n\n \nTotal current liabilities \n \n\n \n5,180 \n5,417\n\n \nNon-current liabilities \n \n\n \n \n\n \n \n\n \nInterest-bearing liabilities\n\n \nC.1\n\n \n10,387 \n11,181\n\n \nDeferred tax liabilities\n\n \n \n\n \n1,273 \n1,182\n\n \nOther financial liabilities\n\n \nD.3\n\n \n363 \n212\n\n \nProvisions\n\n \nD.2\n\n \n6,397 \n6,655\n\n \nTax payable\n\n \n \n\n \n10 \n10\n\n \nLease liabilities\n\n \n \n\n \n1,995 \n1,600\n\n \nOther liabilities\n\n \n \n\n \n352 \n401\n\n \nTotal non-current liabilities \n \n\n \n20,777 \n21,241\n\n \nTotal liabilities \n \n\n \n25,957 \n26,658\n\n \nNet assets \n \n\n \n41,724 \n39,843\n\n \nEquity \n \n\n \n \n\n \n \n\n \nIssued and fully paid shares\n\n \nC.2\n\n \n29,036 \n29,036\n\n \nShares reserved for employee share plans\n\n \nC.2\n\n \n(72) \n(82)\n\n \nOther reserves\n\n \n \n\n \n6,034 \n6,382\n\n \nRetained earnings\n\n \n \n\n \n1,053 \n578\n\n \nEquity attributable to equity holders of the parent \n \n\n \n36,051 \n35,914\n\n \nNon-controlling interest \nE.4\n\n \n5,673 \n3,929\n\n \nTotal equity \n \n\n \n41,724 \n39,843\n\n \n \n\n \nThe accompanying notes form part of the half-year financial statements.\n\n \nCONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS \n \n\n \n\n\nfor the half-year ended 30 June 2026\n\n \n  \n \n\n \n \n\n \n2026 \n2025\n\n \n \n\n \nNotes\n\n \nUS$m \nUS$m\n\n \nCash flows from/(used in) operating activities \n \n\n \n \n\n \n \n\n \nProfit after tax for the period\n\n \n \n\n \n1,673 \n1,330\n\n \nAdjustments for:\n\n \n \n\n \n \n\n \n \n\n \nNon-cash items\n\n \n \n\n \n \n\n \n \n\n \nDepreciation and amortisation\n\n \n \n\n \n2,223 \n2,555\n\n \nDepreciation of lease assets\n\n \n \n\n \n89 \n85\n\n \nChange in fair value of derivative financial instruments\n\n \n \n\n \n176 \n(206)\n\n \nNet finance costs\n\n \n \n\n \n122 \n63\n\n \nTax expense\n\n \n \n\n \n362 \n424\n\n \nImpairment losses\n\n \nB.3\n\n \n178 \n143\n\n \nRestoration movement\n\n \n \n\n \n(5) \n445\n\n \nOther\n\n \n \n\n \n(143) \n(99)\n\n \nChanges in assets and liabilities\n\n \n \n\n \n \n\n \n \n\n \n(Increase)/decrease in trade and other receivables\n\n \n \n\n \n(65) \n122\n\n \nDecrease/(increase) in inventories\n\n \n \n\n \n31 \n(65)\n\n \nDecrease in provisions\n\n \n \n\n \n(129) \n(112)\n\n \n(Decrease)/increase in other assets and liabilities\n\n \n \n\n \n(363) \n103\n\n \nDecrease in trade and other payables\n\n \n \n\n \n(62) \n(186)\n\n \nCash generated from operations\n\n \n \n\n \n4,087 \n4,602\n\n \nInterest received\n\n \n \n\n \n109 \n89\n\n \nBorrowing costs relating to operating activities\n\n \n \n\n \n(84) \n(5)\n\n \nIncome tax and PRRT paid\n\n \n \n\n \n(825) \n(782)\n\n \nPayments for restoration\n\n \n \n\n \n(274) \n(565)\n\n \nNet cash from operating activities \n \n\n \n3,013 \n3,339\n\n \nCash flows (used in)/from investing activities \n \n\n \n \n\n \n \n\n \nCash paid relating to business combination 1 \n \n\n \n(470) \n—\n\n \nPayments for capital and exploration expenditure\n\n \n \n\n \n(3,673) \n(4,881)\n\n \nReimbursements received from external parties for capital expenditure\n\n \n \n\n \n181 \n236\n\n \nBorrowing costs relating to investing activities\n\n \n \n\n \n(297) \n(330)\n\n \nDeposits received from disposal of non-current assets\n\n \n \n\n \n— \n21\n\n \n(Contributions to)/dividends from associates\n\n \n \n\n \n(27) \n17\n\n \nNet cash used in investing activities \n \n\n \n(4,286) \n(4,937)\n\n \nCash flows (used in)/from financing activities \n \n\n \n \n\n \n \n\n \nProceeds from borrowings\n\n \nC.1\n\n \n— \n4,849\n\n \nRepayment of borrowings\n\n \nC.1\n\n \n(602) \n(2,900)\n\n \nPurchases of shares relating to employee