\n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n Prior<\/b><\/p>\n<\/td>\n | \n Current<\/b><\/p>\n<\/td>\n<\/tr>\n\n| \n \nTotal production volumes45<\/sup><\/p>\n<\/td>\n| \n \nMMboe<\/p>\n<\/td>\n | \n \n86.5<\/p>\n<\/td>\n | \n \n99.2<\/p>\n<\/td>\n | \n \n(13%)<\/p>\n<\/td>\n | \n \n172 – 186<\/p>\n<\/td>\n | \n \n174-185<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nGas hub exposure6<\/sup><\/p>\n<\/td>\n| \n \n%<\/p>\n<\/td>\n | \n \n38.7%<\/p>\n<\/td>\n | \n \n24.2%<\/p>\n<\/td>\n | \n \n15%<\/p>\n<\/td>\n | \n \n~30<\/p>\n<\/td>\n | \n \nNo change<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nCapital expenditure1,78<\/sup><\/p>\n<\/td>\n| \n \n$ million<\/p>\n<\/td>\n | \n \n1,637<\/p>\n<\/td>\n | \n \n2,558<\/p>\n<\/td>\n | \n \n(36%)<\/p>\n<\/td>\n | \n \n4,000 – 4,500<\/p>\n<\/td>\n | \n \nNo change<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nAbandonment expenditure<\/p>\n<\/td>\n | \n \n$ million<\/p>\n<\/td>\n | \n \n255<\/p>\n<\/td>\n | \n \n517<\/p>\n<\/td>\n | \n \n(51%)<\/p>\n<\/td>\n | \n \n500 – 800<\/p>\n<\/td>\n | \n \nNo change<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nExploration expenditure1<\/sup><\/p>\n<\/td>\n| \n \n$ million<\/p>\n<\/td>\n | \n \n119<\/p>\n<\/td>\n | \n \n84<\/p>\n<\/td>\n | \n \n42%<\/p>\n<\/td>\n | \n \n~200<\/p>\n<\/td>\n | \n \nNo change<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nProduction costs<\/p>\n<\/td>\n | \n \n$ million<\/p>\n<\/td>\n | \n \n749<\/p>\n<\/td>\n | \n \n667<\/p>\n<\/td>\n | \n \n12%<\/p>\n<\/td>\n | \n \n1,500 – 1,800<\/p>\n<\/td>\n | \n \nNo change<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nFeed gas, services and processing costs<\/p>\n<\/td>\n | \n \n$ million<\/p>\n<\/td>\n | \n \n238<\/p>\n<\/td>\n | \n \n92<\/p>\n<\/td>\n | \n \n159%<\/p>\n<\/td>\n | \n \n500 – 600<\/p>\n<\/td>\n | \n \nNo change<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nProperty, plant and equipment depreciation and amortisation<\/p>\n<\/td>\n | \n \n$ million<\/p>\n<\/td>\n | \n \n2,209<\/p>\n<\/td>\n | \n \n2,541<\/p>\n<\/td>\n | \n \n(13%)<\/p>\n<\/td>\n | \n \n4,200 – 4,700<\/p>\n<\/td>\n | \n \nNo change<\/p>\n<\/td>\n<\/tr>\n<\/table>\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\u2019s Annual Report 2025.<\/p>\n \n\n| \n Summary<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n \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.<\/p>\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\u2019s Marketing and Trading division continued to optimise the portfolio to manage risk and maximise value while fulfilling customer commitments.<\/p>\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<\/sup><\/p>\n\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.<\/p>\n \n\u201cWe once again delivered strong production, cash flow and shareholder returns, while continuing to execute the next phase of growth.<\/p>\n \n\u201cKeeping 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.<\/p>\n \n\u201cWe 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.<\/p>\n \n\u201cThe 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.<\/p>\n \n\u201cThe 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.<\/p>\n \n\u201cAt Louisiana LNG, key milestones were achieved relating to the LNG tanks and marine infrastructure. The project\u2019s foundation development was 28% complete at the end of the half, with first LNG targeted for 2029.<\/p>\n \n\u201cIn 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.<\/p>\n \n\u201cWe 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.<\/p>\n \n\u201cAs we focus on Woodside\u2019s 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 $350 million from 2028 to be delivered through the structured review of our business.