share plans\n\n \n \n\n \n— \n(26)\n\n \nRepayment of the principal portion of lease liabilities\n\n \n \n\n \n(111) \n(108)\n\n \nBorrowing costs relating to lease liabilities\n\n \n \n\n \n(1) \n(1)\n\n \nContributions from/to non-controlling interests 2 \n \n\n \n1,737 \n1,843\n\n \nDividends paid\n\n \n \n\n \n(1,122) \n(1,006)\n\n \nNet cash (used in)/from financing activities \n \n\n \n(99) \n2,651\n\n \nNet (decrease)/increase in cash held \n \n\n \n(1,372) \n1,053\n\n \nLess: Cash and cash equivalents classified within assets held for sale \n \n\n \n— \n(108)\n\n \nCash and cash equivalents at the beginning of the period \n \n\n \n5,712 \n3,923\n\n \nEffects of exchange rate changes\n\n \n \n\n \n(1) \n12\n\n \nCash and cash equivalents at the end of the period \n \n\n \n4,339 \n4,880\n\n \n\nRelates to the final acquisition completion payment for Beaumont New Ammonia.\n\n \n\nIncludes capital contribution of $1,668 million (2025: $1,870 million) from Stonepeak and $57 million (2025: nil) from Williams for the development of Louisiana LNG. Refer to Note B.5 for the transactions with equity holders of the Group.\n \nThe accompanying notes form part of the half-year financial statements.\n\n \nCONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY \n \n\n \n\n\nfor the half-year ended 30 June 2026\n\n \n \n\n \n \n\n \nIssued and fully paid shares \nReserved shares \nEmployee benefits reserve \nNon-controlling interest reserve \nForeign currency translation reserve \nHedging reserve \nDistributable profits reserve \nOther reserve \nRetained earnings \nEquity holders of the parent \nNon-controlling interest \nTotal equity \nNotes\n\n \nC.2\n\n \nC.2\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nE.4\n\n \n \n\n \n \n\n \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nAt 1 January 2026 \n29,036 \n(82) \n287 \n(373) \n795 \n188 \n5,557 \n(72) \n578 \n35,914 \n3,929 \n39,843 \nProfit for the period\n\n \n— \n— \n— \n— \n— \n— \n— \n— \n1,672 \n1,672 \n1 \n1,673 \nOther comprehensive (loss)/income\n\n \n— \n— \n— \n— \n— \n(449) \n— \n— \n3 \n(446) \n— \n(446) \nTotal comprehensive (loss)/income for the period\n\n \n— \n— \n— \n— \n— \n(449) \n— \n— \n1,675 \n1,226 \n1 \n1,227 \nTransfers\n\n \n— \n— \n— \n— \n— \n— \n1,200 \n— \n(1,200) \n— \n— \n— \nTransactions with non-controlling interests 1 \n— \n— \n— \n(20) \n— \n— \n— \n— \n— \n(20) \n1,754 \n1,734 \nEmployee share plan redemptions\n\n \n— \n10 \n(10) \n— \n— \n— \n— \n— \n— \n— \n— \n— \nShare-based payments (net of tax)\n\n \n— \n— \n53 \n— \n— \n— \n— \n— \n— \n53 \n— \n53 \nDividends paid\n\n \n— \n— \n— \n— \n— \n— \n(1,122) \n— \n— \n(1,122) \n(11) \n(1,133) \nAt 30 June 2026 \n29,036 \n(72) \n330 \n(393) \n795 \n(261) \n5,635 \n(72) \n1,053 \n36,051 \n5,673 \n41,724 \nAt 1 January 2025\n\n \n29,001\n\n \n(58)\n\n \n281\n\n \n—\n\n \n795\n\n \n1\n\n \n3,069\n\n \n(38)\n\n \n2,348\n\n \n35,399\n\n \n754\n\n \n36,153\n\n \nProfit for the period\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n1,316\n\n \n1,316\n\n \n14\n\n \n1,330\n\n \nOther comprehensive income/(loss)\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n216\n\n \n—\n\n \n(33)\n\n \n2\n\n \n185\n\n \n—\n\n \n185\n\n \nTotal comprehensive income/(loss) for the period\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n216\n\n \n—\n\n \n(33)\n\n \n1,318\n\n \n1,501\n\n \n14\n\n \n1,515\n\n \nTransfers\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n3,000\n\n \n—\n\n \n(3,000)\n\n \n—\n\n \n—\n\n \n—\n\n \nTransactions with non-controlling interests 1 \n—\n\n \n—\n\n \n—\n\n \n(270)\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n(270)\n\n \n2,140\n\n \n1,870\n\n \nEmployee share plan purchases\n\n \n—\n\n \n(26)\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n(26)\n\n \n—\n\n \n(26)\n\n \nEmployee share plan redemptions\n\n \n—\n\n \n13\n\n \n(13)\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \nShare-based payments (net of tax)\n\n \n—\n\n \n—\n\n \n41\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n41\n\n \n—\n\n \n41\n\n \nDividends paid\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n—\n\n \n(1,006)\n\n \n—\n\n \n—\n\n \n(1,006)\n\n \n(40)\n\n \n(1,046)\n\n \nAt 30 June 2025\n\n \n29,001\n\n \n(71)\n\n \n309\n\n \n(270)\n\n \n795\n\n \n217\n\n \n5,063\n\n \n(71)\n\n \n666\n\n \n35,639\n\n \n2,868\n\n \n38,507\n\n \n\nRepresents 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.\n\n \nThe accompanying notes form part of the half-year financial statements.\n\n \nNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS \nfor the half-year ended 30 June 2026\n\n \nAbout these statements \nWoodside 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.\n\n \nThe condensed consolidated half-year financial statements were authorised for issue in accordance with a resolution of the directors on 25 August 2026.\n\n \nStatement of compliance \nThe 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.\n\n \nThe 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).\n\n \nThe 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.\n\n \nThe 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.\n\n \nCurrency \nThe functional and presentation currency of Woodside and all its material subsidiaries is US dollars.\n\n \nTransactions 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.\n\n \nRounding of amounts \nThe 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.\n\n \nBasis of preparation \nThe 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.\n\n \nThe 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.\n\n \nThe 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.\n\n \nNon-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.\n\n \nComparative information \nThe 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.\n\n \nReporting segments \nRefer to the 2025 Financial Statements for details of the Group’s operating segment information.\n\n \nA. Earnings for the period \nA.1 Segment revenue and expenses \n \n\n \nAustralia \nInternational \nMarketing \nCorporate \nConsolidated \n \n\n \n2026 \n2025\n\n \n2026 \n2025\n\n \n2026 \n2025\n\n \n2026 \n2025\n\n \n2026 \n2025\n\n \n \n\n \nUS$m \nUS$m\n\n \nUS$m \nUS$m\n\n \nUS$m \nUS$m\n\n \nUS$m \nUS$m\n\n \nUS$m \nUS$m\n\n \nLiquified natural gas\n\n \n2,189 \n2,417\n\n \n— \n—\n\n \n836 \n522\n\n \n— \n—\n\n \n3,025 \n2,939\n\n \nPipeline gas\n\n \n565 \n564\n\n \n20 \n141\n\n \n— \n—\n\n \n— \n—\n\n \n585 \n705\n\n \nCrude oil and condensate\n\n \n784 \n683\n\n \n2,515 \n2,011\n\n \n142 \n13\n\n \n— \n—\n\n \n3,441 \n2,707\n\n \nNatural gas liquids\n\n \n115 \n90\n\n \n17 \n18\n\n \n2 \n9\n\n \n— \n—\n\n \n134 \n117\n\n \nAmmonia\n\n \n— \n—\n\n \n171 \n—\n\n \n— \n—\n\n \n— \n—\n\n \n171 \n—\n\n \nRevenue from sale of products \n3,653 \n3,754\n\n \n2,723 \n2,170\n\n \n980 \n544\n\n \n— \n—\n\n \n7,356 \n6,468\n\n \nIntersegment revenue 1 \n(101) \n(9)\n\n \n— \n—\n\n \n101 \n9\n\n \n— \n—\n\n \n— \n—\n\n \nProcessing and services revenue\n\n \n88 \n109\n\n \n— \n—\n\n \n— \n—\n\n \n— \n—\n\n \n88 \n109\n\n \nShipping and other revenue\n\n \n— \n—\n\n \n— \n—\n\n \n2 \n13\n\n \n— \n—\n\n \n2 \n13\n\n \nOther revenue\n\n \n(13) \n100\n\n \n— \n—\n\n \n103 \n22\n\n \n— \n—\n\n \n90 \n122\n\n \nOperating revenue 2 \n3,640 \n3,854\n\n \n2,723 \n2,170\n\n \n1,083 \n566\n\n \n— \n—\n\n \n7,446 \n6,590\n\n \nProduction costs 3 \n(539) \n(399)\n\n \n(210) \n(268)\n\n \n— \n—\n\n \n— \n—\n\n \n(749) \n(667)\n\n \nFeed gas, services and processing costs 3 \n(92) \n(92)\n\n \n(146) \n—\n\n \n— \n—\n\n \n— \n—\n\n \n(238) \n(92)\n\n \nRoyalties, excise and levies\n\n \n(134) \n(126)\n\n \n(9) \n(30)\n\n \n— \n—\n\n \n— \n—\n\n \n(143) \n(156)\n\n \nInsurance\n\n \n(16) \n(19)\n\n \n(11) \n(8)\n\n \n— \n—\n\n \n(6) \n(10)\n\n \n(33) \n(37)\n\n \nInventory movement\n\n \n(77) \n(7)\n\n \n23 \n6\n\n \n— \n—\n\n \n— \n—\n\n \n(54) \n(1)\n\n \nCosts of production\n\n \n(858) \n(643)\n\n \n(353) \n(300)\n\n \n— \n—\n\n \n(6) \n(10)\n\n \n(1,217) \n(953)\n\n \nProperty, plant and equipment depreciation\n\n \n(1,032) \n(1,170)\n\n \n(1,150) \n(1,340)\n\n \n— \n—\n\n \n(27) \n(31)\n\n \n(2,209) \n(2,541)\n\n \nShipping and direct sales costs\n\n \n(70) \n(36)\n\n \n(53) \n(41)\n\n \n(54) \n(43)\n\n \n— \n—\n\n \n(177) \n(120)\n\n \nTrading costs\n\n \n(101) \n(88)\n\n \n— \n—\n\n \n(871) \n(322)\n\n \n— \n—\n\n \n(972) \n(410)\n\n \nOther hydrocarbon costs\n\n \n(10) \n(6)\n\n \n— \n—\n\n \n— \n—\n\n \n— \n—\n\n \n(10) \n(6)\n\n \nOther\n\n \n(14) \n(15)\n\n \n(5) \n—\n\n \n— \n—\n\n \n— \n—\n\n \n(19) \n(15)\n\n \nOther cost of sales\n\n \n(195) \n(145)\n\n \n(58) \n(41)\n\n \n(925) \n(365)\n\n \n— \n—\n\n \n(1,178) \n(551)\n\n \nCost of sales \n(2,085) \n(1,958)\n\n \n(1,561) \n(1,681)\n\n \n(925) \n(365)\n\n \n(33) \n(41)\n\n \n(4,604) \n(4,045)\n\n \nGross profit/(loss) \n1,555 \n1,896\n\n \n1,162 \n489\n\n \n158 \n201\n\n \n(33) \n(41)\n\n \n2,842 \n2,545\n\n \nOther income 4 \n230 \n82\n\n \n8 \n67\n\n \n12 \n(9)\n\n \n14 \n239\n\n \n264 \n379\n\n \nExploration and evaluation expenditure\n\n \n(26) \n(10)\n\n \n(73) \n(71)\n\n \n— \n—\n\n \n— \n—\n\n \n(99) \n(81)\n\n \nAmortisation of permit acquisitions\n\n \n— \n—\n\n \n(4) \n(3)\n\n \n— \n—\n\n \n— \n—\n\n \n(4) \n(3)\n\n \nWrite-offs\n\n \n— \n—\n\n \n(1) \n—\n\n \n— \n—\n\n \n— \n—\n\n \n(1) \n—\n\n \nExploration and evaluation\n\n \n(26) \n(10)\n\n \n(78) \n(74)\n\n \n— \n—\n\n \n— \n—\n\n \n(104) \n(84)\n\n \nGeneral, administration and other costs\n\n \n(28) \n(15)\n\n \n(46) \n(8)\n\n \n— \n(1)\n\n \n(168) \n(237)\n\n \n(242) \n(261)\n\n \nAmortisation of intangible assets\n\n \n— \n—\n\n \n(1) \n—\n\n \n— \n—\n\n \n(9) \n(11)\n\n \n(10) \n(11)\n\n \nDepreciation of lease assets\n\n \n(12) \n(18)\n\n \n(3) \n(1)\n\n \n(44) \n(39)\n\n \n(30) \n(27)\n\n \n(89) \n(85)\n\n \nRestoration movement\n\n \n3 \n(443)\n\n \n2 \n(2)\n\n \n— \n—\n\n \n— \n—\n\n \n5 \n(445)\n\n \nOther 5 \n(58) \n(19)\n\n \n(26) \n(2)\n\n \n(72) \n(8)\n\n \n(175) \n(49)\n\n \n(331) \n(78)\n\n \nOther costs\n\n \n(95) \n(495)\n\n \n(74) \n(13)\n\n \n(116) \n(48)\n\n \n(382) \n(324)\n\n \n(667) \n(880)\n\n \nOther expenses \n(121) \n(505)\n\n \n(152) \n(87)\n\n \n(116) \n(48)\n\n \n(382) \n(324)\n\n \n(771) \n(964)\n\n \nImpairment losses 6 \n— \n—\n\n \n(135) \n—\n\n \n— \n—\n\n \n(43) \n(143)\n\n \n(178) \n(143)\n\n \nProfit/(loss) before tax and net finance costs\n\n \n1,664 \n1,473\n\n \n883 \n469\n\n \n54 \n144\n\n \n(444) \n(269)\n\n \n2,157 \n1,817\n\n \n\nIntersegment revenue reflects the margin recognised on products and services transferred between segments.\n\n \n\nOperating 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.\n\n \n\nIn 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.\n\n \n\nIncludes $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.\n\n \n\nIncludes $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.\n\n \n\nIncludes $135 million (2025: nil) relating to the impairment of the Calypso exploration and evaluation asset and $43 million (2025: $143 million) relating to the impairment of the H2OK Project. Refer to Note B.3 for details on impairment.