\u201d<\/p>\n \n\n| \n Financial summary<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n\n\n| \n Key metrics<\/b><\/p>\n<\/td>\n | | \n | \n | \n | <\/tr>\n \n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n H1<\/b><\/p>\n<\/td>\n | \n H1<\/b><\/p>\n<\/td>\n | \n Change<\/b><\/p>\n<\/td>\n<\/tr>\n\n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n 2026<\/b><\/p>\n<\/td>\n | \n 2025<\/b><\/p>\n<\/td>\n | \n %<\/b><\/p>\n<\/td>\n<\/tr>\n\n| \n \nOperating revenue<\/p>\n<\/td>\n | \n \n$ million<\/p>\n<\/td>\n | \n \n7,446<\/p>\n<\/td>\n | \n \n6,590<\/p>\n<\/td>\n | \n \n13%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nEBITDA excluding impairment10<\/sup><\/p>\n<\/td>\n| \n \n$ million<\/p>\n<\/td>\n | \n \n4,647<\/p>\n<\/td>\n | \n \n4,600<\/p>\n<\/td>\n | \n \n1%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nEBIT10<\/sup><\/p>\n<\/td>\n| \n \n$ million<\/p>\n<\/td>\n | \n \n2,157<\/p>\n<\/td>\n | \n \n1,817<\/p>\n<\/td>\n | \n \n19%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nNet profit after tax (NPAT)1112<\/sup><\/p>\n<\/td>\n| \n \n$ million<\/p>\n<\/td>\n | \n \n1,672<\/p>\n<\/td>\n | \n \n1,316<\/p>\n<\/td>\n | \n \n27%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nUnderlying NPAT10<\/sup><\/p>\n<\/td>\n| \n \n$ million<\/p>\n<\/td>\n | \n \n1,334<\/p>\n<\/td>\n | \n \n1,247<\/p>\n<\/td>\n | \n \n7%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nNet cash from operating activities<\/p>\n<\/td>\n | \n \n$ million<\/p>\n<\/td>\n | \n \n3,013<\/p>\n<\/td>\n | \n \n3,339<\/p>\n<\/td>\n | \n \n(10%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nCapital expenditure10,13<\/sup><\/p>\n<\/td>\n| \n \n$ million<\/p>\n<\/td>\n | \n \n1,637<\/p>\n<\/td>\n | \n \n2,558<\/p>\n<\/td>\n | \n \n(36%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nExploration expenditure10,14<\/sup><\/p>\n<\/td>\n| \n \n$ million<\/p>\n<\/td>\n | \n \n119<\/p>\n<\/td>\n | \n \n84<\/p>\n<\/td>\n | \n \n42%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nFree cash flow10,15<\/sup><\/p>\n<\/td>\n| \n \n$ million<\/p>\n<\/td>\n | \n \n352<\/p>\n<\/td>\n | \n \n136<\/p>\n<\/td>\n | \n \n159%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nAverage realised price10,18<\/sup><\/p>\n<\/td>\n| \n \nUS$\/boe<\/p>\n<\/td>\n | \n \n74.0<\/p>\n<\/td>\n | \n \n61.7<\/p>\n<\/td>\n | \n \n20%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nDividends distributed<\/p>\n<\/td>\n | \n \n$ million<\/p>\n<\/td>\n | \n 1,122<\/b><\/p>\n<\/td>\n | \n 1,006<\/b><\/p>\n<\/td>\n | \n \n12%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nInterim dividend determined<\/p>\n<\/td>\n | \n \nUS cps<\/p>\n<\/td>\n | \n \n57<\/p>\n<\/td>\n | \n \n53<\/p>\n<\/td>\n | \n \n8%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n Key ratios<\/b><\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nEarnings per share<\/p>\n<\/td>\n | \n \nUS cps<\/p>\n<\/td>\n | \n \n88.2<\/p>\n<\/td>\n | \n \n69.4<\/p>\n<\/td>\n | \n \n27%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nGearing10<\/sup><\/p>\n<\/td>\n| \n \n%<\/p>\n<\/td>\n | \n \n20.6<\/p>\n<\/td>\n | \n \n19.5<\/p>\n<\/td>\n | \n \n1%<\/p>\n<\/td>\n<\/tr>\n | \n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n Production volumes16,17<\/sup><\/b><\/p>\n<\/td>\n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nGas<\/p>\n<\/td>\n | \n \nMMboe<\/p>\n<\/td>\n | \n \n46.1<\/p>\n<\/td>\n | \n \n58.2<\/p>\n<\/td>\n | \n \n(21%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nLiquids<\/p>\n<\/td>\n | \n \nMMboe<\/p>\n<\/td>\n | \n \n39.4<\/p>\n<\/td>\n | \n \n41.0<\/p>\n<\/td>\n | \n \n(4%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nAmmonia<\/p>\n<\/td>\n | \n \nMMboe<\/p>\n<\/td>\n | \n \n1.0<\/p>\n<\/td>\n | \n \n–<\/p>\n<\/td>\n | \n \nN\/A<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nTotal<\/p>\n<\/td>\n | \n \nMMboe<\/p>\n<\/td>\n | \n \n86.5<\/p>\n<\/td>\n | \n \n99.2<\/p>\n<\/td>\n | \n \n(13%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n Production volumes per day17<\/sup><\/b><\/p>\n<\/td>\n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nGas<\/p>\n<\/td>\n | \n \nMMscf\/d<\/p>\n<\/td>\n | \n \n1,451<\/p>\n<\/td>\n | \n \n1,833<\/p>\n<\/td>\n | \n \n(21%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nLiquids<\/p>\n<\/td>\n | \n \nMbbl\/d<\/p>\n<\/td>\n | \n \n217<\/p>\n<\/td>\n | \n \n226<\/p>\n<\/td>\n | \n \n(4%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nAmmonia<\/p>\n<\/td>\n | \n \nkT\/d<\/p>\n<\/td>\n | \n \n1.5<\/p>\n<\/td>\n | \n \n–<\/p>\n<\/td>\n | \n \nN\/A<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nTotal<\/p>\n<\/td>\n | \n \nMboe\/d<\/p>\n<\/td>\n | \n \n478<\/p>\n<\/td>\n | \n \n548<\/p>\n<\/td>\n | \n \n(13%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n Sales volumes17<\/sup><\/b><\/p>\n<\/td>\n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nGas18<\/sup><\/p>\n<\/td>\n| \n \nMMboe<\/p>\n<\/td>\n | \n \n58.5<\/p>\n<\/td>\n | \n \n63.9<\/p>\n<\/td>\n | \n \n(8%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nLiquids<\/p>\n<\/td>\n | \n \nMMboe<\/p>\n<\/td>\n | \n \n40.3<\/p>\n<\/td>\n | \n \n40.9<\/p>\n<\/td>\n | \n \n(1%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nAmmonia<\/p>\n<\/td>\n | \n \nMMboe<\/p>\n<\/td>\n | \n \n1.0<\/p>\n<\/td>\n | \n \n–<\/p>\n<\/td>\n | \n \nN\/A<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nTotal<\/p>\n<\/td>\n | \n MMboe<\/b><\/p>\n<\/td>\n | \n \n99.8<\/p>\n<\/td>\n | \n \n104.8<\/p>\n<\/td>\n | \n \n(5%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n Sales volumes per day17<\/sup><\/b><\/p>\n<\/td>\n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nGas18<\/sup><\/p>\n<\/td>\n| \n \nMMscf\/d<\/p>\n<\/td>\n | \n \n1,843<\/p>\n<\/td>\n | \n \n2,012<\/p>\n<\/td>\n | \n \n(8%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nLiquids<\/p>\n<\/td>\n | \n \nMbbl\/d<\/p>\n<\/td>\n | \n \n223<\/p>\n<\/td>\n | \n \n226<\/p>\n<\/td>\n | \n \n(1%)<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nAmmonia<\/p>\n<\/td>\n | \n \nkT\/d<\/p>\n<\/td>\n | \n \n1.4<\/p>\n<\/td>\n | \n \n–<\/p>\n<\/td>\n | \n \nN\/A<\/p>\n<\/td>\n<\/tr>\n | \n| \n \n\u00a0<\/p>\n<\/td>\n | \n Mboe\/d<\/b><\/p>\n<\/td>\n | \n \n551<\/p>\n<\/td>\n | \n \n579<\/p>\n<\/td>\n | \n \n(5%)<\/p>\n<\/td>\n<\/tr>\n<\/table>\n \n\n| \n Appendix 4D<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n Results for announcement to the market<\/b><\/p>\n \nMore information is available on page 48.<\/p>\n \n\n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n US$ million<\/b><\/p>\n<\/td>\n<\/tr>\n\n| \n \nRevenue from ordinary activities<\/p>\n<\/td>\n | \n \nIncreased<\/p>\n<\/td>\n | \n \n13%19<\/sup><\/p>\n<\/td>\n| \n \nto<\/p>\n<\/td>\n | \n \n7,446<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nProfit from ordinary activities after tax attributable to members<\/p>\n<\/td>\n | \n \nIncreased<\/p>\n<\/td>\n | \n \n27%19<\/sup><\/p>\n<\/td>\n| \n \nto<\/p>\n<\/td>\n | \n \n1,672<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nNet profit for the period attributable to members<\/p>\n<\/td>\n | \n \nIncreased<\/p>\n<\/td>\n | \n \n27%19<\/sup><\/p>\n<\/td>\n| \n \nto<\/p>\n<\/td>\n | \n \n1,672<\/p>\n<\/td>\n<\/tr>\n | \n| \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nInterim dividend – fully franked<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n57 US cps H1 2026<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nRecord date for determining entitlements to the dividend<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n4 September 2026<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n<\/table>\n \n\n| \n Net profit after tax reconciliation<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n \nThe following table summarises the variance between the H1 2025 and H1 2026 results for the contribution of each line item to NPAT.<\/p>\n \n\n| \n \n\u00a0<\/p>\n<\/td>\n | \n US$m<\/b><\/p>\n<\/td>\n | \n Primary reasons for variance<\/b><\/p>\n<\/td>\n<\/tr>\n\n| \n 2025 H1 reported NPAT<\/b><\/p>\n<\/td>\n | \n 1,316<\/b><\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nRevenue from sale of products<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nProduced – price impact<\/p>\n<\/td>\n | \n \n755<\/p>\n<\/td>\n | \n \nHigher average realised prices.<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nProduced – volume impact<\/p>\n<\/td>\n | \n \n(307)<\/p>\n<\/td>\n | \n \nLower production due to cyclone impacts, Pluto planned turnaround and divestment of the Greater Angostura assets offset by first ammonia sales.