\n\n \nA.2 Finance costs \n \n\n \n2026 \n2025\n\n \n \n\n \nUS$m \nUS$m\n\n \nInterest on interest-bearing liabilities\n\n \n303 \n281\n\n \nInterest on lease liabilities\n\n \n65 \n51\n\n \nAccretion charge\n\n \n156 \n148\n\n \nOther finance costs\n\n \n17 \n29\n\n \nLess: Borrowing costs capitalised against qualifying assets\n\n \n(296) \n(340)\n\n \nTotal finance costs \n245 \n169\n\n \nA.3 Dividends paid and proposed \nWoodside Energy Group Ltd, the parent entity, paid and proposed dividends as set out below:\n\n \n \n\n \n2026 \n2025\n\n \n \n\n \nUS$m \nUS$m\n\n \n(a) Dividends paid during the financial year\n\n \n \n\n \n \n\n \nPrior year fully franked final dividend US$0.59, paid on 27 March 2026 (2025: US$0.53, paid on 2 April 2025)\n\n \n1,122 \n1,006\n\n \n(b) Dividend determined subsequent to the reporting period (not recorded as a liability)\n\n \n \n\n \n \n\n \nCurrent year fully franked interim dividend US$0.57 to be paid on 25 September 2026\n\n \n\n\n(2025: US$0.53 to be paid on 24 September 2025)\n\n \n1,084 \n1,006 \nA.4 Earnings per share \n \n\n \n2026 \n2025\n\n \nProfit attributable to equity holders of the parent (US$m)\n\n \n1,672 \n1,316\n\n \nWeighted average number of shares on issue for basic earnings per share\n\n \n1,896,068,066 \n1,895,162,804\n\n \nEffect of dilution from contingently issuable shares\n\n \n19,457,286 \n17,049,593\n\n \nWeighted average number of shares on issue adjusted for the effect of dilution\n\n \n1,915,525,352 \n1,912,212,397\n\n \nBasic earnings per share (US cents) \n88.2 \n69.4\n\n \nDiluted earnings per share (US cents) \n87.3 \n68.8\n\n \nEarnings 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.\n\n \nA.5 Taxes \n \n\n \n2026 \n2025\n\n \n \n\n \nUS$m \nUS$m \nReconciliation of income tax expense/(benefit) \n \n\n \n \n\n \nProfit before tax\n\n \n2,035 \n1,754\n\n \nPRRT benefit/(expense)\n\n \n305 \n(71)\n\n \nProfit before income tax\n\n \n2,340 \n1,683\n\n \nIncome tax expense calculated at 30%\n\n \n702 \n505\n\n \nEffect of tax rate differentials\n\n \n41 \n42\n\n \nEffect of deferred tax assets not recognised\n\n \n50 \n12\n\n \nEffect of tax benefits previously unrecognised\n\n \n(90) \n(193)\n\n \nForeign exchange impact on tax expense/(benefit)\n\n \n28 \n(35)\n\n \nAdjustment to prior years\n\n \n(41) \n4\n\n \nOther\n\n \n(23) \n18\n\n \nIncome tax expense \n667 \n353\n\n   \nThe 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.\n\n \n\n\n \n\n \n\n\nDuring 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 $90 million income tax deferred tax asset in respect of heritage Woodside US net operating loss carryforwards, as utilisation of those losses is now considered probable.\n\n \nB. Production and growth assets \nB.1 Exploration and evaluation assets \n \n\n \nAsia Pacific \nAmericas \nAfrica \nTotal \n \n\n \nUS$m \nUS$m \nUS$m \nUS$m \nHalf-year ended 30 June 2026 \n \n\n \n \n\n \n \n\n \n \n\n \nCarrying amount at 1 January 2026\n\n \n582 \n207 \n1 \n790 \nAdditions\n\n \n18 \n47 \n— \n65 \nAmortisation of licence acquisition costs\n\n \n— \n(4) \n— \n(4) \nExpensed\n\n \n— \n(1) \n— \n(1) \nImpairment 1 \n— \n(135) \n— \n(135) \nTransferred exploration and evaluation\n\n \n(5) \n— \n— \n(5) \nCarrying amount at 30 June 2026 \n595 \n114 \n1 \n710 \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nYear ended 31 December 2025 \n \n\n \n \n\n \n \n\n \n \n\n \nCarrying amount at 1 January 2025\n\n \n571\n\n \n149\n\n \n1\n\n \n721\n\n \nAdditions\n\n \n17\n\n \n67\n\n \n—\n\n \n84\n\n \nAmortisation of licence acquisition costs\n\n \n—\n\n \n(5)\n\n \n—\n\n \n(5)\n\n \nExpensed\n\n \n—\n\n \n(4)\n\n \n—\n\n \n(4)\n\n \nTransferred exploration and evaluation\n\n \n(6)\n\n \n—\n\n \n—\n\n \n(6)\n\n \nCarrying amount at 31 December 2025 \n582\n\n \n207\n\n \n1\n\n \n790\n\n \n\nRefer to Note B.3 for details of impairment of the Calypso exploration and evaluation asset.\n\n \nB.2 Property, plant and equipment \n \n\n \nLand and buildings \nOil and gas properties \nProjects in development 1 \nOther plant and equipment \nTotal \n \n\n \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nHalf-year ended 30 June 2026 \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nCarrying amount at 1 January 2026\n\n \n744 \n23,091 \n22,437 \n283 \n46,555 \nAdditions 2 \n— \n9 \n3,492 \n— \n3,501 \nDisposals at written down value\n\n \n— \n— \n(12) \n— \n(12) \nImpairment loss 3 \n— \n— \n(43) \n— \n(43) \nCompletions and transfers 4 \n136 \n398 \n(2,010) \n1,481 \n5 \nDepreciation\n\n \n(32) \n(2,135) \n— \n(42) \n(2,209) \nCarrying amount at 30 June 2026 \n848 \n21,363 \n23,864 \n1,722 \n47,797 \nAt 30 June 2026 \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nHistorical cost\n\n \n2,035 \n59,227 \n24,389 \n2,201 \n87,852 \nAccumulated depreciation and impairment\n\n \n(1,187) \n(37,864) \n(525) \n(479) \n(40,055) \nCarrying amount \n848 \n21,363 \n23,864 \n1,722 \n47,797 \nYear ended 31 December 2025\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nCarrying amount at 1 January 2025\n\n \n734\n\n \n25,787\n\n \n15,926\n\n \n189\n\n \n42,636\n\n \nAdjustment to purchase price allocation\n\n \n(21)\n\n \n—\n\n \n(9)\n\n \n—\n\n \n(30)\n\n \nAdditions\n\n \n—\n\n \n657\n\n \n8,658\n\n \n10\n\n \n9,325\n\n \nDisposals at written down value\n\n \n(6)\n\n \n(44)\n\n \n(143)\n\n \n(3)\n\n \n(196)\n\n \nImpairment loss\n\n \n—\n\n \n—\n\n \n(143)\n\n \n—\n\n \n(143)\n\n \nCompletions and transfers\n\n \n98\n\n \n1,609\n\n \n(1,852)\n\n \n151\n\n \n6\n\n \nDepreciation\n\n \n(61)\n\n \n(4,918)\n\n \n—\n\n \n(64)\n\n \n(5,043)\n\n \nCarrying amount at 31 December 2025\n\n \n744\n\n \n23,091\n\n \n22,437\n\n \n283\n\n \n46,555\n\n \nAt 31 December 2025\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nHistorical cost\n\n \n1,899\n\n \n58,820\n\n \n22,919\n\n \n720\n\n \n84,358\n\n \nAccumulated depreciation and impairment\n\n \n(1,155)\n\n \n(35,729)\n\n \n(482)\n\n \n(437)\n\n \n(37,803)\n\n \nCarrying amount\n\n \n744\n\n \n23,091\n\n \n22,437\n\n \n283\n\n \n46,555\n\n \n\nProjects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.\n\n \n\nIncludes $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.\n\n \n\nRefer to Note B.3 for details of impairment of the H2OK Project.\n\n \n\nPrimarily 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. \n\n \n \n\n \nThe 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.\n\n \nB.3 Impairment of exploration and evaluation assets, property, plant and equipment and goodwill \nImpairment of Calypso exploration and evaluation asset \nAs 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.\n\n \nImpairment of H2OK Project \nAs 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: $143 million) was recognised in the Corporate segment of Note A.1 for the half-year ended 30 June 2026 reducing the carrying value of the assets to nil.\n\n \nB.4 Intangible assets \n \n\n \nGoodwill \nContract assets \nSoftware \nTotal \n \n\n \nUS$m \nUS$m \nUS$m \nUS$m \nHalf-year ended 30 June 2026 \n \n\n \n \n\n \n \n\n \n \n\n \nCarrying amount at 1 January 2026\n\n \n3,952 \n714 \n187 \n4,853 \nAdditions\n\n \n– \n– \n18 \n18 \nAmortisation\n\n \n– \n(2) \n(8) \n(10) \nDisposals\n\n \n– \n(5) \n– \n(5) \nCarrying amount at 30 June 2026 \n3,952 \n707 \n197 \n4,856 \nAt 30 June 2026 \n \n\n \n \n\n \n \n\n \n \n\n \nCost\n\n \n4,429 \n796 \n238 \n5,463 \nAccumulated amortisation and impairment\n\n \n(477) \n(89) \n(41) \n(607) \nCarrying amount \n3,952 \n707 \n197 \n4,856 \nYear ended 31 December 2025\n\n \n \n\n \n \n\n \n \n\n \n \n\n \nCarrying amount at 1 January 2025\n\n \n3,866\n\n \n757\n\n \n203\n\n \n4,826\n\n \nAdjustment to purchase price allocation\n\n \n86\n\n \n30\n\n \n–\n\n \n116\n\n \nAdditions\n\n \n–\n\n \n–\n\n \n2\n\n \n2\n\n \nAmortisation\n\n \n–\n\n \n(73)\n\n \n(18)\n\n \n(91)\n\n \nCarrying amount at 31 December 2025\n\n \n3,952\n\n \n714\n\n \n187\n\n \n4,853\n\n \nAt 31 December 2025\n\n \n \n\n \n \n\n \n \n\n \n \n\n \nCost\n\n \n4,429\n\n \n814\n\n \n220\n\n \n5,463\n\n \nAccumulated amortisation and impairment\n\n \n(477)\n\n \n(100)\n\n \n(33)\n\n \n(610)\n\n \nCarrying amount\n\n \n3,952\n\n \n714\n\n \n187\n\n \n4,853\n\n \n \n\n \nB.5 Transactions with equity holders of the Group \nSell-down arrangement with Stonepeak \nDuring 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 $4,262 million was received.\n\n \nUnder the agreement, the Group still controls Louisiana LNG Infrastructure LLC, while Stonepeak now holds a non-controlling interest. Transactions that do not result in the Group's loss of control are treated as equity transactions. When ownership percentages change, the carrying amounts of both controlling and non-controlling interests are adjusted based on their relative interest in the subsidiary. Any difference between the adjustment to non-controlling interests and consideration received is recorded in a separate equity reserve. Stonepeak’s non-controlling interest percentage is based on the proportion of total contributions to date and will fluctuate during the construction phase. The non-controlling interest percentage will to revert to 40% when the project starts generating revenue. Refer to Note E.4 Subsidiaries.\n\n \nC. Debt and capital \nC.1 Interest-bearing liabilities and financing facilities \n \n\n \nBilateral facilities \nSyndicated facilities \nJBIC facility \nUS bonds \nMedium term notes \nTotal \n \n\n \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nUS$m \nHalf-year ended 30 June 2026 \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nAt 1 January 2026\n\n \n(4) \n2,232 \n1,000 \n8,535 \n200 \n11,963 \nRepayments 1 \n— \n(600) \n— \n— \n— \n(600) \nTransaction costs capitalised and amortised\n\n \n(1) \n2 \n— \n6 \n— \n7 \nCarrying amount at 30 June 2026 \n(5) \n1,634 \n1,000 \n8,541 \n200 \n11,370 \nCurrent\n\n \n(2) \n(4) \n— \n789 \n200 \n983 \nNon-current\n\n \n(3) \n1,638 \n1,000 \n7,752 \n— \n10,387 \nCarrying amount at 30 June 2026 \n(5) \n1,634 \n1,000 \n8,541 \n200 \n11,370 \nUndrawn balance at 30 June 2026 \n2,650 \n1,200 \n— \n— \n— \n3,850 \nYear ended 31 December 2025\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \n \n\n \nAt 1 January 2025\n\n \n495\n\n \n2,233\n\n \n1,000\n\n \n6,069\n\n \n200\n\n \n9,997\n\n \nDrawdowns\n\n \n1,400\n\n \n—\n\n \n—\n\n \n3,500\n\n \n—\n\n \n4,900\n\n \nRepayments\n\n \n(1,900)\n\n \n—\n\n \n—\n\n \n(1,000)\n\n \n—\n\n \n(2,900)\n\n \nTransaction costs capitalised and amortised\n\n \n1\n\n \n(1)\n\n \n—\n\n \n(34)\n\n \n—\n\n \n(34)\n\n \nCarrying amount at 31 December 2025\n\n \n(4)\n\n \n2,232\n\n \n1,000\n\n \n8,535\n\n \n200\n\n \n11,963\n\n \nCurrent\n\n \n(2)\n\n \n(5)\n\n \n—\n\n \n789\n\n \n—\n\n \n782\n\n \nNon-current\n\n \n(2)\n\n \n2,237\n\n \n1,000\n\n \n7,746\n\n \n200\n\n \n11,181\n\n \nCarrying amount at 31 December 2025\n\n \n(4)\n\n \n2,232\n\n \n1,000\n\n \n8,535\n\n \n200\n\n \n11,963\n\n \nUndrawn balance at 31 December 2025\n\n \n2,350\n\n \n1,200\n\n \n—\n\n \n—\n\n \n—\n\n \n3,550\n\n \n\nIn June 2026, the Group settled the $600 million syndicated facility that was executed on 17 January 2020.\n\n \nThere were no new covenants or other material changes to interest-bearing liabilities and financing facilities.\n\n \nFair value \nThe 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: $197 million). Fair value is determined by reference to quoted market prices for these instruments and is classified as Level 1 within the fair value hierarchy.\n\n \nC.2 Contributed equity \nIssued and fully paid shares \n \n\n \nNumber of shares \nUS$m \nHalf-year ended 30 June 2026 \n \n\n \n \n\n \nOpening balance\n\n \n1,901,100,143 \n29,036 \nAmounts as at 30 June 2026 \n1,901,100,143 \n29,036 \nYear ended 31 December 2025\n\n \n \n\n \n \n\n \nOpening balance\n\n \n1,898,749,771\n\n \n29,001\n\n \nShares issued\n\n \n2,350,372\n\n \n35\n\n \nAmounts as at 31 December 2025\n\n \n1,901,100,143\n\n \n29,036\n\n \nAll 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.\n\n \nReserved shares \nReserved 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.\n\n \n \n\n \nNumber of shares \nUS$m \nHalf-year ended 30 June 2026 \n \n\n \n \n\n \nOpening balance\n\n \n5,283,450 \n(82) \nVested/allocated during the half-year\n\n \n(644,610) \n10 \nAmounts as at 30 June 2026 \n4,638,840 \n(72) \nYear ended 31 December 2025\n\n \n \n\n \n \n\n \nOpening balance\n\n \n3,080,842\n\n \n(58)\n\n \nPurchases during the year\n\n \n5,700,372\n\n \n(88)\n\n \nVested/allocated during the year\n\n \n(3,497,764)\n\n \n64\n\n \nAmounts as at 31 December 2025\n\n \n5,283,450\n\n \n(82)\n\n \nD. Other assets and liabilities \nD.1 Segment assets and liabilities \n \n\n \n30 June 2026 \n31 December 2025\n\n \n \n\n \nUS$m \nUS$m\n\n \n(a) Segment assets \n \n\n \n \n\n \nAustralia\n\n \n30,569 \n30,541\n\n \nInternational\n\n \n26,885 \n24,773\n\n \nMarketing\n\n \n1,094 \n965\n\n \nCorporate\n\n \n9,133 \n10,222\n\n \n \n\n \n67,681 \n66,501\n\n \n \n\n \n \n\n \n \n\n \n \n\n \n30 June 2026 \n31 December 2025\n\n \n \n\n \nUS$m \nUS$m\n\n \n(b) Segment liabilities \n \n\n \n \n\n \nAustralia\n\n \n6,899 \n7,252\n\n \nInternational\n\n \n2,856 \n2,531\n\n \nMarketing\n\n \n1,297 \n1,054\n\n \nCorporate\n\n \n14,905 \n15,821\n\n \n \n\n \n25,957 \n26,658\n\n \nCorporate assets mainly comprise cash and cash equivalents, deferred tax assets, new energy assets in development and lease assets. Corporate liabilities mainly comprise interest-bearing liabilities, deferred tax liabilities and lease liabilities.\n\n \nD.2 Provisions \n \n\n \nRestoration 1 \nEmployee benefits \nOther \nTotal \n \n\n \nUS$m \nUS$m \nUS$m \nUS$m \nHalf-year ended 30 June 2026 \n \n\n \n \n\n \n \n\n \n \n\n \nAt 1 January 2026\n\n \n6,886 \n669 \n312 \n7,867 \nChange in provision\n\n \n(229) \n(86) \n(73) \n(388) \nUnwinding of present value discount\n\n \n156 \n— \n— \n156 \nCarrying amount at 30 June 2026 \n6,813 \n583 \n239 \n7,635 \nAt 30 June 2026\n\n \n \n\n \n \n\n \n \n\n \n \n\n \nCurrent\n\n \n765 \n373 \n100 \n1,238 \nNon-current\n\n \n6,048 \n210 \n139 \n6,397 \nCarrying amount \n6,813 \n583 \n239 \n7,635 \nYear ended 31 December 2025\n\n \n \n\n \n \n\n \n \n\n \n \n\n \nAt 1 January 2025\n\n \n6,526\n\n \n654\n\n \n367\n\n \n7,547\n\n \nAdjustment to purchase price allocation\n\n \n—\n\n \n—\n\n \n100\n\n \n100\n\n \nChange in provision\n\n \n254\n\n \n11\n\n \n(138)\n\n \n127\n\n \nUnwinding of present value discount\n\n \n283\n\n \n5\n\n \n—\n\n \n288\n\n \nDisposals\n\n \n(177)\n\n \n(1)\n\n \n(17)\n\n \n(195)\n\n \nCarrying amount at 31 December 2025\n\n \n6,886\n\n \n669\n\n \n312\n\n \n7,867\n\n \nAt 31 December 2025\n\n \n \n\n \n \n\n \n \n\n \n \n\n \nCurrent\n\n \n637\n\n \n449\n\n ...

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