<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nPurchased – price and volume impact<\/p>\n<\/td>\n | \n \n440<\/p>\n<\/td>\n | \n \nHigher third-party LNG trading activity.<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nCost of sales<\/p>\n<\/td>\n | \n \n(559)<\/p>\n<\/td>\n | \n \nHigher third-party LNG trading activity, first ammonia production and Pluto planned turnaround.<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nPerdaman embedded derivative<\/p>\n<\/td>\n | \n \n(297)<\/p>\n<\/td>\n | \n \nA non-cash unrealised loss of $135 million in H1 2026 compared to an unrealised gain of $162 million in H1 2025.<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nHedging<\/p>\n<\/td>\n | \n \n(106)<\/p>\n<\/td>\n | \n \nPre-tax hedge losses of $64 million in H1 2026 compared to pre-tax hedge gains of $42 million in H1 2025.<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nRestoration movement<\/p>\n<\/td>\n | \n \n450<\/p>\n<\/td>\n | \n \nRestoration provision updates primarily due to Stybarrow, Griffin and Minerva in 2025.<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nImpairment losses<\/p>\n<\/td>\n | \n \n(35)<\/p>\n<\/td>\n | \n \nPre-tax impairment for the Calypso Project offset by lower pre-tax impairment for the H2OK Project compared with H1 2025.<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nIncome tax and PRRT expense<\/p>\n<\/td>\n | \n \n62<\/p>\n<\/td>\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.<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nOther<\/p>\n<\/td>\n | \n \n(47)<\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n 2026 H1 reported NPAT<\/b><\/p>\n<\/td>\n | \n 1,672<\/b><\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n | \n| \n \nUnderlying adjustments<\/p>\n<\/td>\n | \n (338)<\/b><\/p>\n<\/td>\n | \n \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.<\/p>\n<\/td>\n<\/tr>\n | \n| \n 2026 H1 underlying NPAT20<\/sup><\/b><\/p>\n<\/td>\n| \n 1,334<\/b><\/p>\n<\/td>\n | \n \n\u00a0<\/p>\n<\/td>\n<\/tr>\n<\/table>\n \n\n| \n Capital management<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n \nWoodside\u2019s capital management framework provides us with the flexibility to optimise value and shareholder returns delivered from the portfolio of opportunities.<\/p>\n Interim dividend and dividend reinvestment plan<\/b><\/p>\n \nA 2026 fully franked interim dividend of 57 US cps has been determined, representing an annualised dividend yield of 5.9% .21<\/sup> 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<\/sup><\/p>\n\nThe dividend reinvestment plan remains suspended.<\/p>\n Liquidity and balance sheet<\/b><\/p>\n \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<\/sup><\/p>\n\nDuring this period, Woodside repaid a $600 million Syndicated Term Loan approximately 6 months prior to maturity.<\/p>\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<\/sup><\/p>\n\nWoodside\u2019s gearing as at 30 June 2026 was 20.6%, marginally outside the target range of 10 to 20%.22 <\/sup>Woodside\u2019s gearing may at times fall outside the target range as the balance sheet is managed through the investment cycle.<\/p>\n\nNet debt and gearing were impacted by:<\/p>\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<\/sup><\/li>\n
- \nNet cash outflow of $419 million for hedge settlements.<\/p>\n<\/li>\n
- \nHigher pricing driving a $101 million increase in trade receivables that were received in July 2026.<\/p>\n<\/li>\n<\/ul>\n
\nWoodside\u2019s 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\u2019s capital management framework.<\/p>\n Commodity price risk management<\/b><\/p>\n \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.<\/p>\n \nCommodity swaps were used to continue managing risk associated with the Corpus Christi LNG volumes.<\/p>\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.<\/p>\n Embedded commodity derivative<\/b><\/p>\n \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.<\/p>\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.<\/p>\n \n\n| \n Australian operations<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n Pluto LNG<\/b><\/p>\n \nPluto LNG is a gas processing facility in the Pilbara region of Western Australia, comprising an offshore platform and one onshore LNG processing train.<\/p>\n \nWoodside\u2019s 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.<\/p>\n \nPluto LNG achieved reliability of 98.7% in H1 2026, reflecting the asset’s strong operating performance.<\/p>\n \nIn H1 2026, drilling of the XNA-03 infill well was completed and preparations continue for start-up targeted for H2 2026.<\/p>\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.<\/p>\n \nWoodside is operator and holds a 90% participating interest.<\/p>\n North West Shelf Project<\/b><\/p>\n \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.<\/p>\n \nWoodside\u2019s 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.<\/p>\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.<\/p>\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.<\/p>\n \nPreparations are continuing for a planned turnaround for a single LNG Train targeted to commence in September 2026.<\/p>\n \nThe NWS is continuing with infrastructure retirement planning at KGP while maintaining the capacity to provide processing services for third-party gas.<\/p>\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.<\/p>\n \nWoodside is operator and holds a 33.33% participating interest.<\/p>\n \nFollowing completion of the asset swap agreement with Chevron announced in 2024, Woodside\u2019s participating interest will increase to 50%. The asset swap remains targeted for completion in Q4 2026.25<\/sup><\/p>\nWheatstone and Julimar-Brunello<\/b><\/p>\n \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.<\/p>\n \nWoodside\u2019s 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.<\/p>\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.<\/p>\n \nIn parallel, decommissioning of three Julimar\u2013Brunello exploration wells commenced in H1 2026. Completion of both activities are condition precedents to the Chevron asset swap.<\/p>\n \nWoodside is operator and holds a 65% participating interest in the Julimar-Brunello fields.<\/p>\n \nWoodside holds a 13% non-operating participating interest in the Wheatstone Project.<\/p>\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<\/sup><\/p>\nBass Strait<\/b><\/p>\n \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).<\/p>\n \nWoodside\u2019s 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.<\/p>\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.<\/p>\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<\/sup><\/p>\n\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\u2019s 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.<\/p>\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.<\/p>\n Other Australian oil and gas assets<\/b><\/p>\n \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%).<\/p>\n \nFollowing completion of the asset swap agreement with Chevron announced in 2024, Woodside\u2019s participating interest in the Okha FPSO will increase to 66.67%. The asset swap remains targeted for completion in Q4 2026.26<\/sup><\/p>\n\nWoodside\u2019s 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.<\/p>\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.<\/p>\n \nWoodside\u2019s 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.<\/p>\n Woodside Solar<\/b><\/p>\n \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.<\/p>\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.<\/p>\n \n\n| \n International operations<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n Sangomar<\/b><\/p>\n \nThe Sangomar Field Development Phase 1 is a deepwater project with a stand-alone FPSO facility moored approximately 100 km offshore Senegal.<\/p>\n \nWoodside\u2019s 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.<\/p>\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<\/sup> 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.<\/p>\n\nH1 2026 sales of Sangomar crude oil were directed to Europe and South Asia during the Middle East conflict, attracting strong premiums.<\/p>\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.<\/p>\n \nWoodside is operator and has an 82% participating interest.<\/p>\n Shenzi<\/b><\/p>\n \nShenzi is a conventional offshore oil and gas field developed through a tension leg platform located offshore in the Gulf of America.<\/p>\n \nWoodside\u2019s 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.<\/p>\n \nWoodside is operator and holds a 72% participating interest.<\/p>\n Atlantis<\/b><\/p>\n \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.<\/p>\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.<\/p>\n \nWoodside\u2019s 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.<\/p>\n \nWoodside holds a 44% non-operating participating interest.<\/p>\n Mad Dog<\/b><\/p>\n \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.<\/p>\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.<\/p>\n \nWoodside\u2019s 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.<\/p>\n \nWoodside holds a 23.9% non-operating participating interest.<\/p>\n Beaumont New Ammonia<\/b><\/p>\n \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.<\/p>\n \nWoodside’s production in H1 2026 was 279 kT with reliability of 87.6% including the start-up and commissioning period.29<\/sup> 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\u2019s low-carbon hydrogen facilities and startup of ExxonMobil\u2019s CCS infrastructure, including approval of the relevant CCS permitting process.30<\/sup><\/p>\n\nWoodside is operator and holds a 100% participating interest.<\/p>\n \n\n| \n Marketing and Trading<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n Revenue and trading<\/b><\/p>\n \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.<\/p>\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.<\/p>\n \nThe marketing segment delivered EBIT of $54 million in H1 2026, representing approximately 3% of total EBIT.31<\/sup> Pre-tax hedge losses of $62 million were recognised in the segment, primarily relating to Corpus Christi LNG hedges, reducing EBIT.<\/p>\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.<\/p>\n Shipping<\/b><\/p>\n \nWoodside has signed five long-term time charter parties for LNG vessels all commencing in 2029, and added the Woodside Bilangara to Woodside\u2019s fleet of LNG vessels during the period to support the start-up of the Scarborough Energy Project, bringing Woodside\u2019s total number of long-term chartered vessels on the water to nine.<\/p>\n Pipeline gas<\/b><\/p>\n \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.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\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\u2019s position as a reliable energy supplier to domestic and international customers.<\/p>\n \n\n| \n Projects<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n Scarborough Energy Project<\/b><\/p>\n \nThe Scarborough gas field is located in the Carnarvon Basin, approximately 375 km off the coast of Western Australia.<\/p>\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.<\/p>\n \nThe project includes the construction of an integrated remote operations centre (IROC) at Woodside\u2019s headquarters. The IROC will have the capacity to operate the FPU and the Pluto LNG facility from Perth.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\n Trion<\/b><\/p>\n \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.<\/p>\n \nThe project was 64% complete at the end of H1 2026. First oil is targeted for 2028.<\/p>\n \nDrilling of 24 subsea wells commenced in March 2026 with three production wells drilled during the period.<\/p>\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<\/p>\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.<\/p>\n \nWoodside is the operator and holds a 60% participating interest.<\/p>\n Louisiana LNG<\/b><\/p>\n \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.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\n \nWith foundational transportation and storage capacity secured in 2025, Woodside continued to advance feed gas procurement in line with its gas supply strategy.<\/p>\n \nOngoing engagement with high-quality counterparties for equity participation and LNG offtake continues to support progress on the Louisiana LNG sell-down process.<\/p>\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.<\/p>\n Hydrogen Refueller @H2Perth<\/b><\/p>\n \nThe Hydrogen Refueller @H2Perth is a self-contained hydrogen production, storage and refuelling station located in Perth, Western Australia.32<\/sup><\/p>\n\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.<\/p>\n \nWoodside is operator and holds a 100% participating interest.<\/p>\n \n\n| \n Decommissioning<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n \nWoodside continued execution of planned decommissioning activities in H1 2026, spending approximately $274 million across its portfolio.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\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.<\/p>\n \n\n| \n Developments and Exploration<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n Browse<\/b><\/p>\n \nThe Browse development comprises the Calliance, Brecknock and Torosa gas and condensate fields located approximately 425 km north of Broome, Western Australia.<\/p>\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.<\/p>\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\u2019s Karratha Gas Plant.<\/p>\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 <\/i>(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.<\/p>\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<\/sup><\/p>\n\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.<\/p>\n \nWoodside is operator and holds a 30.6% participating interest. Woodside\u2019s equity interest in the BJV after completion of the acquisition of CNPC\u2019s interest will increase from 30.6% to 41.27%.<\/p>\n Sunrise<\/b><\/p>\n \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.<\/p>\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.<\/p>\n \nTechnical and commercial activities progressed under the Timor-Leste Cooperation Agreement to support maturation of a potential Timor\u2011based LNG concept.<\/p>\n \nWoodside is operator and holds a 33.44% participating interest.<\/p>\n Calypso<\/b><\/p>\n \nCalypso is a discovered resource located approximately 220 km off the coast of Trinidad in 2,100m water depth.<\/p>\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<\/sup><\/p>\nLiard<\/b><\/p>\n \nThe Liard field is an unconventional gas field located in British Columbia, Canada.<\/p>\n \nWoodside holds a 50% non-operating participating interest.<\/p>\n Exploration<\/b><\/p>\n \nWoodside\u2019s exploration activities focused on maturing current opportunities, consistent with its disciplined exploration strategy.<\/p>\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<\/sup> 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.<\/p>\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.<\/p>\n H2Perth<\/b><\/p>\n \nThe H2Perth Project is a proposal to develop Australia\u2019s first commercial-scale liquid hydrogen production and export facility in Western Australia, located in the Rockingham Industry Zone and Kwinana.<\/p>\n \nIn May 2026, the Environmental Protection Agency approved Woodside\u2019s application under section 43A of the Environmental Protection Act 1986 <\/i>(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.<\/p>\n \nWoodside is operator and holds a 100% participating interest.<\/p>\n NeoSmelt<\/b><\/p>\n \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<\/sup><\/p>\n\nDuring the reporting period, work on the pilot plant continued, with the design phase now approximately 90% complete.<\/p>\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.<\/p>\n \n\n| \n Carbon solutions<\/b><\/p>\n<\/td>\n<\/tr>\n<\/table>\n Carbon capture and storage (CCS)<\/b><\/p>\n \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<\/sup><\/p>\n\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.<\/p>\n \nThe Bonaparte CCS Assessment Joint Venture, operated by INPEX with TotalEnergies and Woodside continues to progress pre-FEED activities.<\/p>\n Carbon credits portfolio<\/b><\/p>\n \nDuring H1 2026, environmental planting activities under Woodside\u2019s 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.<\/p>\n | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |