{"success":true,"data":{"pressRelease":{"id":"126530","rtpr_id":"nBwbQ4794a","ticker":"WDS","exchange":"NYSE","all_tickers":["WDS"],"title":"Woodside Energy Half-Year Report for Period Ended 30 June 2026","author":"Business Wire","published_at":"2026-08-25T04:39:00.413Z","article_body":"Woodside Energy Half-Year Report for Period Ended 30 June 2026\n\nWoodside Energy Group (ASX: WDS) (NYSE: WDS):\n\nThis press release features multimedia. View the full release here:\nhttps://www.businesswire.com/news/home/20260824865396/en/\n(https://www.businesswire.com/news/home/20260824865396/en/)\n\nDisciplined execution\n\nOperational excellence and project delivery\n\n\n * Recorded operating revenue of $7,446 million, up 13% from H1 2025.\n\n * Delivered production of 478 Mboe/d (86.5 MMboe) and unit production costs of\n$8.8/boe.(1)\n\n * Progressed major projects with Scarborough 98%, Trion 64%, and Louisiana LNG\n28% complete.\n\n * Maintained high asset reliability, with operated LNG facilities achieving\n98.7% reliability, Sangomar 99.5%, and Shenzi 99.1%.\n\n * Safely executed the Pluto planned turnaround campaign on schedule and within\nbudget, including key integration activities supporting the Scarborough Energy\nProject, with more than 400,000 hours worked and zero lost-time injuries.\n\nDelivering value\n\n\n * Determined a fully franked interim dividend of 57 US cents per share (cps).\n\n * Achieved net profit after tax (NPAT) of $1,672 million (underlying NPAT $1,334\nmillion).(1)\n\n * Delivered EBITDA of $4,647 million from underlying base business.(1)\n\n * Delivered operating cash flow of $3,013 million and free cash flow of $352\nmillion.\n\n * Disciplined capital management resulted in strong liquidity of $8,189\nmillion.(1)\n\n * Gearing of 20.6%, marginally outside the target range of 10 - 20%, impacted by\n$655 million of new lease liabilities, a $419 million net cash outflow from\nhedge settlements, and a $101 million increase in trade receivables.(1)\n Comparative performance \n\n     H1 H1 Change   \n \n \n \n \n \n2026 \n2025 \n% \n Operating revenue $ million 7,446 6,590 13%   \n Underlying NPAT(1) $ million 1,334 1,247 7%   \n Free cash flow(1,2) $ million 352 136 159%   \n Average realised price(1,3) $/boe 74.0 61.7 20%     \n           2026 full-year guidance \n           Prior Current \n Total production volumes(45) MMboe 86.5 99.2 (13%) 172 - 186 174-185 \n Gas hub exposure(6) % 38.7% 24.2% 15% ~30 No change \n Capital expenditure(1,78) $ million 1,637 2,558 (36%) 4,000 - 4,500 No change \n Abandonment expenditure $ million 255 517 (51%) 500 - 800 No change \n Exploration expenditure(1) $ million 119 84 42% ~200 No change \n Production costs $ million 749 667 12% 1,500 - 1,800 No change \n Feed gas, services and processing costs $ million 238 92 159% 500 - 600 No change \n Property, plant and equipment depreciation and amortisation $ million 2,209 2,541 (13%) 4,200 - 4,700 No change \n\n\nThis page and the following 66 pages comprise the half-year information given\nto the ASX under Listing Rule 4.2A and should be read in conjunction with\nWoodside’s Annual Report 2025.\n Summary \n\n\nWoodside delivered strong half-year production of 478 thousand barrels oil\nequivalent per day (86.5 million barrels of oil equivalent total) and reported\na half-year net profit after tax (NPAT) of $1,672 million. Underlying NPAT was\n$1,334 million, compared to $1,247 million in the corresponding period in\n2025. Operating revenue rose 13% year-on-year to $7,446 million.\n\nDuring the half, the Middle East conflict disrupted the global supply of LNG\nand oil resulting in strengthening commodity prices and an increase in\ncustomer demand for products. Woodside’s Marketing and Trading division\ncontinued to optimise the portfolio to manage risk and maximise value while\nfulfilling customer commitments.\n\nThe directors have determined a fully franked interim dividend of 57 US cents\nper share (cps), representing an 80% payout ratio of underlying NPAT, and an\nannualised yield of 5.9%.(9)\n\nWoodside CEO Liz Westcott said the company delivered a resilient first half\nperformance, remaining a secure and reliable supplier to customers throughout\na period of global volatility.\n\n“We once again delivered strong production, cash flow and shareholder\nreturns, while continuing to execute the next phase of growth.\n\n“Keeping our people safe remains our highest priority. We recorded one high\nconsequence injury during the period while undertaking over 11 million work\nhours. This reinforces the need for ongoing focus on critical risk management,\nstrong safety leadership and disciplined execution of safe work practices\nacross our operations.\n\n“We maintained operational excellence at our assets. Operated LNG\nreliability was more than 98% and the planned turnaround at Pluto LNG was\ncompleted on budget and schedule, derisking the Scarborough Energy Project\nschedule in the process. We achieved exceptional performance at Sangomar,\nwhich produced at near nameplate capacity with 99.5% reliability.\n\n“The Scarborough Energy Project is now 98% complete and remains on track to\ndeliver first LNG cargo in the fourth quarter of 2026. During the half, we\ncompleted all upstream infrastructure, and subsequent to the period, achieved\nready for start-up and first gas at the floating production unit. Our focus\nremains on disciplined commissioning and start-up of all facilities to ensure\nsafe and reliable operations from day one.\n\n“The Trion Project offshore Mexico also made strong progress and is now 64%\ncomplete, targeting first oil in 2028. Key construction and drilling\nmilestones achieved in the first half included completion of the topsides lift\nonto the floating production unit and drilling of the first three of 24 subsea\nwells.\n\n“At Louisiana LNG, key milestones were achieved relating to the LNG tanks\nand marine infrastructure. The project’s foundation development was 28%\ncomplete at the end of the half, with first LNG targeted for 2029.\n\n“In July, Woodside assumed operatorship of the Gippsland Basin assets,\ncreating greater flexibility for future development opportunities while\nreinforcing our commitment to supporting energy security in the eastern\nAustralian domestic market.\n\n“We continued to deliver on our sustainability commitments during the half,\ntaking forward biodiversity initiatives in Western Australia and Louisiana,\nand enhancing methane emissions reporting across the Sangomar and North West\nShelf operations.\n\n“As we focus on Woodside’s next phase of disciplined delivery, we have\nannounced a series of actions to lift performance and sharpen our focus on\nvalue. We have set an annual cost savings target of $350 million from 2028 to\nbe delivered through the structured review of our business.”\n Financial summary \n\n Key metrics \n     H1 H1 Change \n     2026 2025 % \n Operating revenue $ million 7,446 6,590 13% \n EBITDA excluding impairment(10) $ million 4,647 4,600 1% \n EBIT(10) $ million 2,157 1,817 19% \n Net profit after tax (NPAT)(1112) $ million 1,672 1,316 27% \n Underlying NPAT(10) $ million 1,334 1,247 7% \n Net cash from operating activities $ million 3,013 3,339 (10%) \n Capital expenditure(10,13) $ million 1,637 2,558 (36%) \n Exploration expenditure(10,14) $ million 119 84 42% \n Free cash flow(10,15) $ million 352 136 159% \n Average realised price(10,18) US$/boe 74.0 61.7 20% \n Dividends distributed $ million 1,122 1,006 12% \n Interim dividend determined US cps 57 53 8% \n           \n Key ratios         \n Earnings per share US cps 88.2 69.4 27% \n Gearing(10) % 20.6 19.5 1% \n           \n Production volumes(16,17)         \n Gas MMboe 46.1 58.2 (21%) \n Liquids MMboe 39.4 41.0 (4%) \n Ammonia MMboe 1.0 - N/A \n Total MMboe 86.5 99.2 (13%) \n           \n Production volumes per day(17)         \n Gas MMscf/d 1,451 1,833 (21%) \n Liquids Mbbl/d 217 226 (4%) \n Ammonia kT/d 1.5 - N/A \n Total Mboe/d 478 548 (13%) \n           \n Sales volumes(17)         \n Gas(18) MMboe 58.5 63.9 (8%) \n Liquids MMboe 40.3 40.9 (1%) \n Ammonia MMboe 1.0 - N/A \n Total MMboe 99.8 104.8 (5%) \n           \n Sales volumes per day(17)         \n Gas(18) MMscf/d 1,843 2,012 (8%) \n Liquids Mbbl/d 223 226 (1%) \n Ammonia kT/d 1.4 - N/A \n   Mboe/d 551 579 (5%) \n\n Appendix 4D \n\n\nResults for announcement to the market\n\nMore information is available on page 48.\n         US$ million \n Revenue from ordinary activities Increased 13%(19) to 7,446 \n Profit from ordinary activities after tax attributable to members Increased 27%(19) to 1,672 \n Net profit for the period attributable to members Increased 27%(19) to 1,672 \n           \n Interim dividend - fully franked   57 US cps H1 2026   \n Record date for determining entitlements to the dividend   4 September 2026   \n\n Net profit after tax reconciliation \n\n\nThe following table summarises the variance between the H1 2025 and H1 2026\nresults for the contribution of each line item to NPAT.\n   US$m Primary reasons for variance \n 2025 H1 reported NPAT 1,316   \n Revenue from sale of products     \n Produced - price impact 755 Higher average realised prices. \n Produced - volume impact (307) Lower production due to cyclone impacts, Pluto planned turnaround and \n divestment of the Greater Angostura assets offset by first ammonia sales. \n Purchased - price and volume impact 440 Higher third-party LNG trading activity. \n Cost of sales (559) Higher third-party LNG trading activity, first ammonia production and Pluto \n planned turnaround. \n Perdaman embedded derivative (297) A non-cash unrealised loss of $135 million in H1 2026 compared to an \n unrealised gain of $162 million in H1 2025. \n Hedging (106) Pre-tax hedge losses of $64 million in H1 2026 compared to pre-tax hedge gains \n of $42 million in H1 2025. \n Restoration movement 450 Restoration provision updates primarily due to Stybarrow, Griffin and Minerva \n in 2025. \n Impairment losses (35) Pre-tax impairment for the Calypso Project offset by lower pre-tax impairment \n for the H2OK Project compared with H1 2025. \n Income tax and PRRT expense 62 Recognition of the Pluto PRRT and US income tax DTA in 2026 offset by higher \n taxable profits and recognition of the Louisiana LNG DTA in 2025. \n Other (47)   \n 2026 H1 reported NPAT 1,672   \n Underlying adjustments (338) Adjusted for the recognition of the Pluto PRRT and US income tax DTA benefits \n and the post-tax impairment of the Calypso and H2OK Projects. \n 2026 H1 underlying NPAT(20) 1,334   \n\n Capital management \n\n\nWoodside’s capital management framework provides us with the flexibility to\noptimise value and shareholder returns delivered from the portfolio of\nopportunities.\n\nInterim dividend and dividend reinvestment plan\n\nA 2026 fully franked interim dividend of 57 US cps has been determined,\nrepresenting an annualised dividend yield of 5.9% .(21) The total amount of\nthe interim dividend payment is $1,084 million which represents 80% of\nunderlying NPAT for the first half of 2026.(22)\n\nThe dividend reinvestment plan remains suspended.\n\nLiquidity and balance sheet\n\nIn H1 2026, Woodside generated $3,013 million of cash flow from operating\nactivities and delivered positive free cash flow of $352 million, which\nincludes the $1,725 million in capital contributions received from Stonepeak\nand Williams for the development of Louisiana LNG.(22,23)\n\nDuring this period, Woodside repaid a $600 million Syndicated Term Loan\napproximately 6 months prior to maturity.\n\nAt the end of the period, Woodside had cash and cash equivalents of $4,339\nmillion, liquidity of $8,189 million, and drawn debt of $11,450 million,\nincluding $800 million of ten-year bonds due in September 2026.(22)\n\nWoodside’s gearing as at 30 June 2026 was 20.6%, marginally outside the\ntarget range of 10 to 20%.(22 )Woodside’s gearing may at times fall outside\nthe target range as the balance sheet is managed through the investment cycle.\n\nNet debt and gearing were impacted by:\n\n\n * $655 million of lease liabilities recognised in the first half of 2026, for\nthe Woodside Bilangara LNG vessel and Trion construction related vessels.(24)\n\n * Net cash outflow of $419 million for hedge settlements.\n\n * Higher pricing driving a $101 million increase in trade receivables that were\nreceived in July 2026.\n\nWoodside’s commitment to an investment-grade credit rating remains unchanged\nand supports the aim of providing sustainable returns to shareholders, both\nnow from the strong existing business and in the future from the growth\nopportunities, in accordance with Woodside’s capital management framework.\n\nCommodity price risk management\n\nAs at 30 June 2026, approximately 62% of the 30 MMboe of 2026 oil-linked\nproduction previously hedged (at an average price of $74.23 per barrel) had\nbeen cash settled and 10 MMboe of 2027 oil-linked production was hedged at an\naverage price of $76.76 per barrel.\n\nCommodity swaps were used to continue managing risk associated with the Corpus\nChristi LNG volumes.\n\nFor the period ended 30 June 2026, pre-tax hedge losses of $64 million\nprimarily relating to Corpus Christi LNG hedges and foreign exchange hedges\nwere recognised, and hedge settlements resulted in a net cash outflow of $419\nmillion. The hedge settlement net cash outflow in H1 2026 is primarily due to\ntiming with oil-linked hedge losses cash settled ahead of the related revenue\nrecognition, and expected to be offset by higher revenue from Q2 price lag\nrealisation in H2 2026.\n\nEmbedded commodity derivative\n\nIn 2023, Woodside entered a revised long-term gas sale and purchase agreement\nwith Perdaman. A component of the selling price is linked to the price of\nurea, creating an embedded commodity derivative in the contract. The fair\nvalue of the embedded derivative is estimated using a Monte Carlo simulation\nmodel.\n\nAs there is no long-term urea forward curve, TTF continues to be used as a\nproxy to simulate the value of the derivative over the life of the contract.\nFor the half-year ended 30 June 2026, an unrealised loss of $135 million has\nbeen recognised through other expenses.\n Australian operations \n\n\nPluto LNG\n\nPluto LNG is a gas processing facility in the Pilbara region of Western\nAustralia, comprising an offshore platform and one onshore LNG processing\ntrain.\n\nWoodside’s share of production in H1 2026 was 20.6 MMboe. This was an 18%\ndecrease compared with 25.0 MMboe in H1 2025, primarily due to the impact of a\nplanned turnaround and Severe Tropical Cyclone Mitchell in the reporting\nperiod. H1 2026 production included 3.9 MMboe of Pluto gas processed at\nKarratha Gas Plant through the Interconnector.\n\nPluto LNG achieved reliability of 98.7% in H1 2026, reflecting the asset's\nstrong operating performance.\n\nIn H1 2026, drilling of the XNA-03 infill well was completed and preparations\ncontinue for start-up targeted for H2 2026.\n\nThe planned turnaround in May 2026 was successfully delivered safely, on\nschedule and within budget, including critical integration scopes supporting\nthe Scarborough Energy Project. The turnaround involved over 1,500 personnel\non site to deliver a safe lost time injury-free campaign with more than\n400,000 hours worked.\n\nWoodside is operator and holds a 90% participating interest.\n\nNorth West Shelf Project\n\nThe North West Shelf Project (NWS) consists of three offshore platforms and\nthe onshore Karratha Gas Plant (KGP) which includes four onshore LNG\nprocessing trains and two domestic gas trains.\n\nWoodside’s share of production in H1 2026 was 14.0 MMboe. This was a 7%\ndecrease compared with H1 2025 due to natural reservoir decline and impacts\nfrom Severe Tropical Cyclone Narelle.\n\nDespite these impacts, the NWS achieved LNG reliability of 98.7% in H1 2026,\nhighlighting the continued dependability and efficiency of the integrated\nfacilities.\n\nIn H1 2026, the NWS Joint Venture approved the drilling rig contract for the\nGreater Western Flank Phase 4 Project with drilling targeted to commence in\n2027, and targeting first production in 2028.\n\nPreparations are continuing for a planned turnaround for a single LNG Train\ntargeted to commence in September 2026.\n\nThe NWS is continuing with infrastructure retirement planning at KGP while\nmaintaining the capacity to provide processing services for third-party gas.\n\nDuring H1 2026, three legal proceedings continued in the Federal Court of\nAustralia, and one in the Western Australian Supreme Court, associated with\nthe NWS Project Extension Commonwealth and State environmental approvals.\nSubsequent to the period, hearings on the three Federal Court proceedings took\nplace in July 2026, and the Western Australian Supreme Court proceeding is\ncurrently scheduled in Q4 2026.\n\nWoodside is operator and holds a 33.33% participating interest.\n\nFollowing completion of the asset swap agreement with Chevron announced in\n2024, Woodside’s participating interest will increase to 50%. The asset swap\nremains targeted for completion in Q4 2026.(25)\n\nWheatstone and Julimar-Brunello\n\nWheatstone is an LNG processing facility near Onslow, Western Australia,\ncomprising an offshore production platform and two onshore LNG production\ntrains. It processes gas from several offshore gas fields, including Julimar\nand Brunello.\n\nWoodside’s share of Wheatstone production in H1 2026 was 4.4 MMboe. This was\na 30% decrease compared with H1 2025 due to the impacts of Severe Tropical\nCyclone Narelle.\n\nThe Julimar Phase 3 Project, a subsea tie-back to the existing Julimar field\nproduction system, completed its subsea construction and drilling campaign in\nH1 2026 and remains targeted for start-up in H2 2026.\n\nIn parallel, decommissioning of three Julimar–Brunello exploration wells\ncommenced in H1 2026. Completion of both activities are condition precedents\nto the Chevron asset swap.\n\nWoodside is operator and holds a 65% participating interest in the\nJulimar-Brunello fields.\n\nWoodside holds a 13% non-operating participating interest in the Wheatstone\nProject.\n\nFollowing completion of the asset swap agreement with Chevron announced in\n2024, Woodside will no longer have an interest in Wheatstone and\nJulimar-Brunello. The asset swap remains targeted for completion in Q4\n2026.(26)\n\nBass Strait\n\nBass Strait is located in the south east of Australia and produces gas through\na network of offshore platforms, pipelines and onshore processing facilities.\nThe Bass Strait assets include the Gippsland Basin Joint Venture (GBJV) and\nthe Kipper Unit Joint Venture (KUJV).\n\nWoodside’s share of production from Bass Strait was 8.4 MMboe in H1 2026, an\n8% decrease from H1 2025 predominantly due to reduced available capacity\nthrough scheduled maintenance programs and domestic gas demand.\n\nIn H1 2026, drilling of the five wells under the Turrum Phase 3 Project was\ncompleted. The Turrum Phase 3 Project is targeting delivery of gas to the\neastern Australian domestic gas market by H1 2027 from the Turrum and North\nTurrum fields with topsides modifications to the Marlin B platform.\n\nSubsequent to the period, on 1 July 2026, the transfer of operatorship of the\nBass Strait assets from ExxonMobil to Woodside occurred, following the\nsatisfaction of the conditions precedent to the transaction.(27)\n\nWoodside continues to progress technical maturation of four potential\ndevelopment wells that could deliver up to 200 PJ of sales gas to the market.\nTechnical maturity and the impact of the Federal Government’s new domestic\ngas reservation scheme will influence whether these opportunities are\nprogressed to a final investment decision. Subject to a final investment\ndecision, these would be developed solely by Woodside through the Bass Strait\ninfrastructure.\n\nWoodside became operator on 1 July 2026 and holds a 50% participating interest\nin the GBJV and a 32.5% participating interest in the KUJV.\n\nOther Australian oil and gas assets\n\nWoodside operates three floating production storage and offloading (FPSO)\nfacilities off the north west coast of Western Australia. These are the\nNgujima-Yin FPSO (Woodside participating interest: 60%), Pyrenees FPSO\n(Woodside participating interest: 40% in WA-43-L and 71.4% in WA-42-L) and\nOkha FPSO (Woodside participating interest: 50%).\n\nFollowing completion of the asset swap agreement with Chevron announced in\n2024, Woodside’s participating interest in the Okha FPSO will increase to\n66.67%. The asset swap remains targeted for completion in Q4 2026.(26)\n\nWoodside’s share of production from the FPSO assets was 2.2 MMboe in H1\n2026. This was a 39% decrease from H1 2025 primarily due to the planned\nshipyard maintenance and a subsea mooring system defect for the Okha FPSO and\nSevere Tropical Cyclone Narelle impacting in-field infrastructure at Pyrenees\nFPSO.\n\nWoodside also operates Macedon (Woodside participating interest: 71.4%), a gas\nproject located near Onslow, Western Australia which produces pipeline gas for\nthe Western Australian domestic gas market.\n\nWoodside’s share of production from Macedon was 4.0 MMboe, a 5% decrease\nfrom H1 2025 primarily reflecting natural field decline. The Macedon facility\ndelivered approximately 16% of the Western Australian domestic gas market\nsupply in H1 2026.\n\nWoodside Solar\n\nWoodside is progressing a potential opportunity to reduce gross Scope 1\ngreenhouse gas emissions at Pluto LNG by utilising solar energy from the\nproposed Woodside Solar Project.\n\nWoodside continued activities to progress the proposed Woodside Solar Project,\nincluding arrangements to secure access to new and existing common-user\ntransmission infrastructure required to transmit renewable energy to Pluto\nLNG. Development of this infrastructure is being led by the Western Australian\nGovernment and APA Group.\n International operations \n\n\nSangomar\n\nThe Sangomar Field Development Phase 1 is a deepwater project with a\nstand-alone FPSO facility moored approximately 100 km offshore Senegal.\n\nWoodside’s share of production was 15.0 MMboe in H1 2026, a 4% increase from\nH1 2025 due to continued strong reservoir performance, high reliability and\noptimisation of wells, flow lines and system hydraulics.\n\nIn H1 2026, Sangomar continued to deliver strong operational performance,\naveraging 99 Mbbl/d (100% basis, 83 Mbbl/d Woodside share) at 99.5% production\nreliability.(28) Reservoir performance continues to exceed expectations,\nparticularly in the S500 reservoirs. Greater-than-anticipated aquifer pressure\nsupport, combined with well and network optimisation has enabled an extended\ninitial production plateau and reduced the impact of reservoir decline.\nAlthough ongoing optimisation activities continue to moderate decline rates,\nproduction is expected to increasingly reflect the underlying reservoir\ndecline profile.\n\nH1 2026 sales of Sangomar crude oil were directed to Europe and South Asia\nduring the Middle East conflict, attracting strong premiums.\n\nEvaluation of future development opportunities is ongoing. A potential Phase 2\ndevelopment leveraging existing installed capacity would include wells\ntargeting the upper S400 reservoirs. Engagements are ongoing with Petrosen\n(18% participating interest) and the Senegalese Government for Phase 2.\n\nWoodside is operator and has an 82% participating interest.\n\nShenzi\n\nShenzi is a conventional offshore oil and gas field developed through a\ntension leg platform located offshore in the Gulf of America.\n\nWoodside’s share of production in H1 2026 was 4.1 MMboe at 99.1%\nreliability. This was a 12.8% decrease compared with H1 2025 due to natural\nfield decline and reduced pressure support from a major water injector.\n\nWoodside is operator and holds a 72% participating interest.\n\nAtlantis\n\nAtlantis is a conventional offshore oil and gas development in the Gulf of\nAmerica. It includes a semi-submersible facility and is one of the largest\nproducing fields in the United States.\n\nIn H1 2026, water injection commenced on a new well, and the Atlantis Major\nFacility Expansion Project progressed. Subsequent to the period, the Major\nFacility Expansion project achieved start-up. The project added subsea\ninfrastructure and upgraded water injection equipment.\n\nWoodside’s share of production in H1 2026 was 6.3 MMboe. This was a 5%\nincrease compared with H1 2025 due to high reliability and production from the\nDrill Center 1 Expansion which started production in H2 2025.\n\nWoodside holds a 44% non-operating participating interest.\n\nMad Dog\n\nMad Dog is an offshore conventional oil and gas field located in the Gulf of\nAmerica and is currently producing from two offshore facilities, A-Spar and\nArgos. The Argos facility was installed as part of the Mad Dog Phase 2\nProject, an ongoing development of the southern flank of the Mad Dog field.\n\nThe third and final Mad Dog Southwest Extension well was brought online in Q1\n2026, completing the project that began with production from the first\nproduction well in August 2025.\n\nWoodside’s share of production in H1 2026 was 5.8 MMboe. This was a 9%\nincrease compared with H1 2025 due to five new producing wells starting\nproduction over the last 12 months.\n\nWoodside holds a 23.9% non-operating participating interest.\n\nBeaumont New Ammonia\n\nBeaumont New Ammonia (BNA) is a 1.1 Mtpa ammonia synthesis plant located in\nBeaumont, Texas. First production of ammonia commenced in December 2025 and\nWoodside assumed operational control of BNA in March 2026 following successful\ncompletion of performance testing and handover from OCI Global.\n\nWoodside's production in H1 2026 was 279 kT with reliability of 87.6%\nincluding the start-up and commissioning period.(29) Production remained below\ncapacity due to feedstock constraints arising from construction delays at\nthird-party suppliers, with Q2 production averaging 69% of capacity. These\nconstraints are expected to continue into 2027. Lower-carbon ammonia\nproduction remains targeted for 2027, subject to commissioning of Linde’s\nlow-carbon hydrogen facilities and startup of ExxonMobil’s CCS\ninfrastructure, including approval of the relevant CCS permitting process.(30)\n\nWoodside is operator and holds a 100% participating interest.\n Marketing and Trading \n\n\nRevenue and trading\n\nRevenue increased 13% to $7,446 million in H1 2026, reflecting higher average\nrealised prices. Stronger commodity prices amid global supply disruptions,\ntogether with realisation of premiums increased the average realised price to\n$74.0/boe, up 20% compared with H1 2025.\n\nPortfolio optimisation activities captured higher value opportunities across\nmultiple trades, including redirecting Woodside cargoes to higher price\nmarkets, and using third-party purchases to meet long-term customer\ncommitments. The value from these activities are realised as cargoes are\ndelivered, resulting in fluctuations in earnings between reporting periods.\nFurther value from trading activities in H1 2026 is expected to be realised in\nH2 2026.\n\nThe marketing segment delivered EBIT of $54 million in H1 2026, representing\napproximately 3% of total EBIT.(31) Pre-tax hedge losses of $62 million were\nrecognised in the segment, primarily relating to Corpus Christi LNG hedges,\nreducing EBIT.\n\nIn H1 2026, approximately 39% of LNG sold was linked to gas hub indices\nimpacted by lower volumes available due to the Pluto planned turnaround.\n\nShipping\n\nWoodside has signed five long-term time charter parties for LNG vessels all\ncommencing in 2029, and added the Woodside Bilangara to Woodside’s fleet of\nLNG vessels during the period to support the start-up of the Scarborough\nEnergy Project, bringing Woodside’s total number of long-term chartered\nvessels on the water to nine.\n\nPipeline gas\n\nThroughout H1 2026, Western Australia domestic gas spot volume pricing held\nsteady at approximately A$5.50/GJ, not impacted by fluctuations in global\nmarkets.\n\nWoodside executed incremental pipeline gas sales agreements for 58.6 PJ to be\ndelivered to the Western Australian market from 2026 to 2029, including an\nagreement for the supply of 31.1 PJ with Alcoa.\n\nWoodside also executed incremental pipeline gas sales agreements for 47 PJ to\nbe delivered to the east coast of Australia across 2026, 2027 and 2028.\n\nOn the east coast of Australia, Woodside commenced an expression of interest\nfor 20 PJ of Bass Strait supply across 2027 and 2028 and is progressing in\nline with its obligations under its Ministerial Exemption to the Gas Market\nCode. Interest has been received from a wide variety of gas users including\npower generators, retailers and manufacturers with final offers expected in Q3\n2026.\n\nA total of 1,271 TJ of Trucked LNG, equivalent to approximately 1,200\ntrailers, was delivered in H1 2026 to customers in northern Western Australia.\nSince the commencement of operations at the Pluto LNG Truck Loading Facility\nin 2019, Woodside has delivered 6,892 trailers of LNG (7,100 TJ), offering a\nlower-carbon alternative to diesel.\n\nThe Australian Government has released a draft framework for its proposed\nDomestic Gas Reservation Scheme. Woodside is participating in the consultation\nprocess and will continue engaging with government and industry on the design\nof the scheme. It is important that the final arrangements support national\nenergy security, economic growth and ongoing investment in the new gas supply,\nhelping maintain Australia’s position as a reliable energy supplier to\ndomestic and international customers.\n Projects \n\n\nScarborough Energy Project\n\nThe Scarborough gas field is located in the Carnarvon Basin, approximately 375\nkm off the coast of Western Australia.\n\nThe development includes installation of a floating production unit (FPU) with\neight wells drilled in the initial phase and 13 wells drilled over the life of\nthe Scarborough field. Expansion of the Pluto LNG facility includes\nconstruction of a second LNG train (Pluto Train 2), installation of additional\ndomestic gas processing facilities and supporting infrastructure, and\nmodifications to Pluto Train 1 to allow it to process Scarborough gas.\n\nThe project includes the construction of an integrated remote operations\ncentre (IROC) at Woodside’s headquarters. The IROC will have the capacity to\noperate the FPU and the Pluto LNG facility from Perth.\n\nThe project was 98% complete at the end of H1 2026, excluding Pluto Train 1\nmodifications. First LNG cargo is on-track for Q4 2026.\n\nThe FPU achieved significant milestones throughout the first half of 2026. All\nupstream infrastructure is now in place, following completion of FPU mooring\nand hook up to the subsea production system. Subsequent to the period,\nupstream commissioning and preparations for the introduction of hydrocarbons\nwas completed, and the FPU achieved ready for start-up status and first gas.\n\nConstruction and commissioning activities at the Pluto Train 2 site continued,\nincluding completion of the gas turbine generator synchronisation with the\nPluto site power grid and mechanical runs of three of the six liquefaction\ncompressors.\n\nModifications which will allow processing of Scarborough gas through Pluto\nTrain 1 have been ongoing, including successful execution of tie-ins during\nthe Pluto Train 1 planned turnaround in the reporting period. The final module\nfor Pluto Train 1 modifications departed the fabrication yard in Thailand and\nsubsequent to the period, arrived at site. Civil, structural, piping and\nelectrical works continue.\n\nWoodside is operator and holds a 74.9% participating interest in Scarborough,\na 51% participating interest in Pluto Train 2 and a 90% participating interest\nin Pluto Train 1.\n\nTrion\n\nTrion is an offshore oil development located in Mexico, approximately 180 km\noff the Mexican coastline and 30 km south of the United States/Mexico maritime\nborder. The development includes a 24 subsea well development, a\nsemi-submersible FPU capable of producing and transferring 100,000 barrels of\noil per day, and a floating storage and offloading (FSO) facility.\n\nThe project was 64% complete at the end of H1 2026. First oil is targeted for\n2028.\n\nDrilling of 24 subsea wells commenced in March 2026 with three production\nwells drilled during the period.\n\nThe FPU achieved key H1 2026 milestones, including completion of topsides and\nliving quarters lifts onto the hull, and commencement of integration and\npre-commissioning. FSO construction with dry mega block assembly in dry dock\ncontinue to progress in accordance with plan. Fabrication and testing of the\ndisconnectable buoy of the FSO has been completed\n\nSubsea equipment fabrication, including drill centre and central manifolds,\nthree trees, static umbilicals, mooring systems and anchor piles, has been\ncompleted and delivered to Mexico ahead of installation commencing in Q3 2026.\nRemaining subsea production system components are progressing to plan and are\nin the final stages of fabrication.\n\nWoodside is the operator and holds a 60% participating interest.\n\nLouisiana LNG\n\nLouisiana LNG is a fully permitted, under-construction LNG production and\nexport terminal located near Lake Charles, Louisiana. The project is\nstructured as a scalable development with a total permitted capacity of 27.6\nMtpa across five LNG trains and supporting infrastructure.\n\nIn April 2025, Woodside approved an FID to develop the foundation phase of the\nproject, comprising three LNG trains with a capacity of 16.5 Mtpa.\n\nThe foundation development was 28% complete at the end of the period, with\nTrain 1 35% complete, Train 2 25% complete, and Train 3 18% complete. The\nproject is targeting first LNG in 2029.\n\nKey construction progressed during the period included structural steel\nerection and commencement of above-ground piping installation, advancement of\nLNG tanks, and marine infrastructure works, including commissioning of the\nmaterial offloading facility and commencement of dredging.\n\nBechtel sources structural steel for Louisiana LNG from its fabrication\nfacility in the United Arab Emirates. In response to ongoing supply chain\nrisks associated with disruptions in the Middle East, the project is\nproactively assessing and implementing mitigation measures, including\nalternative logistics routes and fabrication sources, to support continuity of\nsteel supply and maintain planned construction schedules beyond 2026.\n\nWoodside completed the transition of Driftwood Pipeline LLC operatorship to\nWilliams, with execution of the Line 200 lateral pipeline progressing under\nWilliams as operator, including advancing engineering, procurement, and right\nof way activities.\n\nWith foundational transportation and storage capacity secured in 2025,\nWoodside continued to advance feed gas procurement in line with its gas supply\nstrategy.\n\nOngoing engagement with high-quality counterparties for equity participation\nand LNG offtake continues to support progress on the Louisiana LNG sell-down\nprocess.\n\nWoodside is operator with a 90% interest in Louisiana LNG LLC. Louisiana LNG\nLLC owns a 60% interest in Louisiana LNG Infrastructure LLC and Woodside is\noperator. Woodside has a 20% non-operating interest in Driftwood Pipeline LLC.\n\nHydrogen Refueller @H2Perth\n\nThe Hydrogen Refueller @H2Perth is a self-contained hydrogen production,\nstorage and refuelling station located in Perth, Western Australia.(32)\n\nCommissioning activities continued on site and the facility has now been\nhanded over to Woodside from the contractor following successful leak testing\nand cold commissioning. Ready for start-up is now targeted for Q3 2026 and\nfirst hydrogen production is targeted for Q4 2026.\n\nWoodside is operator and holds a 100% participating interest.\n Decommissioning \n\n\nWoodside continued execution of planned decommissioning activities in H1 2026,\nspending approximately $274 million across its portfolio.\n\nIn H1 2026, well decommissioning activities continued across multiple assets,\nincluding commencing offshore plug and abandonment (P&A) operations for\neight subsea wells across the North West Shelf and Julimar-Brunello fields,\nwith P&A completed for two wells so far.\n\nOffshore execution has also progressed at the Stybarrow and Griffin fields in\nnorth-west Western Australia. At Stybarrow, more than 18 km of flexible\nflowlines and umbilicals were removed in H1 2026, while approximately 8 km of\nflexible flowlines have been removed from Griffin.\n\nFollowing the completion of planned infrastructure recovery from Enfield in\n2025, a final seabed survey was completed in H1 2026, with results planned to\nbe submitted to the regulator in H2 2026. Consultation with relevant persons\nfor the development of the Environment Plan to remove the remaining Minerva\ninfrastructure was also completed during H1 2026.\n\nAt Bass Strait, GBJV made strong progress on P&A activities during the\nperiod, completing plugging operations on the West Kingfish and Cobia platform\nwells and commencing platform rig operations on the Halibut and Tuna\nplatforms. This completed all P&A activities for platforms scheduled for\nremoval in Bass Strait Offshore Platform Removal Campaign 1, which is set to\ncommence in Q3 2027.\n\nPreparation for the campaign also advanced, with the National Offshore\nPetroleum Safety and Environmental Management Authority accepting the\nEnvironmental Plan and upgrades commencing at the onshore reception centre at\nBarry Beach Marine Terminal.\n Developments and Exploration \n\n\nBrowse\n\nThe Browse development comprises the Calliance, Brecknock and Torosa gas and\ncondensate fields located approximately 425 km north of Broome, Western\nAustralia.\n\nDuring H1 2026, work continued to advance regulatory approvals, advance\ntechnical definition and progress commercial arrangements for processing\nBrowse volumes through the Karratha Gas Plant. Contractors were engaged to\nprogress pre-FEED engineering scopes for the FPSO facilities. Invitations to\ntender for the design and construction of the Browse FPSO facilities were\nissued that will provide market pricing and schedule assumptions to inform a\nFEED entry decision. Engineering studies commenced to assess downstream\nmodifications required for processing Browse gas at Karratha Gas Plant with a\nthree-train development concept.\n\nThe gas processing agreement has been progressed, and will establish the\ncommercial framework and terms for processing Browse gas at the North West\nShelf Project’s Karratha Gas Plant.\n\nWoodside continued to engage with regulators as it progresses the primary\nenvironmental approvals for Browse. In June 2026, following a determination by\nthe Federal Environment Minister that the Browse CCS Project can be assessed\nwholly under the amended Environment Protection and Biodiversity Conservation\nAct 1999 (Cth), Woodside submitted a revised environmental referral to the\nCommonwealth regulator. The resubmission does not involve any significant\nchanges to the nature, scope or intent of the project.\n\nIn June 2026, Woodside exercised its pre-emption right to acquire CNPC's\n10.67% interest in the Browse Joint Venture (BJV). The terms of the\ntransaction include an amount payable on completion of $225 million plus\nreimbursement of CNPC's BJV cash call contributions from 30 June 2025 to\ncompletion. A contingent payment of $175 million is payable upon a final\ninvestment decision for the development of all of the Brecknock, Calliance and\nTorosa fields on or before 30 June 2032.(33)\n\nSubsequent to the period, the Browse to NWS Project was granted State\nSignificant Project status under the Lead Agency Framework by the Western\nAustralian State Government. State Significant Project status provides the\nhighest level of support, helping coordinate engagement on approvals and\nproject development.\n\nWoodside is operator and holds a 30.6% participating interest. Woodside’s\nequity interest in the BJV after completion of the acquisition of CNPC’s\ninterest will increase from 30.6% to 41.27%.\n\nSunrise\n\nThe Sunrise development comprises the Sunrise and Troubadour gas and\ncondensate fields, located approximately 450 km north-west of Darwin and 150\nkm south of Timor-Leste.\n\nThe Sunrise Joint Venture participants continued to engage with the\nGovernments of Timor-Leste and Australia to advance the fiscal and regulatory\nframeworks supporting the potential development of Sunrise.\n\nTechnical and commercial activities progressed under the Timor-Leste\nCooperation Agreement to support maturation of a potential Timor‑based LNG\nconcept.\n\nWoodside is operator and holds a 33.44% participating interest.\n\nCalypso\n\nCalypso is a discovered resource located approximately 220 km off the coast of\nTrinidad in 2,100m water depth.\n\nWoodside is operator and holds a 70% participating interest. Subsequent to the\nperiod, Woodside entered an agreement to divest its 70% operated interest in\nCalypso to joint venture participant bp.(34)\n\nLiard\n\nThe Liard field is an unconventional gas field located in British Columbia,\nCanada.\n\nWoodside holds a 50% non-operating participating interest.\n\nExploration\n\nWoodside’s exploration activities focused on maturing current opportunities,\nconsistent with its disciplined exploration strategy.\n\nIn the US, Woodside was awarded 10 blocks from Gulf of America Lease Sales Big\nBeautiful Gulf 1 and Big Beautiful Gulf 2. Woodside also participated in the\nBandit-1 well which reached total depth during H1 2026 and resulted in a\nMiocene discovery.(35) Post-well analysis continues in order to inform a\npotential appraisal decision. Woodside continued to actively manage its\nacreage position across the central and western Gulf of America.\n\nWoodside continued to pursue disciplined portfolio optimisation, including\nexiting blocks no longer considered prospective. In Australia, the expiry of\nexploration permit WA-28-P concluded 57 years of exploration activity on the\npermit. Woodside also allowed its Marine XX permit to expire offshore the\nRepublic of Congo following the completion of its permit terms.\n\nH2Perth\n\nThe H2Perth Project is a proposal to develop Australia’s first\ncommercial-scale liquid hydrogen production and export facility in Western\nAustralia, located in the Rockingham Industry Zone and Kwinana.\n\nIn May 2026, the Environmental Protection Agency approved Woodside’s\napplication under section 43A of the Environmental Protection Act 1986 (WA) to\namend the proposal for the Project from its previous concept of a liquified\nhydrogen and ammonia production facility to a liquefied hydrogen only\nfacility.\n\nWoodside is operator and holds a 100% participating interest.\n\nNeoSmelt\n\nThe NeoSmelt project aims to demonstrate a potential lower-emissions\nsteelmaking pathway for Pilbara iron ores, involving Direct Reduced Iron and\nElectric Smelting Furnace (DRI-ESF) technology.(36)\n\nDuring the reporting period, work on the pilot plant continued, with the\ndesign phase now approximately 90% complete.\n\nWoodside holds a 20% non-operating participating interest. The other\nparticipants in the project are BHP, BlueScope, Mitsui Iron Ore Development\nand Rio Tinto.\n Carbon solutions \n\n\nCarbon capture and storage (CCS)\n\nWoodside progressed proposed CCS opportunities in Australia and the\nAsia-Pacific, including the operated Angel CCS (Woodside participating\ninterest: 20%) and non-operated Bonaparte CCS opportunities (Woodside\nparticipating interest: 21%).(37)\n\nIn H1 2026, the proposed Angel CCS Project completed engineering studies as\npart of pre-FEED and commenced domestic and international engagement with\npotential customers for CCS services.\n\nThe Bonaparte CCS Assessment Joint Venture, operated by INPEX with\nTotalEnergies and Woodside continues to progress pre-FEED activities.\n\nCarbon credits portfolio\n\nDuring H1 2026, environmental planting activities under Woodside’s Native\nReforestation Project, including site preparation and seedling installation,\nwere carried out on Woodside-owned properties in Western Australia and New\nSouth Wales. Approximately 4,400 hectares are forecast to be planted in 2026\nand these activities were 25% complete at the end of H1 2026.\n Climate and Sustainability \n\n\nHealth, safety and wellbeing\n\nThere were zero fatalities recorded in H1 2026, and zero Tier 1 or Tier 2\nprocess safety events. One high-consequence injury was recorded during the\nperiod, across more than 11 million work hours. The year-to-date lost time\ninjury frequency rate was 0.17, compared with 0.26 for full-year 2025, and the\ntotal recordable injury rate was 2.09, compared to 1.64 recorded for full-year\n2025.\n\nSubsequent to the period, a sustainability focus session was held on 22 July\n2026 with investors on Woodside’s approach to process safety.\n\nIndigenous Peoples cultural heritage and engagement\n\nWoodside continued to engage with around 43 Traditional Owner representative\nbodies in Australia to discuss current and potential future activities. This\nincluded consultation on the Browse to North West Shelf Geophysical and\nGeotechnical Surveys and Minerva Field Decommissioning Environment Plans. In\naddition, archaeological and ethnographic surveys with some Traditional\nCustodians were also undertaken.\n\nSubsequent to the period, the Global Indigenous Peoples Strategy (2025-2030)\nwas launched and is now available on Woodside's website.\n\nSocial and economic impact\n\nWoodside published its 2025 Social Contribution Report in April 2026. The\nreport highlighted the positive impacts of Woodside’s A$39.8 million social\ncontribution in 2025, which was directed through strategic partnerships,\nphilanthropy initiatives, the value of time employees spent volunteering, and\npayments required by government regulations or contractual agreements with\nIndigenous Peoples.\n\nWoodside paid over A$1 billion in Australian taxes, royalties and levies to\nthe Federal and State governments in H1 2026. Additionally Woodside paid more\nthan US$450 million in international corporate taxes, royalties and production\nentitlements in H1 2026 (excludes Australia).\n\nEnvironment and biodiversity\n\nIn H1 2026, there were zero hydrocarbon or hazardous non-hydrocarbon spills\nthat resulted in a moderate environmental impact.(38)\n\nDuring the half, Woodside launched the Sam Houston Jones Restoration Project,\nsupporting restoration of threatened habitats and key wildlife species in\nLouisiana.\n\nIn H1 2026, the Watheroo Biodiversity Project in Western Australia was also\nformally launched, with the establishment of a long-term funding agreement\nwith Department of Biodiversity, Conservation and Attractions.\n\nClimate and the energy transition\n\nIn Q1 2026, Woodside published AASB S2 climate-related disclosures in the 2025\nAnnual Report.\n\nWoodside Sustainability Briefing 2026 was held on 16 March 2026, highlighting\nWoodside’s 2025 sustainability performance with regards to its 2025 material\ntopics.(39) This included content relevant to its 2025 material sustainability\ntopics.\n\nIn H1 2026, Woodside submitted its second annual Oil and Gas Methane\nPartnership 2.0 (OGMP2.0) implementation plan to the United Nations\nEnvironment Programme (UNEP), including first-time Level 5 reporting for\nLéopold Sédar Senghor FPSO and Karratha Gas Plant methane emissions. Level 5\nis OGMP 2.0’s highest data quality standard, requiring reconciliation of\ngranular source-level estimates with independent site-level measurements.\n Directors’ Report \n\n\nThe directors of Woodside Energy Group Ltd present their report (including the\nreview of operations of Woodside Energy Group Ltd and its controlled entities\n(Group) set out on pages 1 – 15 which forms part of this report) together\nwith the Half-Year Financial Statements of the Group.\n\nBoard of directors\n\nThe names of directors in office during or since the end of the 2026 half-year\nare as follows:\n Mr Richard Goyder, AO (Chair) Ms Liz Westcott (CEO and Managing Director) (40) \n Mr Larry Archibald Mr Ashok Belani \n Mr Arnaud Breuillac Ms Swee Chen Goh \n Mr Ben Wyatt, AO Ms Angela Minas \n Mr Mark Cutifani, CBE(41) Ms Ann Pickard \n Mr Ian Macfarlane (retired)(42) Mr Tony O’Neill (resigned)(43) \n\n\nRounding of amounts\n\nWoodside Energy Group Ltd is an entity to which the Australian Securities and\nInvestments Commission (ASIC) Corporations (Rounding in Financial/Directors’\nReports) Instrument 2026/183 (ASIC Instrument 2026/183) applies. Amounts in\nthis report have been rounded in accordance with ASIC Instrument 2026/183.\nThis means that amounts contained in this report have been rounded to the\nnearest million dollars, unless otherwise stated.\n\nAuditor’s Independence Declaration\n\nThe Auditor’s Independence Declaration, as required under section 307C of\nthe Corporations Act 2001, is set out on page 17 and forms part of this\nreport.\n\nSigned in accordance with a resolution of the directors.\n\nR J Goyder, AO\n\nChair\n\nMelbourne, Victoria\n\n25 August 2026\n Auditor’s Independence Declaration to the Directors of Woodside Energy Group \n Ltd \n\n\nAuditor’s Independence Declaration\n\nAs lead auditor of Woodside Energy Group Ltd's financial report for the\nhalf-year ended 30 June 2026, I declare that, to the best of my knowledge and\nbelief, there have been:\n\n\n 1. no contraventions of the auditor independence requirements of the Corporations\nAct 2001 in relation to the review of the financial report; and\n\n 2. no contraventions of any applicable code of professional conduct in relation\nto the review of the financial report.\n N M Henry   Perth, Western Australia \n \nPartner \n25 August 2026 \n \nPricewaterhouseCoopers \n     \n pwc.com.au   PricewaterhouseCoopers, ABN 52 780 433 757 \n \n \n \nBrookfield Place, Level 15, 125 St Georges Terrace, PERTH WA 6000, \n \n \n \nGPO Box D198, PERTH WA 6840 \n \n \n \nT: +61 8 9238 3000, F: +61 8 9238 3999, www.pwc.com.au \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.pwc.com.au&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.pwc.com.au&index=1&md5=887b31b74b98ff31b725a32425bd7c7f) \n \n \n \n  \n \n \n \nLiability limited by a scheme approved under Professional Standards \n Legislation. \n\n\nHALF-YEAR FINANCIAL STATEMENTS\n\nfor the half-year ended 30 June 2026\n\nCONTENTS\n CONDENSED CONSOLIDATED INCOME STATEMENT 20 \n CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME 21 \n CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION 22 \n CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS 23 \n CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY 24 \n NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 25 \n A. Earnings for the period 27 \n A.1 Segment revenue and expenses 27 \n A.2 Finance costs 28 \n A.3 Dividends paid and proposed 28 \n A.4 Earnings per share 28 \n A.5 Taxes 29 \n B. Production and growth assets 30 \n B.1 Exploration and evaluation assets 30 \n B.2 Property, plant and equipment 31 \n B.3 Impairment of exploration and evaluation assets, property, plant and 32 \n equipment and goodwill \n B.4 Intangible assets 33 \n B.5 Transactions with equity holders of the Group 34 \n C. Debt and capital 35 \n C.1 Interest-bearing liabilities and financing facilities 35 \n C.2 Contributed equity 36 \n D. Other assets and liabilities 37 \n D.1 Segment assets and liabilities 37 \n D.2 Provisions 38 \n D.3 Other financial assets and liabilities 39 \n E. Other items 41 \n E.1 Contingent liabilities and assets 41 \n E.2 New standards and interpretations 41 \n E.3 Events after the end of the reporting period 41 \n E.4 Subsidiaries 42 \n DIRECTORS’ DECLARATION 44 \n INDEPENDENT AUDITOR’S REVIEW REPORT 45 \n\n\nSignificant changes in the current reporting period\n\nThe financial performance and position of the Group were affected by the\nfollowing:\n\n\n * Geopolitical developments in the Middle East contributed to increased\nvolatility in oil and LNG prices and broader market uncertainty during the\nperiod. The full impact of higher LNG prices has not yet been realised due to\nlagged pricing mechanisms.\n\n * In July 2025, the Group completed the disposal of the Greater Angostura assets\nin Trinidad and Tobago to Perenco Energies International Limited (Perenco),\nwhich impacted revenue for the first half of 2026 relative to the comparative\nperiod, when the assets contributed $145m of revenue.\n\n * The Group recognised an additional $596 million in Pluto PRRT deferred tax\nassets and a $90 million income tax deferred tax asset relating to heritage\nWoodside US net operating loss carryforwards (Refer to Note A.5).\n\n * As at 30 June 2026, the Group recognised impairment losses of $178 million,\ncomprising $135 million on the Calypso exploration and evaluation asset\nfollowing the decision to divest its 70% operated interest in the Calypso\nProject, and $43 million on the H2OK Project following the decision to retire\nthe assets (Refer to Note B.3).\n\n * The Group recognised $138 million of other income from the release of deferred\nincome associated with the Pluto Train 2 Global Infrastructure Partners (Pluto\nTrain 2 GIP) transaction, reflecting updated expectations that potential\nconstruction cost overruns and liquidated damages will not crystallise.\n\n * The Group recognised approximately $655 million of new lease liabilities,\nprimarily relating to the three-year leases for the Trion drilling campaign\nand the Woodside Bilangara vessel.\n CONDENSED CONSOLIDATED INCOME STATEMENT \n \n \n \n  \n \n \n \nfor the half-year ended 30 June 2026 \n   \n     2026 2025 \n   Notes US$m US$m \n Operating revenue A.1 7,446 6,590 \n Cost of sales A.1 (4,604) (4,045) \n Gross profit   2,842 2,545 \n Other income A.1 264 379 \n Other expenses A.1 (771) (964) \n Impairment losses A.1 (178) (143) \n Profit before tax and net finance costs   2,157 1,817 \n Finance income   123 106 \n Finance costs A.2 (245) (169) \n Profit before tax   2,035 1,754 \n Petroleum resource rent tax (PRRT) benefit/(expense) A.5 305 (71) \n Income tax expense A.5 (667) (353) \n Profit after tax   1,673 1,330 \n Profit attributable to:       \n Equity holders of the parent   1,672 1,316 \n Non-controlling interest E.4 1 14 \n Profit for the period   1,673 1,330 \n Basic earnings per share attributable to equity holders of the parent (US A.4 88.2 69.4 \n cents) \n Diluted earnings per share attributable to equity holders of the parent (US A.4 87.3 68.8 \n cents) \n   \n The accompanying notes form part of the half-year financial statements. \n\n CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME \n \n \n \n  \n \n \n \nfor the half-year ended 30 June 2026 \n   \n   2026 2025 \n   US$m US$m \n Profit for the period 1,673 1,330 \n Other comprehensive (loss)/income     \n Items that may be reclassified to the income statement in subsequent periods:     \n (Losses)/gains on cash flow hedges (526) 289 \n Gains on cash flow hedges reclassified to the income statement (72) (16) \n Tax recognised within other comprehensive income 149 (57) \n Items that will not be reclassified to the income statement in subsequent     \n periods: \n Remeasurement gain on defined benefit plan 3 2 \n Net loss on financial instruments at fair value through other comprehensive — (33) \n income \n Other comprehensive (loss)/income for the period, net of tax (446) 185 \n Total comprehensive income for the period 1,227 1,515 \n Total comprehensive income attributable to:     \n Equity holders of the parent 1,226 1,501 \n Non-controlling interest 1 14 \n Total comprehensive income for the period 1,227 1,515 \n   \n The accompanying notes form part of the half-year financial statements. \n\n CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION \n \n \n \n  \n \n \n \nas at 30 June 2026 \n   \n     30 June 2026 31 December 2025 \n   Notes US$m US$m \n Current assets       \n Cash and cash equivalents   4,339 5,712 \n Receivables   1,928 1,751 \n Inventories   579 693 \n Other financial assets D.3 119 229 \n Tax receivable   184 114 \n Other assets   47 123 \n Total current assets   7,196 8,622 \n Non-current assets       \n Receivables   771 823 \n Inventories   371 288 \n Other financial assets D.3 109 64 \n Exploration and evaluation assets B.1 710 790 \n Property, plant and equipment B.2 47,797 46,555 \n Deferred tax assets   3,288 2,658 \n Lease assets   1,795 1,428 \n Investments accounted for using the equity method   272 260 \n Intangible assets B.4 4,856 4,853 \n Other assets   516 160 \n Total non-current assets   60,485 57,879 \n Total assets   67,681 66,501 \n Current liabilities       \n Payables   1,779 1,841 \n Interest-bearing liabilities C.1 983 782 \n Other financial liabilities D.3 148 8 \n Provisions D.2 1,238 1,212 \n Tax payable   500 539 \n Lease liabilities   303 159 \n Other liabilities   229 876 \n Total current liabilities   5,180 5,417 \n Non-current liabilities       \n Interest-bearing liabilities C.1 10,387 11,181 \n Deferred tax liabilities   1,273 1,182 \n Other financial liabilities D.3 363 212 \n Provisions D.2 6,397 6,655 \n Tax payable   10 10 \n Lease liabilities   1,995 1,600 \n Other liabilities   352 401 \n Total non-current liabilities   20,777 21,241 \n Total liabilities   25,957 26,658 \n Net assets   41,724 39,843 \n Equity       \n Issued and fully paid shares C.2 29,036 29,036 \n Shares reserved for employee share plans C.2 (72) (82) \n Other reserves   6,034 6,382 \n Retained earnings   1,053 578 \n Equity attributable to equity holders of the parent   36,051 35,914 \n Non-controlling interest E.4 5,673 3,929 \n Total equity   41,724 39,843 \n   \n The accompanying notes form part of the half-year financial statements. \n\n CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS \n \n \n \n  \n \n \n \nfor the half-year ended 30 June 2026 \n   \n     2026 2025 \n   Notes US$m US$m \n Cash flows from/(used in) operating activities       \n Profit after tax for the period   1,673 1,330 \n Adjustments for:       \n Non-cash items       \n Depreciation and amortisation   2,223 2,555 \n Depreciation of lease assets   89 85 \n Change in fair value of derivative financial instruments   176 (206) \n Net finance costs   122 63 \n Tax expense   362 424 \n Impairment losses B.3 178 143 \n Restoration movement   (5) 445 \n Other   (143) (99) \n Changes in assets and liabilities       \n (Increase)/decrease in trade and other receivables   (65) 122 \n Decrease/(increase) in inventories   31 (65) \n Decrease in provisions   (129) (112) \n (Decrease)/increase in other assets and liabilities   (363) 103 \n Decrease in trade and other payables   (62) (186) \n Cash generated from operations   4,087 4,602 \n Interest received   109 89 \n Borrowing costs relating to operating activities   (84) (5) \n Income tax and PRRT paid   (825) (782) \n Payments for restoration   (274) (565) \n Net cash from operating activities   3,013 3,339 \n Cash flows (used in)/from investing activities       \n Cash paid relating to business combination(1)   (470) — \n Payments for capital and exploration expenditure   (3,673) (4,881) \n Reimbursements received from external parties for capital expenditure   181 236 \n Borrowing costs relating to investing activities   (297) (330) \n Deposits received from disposal of non-current assets   — 21 \n (Contributions to)/dividends from associates   (27) 17 \n Net cash used in investing activities   (4,286) (4,937) \n Cash flows (used in)/from financing activities       \n Proceeds from borrowings C.1 — 4,849 \n Repayment of borrowings C.1 (602) (2,900) \n Purchases of shares relating to employee share plans   — (26) \n Repayment of the principal portion of lease liabilities   (111) (108) \n Borrowing costs relating to lease liabilities   (1) (1) \n Contributions from/to non-controlling interests(2)   1,737 1,843 \n Dividends paid   (1,122) (1,006) \n Net cash (used in)/from financing activities   (99) 2,651 \n Net (decrease)/increase in cash held   (1,372) 1,053 \n Less: Cash and cash equivalents classified within assets held for sale   — (108) \n Cash and cash equivalents at the beginning of the period   5,712 3,923 \n Effects of exchange rate changes   (1) 12 \n Cash and cash equivalents at the end of the period   4,339 4,880 \n 1. Relates to the final acquisition completion payment for Beaumont New Ammonia. \n \n2. Includes capital contribution of $1,668 million (2025: $1,870 million) from \n Stonepeak and $57 million (2025: nil) from Williams for the development of \n Louisiana LNG. Refer to Note B.5 for the transactions with equity holders of \n the Group. \n The accompanying notes form part of the half-year financial statements. \n\n CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY \n \n \n \n  \n \n \n \nfor the half-year ended 30 June 2026 \n   \n   Issued and fully paid shares Reserved shares Employee benefits reserve Non-controlling interest reserve Foreign currency translation reserve Hedging reserve Distributable profits reserve Other reserve Retained earnings Equity holders of the parent Non-controlling interest Total equity \n Notes C.2 C.2                 E.4   \n   US$m US$m US$m US$m US$m US$m US$m US$m US$m US$m US$m US$m \n At 1 January 2026 29,036 (82) 287 (373) 795 188 5,557 (72) 578 35,914 3,929 39,843 \n Profit for the period — — — — — — — — 1,672 1,672 1 1,673 \n Other comprehensive (loss)/income — — — — — (449) — — 3 (446) — (446) \n Total comprehensive (loss)/income for the period — — — — — (449) — — 1,675 1,226 1 1,227 \n Transfers — — — — — — 1,200 — (1,200) — — — \n Transactions with non-controlling interests(1) — — — (20) — — — — — (20) 1,754 1,734 \n Employee share plan redemptions — 10 (10) — — — — — — — — — \n Share-based payments (net of tax) — — 53 — — — — — — 53 — 53 \n Dividends paid — — — — — — (1,122) — — (1,122) (11) (1,133) \n At 30 June 2026 29,036 (72) 330 (393) 795 (261) 5,635 (72) 1,053 36,051 5,673 41,724 \n At 1 January 2025 29,001 (58) 281 — 795 1 3,069 (38) 2,348 35,399 754 36,153 \n Profit for the period — — — — — — — — 1,316 1,316 14 1,330 \n Other comprehensive income/(loss) — — — — — 216 — (33) 2 185 — 185 \n Total comprehensive income/(loss) for the period — — — — — 216 — (33) 1,318 1,501 14 1,515 \n Transfers — — — — — — 3,000 — (3,000) — — — \n Transactions with non-controlling interests(1) — — — (270) — — — — — (270) 2,140 1,870 \n Employee share plan purchases — (26) — — — — — — — (26) — (26) \n Employee share plan redemptions — 13 (13) — — — — — — — — — \n Share-based payments (net of tax) — — 41 — — — — — — 41 — 41 \n Dividends paid — — — — — — (1,006) — — (1,006) (40) (1,046) \n At 30 June 2025 29,001 (71) 309 (270) 795 217 5,063 (71) 666 35,639 2,868 38,507 \n 1. Represents the difference between the amount of the adjustment to \n non-controlling interest and any consideration received. Refer to Note B.5 for \n the transactions with equity holders of the Group. \n \n The accompanying notes form part of the half-year financial statements. \n\n\nNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS\n\nfor the half-year ended 30 June 2026\n\nAbout these statements\n\nWoodside Energy Group Ltd (Woodside or the Group) is a for-profit entity\nlimited by shares, incorporated and domiciled in Australia. Its shares are\npublicly traded on the Australian Securities Exchange (ASX) and on the New\nYork Stock Exchange (NYSE) (in the form of Woodside American Depositary\nShares). The nature of the operations and principal activities of the Group\nare described in the Australia Operations, International Operations, Marketing\nand Trading, Projects, Decommissioning, Developments and Exploration and\nCarbon Solutions sections.\n\nThe condensed consolidated half-year financial statements were authorised for\nissue in accordance with a resolution of the directors on 25 August 2026.\n\nStatement of compliance\n\nThe condensed consolidated half-year financial statements are condensed\ngeneral purpose financial statements, which have been prepared in accordance\nwith Australian Accounting Standard (AASB) 134 Interim Financial Reporting as\nissued by the Australian Accounting Standards Board and the Australian\nCorporations Act 2001. These condensed consolidated half-year financial\nstatements also comply with International Accounting Standard (IAS) 34 Interim\nFinancial Reporting as issued by the International Accounting Standards Board.\n\nThe condensed consolidated half-year financial statements do not include all\nnotes of the type normally included in annual financial statements.\nAccordingly, these condensed consolidated half-year financial statements are\nto be read in conjunction with the Financial Statements within the Annual\nReport for the year ended 31 December 2025 (2025 Financial Statements).\n\nThe Group’s accounting policies are materially consistent with those\ndisclosed in the Group’s 2025 Financial Statements. Adoption of new or\namended standards and interpretations effective 1 January 2026 did not result\nin any significant changes to the Group’s accounting policies. Refer to Note\nE.2 for more details.\n\nThe significant accounting estimates and judgements are consistent with those\ndisclosed in the 2025 Financial Statements. Estimates have been revised, where\nrequired, to reflect current market conditions including the impact of climate\nchange.\n\nCurrency\n\nThe functional and presentation currency of Woodside and all its material\nsubsidiaries is US dollars.\n\nTransactions in foreign currencies are initially recorded in the functional\ncurrency of the transacting entity at the exchange rates ruling at the date of\ntransaction. Monetary assets and liabilities denominated in foreign currencies\nat the reporting date are translated at the rates of exchange ruling at that\ndate. Exchange differences in the consolidated financial statements are taken\nto the condensed consolidated income statement.\n\nRounding of amounts\n\nThe amounts contained in the condensed consolidated half-year financial\nstatements have been rounded to the nearest million dollars under the option\navailable to the Group under Australian Securities and Investments Commission\n(ASIC) Corporations (Rounding in Financial/Directors’ Reports) Instrument\n2026/183 dated 24 March 2026, unless otherwise stated.\n\nBasis of preparation\n\nThe condensed consolidated half-year financial statements have been prepared\non an historical cost basis, except for derivative financial instruments and\ncertain other financial assets and financial liabilities, which have been\nmeasured at fair value adjusted for changes in fair value attributable to the\nrisks that are being hedged in effective hedge relationships. Where not\ncarried at fair value, if the carrying value of financial assets and financial\nliabilities does not approximate their fair value, the fair value has been\nincluded in the notes to the condensed consolidated half-year financial\nstatements.\n\nThe condensed consolidated half-year financial statements comprise the\nfinancial results of the Group for the period ended 30 June 2026. Subsidiaries\nare fully consolidated from the date on which control is obtained by the Group\nand cease to be consolidated from the date at which the Group ceases to have\ncontrol.\n\nThe material subsidiaries of the Group apply the same reporting period and\naccounting policies as the parent company in preparation of the condensed\nconsolidated half-year financial statements. All intercompany balances and\ntransactions, including unrealised profits and losses arising from intra-group\ntransactions, have been eliminated in full.\n\nNon-controlling interests are allocated their share of the net profit after\ntax in the condensed consolidated income statement; their share of other\ncomprehensive income, net of tax, in the condensed consolidated statement of\ncomprehensive income; and are presented within equity in the condensed\nconsolidated statement of financial position, separately from parent\nshareholders’ equity.\n\nComparative information\n\nThe condensed consolidated half-year financial statements provide comparative\ninformation in respect of the previous period. Where required, a\nreclassification of items in the financial statements of the previous period\nhas been made in accordance with the classification of items in the condensed\nconsolidated half-year financial statements of the current period. Refer to\nNote A.1 for more details.\n\nReporting segments\n\nRefer to the 2025 Financial Statements for details of the Group’s operating\nsegment information.\n\nA. Earnings for the period\n\nA.1 Segment revenue and expenses\n   Australia International Marketing Corporate Consolidated \n   2026 2025 2026 2025 2026 2025 2026 2025 2026 2025 \n   US$m US$m US$m US$m US$m US$m US$m US$m US$m US$m \n Liquified natural gas 2,189 2,417 — — 836 522 — — 3,025 2,939 \n Pipeline gas 565 564 20 141 — — — — 585 705 \n Crude oil and condensate 784 683 2,515 2,011 142 13 — — 3,441 2,707 \n Natural gas liquids 115 90 17 18 2 9 — — 134 117 \n Ammonia — — 171 — — — — — 171 — \n Revenue from sale of products 3,653 3,754 2,723 2,170 980 544 — — 7,356 6,468 \n Intersegment revenue(1) (101) (9) — — 101 9 — — — — \n Processing and services revenue 88 109 — — — — — — 88 109 \n Shipping and other revenue — — — — 2 13 — — 2 13 \n Other revenue (13) 100 — — 103 22 — — 90 122 \n Operating revenue(2) 3,640 3,854 2,723 2,170 1,083 566 — — 7,446 6,590 \n Production costs(3) (539) (399) (210) (268) — — — — (749) (667) \n Feed gas, services and processing costs(3) (92) (92) (146) — — — — — (238) (92) \n Royalties, excise and levies (134) (126) (9) (30) — — — — (143) (156) \n Insurance (16) (19) (11) (8) — — (6) (10) (33) (37) \n Inventory movement (77) (7) 23 6 — — — — (54) (1) \n Costs of production (858) (643) (353) (300) — — (6) (10) (1,217) (953) \n Property, plant and equipment depreciation (1,032) (1,170) (1,150) (1,340) — — (27) (31) (2,209) (2,541) \n Shipping and direct sales costs (70) (36) (53) (41) (54) (43) — — (177) (120) \n Trading costs (101) (88) — — (871) (322) — — (972) (410) \n Other hydrocarbon costs (10) (6) — — — — — — (10) (6) \n Other (14) (15) (5) — — — — — (19) (15) \n Other cost of sales (195) (145) (58) (41) (925) (365) — — (1,178) (551) \n Cost of sales (2,085) (1,958) (1,561) (1,681) (925) (365) (33) (41) (4,604) (4,045) \n Gross profit/(loss) 1,555 1,896 1,162 489 158 201 (33) (41) 2,842 2,545 \n Other income(4) 230 82 8 67 12 (9) 14 239 264 379 \n Exploration and evaluation expenditure (26) (10) (73) (71) — — — — (99) (81) \n Amortisation of permit acquisitions — — (4) (3) — — — — (4) (3) \n Write-offs — — (1) — — — — — (1) — \n Exploration and evaluation (26) (10) (78) (74) — — — — (104) (84) \n General, administration and other costs (28) (15) (46) (8) — (1) (168) (237) (242) (261) \n Amortisation of intangible assets — — (1) — — — (9) (11) (10) (11) \n Depreciation of lease assets (12) (18) (3) (1) (44) (39) (30) (27) (89) (85) \n Restoration movement 3 (443) 2 (2) — — — — 5 (445) \n Other(5) (58) (19) (26) (2) (72) (8) (175) (49) (331) (78) \n Other costs (95) (495) (74) (13) (116) (48) (382) (324) (667) (880) \n Other expenses (121) (505) (152) (87) (116) (48) (382) (324) (771) (964) \n Impairment losses(6) — — (135) — — — (43) (143) (178) (143) \n Profit/(loss) before tax and net finance costs 1,664 1,473 883 469 54 144 (444) (269) 2,157 1,817 \n 1. Intersegment revenue reflects the margin recognised on products and services \n transferred between segments. \n \n2. Operating revenue includes revenue from contracts with customers of $7,444 \n million (2025: $6,577 million) and sub-lease income of $2 million (2025: $13 \n million) disclosed within shipping and other revenue. \n \n3. In 2026, feed gas, services and processing-related costs are presented \n separately to better reflect underlying activities of the Group. In the 2025 \n Financial Statements, these costs were included within production costs. \n \n4. Includes $138 million of released deferred income associated with the Pluto \n Train 2 GIP transaction and other income not associated with the ongoing \n operations of the business. The 2025 amount includes a $162 million unrealised \n fair value gain on the Perdaman-related embedded derivatives, $32 million net \n gain on hedging activities, fees, recoveries and other income not associated \n with the ongoing operations of the business. \n \n5. Includes $135 million unrealised fair value loss on the Perdaman-related \n embedded derivatives, $71 million net loss on hedging activities and other \n items not associated with the ongoing operations of the business. \n \n6. Includes $135 million (2025: nil) relating to the impairment of the Calypso \n exploration and evaluation asset and $43 million (2025: $143 million) relating \n to the impairment of the H2OK Project. Refer to Note B.3 for details on \n impairment. \n\n\nA.2 Finance costs\n   2026 2025 \n   US$m US$m \n Interest on interest-bearing liabilities 303 281 \n Interest on lease liabilities 65 51 \n Accretion charge 156 148 \n Other finance costs 17 29 \n Less: Borrowing costs capitalised against qualifying assets (296) (340) \n Total finance costs 245 169 \n\n\nA.3 Dividends paid and proposed\n\nWoodside Energy Group Ltd, the parent entity, paid and proposed dividends as\nset out below:\n   2026 2025 \n   US$m US$m \n (a) Dividends paid during the financial year     \n Prior year fully franked final dividend US$0.59, paid on 27 March 2026 (2025: 1,122 1,006 \n US$0.53, paid on 2 April 2025) \n (b) Dividend determined subsequent to the reporting period (not recorded as a     \n liability) \n Current year fully franked interim dividend US$0.57 to be paid on 25 September 1,084 1,006 \n 2026 \n \n \n \n(2025: US$0.53 to be paid on 24 September 2025) \n\n\nA.4 Earnings per share\n   2026 2025 \n Profit attributable to equity holders of the parent (US$m) 1,672 1,316 \n Weighted average number of shares on issue for basic earnings per share 1,896,068,066 1,895,162,804 \n Effect of dilution from contingently issuable shares 19,457,286 17,049,593 \n Weighted average number of shares on issue adjusted for the effect of dilution 1,915,525,352 1,912,212,397 \n Basic earnings per share (US cents) 88.2 69.4 \n Diluted earnings per share (US cents) 87.3 68.8 \n Earnings per share is calculated by dividing the profit for the period \n attributable to ordinary equity holders of the parent by the weighted average \n number of shares on issue during the period. The weighted average number of \n shares makes allowance for shares reserved for employee share plans. Diluted \n earnings per share is calculated by adjusting basic earnings per share by the \n number of ordinary shares that would be issued on conversion of all the \n dilutive potential ordinary shares into ordinary shares. \n\n\nA.5 Taxes\n   2026 2025 \n   US$m US$m \n Reconciliation of income tax expense/(benefit)     \n Profit before tax 2,035 1,754 \n PRRT benefit/(expense) 305 (71) \n Profit before income tax 2,340 1,683 \n Income tax expense calculated at 30% 702 505 \n Effect of tax rate differentials 41 42 \n Effect of deferred tax assets not recognised 50 12 \n Effect of tax benefits previously unrecognised (90) (193) \n Foreign exchange impact on tax expense/(benefit) 28 (35) \n Adjustment to prior years (41) 4 \n Other (23) 18 \n Income tax expense 667 353 \n   \n The global operations effective income tax rate (EITR) of 28.5% (2025: 21.0%) \n is calculated as the Group’s income tax expense divided by profit before \n income tax. The underlying EITR is 29.6% when excluding the recognition of \n additional Pluto PRRT deferred tax asset, income tax deferred tax asset \n relating to US net operating losses and impairment losses. \n \n \n \n  \n \n \n \nDuring the period, the Group recognised an additional PRRT deferred tax asset \n of $596 million ($417 million post tax) for the Pluto project, reflecting \n increased expected utilisation of available PRRT deductions driven by the \n higher pricing environment. The Group also recognised a $90 million income tax \n deferred tax asset in respect of heritage Woodside US net operating loss \n carryforwards, as utilisation of those losses is now considered probable. \n\n\nB. Production and growth assets\n\nB.1 Exploration and evaluation assets\n   Asia Pacific Americas Africa Total \n   US$m US$m US$m US$m \n Half-year ended 30 June 2026         \n Carrying amount at 1 January 2026 582 207 1 790 \n Additions 18 47 — 65 \n Amortisation of licence acquisition costs — (4) — (4) \n Expensed — (1) — (1) \n Impairment(1) — (135) — (135) \n Transferred exploration and evaluation (5) — — (5) \n Carrying amount at 30 June 2026 595 114 1 710 \n           \n Year ended 31 December 2025         \n Carrying amount at 1 January 2025 571 149 1 721 \n Additions 17 67 — 84 \n Amortisation of licence acquisition costs — (5) — (5) \n Expensed — (4) — (4) \n Transferred exploration and evaluation (6) — — (6) \n Carrying amount at 31 December 2025 582 207 1 790 \n 1. Refer to Note B.3 for details of impairment of the Calypso exploration and \n evaluation asset. \n\n\nB.2 Property, plant and equipment\n   Land and buildings Oil and gas properties Projects in development(1) Other plant and equipment Total \n   US$m US$m US$m US$m US$m \n Half-year ended 30 June 2026           \n Carrying amount at 1 January 2026 744 23,091 22,437 283 46,555 \n Additions(2) — 9 3,492 — 3,501 \n Disposals at written down value — — (12) — (12) \n Impairment loss(3) — — (43) — (43) \n Completions and transfers(4) 136 398 (2,010) 1,481 5 \n Depreciation (32) (2,135) — (42) (2,209) \n Carrying amount at 30 June 2026 848 21,363 23,864 1,722 47,797 \n At 30 June 2026           \n Historical cost 2,035 59,227 24,389 2,201 87,852 \n Accumulated depreciation and impairment (1,187) (37,864) (525) (479) (40,055) \n Carrying amount 848 21,363 23,864 1,722 47,797 \n Year ended 31 December 2025           \n Carrying amount at 1 January 2025 734 25,787 15,926 189 42,636 \n Adjustment to purchase price allocation (21) — (9) — (30) \n Additions — 657 8,658 10 9,325 \n Disposals at written down value (6) (44) (143) (3) (196) \n Impairment loss — — (143) — (143) \n Completions and transfers 98 1,609 (1,852) 151 6 \n Depreciation (61) (4,918) — (64) (5,043) \n Carrying amount at 31 December 2025 744 23,091 22,437 283 46,555 \n At 31 December 2025           \n Historical cost 1,899 58,820 22,919 720 84,358 \n Accumulated depreciation and impairment (1,155) (35,729) (482) (437) (37,803) \n Carrying amount 744 23,091 22,437 283 46,555 \n 1. Projects in development include the fair value ascribed to future phases of \n certain projects acquired through business combinations. \n \n2. Includes $3,243 million of capital additions, $296 million of capitalised \n borrowing costs, and $26 million relating to changes in restoration provision \n assumptions. Included within capital additions is $1,595 million relating to \n the Louisiana LNG Project. \n \n3. Refer to Note B.3 for details of impairment of the H2OK Project. \n \n4. Primarily reflects the transfer of the Beaumont New Ammonia (BNA) Project \n carrying amount from projects in development to other plant and equipment \n following completion in March 2026.  \n \n \n   \n The Group has capital commitments contracted for, but not provided for in the \n financial statements, of $9,699 million (31 December 2025: $11,957 million). \n Capital commitments relate predominantly to the Louisiana LNG and Trion \n Projects (31 December 2025: Louisiana LNG, Trion and Scarborough Energy \n Projects). Capital commitments for Louisiana LNG totalling $8,170 million (31 \n December 2025: $9,986 million) are shared between the Group, Stonepeak and \n Williams based on their respective interests in the project. Under the \n transaction arrangements, Stonepeak has committed up to $5,700 million to fund \n its share of the capital expenditure associated with the foundation \n development of Louisiana LNG. Refer to Note B.5 for details of the sell-down \n arrangement with Stonepeak and the contributions made by Stonepeak to date. \n\n\nB.3 Impairment of exploration and evaluation assets, property, plant and\nequipment and goodwill\n\nImpairment of Calypso exploration and evaluation asset\n\nAs at 30 June 2026, the Calypso exploration and evaluation asset was assessed\nas not fully recoverable following the Group's decision to pursue a divestment\nof its 70% operated interest in the Calypso Project. Consequently, an\nimpairment loss of $135 million (2025: nil) was recognised in the\nInternational segment of Note A.1 for the half-year ended 30 June 2026. Refer\nto Note E.3 for details of the subsequent agreement to sell the Group's\ninterest in the Calypso Project.\n\nImpairment of H2OK Project\n\nAs at 30 June 2026, the remaining H2OK Project assets were assessed as not\nrecoverable following the decision to retire the assets. Consequently, an\nimpairment loss before tax of $43 million (2025: $143 million) was recognised\nin the Corporate segment of Note A.1 for the half-year ended 30 June 2026\nreducing the carrying value of the assets to nil.\n\nB.4 Intangible assets\n   Goodwill Contract assets Software Total \n   US$m US$m US$m US$m \n Half-year ended 30 June 2026         \n Carrying amount at 1 January 2026 3,952 714 187 4,853 \n Additions – – 18 18 \n Amortisation – (2) (8) (10) \n Disposals – (5) – (5) \n Carrying amount at 30 June 2026 3,952 707 197 4,856 \n At 30 June 2026         \n Cost 4,429 796 238 5,463 \n Accumulated amortisation and impairment (477) (89) (41) (607) \n Carrying amount 3,952 707 197 4,856 \n Year ended 31 December 2025         \n Carrying amount at 1 January 2025 3,866 757 203 4,826 \n Adjustment to purchase price allocation 86 30 – 116 \n Additions – – 2 2 \n Amortisation – (73) (18) (91) \n Carrying amount at 31 December 2025 3,952 714 187 4,853 \n At 31 December 2025         \n Cost 4,429 814 220 5,463 \n Accumulated amortisation and impairment (477) (100) (33) (610) \n Carrying amount 3,952 714 187 4,853 \n   \n\n\nB.5 Transactions with equity holders of the Group\n\nSell-down arrangement with Stonepeak\n\nDuring 2025, the Group and Stonepeak entered into an agreement for Stonepeak\nto acquire a 40% interest in Louisiana LNG Infrastructure LLC, a subsidiary\nwithin the Group. Stonepeak will provide up to $5,700 million towards the\nexpected capital expenditure for the foundation development of Louisiana LNG\non an accelerated basis, contributing 75% of the expected project capital\nexpenditure in both 2025 and 2026. As at 30 June 2026, total payment of $4,262\nmillion was received.\n\nUnder the agreement, the Group still controls Louisiana LNG Infrastructure\nLLC, while Stonepeak now holds a non-controlling interest. Transactions that\ndo not result in the Group's loss of control are treated as equity\ntransactions. When ownership percentages change, the carrying amounts of both\ncontrolling and non-controlling interests are adjusted based on their relative\ninterest in the subsidiary. Any difference between the adjustment to\nnon-controlling interests and consideration received is recorded in a separate\nequity reserve. Stonepeak’s non-controlling interest percentage is based on\nthe proportion of total contributions to date and will fluctuate during the\nconstruction phase. The non-controlling interest percentage will to revert to\n40% when the project starts generating revenue. Refer to Note E.4\nSubsidiaries.\n\nC. Debt and capital\n\nC.1 Interest-bearing liabilities and financing facilities\n   Bilateral facilities Syndicated facilities JBIC facility US bonds Medium term notes Total \n   US$m US$m US$m US$m US$m US$m \n Half-year ended 30 June 2026             \n At 1 January 2026 (4) 2,232 1,000 8,535 200 11,963 \n Repayments(1) — (600) — — — (600) \n Transaction costs capitalised and amortised (1) 2 — 6 — 7 \n Carrying amount at 30 June 2026 (5) 1,634 1,000 8,541 200 11,370 \n Current (2) (4) — 789 200 983 \n Non-current (3) 1,638 1,000 7,752 — 10,387 \n Carrying amount at 30 June 2026 (5) 1,634 1,000 8,541 200 11,370 \n Undrawn balance at 30 June 2026 2,650 1,200 — — — 3,850 \n Year ended 31 December 2025             \n At 1 January 2025 495 2,233 1,000 6,069 200 9,997 \n Drawdowns 1,400 — — 3,500 — 4,900 \n Repayments (1,900) — — (1,000) — (2,900) \n Transaction costs capitalised and amortised 1 (1) — (34) — (34) \n Carrying amount at 31 December 2025 (4) 2,232 1,000 8,535 200 11,963 \n Current (2) (5) — 789 — 782 \n Non-current (2) 2,237 1,000 7,746 200 11,181 \n Carrying amount at 31 December 2025 (4) 2,232 1,000 8,535 200 11,963 \n Undrawn balance at 31 December 2025 2,350 1,200 — — — 3,550 \n 1. In June 2026, the Group settled the $600 million syndicated facility that was \n executed on 17 January 2020. \n\n\nThere were no new covenants or other material changes to interest-bearing\nliabilities and financing facilities.\n\nFair value\n\nThe carrying amounts of interest-bearing liabilities approximate their fair\nvalues, with the exception of the Group’s unsecured bonds and the\nmedium-term notes. The unsecured bonds have a carrying amount of $8,541\nmillion (31 December 2025: $8,535 million) and a fair value of $8,636 million\n(31 December 2025: $8,665 million). The medium-term notes have a carrying\namount of $200 million (31 December 2025: $200 million) and a fair value of\n$198 million (31 December 2025: $197 million). Fair value is determined by\nreference to quoted market prices for these instruments and is classified as\nLevel 1 within the fair value hierarchy.\n\nC.2 Contributed equity\n\nIssued and fully paid shares\n   Number of shares US$m \n Half-year ended 30 June 2026     \n Opening balance 1,901,100,143 29,036 \n Amounts as at 30 June 2026 1,901,100,143 29,036 \n Year ended 31 December 2025     \n Opening balance 1,898,749,771 29,001 \n Shares issued 2,350,372 35 \n Amounts as at 31 December 2025 1,901,100,143 29,036 \n\n\nAll shares are a single class with equal rights to dividends, capital\ndistributions and voting. The Company does not have authorised capital nor par\nvalue in respect of its issued shares.\n\nReserved shares\n\nReserved shares are the Company’s own equity instruments, which are used in\nemployee share-based payment arrangements or the Dividend Reinvestment Plan\n(DRP). The DRP was suspended on 27 February 2023. These shares are deducted\nfrom equity.\n   Number of shares US$m \n Half-year ended 30 June 2026     \n Opening balance 5,283,450 (82) \n Vested/allocated during the half-year (644,610) 10 \n Amounts as at 30 June 2026 4,638,840 (72) \n Year ended 31 December 2025     \n Opening balance 3,080,842 (58) \n Purchases during the year 5,700,372 (88) \n Vested/allocated during the year (3,497,764) 64 \n Amounts as at 31 December 2025 5,283,450 (82) \n\n\nD. Other assets and liabilities\n\nD.1 Segment assets and liabilities\n   30 June 2026 31 December 2025 \n   US$m US$m \n (a) Segment assets     \n Australia 30,569 30,541 \n International 26,885 24,773 \n Marketing 1,094 965 \n Corporate 9,133 10,222 \n   67,681 66,501 \n       \n   30 June 2026 31 December 2025 \n   US$m US$m \n (b) Segment liabilities     \n Australia 6,899 7,252 \n International 2,856 2,531 \n Marketing 1,297 1,054 \n Corporate 14,905 15,821 \n   25,957 26,658 \n Corporate assets mainly comprise cash and cash equivalents, deferred tax \n assets, new energy assets in development and lease assets. Corporate \n liabilities mainly comprise interest-bearing liabilities, deferred tax \n liabilities and lease liabilities. \n\n\nD.2 Provisions\n   Restoration(1) Employee benefits Other Total \n   US$m US$m US$m US$m \n Half-year ended 30 June 2026         \n At 1 January 2026 6,886 669 312 7,867 \n Change in provision (229) (86) (73) (388) \n Unwinding of present value discount 156 — — 156 \n Carrying amount at 30 June 2026 6,813 583 239 7,635 \n At 30 June 2026         \n Current 765 373 100 1,238 \n Non-current 6,048 210 139 6,397 \n Carrying amount 6,813 583 239 7,635 \n Year ended 31 December 2025         \n At 1 January 2025 6,526 654 367 7,547 \n Adjustment to purchase price allocation — — 100 100 \n Change in provision 254 11 (138) 127 \n Unwinding of present value discount 283 5 — 288 \n Disposals (177) (1) (17) (195) \n Carrying amount at 31 December 2025 6,886 669 312 7,867 \n At 31 December 2025         \n Current 637 449 126 1,212 \n Non-current 6,249 220 186 6,655 \n Carrying amount 6,886 669 312 7,867 \n 1. 2026 change in provision is due to provisions used of $255 million, a revision \n of discount rates of $90 million offset by changes in foreign exchange rates \n of $92 million and changes in estimates of $24 million. 2025 change in \n provision is due to changes in estimates of $898 million, changes in foreign \n exchange rates of $233 million offset by provisions used of $823 million and a \n revision of discount rates of $54 million. \n\n\nD.3 Other financial assets and liabilities\n   30 June 2026 31 December 2025 \n   US$m US$m \n Other financial assets     \n Financial instruments at fair value through profit and loss     \n Derivative financial instruments designated as hedges 152 217 \n Other financial assets 18 14 \n Financial instruments at fair value through other comprehensive income     \n Other financial assets 58 62 \n Total other financial assets 228 293 \n Current 119 229 \n Non-current 109 64 \n Net carrying amount 228 293 \n Other financial liabilities     \n Financial instruments at fair value through profit and loss     \n Derivative financial instruments designated as hedges 130 7 \n Embedded derivative 347 212 \n Other financial liabilities 34 1 \n Total other financial liabilities 511 220 \n Current 148 8 \n Non-current 363 212 \n Net carrying amount 511 220 \n\n\nHedging activities\n\nAs at 30 June 2026, the Group had the following principal unrealised commodity\nhedging positions:\n\n\n * 36 MMboe of oil production volumes hedged at an average price of $75 per\nbarrel through to 2027.\n\n * Corpus Christi LNG volumes hedged through Henry Hub (HH) and Title Transfer\nFacility (TTF) commodity swap contracts.\n\nThe following table presents the Group’s derivative financial instruments\ndesignated as hedges, measured and recognised at fair value:\n   30 June 2026 31 December 2025 \n   US$m US$m \n Brent commodity swaps (cash flow hedges) 103 114 \n HH natural gas commodity swaps (cash flow hedges) (26) (4) \n TTF LNG commodity swaps (cash flow hedges) (63) 66 \n Interest rate swaps (cash flow hedges) (1) — 15 \n Foreign exchange forwards (cash flow hedges) 8 19 \n Total derivative financial instruments asset designated as hedges 22 210 \n 1. During June 2026, the Group early settled the $600 million syndicated \n facility, being the underlying hedged item. Accordingly, the associated \n hedging instrument ceased to be designated as a hedge. Refer to Note C.1. \n\n\nEmbedded commodity derivative\n\nIn 2023, the Group entered into a revised long-term gas sale and purchase\ncontract (GSPA) with Perdaman, where a component of the selling price is\nlinked to the price of urea. The contract was assessed to contain an embedded\ncommodity derivative that is required to be separated and recognised at fair\nvalue through profit and loss. The carrying value of the embedded derivative\nat 30 June 2026 amounted to a net liability of $347 million (31 December 2025:\nnet liability of $212 million). The derivative is remeasured to fair value at\neach reporting date. For the half-year ended 30 June 2026, an unrealised loss\nof $135 million has been recognised through other expense (30 June 2025:\nunrealised gain of $162 million through other income).\n\nD.3 Other financial assets and liabilities (continued)\n\nFair value\n\nExcept for the other financial assets and other financial liabilities set out\nin this note, there are no other material financial assets or financial\nliabilities carried at fair value. Other financial assets and other financial\nliabilities set out in this note are classified as Level 2 on the fair value\nhierarchy with market observable inputs, with the exception of the embedded\ncommodity derivative which has been classified as Level 3 on the fair value\nhierarchy with no market observable inputs. Refer to key estimates and\njudgements for further details. During the period, there were no\nreclassifications between the fair value hierarchy levels.\n\nThere were no changes to the Group’s valuation processes, valuation\ntechniques and types of inputs used in the fair value measurements during the\nperiod.\n\nFinancial risk factors\n\nThe Group’s activities expose its financial instruments to a variety of\nmarket risks, including foreign exchange, commodity price and interest rate\nrisk. The half-year financial statements does not include all financial risk\nmanagement information and disclosures required in the Annual Report and, as\nsuch, should be read in conjunction with the Group’s 2025 Financial\nStatements. There have been no significant changes in risk management policies\nsince 31 December 2025. Refer to the embedded commodity derivative key\nestimates and judgements section below for the sensitivity assessment on\ndiscount rates and pricing.\n\nKey estimates and judgements\n\n(a) Embedded commodity derivative\n\nThe fair value of the Perdaman embedded derivative has been estimated using a\nMonte Carlo simulation model. The assessment requires management to make\ncertain assumptions about the model inputs, including forecast cash flows,\ndiscount rate, credit risk and volatility. These assumptions require\nsignificant judgement and are subject to risk and uncertainty, and hence\nchanges in economic conditions can affect the assumptions. The present value\nof the embedded derivative was estimated using the assumptions set out below.\n\n\n * Inflation rate – 2.50%.\n\n * Discount rate – a pre-tax interest rate curve (range: 5.04% to 8.07%).\n\n * Domestic gas pricing – forecast sales are subject to urea pricing. Price\nassumptions are based on the best market information available at measurement\ndate and derived from short- and long-term views of global supply and demand,\nbuilding upon past experience of the industry and consistent with external\nsources. The long-term urea price is determined with reference to the\nprevailing gas hub (TTF) prices available in the market.\n\nThe embedded derivative is most sensitive to changes in discount rates and\npricing, which may result in unrealised gains or losses recognised in other\nincome/expenses. The nominal impacts of the effects of changes to discount\nrate and long-term price assumptions are estimated as follows. The valuation\nis over a contract period of 20 years and the below change in assumptions\napplies a linear increase or decrease in inputs over the life of the contract.\nA spot increase is not represented by the sensitivity below.\n   Change in assumption(1) US$m   \n   TTF sales price: increase of 10% 179   \n   TTF sales price: decrease of 10% (177)   \n   Discount rate: increase of 1.5%(2) (182)   \n   Discount rate: decrease of 1.5%(2) 223   \n   1. Amounts shown represent the change of the present value of the contract   \n keeping all other variables constant. \n \n2. A change of 1.5% represents 150 basis points. \n\n\nE. Other items\n\nE.1 Contingent liabilities and assets\n   2026 2025 \n Contingent liabilities at reporting date US$m US$m \n Contingent liabilities 340 322 \n Total disclosed contingent liabilities 340 322 \n\n\nContingent liabilities relate predominantly to possible obligations whose\nexistence will only be confirmed by the occurrence or non-occurrence of\nuncertain future events, and therefore the Group has not provided for such\namounts in these financial statements. The Group operates in complex tax and\nlegislative regimes. The amounts disclosed above include estimates made in\nrelation to ongoing disputes with various tax and government authorities.\nAssessing the value of contingent liabilities requires a high degree of\njudgement. The contingent liabilities relating to tax matters are estimated\nbased on notices received from authorities before interest and penalties. The\npossibility of further claims related to the same matters cannot be ruled out\nand the judicial processes may take extended periods to conclude.\nAdditionally, there are a number of other claims and possible claims that have\narisen in the course of business against entities in the Group, the outcome of\nwhich cannot be estimated at present and for which no amounts have been\nincluded in the table above.\n\nThe Group has contingent assets of $31 million as at 30 June 2026 (31 December\n2025: $30 million).\n\nE.2 New standards and interpretations\n\nNew and amended accounting standards adopted\n\nA number of amended standards became applicable for the current reporting\nperiod, including the amendments to AASB/IFRS 7 and AASB/IFRS 9 disclosed in\nFinancial Statements within the Annual Report for the year ended 31 December\n2025. The Group did not make any significant changes to its accounting\npolicies and did not make retrospective adjustments as a result of adopting\nthese amended standards. These amendments did not materially impact the\naccounting policies or amounts disclosed in the condensed consolidated\nhalf-year financial statements of the Group.\n\nNew standards and interpretations not yet adopted\n\nCertain new accounting standards, amendments to accounting standards and\ninterpretations have been published that are not mandatory for the 30 June\n2026 reporting period and have not been early adopted by the Group. Except for\nAASB 18/IFRS 18 Presentation and Disclosure in Financial Statements, these\npronouncements are not expected to have a material impact on the Group’s\nconsolidated financial statements in the current or future reporting periods.\nAASB/IFRS 18 will replace AASB 101/IAS 1 Presentation of Financial Statements,\nintroducing new requirements that will help to achieve comparability of the\nfinancial performance of similar entities and provide more relevant\ninformation and transparency to users. Even though AASB/IFRS 18 will not\nimpact the recognition or measurement of items in the financial statements,\nits impacts on presentation and disclosure are expected to be pervasive,\nparticularly those related to the consolidated income statement and providing\nmanagement-defined performance measures within the financial statements.\nManagement is currently assessing the detailed implications of applying the\nnew standard on the Group’s financial statements. The Group will apply the\nnew standard from its mandatory effective date of 1 January 2027.\nRetrospective application is required.\n\nE.3 Events after the end of the reporting period\n\nOperatorship of Bass Strait assets\n\nOn 29 July 2025, the Group agreed with ExxonMobil Australia (ExxonMobil) to\nassume operatorship of the Bass Strait production assets, the Longford Gas\nPlant, the Long Island Point gas liquids processing facility and associated\npipeline infrastructure. The Group’s and ExxonMobil’s equity interest in\nthe Joint Venture’s assets and current decommissioning plans and provisions\nremain unchanged. The transaction was completed and effective on 1 July 2026,\nsubsequent to the report date.\n\nAs part of the transaction, Woodside acquired ExxonMobil’s employing entity\nfor the Bass Strait employees which includes employee-related assets and\nliabilities for the consideration of $1. The employee expenses will continue\nto be funded by the Bass Strait joint venture partners based on their equity\ninterests. The acquisition of the employing entity will to be treated as a\nbusiness combination and will be accounted for in the 2026 Annual Report.\n\nE.3 Events after the end of the reporting period (continued)\n\nBrowse Joint Venture pre-emption right\n\nOn 12 June 2026, the Group exercised its pre-emption right to acquire a 10.67%\nparticipating interest in the Browse Joint Venture. The acquisition\nconsideration comprises a payment of $225 million, reimbursement of certain\njoint venture cash call contributions and a contingent payment of $175 million\nsubject to specified future conditions. The transaction is subject to\ncustomary conditions precedent, including regulatory approvals, and had not\ncompleted at the reporting date. Upon completion, the Group's participating\ninterest in the Browse Joint Venture will increase to 41.27%.\n\nCalypso divestment\n\nSubsequent to the reporting date, the Group entered into an agreement to sell\nits 70% operated interest in the Calypso Project to bp. Completion of the\ntransaction is subject to customary conditions precedent, including government\nand regulatory approvals, and is expected to occur by the end of 2026. The\ntransaction comprises fixed and contingent consideration. As disclosed in Note\nB.3, an impairment loss of $135 million was recognised as at 30 June 2026\nfollowing the Group's decision to divest its interest in the Calypso Project.\n\nE.4 Subsidiaries\n\nSubsidiaries with non-controlling interests\n\nThe Group has two Australian subsidiaries and two International subsidiaries\nwith non-controlling interests (NCI).\n Name of entity Principal place of business % held by NCI NCI parties \n Burrup Facilities Company Pty Ltd Australia 10.00% Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd \n Burrup Train 1 Pty Ltd Australia 10.00% Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd \n Louisiana LNG Infrastructure LLC(1) United States 62.87% Stonepeak \n Louisiana LNG LLC United States 10.00% Williams \n 1. The non-controlling interest in Louisiana LNG Infrastructure LLC is \n measured at its proportionate share of the subsidiary’s net assets. The \n proportion of net assets each member is entitled to upon liquidation varies \n prior to operations commencement. Prior to this milestone, entitlements are \n determined in proportion to the cumulative capital contributions made by each \n member. The NCI percentage is expected to revert to 40% when the project \n commences operations. \n\n\nE.4 Subsidiaries (continued)\n\nThe summarised financial information (including consolidation adjustments but\nbefore intercompany eliminations) of subsidiaries with NCI is as follows:\n   Burrup Facilities Company Pty Ltd Burrup Train 1 Pty Ltd Louisiana LNG Infrastructure LLC Louisiana LNG LLC Total \n   US$m US$m US$m US$m US$m \n Half-year ended 30 June 2026           \n Current assets 379 314 678 339 1,710 \n Non-current assets 4,694 2,551 7,315 2,738 17,298 \n Current liabilities (45) (36) (448) (251) (780) \n Non-current liabilities (542) (299) (84) (31) (956) \n Net assets 4,486 2,530 7,461 2,795 17,272 \n Accumulated balance of NCI 449 253 4,691 280 5,673 \n (Loss)/Profit (21) 19 3 (5) (4) \n (Loss)/Profit allocated to NCI (2) 2 2 (1) 1 \n Dividends paid to NCI (1) (10) — — (11) \n Year ended 31 December 2025           \n Current assets 288 225 260 118 891 \n Non-current assets 4,810 2,729 5,402 2,331 15,272 \n Current liabilities (38) (39) (318) (143) (538) \n Non-current liabilities (544) (306) (86) (37) (973) \n Net assets 4,516 2,609 5,258 2,269 14,652 \n Accumulated balance of NCI 452 261 2,989 227 3,929 \n Profit/(Loss) 76 117 — (2) 191 \n Profit allocated to NCI 8 11 — — 19 \n Dividends paid to NCI (36) (24) — — (60) \n\n\nDIRECTORS’ DECLARATION\n\nfor the half-year ended 30 June 2026\n\nIn accordance with a resolution of directors of Woodside Energy Group Ltd, we\nstate that:\n\nIn the opinion of the directors:\n a)   the financial statements and notes of the Group are in accordance with the Australian Corporations Act 2001, including: \n     i.   giving a true and fair view of the Group’s financial position as at 30 June \n 2026 and of its performance for the half-year ended on that date; and \n     ii.   complying with Australian Accounting Standard AASB 134 and International \n Accounting Standard IAS 34 Interim Financial Reporting and the Corporations \n Regulations 2001; \n b)   there are reasonable grounds to believe that Woodside Energy Group Ltd will be able to pay its debts as and when they become due and payable. \n\n\nOn behalf of the Board\n\nR J Goyder, AO\n\nChair of the Board\n\nMelbourne, Victoria\n\n25 August 2026\n\nE M Westcott\n\nChief Executive Officer and Managing Director\n\nSydney, New South Wales\n\n25 August 2026\n\nINDEPENDENT AUDITOR’S REVIEW REPORT\n\nIndependent auditor's review report to the members of Woodside Energy Group\nLtd\n\nReport on the half-year financial report\n\nConclusion\n\nWe have reviewed the half-year financial report of Woodside Energy Group Ltd\n(the Company) and the entities it controlled during the half-year (together\nthe Group), which comprises the condensed consolidated statement of financial\nposition as at 30 June 2026, the condensed consolidated income statement,\ncondensed consolidated statement of comprehensive income, condensed\nconsolidated statement of changes in equity and condensed consolidated\nstatement of cash flows for the half-year ended on that date, selected\nexplanatory notes and the directors’ declaration.\n\nBased on our review, which is not an audit, we have not become aware of any\nmatter that makes us believe that the accompanying half-year financial report\nof Woodside Energy Group Ltd does not comply with the Corporations Act 2001\nincluding:\n\n\n 1. giving a true and fair view of the Group’s financial position as at 30 June\n2026 and of its performance for the half-year ended on that date; and\n\n 2. complying with Accounting Standard AASB 134 Interim Financial Reporting and\nthe Corporations Regulations 2001.\n\nBasis for conclusion\n\nWe conducted our review in accordance with ASRE 2410 Review of a Financial\nReport Performed by the Independent Auditor of the Entity (ASRE 2410). Our\nresponsibilities are further described in the Auditor’s responsibilities for\nthe review of the half-year financial report section of our report.\n\nWe are independent of the Group in accordance with the auditor independence\nrequirements of the Corporations Act 2001 and the ethical requirements of the\nAccounting Professional & Ethical Standards Board’s APES 110 Code of\nEthics for Professional Accountants (including Independence Standards) (the\nCode) that are relevant to the audit of the annual financial report in\nAustralia. We have also fulfilled our other ethical responsibilities in\naccordance with the Code.\n pwc.com.au PricewaterhouseCoopers, ABN 52 780 433 757 \n \n \n \nBrookfield Place, Level 15, 125 St Georges Terrace, PERTH WA 6000, \n \n \n \nGPO Box D198, PERTH WA 6840 \n \n \n \nT: +61 8 9238 3000, F: +61 8 9238 3999, www.pwc.com.au \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.pwc.com.au&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.pwc.com.au&index=2&md5=18a568a9b89674de676e0dbca05b0c44) \n \n \n \n  \n \n \n \nLiability limited by a scheme approved under Professional Standards \n Legislation. \n\n\nResponsibilities of the directors for the half-year financial report\n\nThe directors of the Company are responsible for the preparation of the\nhalf-year financial report, in accordance with Australian Accounting Standards\nand the Corporations Act 2001, including giving a true and fair view, and for\nsuch internal control as the directors determine is necessary to enable the\npreparation of the half-year financial report that is free from material\nmisstatement whether due to fraud or error.\n\nAuditor's responsibilities for the review of the half-year financial report\n\nOur responsibility is to express a conclusion on the half-year financial\nreport based on our review. ASRE 2410 requires us to conclude whether we have\nbecome aware of any matter that makes us believe that the half-year financial\nreport is not in accordance with the Corporations Act 2001 including giving a\ntrue and fair view of the Group’s financial position as at 30 June 2026 and\nof its performance for the half-year ended on that date, and complying with\nAccounting Standard AASB 134 Interim Financial Reporting and the Corporations\nRegulations 2001.\n\nA review of a half-year financial report consists of making enquiries,\nprimarily of persons responsible for financial and accounting matters, and\napplying analytical and other review procedures. A review is substantially\nless in scope than an audit conducted in accordance with Australian Auditing\nStandards and consequently does not enable us to obtain assurance that we\nwould become aware of all significant matters that might be identified in an\naudit. Accordingly, we do not express an audit opinion.\n\nPricewaterhouseCoopers\n N M Henry   Perth, Western Australia \n \nPartner \n25 August 2026 \n\n Appendix 4D \n\n\nDividends\n Ex-dividend date 3 September 2026     \n Record date for the interim dividend 4 September 2026     \n         \n Date the dividend is payable 25 September 2026     \n     Current period Previous corresponding period(44) \n Interim dividend - fully franked US cents per share 57 53 \n None of these dividends are foreign sourced.     \n\n\nWoodside dividends are determined in US dollars. However, shareholders will\nreceive their dividend in Australian dollars unless their registered address\nis in the United Kingdom (in which case they will receive their dividend in\nBritish pounds), in the United States of America (in which case they will\nreceive their dividend in US dollars) or in New Zealand (in which case they\nwill receive their dividend in NZ dollars).\n\nShareholders who reside outside of the United States can elect to receive\ntheir dividend electronically in US dollars, payable into a US financial\ninstitution account. Shareholders who reside outside of the United States, the\nUnited Kingdom, New Zealand and Australia may elect to receive their dividend\nelectronically in their local currency using Global Wire Payment Service from\nthe Company's share registry, Computershare Investor Services Pty Ltd.\n\nShareholders should contact the Company's share registry if they wish to alter\ntheir dividend currency for future dividend payments. Contact details are\navailable on Woodside's website on the Shareholder Information section of the\nInvestors page. Shareholders must make an election to alter their dividend\ncurrency on or before 5.00pm AWST on 7 September 2026.\n\nNet Tangible Assets per ordinary security\n   Current period Previous corresponding period(44) \n   US$ US$ \n Net Tangible Assets (US$ per ordinary security)(45) 16.41 16.19 \n\n\nDetails of Associates and Joint Venture Entities\n   Percentage of ownership interest held at end of period or date of disposal   \n   \n Name of Entity Current period Previous corresponding period(44)   \n North West Shelf Gas Pty Ltd 33.33% 33.33%   \n North West Shelf Liaison Company Pty Ltd —% 33.33%   \n China Administration Company Pty Ltd 33.33% 33.33%   \n International Gas Transportation Company Limited —% 33.33%   \n North West Shelf Shipping Service Company Pty Ltd —% 33.33%   \n North West Shelf Lifting Coordinator Pty Ltd 33.33% 33.33%   \n Blue Ocean Seismic Services Limited 16.17% 16.17%   \n Oakbio Inc 25.32% 25.32%   \n Iwilei District Participating Parties, LLC 14.96% 14.96%   \n Caesar Oil Pipeline Company, LLC 25.00% 25.00%   \n Cleopatra Gas Gathering Company LLC 22.00% 22.00%   \n Marine Well Containment Company LLC 12.92% 12.05%   \n Driftwood Pipeline, LLC 20.00% —%   \n\n Shareholder information \n\n\nKey announcements 2026\n January Fourth quarter 2025 report \n February Woodside Releases Annual Reserves Statement \n Woodside Releases Full-Year 2025 Results \n Full-Year 2025 Results Briefing Transcript \n Annual Report 2025 [and US Annual Report 2025 (Form 20-F)] \n March Sustainability Briefing 2026 \n Liz Westcott Appointed Woodside CEO \n Appointment of Director to Woodside Board \n Woodside assumes control of Beaumont New Ammonia operations \n April 2026 Annual General Meeting voting results \n First quarter 2026 report \n June Woodside exercises Browse pre-emption right \n July Second quarter 2026 report \n August Half-Year 2026 results \n\n\nEvents calendar 2026-2027\n\nKey calendar dates for Woodside shareholders in 2026-2027. Please note dates\nare subject to review.\n August 25 Half-Year 2026 results \n September 3 Ex-dividend date for interim dividend (Australian Securities Exchange) \n 4 Ex-dividend date for interim dividend (New York Stock Exchange) \n 4 Record date for interim dividend \n 25 Payment date for interim dividend \n October 21 Third quarter 2026 report \n November 5 2026 Capital Markets Day (Australia) \n 12 2026 Capital Markets Day (United States) \n December 31 Year-end 2026 \n January 28 Fourth quarter 2026 report \n February 23 2026 Annual Report \n\n\nBusiness directory\n Registered office: Postal address: \n Woodside Energy Group Ltd GPO Box D188 \n Mia Yellagonga Perth WA 6840 \n 11 Mount Street Australia \n Perth WA 6000   \n Australia T: +61 8 9348 4000 \n\n\nInvestor enquiries\n\nInvestors seeking information on the company should contact Investor Relations\nat:\n Postal address:     \n Investor Relations T: ‘+61 8 9348 4000 \n GPO Box D188 E: investor@woodside.com (mailto:investor@woodside.com) \n Perth WA 6840 W: woodside.com \n Australia     \n\n\nShare registry enquiries\n\nInvestors seeking information about their shareholding should contact the\ncompany’s share registry:\n Registered office: Postal address: \n Computershare Investor Services Pty Limited GPO Box D182 \n Level 17 Perth WA 6840 \n 221 St Georges Terrace   \n Perth WA 6000 T: 1300 558 507 (within Australia) \n     ‘+61 3 9415 4632 (outside Australia) \n   E: web.queries@computershare.com.au (mailto:web.queries@computershare.com.au) \n   W: investorcentre.com/wds \n\n\nThe share registry can assist with queries on share transfers, dividend\npayments, the dividend reinvestment plan, notification of tax file numbers and\nchanges of name, address or bank account details.\n\nDetails of shareholdings can be checked by visiting the share registry website\nat www.investorcentre.com/wds\n(https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.investorcentre.com%2Fwds&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.investorcentre.com%2Fwds&index=3&md5=ed88d10be1b8401de7555647332d6ce4)\n.\n\nDetails of the authorised depositary bank for Woodside’s American Depositary\nReceipt programme can be found on the website.\n Assets \n\n\nProducing facilities\n\nAustralia\n Asset Role Equity Product \n Pluto LNG Operator 90 % LNG, pipeline gas and condensate \n North West Shelf(1) Operator 33.33 % LNG, pipeline gas, condensate and NGLs \n Wheatstone(1) Non-operator 13 % LNG, pipeline gas and condensate \n Julimar-Brunello Operator 65 % \n Okha FPSO(1) Operator 50 % Crude oil \n Ngujima-Yin FPSO Operator 60 % Crude oil \n Bass Strait Operator(2) 32.5—50% Pipeline gas, condensate and NGLs \n Pyrenees FPSO Operator 40—71.4% Crude oil \n Macedon Operator 71.4 % Pipeline gas \n 1. In December 2024, Woodside entered into an asset swap with Chevron, refer to \n “Woodside simplifies portfolio and unlocks long-term value” announced 19 \n December 2024 for details. \n \n2. Subsequent to the period, Woodside assumed operatorship of the Bass Strait \n assets. Refer to “Woodside completes Gippsland Basin operatorship \n transition” announced on 1 July 2026. \n\n\nInternational\n Asset Role Equity Product \n Sangomar Operator 82 % Crude oil \n Greater Shenzi Operator 72 % Crude oil, pipeline gas, condensate and NGLs \n Atlantis Non-operator 44 % Crude oil, pipeline gas, condensate and NGLs \n Mad Dog Non-operator 23.9 % Crude oil, pipeline gas, condensate and NGLs \n Beaumont New Ammonia Operator 100 % Ammonia \n   \n\n\nProjects\n\nPost FID\n Asset Role Equity Product \n Scarborough Operator 74.9% LNG and pipeline gas \n Pluto Train 2 Operator 51.0% LNG and pipeline gas \n Trion Operator 60.0% Crude oil \n Louisiana LNG LLC Operator 90.0% LNG \n Louisiana LNG Infrastructure LLC Operator 60.0% LNG \n Hydrogen Refueller@H2Perth Operator 100% Hydrogen \n\n\nDevelopments\n Asset Role Equity Product \n Calypso Operator 70% Gas \n Browse Operator 30.60%(1) LNG, pipeline gas and condensate \n Greater Scarborough(2) Operator 100% Gas \n Liard Non-operator 50% Gas \n Sunrise Operator 33.44% LNG, pipeline gas and condensate \n 1. In June 2026, Woodside pre-empted the sale of CNPC’s stake in Browse. Refer \n to “Woodside exercises Browse pre-emption right” announced 12 June 2026 \n for details. \n \n2. “Greater Scarborough” includes the Jupiter and Thebe fields. \n\n\nNew energy opportunities(1)\n Asset Role Equity Product \n H2Perth Operator 100% Hydrogen \n NeoSmelt Non-operator 20% Iron \n Woodside Solar(2) Proponent 100% Solar energy \n 1. Subject to a final investment decision and regulatory approvals. Excludes \n acquisitions subsequent to the period. \n \n2. Solar generation, battery services and transmission access and services will \n be supplied to Woodside under contracts with third parties. \n \n \n   \n\n\nGreenhouse gas assessment permits\n Country Permit Role Joint venture Comment \n Australia G-7-AP Non-operator Bonaparte CCS Assessment Joint Venture Located in the Bonaparte Basin off the north-west coast of the Northern \n Territory \n G-8-AP Operator Browse Joint Venture For carbon capture and storage evaluation for Browse \n G-10-AP Operator Angel CCS Joint Venture(1) Located in the Northern Carnarvon basin off the north-west coast of Western \n Australia \n G-18-AP Non-operator Greenhouse Gas Assessment Permit G-18-AP Joint Venture Located in the Northern Carnarvon Basin off the north-west coast of Western \n Australia \n G-19-AP Operator(2) Gippsland Basin Joint Venture Located in the Gippsland Basin off the coast of Victoria \n 1. In December 2024, Woodside entered into an asset swap with Chevron, refer to \n “Woodside simplifies portfolio and unlocks long-term value” announced 19 \n December 2024 for details. \n \n2. Subsequent to the period, Woodside assumed operatorship of the Bass Strait \n assets. Refer to “Woodside completes Gippsland Basin operatorship \n transition” announced on 1 July 2026. \n \n \n   \n\n\nExploration\n Country Permit Role Equity Product \n Asia - Pacific         \n Australia WA-404-P Operator 100% Gas prone basin \n WA-550-P Operator 100% Gas prone basin \n WA-554-P Operator 100% Gas prone basin \n Europe         \n Ireland FEL 5/13 Operator 100% - Exit initiated Oil or gas prone basin \n Africa         \n Egypt Tiba Block Non-operator 40% Oil and gas prone basin \n North EI Dabaa Offshore (Block 4) Non-operator 27% Oil or gas prone basin \n Caribbean         \n Barbados Bimshire   60% - Exit initiated Oil or gas prone basin \n North America         \n United States EB 550, EB 594, EB 636, EB 637, EB 638, GB 721, GB 780, GB 821, GB 824, GB Operator 100% Oil prone basin \n 825, GB 866, KC 259, KC 297, KC 301, KC 343, KC 431, KC 859, KC 903, KC 904, \n KC 905, KC 948, KC 949, WR 577, WR 751, WR 795, WR 796 \n WR 443, WR 444, WR 488 Operator 80% Oil prone basin \n GC 124 Operator 75% Oil prone basin \n EB 699, AC 36, AC 80 Operator 70% Oil prone basin \n GC 282, GC 237 Non-operator 50% Oil prone basin \n AC 125, AC 126, AC 81 Operator 45% Oil prone basin \n GC 598 Non-operator 40% Oil prone basin \n AT 453 Non-operator 30% Oil prone basin \n GC 870 Non-operator 24% Oil prone basin \n GC 680, GC 723, GC 724, GC 679, GC 768 Non-operator 18% Oil prone basin \n\n Alternative Performance Measures \n\n\nWoodside uses various alternative performance measures (APM) which are\nnon-IFRS measures that are unaudited but derived from the Half-Year Financial\nStatements. Although certain non-IFRS data has been extracted or derived from\nthe Half-Year financial statements, this data has not been audited or reviewed\nby Woodside’s independent auditors. These measures are presented to provide\nfurther insight into Woodside’s performance. See Non-IFRS Measures on page\n65 for more information.\n\nAPMs and their nearest respective IFRS measure.\n APMs derived from the condensed consolidated income statement and other notes 30 June 2026 30 June 2025 \n   US$m US$m \n EBIT/EBITDA excluding impairment     \n Net profit after tax 1,673 1,330 \n Adjusted for:     \n Finance income (123) (106) \n Finance costs 245 169 \n PRRT expense/(benefit) (305) 71 \n Income tax expense 667 353 \n EBIT 2,157 1,817 \n Adjusted for:     \n Property, plant and equipment depreciation 2,209 2,541 \n Amortisation of licence acquisition costs 4 3 \n Amortisation of intangible assets 10 11 \n Depreciation of lease assets 89 85 \n Impairment losses 178 143 \n EBITDA excluding impairment 4,647 4,600 \n       \n Underlying NPAT     \n Net profit after tax attributable to equity holders of the parent 1,672 1,316 \n Adjusted for the following exceptional items:     \n Less: Pluto DTA recognition (417) — \n Less: USA DTA recognition (90) — \n Add: Impairment loss (post-tax) 169 113 \n Less: Louisiana DTA recognition — (182) \n Underlying NPAT 1,334 1,247 \n       \n Average realised price(1)     \n Adjusted revenue from sale of products(2) 7,381 6,468 \n Sales volumes (MMboe) 99.8 104.8 \n Average realised price (US$ per boe) 74.0 61.7 \n       \n Unit production cost(3)     \n Production costs 749 667 \n Production (reserves) volumes (MMboe)(4) 85.0 98.6 \n Unit production cost (US$ per boe) 8.8 6.8 \n 1. 2025 sales volumes have been restated to include additional volumes of 0.19 \n MMboe to reflect pipeline gas volumes sold in MMBtu at a revised boe \n conversion factor, impacting realised price by ($0.1)/boe \n \n2. Adjusted revenue from sale of products comprises of revenue from sale of \n products of $7,356 million and provisional price adjustments of $25 million, \n which is included in other income (refer to Note A.1). \n \n3. The calculation has been updated to exclude feed gas, services and processing \n costs and processing volumes. The 2025 comparative has been restated to be \n presented on the same basis. \n \n4. 2026 Includes production volumes of 86.5 MMboe, adjusted for processing \n volumes of 1.5 MMboe. \n \n \n   \n\n APMs derived from the condensed consolidated statement of cash flows and other 30 June 2026 30 June 2025 \n notes \n   US$m US$m \n Free cash flow     \n Net cash from operating activities 3,013 3,339 \n Net cash used in investing activities (4,286) (4,937) \n Adjusted for:     \n Contributions from/(to) NCI 1,737 1,843 \n Lease repayments (112) (109) \n Free cash flow(1) 352 136 \n       \n Liquidity     \n Cash and cash equivalents 4,339 4,880 \n Add: Available undrawn facilities 3,850 3,550 \n Liquidity 8,189 8,430 \n 1. The 2026 calculation has been updated to adjust for contributions from/(to) \n NCI and lease repayments. The 2025 comparative has been restated to be \n presented on the same basis. \n\n APMs derived from the condensed consolidated statement of financial 30 June 2026 30 June 2025 \n \n \n \nposition and other notes \n   US$m US$m \n Capital expenditure     \n Capital additions on evaluation 24 29 \n Capital additions on property, plant and equipment 3,243 4,372 \n Less: Cash contributions from participants (1,725) (1,870) \n Capital additions on other 95 27 \n Capital expenditure 1,637 2,558 \n Acquisitions 470 — \n Capital expenditure and acquisitions 2,107 2,558 \n       \n Exploration expenditure     \n Exploration and evaluation expenditure 104 84 \n Adjusted for:     \n Evaluation expenditure (22) (2) \n Amortisation expense (4) (3) \n Prior year expense written off (1) — \n Exploration capitalised 42 5 \n Exploration expenditure(1) 119 84 \n Capital and exploration expenditure(1) 1,756 2,642 \n       \n Net tangible assets per ordinary security     \n Net assets 41,724 38,507 \n Adjusted for:     \n Goodwill (3,952) (3,952) \n Non-controlling interest (5,673) (2,868) \n Other intangible assets (904) (939) \n Net tangible assets 31,195 30,748 \n Number of issued and fully paid shares 1,901,100,143 1,898,749,771 \n Net tangible assets per ordinary security (US$ per ordinary security) 16.41 16.19 \n       \n Gearing     \n Interest-bearing liabilities (Current and non-current) 11,370 11,954 \n Lease liabilities (Current and non-current) 2,298 1,583 \n Adjusted for:     \n Cash and cash equivalents (4,339) (4,880) \n Net debt 9,329 8,657 \n Equity attributable to equity holders of the parent 36,051 35,639 \n Total net debt and equity attributable to equity holders of the parent 45,380 44,296 \n Gearing (%) 20.6% 19.5% \n 1. The 2026 calculation has been updated to adjust for evaluation expenditure. \n The 2025 comparative has been restated to be presented on the same basis. \n\n APMs derived from the condensed consolidated income statement and 30 June 2026 30 June 2025 \n \n \n \nstatement of financial position \n   US$m US$m \n Annualised return on equity     \n Annualised net profit after tax attributable to equity holders of the parent 3,344 2,632 \n Equity attributable to equity holders of the parent 36,051 35,639 \n Annualised return on equity (%) 9.3% 7.4% \n       \n Annualised return on average capital employed     \n Annualised profit before tax and net finance costs 4,314 3,634 \n Opening non-current liabilities 21,241 19,254 \n Closing non-current liabilities 20,777 21,828 \n Average non-current liabilities 21,009 20,541 \n Opening equity 39,843 36,153 \n Closing equity 41,724 38,507 \n Average equity(1) 40,784 37,330 \n Total average non-current liabilities and equity 61,793 57,871 \n Annualised return on average capital employed (%) 7.0% 6.3% \n\n APMs derived from other notes 30 June 2026 30 June 2025 \n   US$m US$m \n Revenue from sale of products (excluding marketing segment) 6,376 5,924 \n       \n Cash margin (excluding marketing segment)     \n Gross profit 2,684 2,344 \n Adjusted for:     \n Other 19 15 \n Property, plant and equipment depreciation 2,209 2,541 \n Other revenue 13 (100) \n Cash margin (excluding marketing segment) 4,925 4,800 \n Cash margin % 77.2% 81.0% \n       \n Production costs (excluding marketing segment)(2) 749 667 \n Production cost margin % 11.7% 11.3% \n       \n Other cash costs (excluding marketing segment):     \n Feed gas, services and processing costs(2) 238 92 \n Royalties, excise and levies 143 156 \n Insurance 33 37 \n Inventory movement 54 1 \n Shipping and direct sales costs 123 77 \n Trading costs 101 88 \n Other hydrocarbon costs 10 6 \n Total other cash costs (excluding marketing segment) 702 457 \n Other cash cost margin % 11.0% 7.7% \n 1. The calculation has been updated to use total equity rather than equity \n attributable to equity holders of the parent. The 2025 comparative has been \n restated to be presented on the same basis. \n \n2. Production costs has been updated to exclude and present feed gas, services \n and processing costs separately. The 2025 comparative has been restated to be \n presented on the same basis. \n\n Notes \n\n\nGlossary\n Term Definition \n $, $m US dollars unless otherwise stated, millions of dollars \n 1P Proved reserves \n 2C Best Estimate of Contingent resources \n 2P Proved plus Probable reserves \n Abate/abatement Avoidance, reduction or removal of an amount of carbon dioxide or equivalent \n Aim Woodside uses this term to describe a result that plans or actions are \n intended to achieve \n Aspiration Woodside uses this term to describe an aspiration to seek the achievement of \n an outcome but where achievement of the outcome is subject to material \n uncertainties and contingencies such that Woodside considers there is not yet \n a suitable defined plan or pathway to achieve that outcome \n ASX Australian Securities Exchange \n Average realised price Revenue from sale of products and provisional pricing adjustments ($ million) \n divided by sales volume (MMboe) \n A$, AUD Australian dollars \n Biodiversity Biological diversity means the variability among living organisms from all \n sources including, inter alia, terrestrial, marine and \n \n \n \nother aquatic ecosystems and the ecological complexes of which they are a \n part; this includes diversity within species, \n \n \n \nbetween species and of ecosystems(46) \n Board The Board of Directors of Woodside Energy Group Ltd \n Brent Intercontinental Exchange (ICE) Brent Crude deliverable futures contract (oil \n price) \n Capital expenditure Capital additions on property, plant and equipment and evaluation capitalised. \n Excludes exploration capitalised and adjusted for the capital contribution \n from partners for the development of Louisiana LNG \n Capital expenditure and acquisitions Includes capital expenditure and acquisition consideration. \n Carbon credit A tradeable financial instrument that is issued by a carbon-crediting program. \n A carbon credit represents a greenhouse gas \n \n \n \nemission reduction to, or removal from, the atmosphere equivalent to 1 tCO2-e, \n calculated as the difference in emissions from \n \n \n \na baseline scenario to a project scenario. Carbon credits are uniquely \n serialised, issued, tracked and retired or administratively \n \n \n \ncancelled by means of an electronic registry operated by an administrative \n body, such as a carbon-crediting program \n Cash margin Gross profit/loss adjusted for other cost of sales, property, plant and \n equipment depreciation and amortisation and other revenue. Excludes the \n marketing segment. Cash margin % is calculated as cash margin divided by \n revenue from sale of products (excluding marketing segment) \n CCS Carbon capture and storage \n CCUS Carbon capture utilisation and storage \n CO(2) Carbon dioxide \n CO(2)-e CO(2) equivalent. The universal unit of measurement to indicate the global \n warming potential of each of the seven greenhouse \n \n \n \ngases, expressed in terms of the global warming potential of one unit of \n carbon dioxide. It is used to evaluate releasing (or \n \n \n \navoiding releasing) any greenhouse gas against a common basis(47) \n Condensate Hydrocarbons that are gaseous in a reservoir but that condense to form liquids \n as they rise to the surface \n cps Cents per share \n DTA Deferred tax asset \n DRP Dividend reinvestment plan \n EBIT Calculated as profit before income tax, PRRT and net finance costs \n EBITDA excluding impairment Calculated as profit before income tax, PRRT, net finance costs, depreciation \n and amortisation, impairment losses, \n \n \n \nimpairment reversals \n Emissions Emissions refers to emissions of greenhouse gases unless otherwise stated \n EPS Earnings per share \n Exploration expenditure Includes exploration and evaluation expenditure less evaluation expenditure, \n amortisation of licence acquisition costs, prior year exploration expense \n written off and exploration capitalised. \n FEED Front-end engineering design \n FID Final investment decision \n FPSO Floating production storage and offloading \n FPU Floating production unit \n Free cash flow Net cash flow from/(used in) operating activities and net cash flow from/(used \n in) investing activities, adjusted for the capital contribution from/(to) \n non-controlling interests and lease repayments. \n Gearing Net debt divided by the total of net debt and equity attributable to equity \n holders of the parent \n GHG or greenhouse gas The seven greenhouse gases listed in the Kyoto Protocol are: carbon dioxide \n (CO2); methane (CH4); nitrous oxide (N2O); \n \n \n \nhydrofluorocarbons (HFCs); nitrogen trifluoride (NF3); perfluorocarbons \n (PFCs); and sulphur hexafluoride (SF6) \n Goal Woodside uses this term to broadly encompass its targets and aspirations \n Gross margin Gross profit divided by operating revenue. Gross profit excludes income tax, \n PRRT, net finance costs, other income and other \n \n \n \nexpenses \n H1, H2 Halves of the calendar year (H1 is 1 January to 30 June and H2 is 1 July to 31 \n December) \n High consequence injury A high-consequence injury is a work-related injury that results in a fatality \n or permanent impairment injury. Woodside’s definition for HCI has changed in \n 2025 to align with the IOGP Fatality and Permanent Impairment definition. This \n definition was adopted to focus attention on the highest risks to people. In \n the previous reporting period, the HCI definition included long-term disabling \n injuries (i.e where the person will make a full recovery, but recovery exceeds \n 180 days) in HCI statistics which focused disproportionate effort towards \n injury management, access to treatment and privacy issues(48) \n IFRS International Financial Reporting Standards. For more information see \n www.ifrs.org \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.ifrs.org&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.ifrs.org&index=4&md5=647764e6fd14284c38b187cb400fcf2d) \n . \n Indigenous Peoples There is diversity within the Indigenous communities in the areas where we are \n active. When communicating with wide audience. Woodside uses the term \n “Indigenous Peoples” to refer to Traditional Owners and Traditional \n Custodians. At a local level, Woodside will be guided by the community about \n the appropriate terms of reference. Following internal and external \n stakeholder feedback, Woodside has updated our reference from First Nations to \n Indigenous Peoples because First Nations is not a globally accepted or widely \n used term beyond Australia. Indigenous Peoples aligns with the United Nations \n Declaration on the Rights of Indigenous Peoples (UNDRIP) language and is the \n recognised collective term in international law \n JV Joint venture \n KGP Karratha Gas Plant \n Liquidity Total cash and cash equivalents and available undrawn debt facilities less \n restricted cash \n LNG Liquefied natural gas \n Lower-carbon Woodside uses this term to describe the characteristic of having lower levels \n of associated potential GHG emissions when \n \n \n \ncompared to historical and/or current conventions or analogues, for example \n relating to an otherwise similar resource, \n \n \n \nprocess, production facility, product or service, or activity \n Lower-carbon ammonia Lower-carbon ammonia is characterised here by the use of hydrogen with \n emissions abated by carbon, capture, and storage \n \n \n \n(CCS), with an expected ammonia lifecycle (Scope 1, 2 and 3) carbon emissions \n intensity of 0.8 tCO2/tNH3 (based on \n \n \n \ncontracted intensity threshold with Linde) relative to unabated ammonia with a \n lifecycle (Scope 1, 2 and 3) carbon emissions \n \n \n \nintensity of 2.3 tCO2/tNH3 (Hydrogen Europe, 2023) \n Lower-carbon portfolio For Woodside, a lower-carbon portfolio is one from which the net equity Scope \n 1 and 2 greenhouse gas emissions, which \n \n \n \nincludes the use of offsets, are being reduced towards targets, and into which \n new energy products and lower-carbon services \n \n \n \nare planned to be introduced as a complement to existing and new investments \n in oil and gas. Our Climate Policy sets out the \n \n \n \nprinciples that we believe will assist us achieve this aim \n Lower-carbon services Woodside uses this term to describe technologies, such as CCUS or offsets that \n could be used by customers to reduce their \n \n \n \nnet greenhouse gas emissions \n Major Project Status Major Project Status is the Australian Government’s recognition of a \n project’s national strategic importance \n Material Topic For the purposes of Woodside's 2026 sustainability disclosures we determine \n which topics are material. For these purposes, “material topic” means a \n 2026 sustainability topic, determined as part of the 2025 materiality \n assessment process undertaken by Woodside. Classification of any topic as \n material through our materiality assessment process should not be read as a \n determination of whether that topic rises to the level of materiality of \n disclosure required by law, including the laws of Australia, and the US. \n However where applicable laws require the disclosure of risks that meet \n certain thresholds, Woodside has disclosed those risks. \n Net debt Interest-bearing liabilities and lease liabilities less cash and cash \n equivalents \n Net equity greenhouse gas emissions Woodside’s equity share of net greenhouse gas emissions which includes the \n utilisation of carbon credits as offsets \n Net greenhouse gas emissions Woodside has set its Scope 1 and 2 greenhouse gas emissions reduction target \n on a net basis, allowing for both direct emissions reductions from its \n operations and emissions reduction achieved from the utilisation of carbon \n credits as offsets (including credits relating to avoidance, reduction and/or \n removal activities). Net greenhouse gas emissions are equal to an entity’s \n gross greenhouse gas \n \n \n \nemissions reduced by the number of retired carbon credits.(49) \n Net profit attributable to Net profit after tax excluding non-controlling interests from the Group’s \n \n operations \n \nequity holders of the \n \n \n \nparent \n Net tangible assets The Group’s net assets less goodwill, non-controlling interest and other \n intangible assets \n Net tangible assets per Net tangible assets divided by the number of issued and fully paid shares \n \n \n \nordinary security \n New energy Woodside uses this term to describe energy technologies, such as hydrogen or \n ammonia, that are emerging in scale but \n \n \n \nwhich are expected to grow during the energy transition due to having lower \n greenhouse gas emissions at the point of use \n \n \n \nthan conventional fossil fuels \n NGLs Natural gas liquids \n NH(3) Ammonia \n NPAT Net profit after tax attributable to equity holders of the parent \n NWS North West Shelf \n NYSE New York Stock Exchange \n Offsets The compensation for an entity’s greenhouse gas emissions within its scope \n by achieving an equivalent amount of emission \n \n \n \nreductions or removals outside the boundary or value chain of that entity \n Operator, Operated and Oil and gas joint venture participants will typically appoint one company as \n \n the operator, which will hold the contractual authority to manage joint \n \nnon-operated venture activities on behalf of the joint venture participants. Where Woodside \n is the operator of a joint venture in which it holds an equity share, this \n report refers to that joint venture as being operated. Where another company \n is the operator of a joint venture in which Woodside holds an equity share, \n this report refers to that joint venture as being non-operated \n Other cash cost margin Other cash costs include feed gas, services and processing costs; royalties, \n excise and levies; insurance; inventory movement; shipping and direct sales \n costs; trading costs; and other hydrocarbon costs. Excludes the marketing \n segment. Other cash cost margin % is calculated as other cash costs divided by \n revenue from sale of products (excluding marketing segment) \n Production cost margin Production cost margin % is calculated as production costs divided by revenue \n from sale of products. Excludes the marketing segment \n PRRT Petroleum resources rent tax \n PSC Production sharing contract \n Return on average capital employed Annualised profit before tax and net finance costs divided by total average \n non-current liabilities and total equity \n Return on equity Annualised net profit after tax attributable to equity holder of the parent \n divided by equity attributable to equity holders of the parent \n Revenue from ordinary Revenue from the sale of products, processing and services revenue and \n \n shipping and other revenue \n \nactivities \n Scope 1 greenhouse gas Direct greenhouse gas emissions. These occur from sources that are owned or \n \n controlled by the company, for example, emissions from \n \nemissions \n \n \ncombustion in owned or controlled boilers, furnaces, vehicles, etc.; emissions \n from chemical production in owned or controlled \n \n \n \nprocess equipment. Woodside estimates greenhouse gas emissions, energy values \n and global warming potentials are \n \n \n \nestimated in accordance with the relevant reporting regulations in the \n jurisdiction where the emissions occur (e.g. Australian \n \n \n \nnational Greenhouse and Energy Reporting (nGER), US EPA Greenhouse Gas \n Reporting Program (GHGRP)). Australian \n \n \n \nregulatory reporting principles have been used for emissions in jurisdictions \n where regulations do not yet exist(5) \n Scope 2 greenhouse gas Electricity indirect greenhouse gas emissions. Scope 2 accounts for GHG \n \n emissions from the generation of purchased electricity \n \nemissions \n \n \nconsumed by the company. Purchased electricity is defined as electricity that \n is purchased or otherwise brought into the \n \n \n \norganisational boundary of the company. Scope 2 emissions physically occur at \n the facility where electricity is generated. \n \n \n \nWoodside estimates greenhouse gas emissions, energy values and global warming \n potentials are estimated in accordance \n \n \n \nwith the relevant reporting regulations in the jurisdiction where the \n emissions occur (e.g. Australian national Greenhouse and \n \n \n \nEnergy Reporting (nGER), US EPA Greenhouse Gas Reporting Program (GHGRP)). \n Australian regulatory reporting principles \n \n \n \nhave been used for emissions in jurisdictions where regulations do not yet \n exist(5) \n Scope 3 greenhouse gas Other indirect greenhouse gas emissions. Scope 3 is a reporting category that \n \n allows for the treatment of all other indirect emissions. \n \nemissions \n \n \nScope 3 emissions are a consequence of the activities of the company but occur \n from sources not owned or controlled by the \n \n \n \ncompany. Some examples of Scope 3 activities are extraction and production of \n purchased materials; transportation of \n \n \n \npurchased fuels; and use of sold products and services. Please refer to the \n Climate data table on our website for further information on the Scope 3 \n emissions categories reported by Woodside(50) \n Starting base Woodside uses a starting base of 6.22 Mt CO2-e which is representative of the \n gross annual average equity Scope 1 and 2 greenhouse gas emissions over \n 2016-2020 and which may be adjusted (up or down) for potential equity changes \n in producing or sanctioned assets with a final investment decision prior to \n 2021. Net equity emissions include the utilisation of carbon credits as \n offsets \n Sustainability (including References to sustainability (including sustainable and sustainably) are used \n \n with reference to Woodside’s Sustainability \n \nsustainable and \n \n \n \nCommittee and sustainability related Board policies, as well as in the context \n \nsustainably) of Woodside’s aim to ensure its business is \n \n \n \nsustainable from a long-term perspective, considering a range of factors \n including economic (including being able to sustain \n \n \n \nour business in the long term by being low cost and profitable), environmental \n (including considering our environmental impact \n \n \n \nand striving for a lower carbon portfolio), social (including supporting our \n license to operate), and regulatory (including ongoing \n \n \n \ncompliance with relevant legal obligations). Use of the terms \n ‘sustainability’, ‘sustainable’ and ‘sustainably’ is not intended \n to \n \n \n \nimply that Woodside will have no adverse impact on the economy, environment, \n or society, or that Woodside will achieve any \n \n \n \nparticular economic, environmental, or social outcomes \n Target Woodside uses this term to describe an intention to seek the achievement of an \n outcome, where Woodside considers that it \n \n \n \nhas developed a suitably defined plan or pathway to achieve that outcome \n Tier 1 process safety event A typical Tier 1 process safety event is loss of containment of hydrocarbons \n greater than 500 kg (in any one-hour period) \n Tier 2 process safety event A typical Tier 2 process safety event is loss of containment of hydrocarbons \n greater than 50 kg but less than 500 kg (in any \n \n \n \none-hour period) \n Traditional Custodian A person or group responsible for maintaining and passing on cultural \n knowledge and practices for a culturally defined area of land or sea \n Traditional Owner An Indigenous person or group directly descended from the original inhabitants \n of a culturally defined area of land or sea \n TTF Title transfer facility \n Underlying NPAT Net profit after tax from the Group’s operations excluding any exceptional \n items \n Unit production cost or Production costs excluding feed gas, services and processing costs ($ million) \n \n divided by reserves production volume (MMboe) \n \nUPC \n US, USA United States of America \n USD US dollars \n WA Western Australia \n\n\nConversion factors\n Product Unit Conversion factor \n Natural gas 5,700 scf 1 boe \n Condensate 1 bbl 1 boe \n Oil 1 bbl 1 boe \n Natural gas liquids 1 bbl 1 boe \n Ammonia 1 metric tonne 3.68 boe \n\n Facility Unit LNG conversion factor \n Karratha Gas Plant 1 tonne 8.08 boe \n Pluto LNG Gas Plant 1 tonne 8.34 boe \n Wheatstone 1 tonne 8.27 boe \n The LNG conversion factor from tonne to boe is specific to volumes produced at \n each facility and is based on gas composition which may change over time. \n\n\nUnits of measure\n Term Definition \n bbl barrel \n bcf billion cubic feet of gas \n boe barrel of oil equivalent \n GJ gigajoule \n kT thousand metric tonnes \n Mbbl thousand barrels \n MMbbl million barrels \n Mbbl/d thousand barrels per day \n Mboe thousand barrels of oil equivalent \n Mboe/d thousand barrels of oil equivalent per day \n MMboe million barrels of oil equivalent \n MMscf million standard cubic feet of gas \n MMscf/d million standard cubic feet of gas per day \n Mtpa million tonnes per annum \n PJ petajoules \n scf standard cubic feet of gas \n TJ terajoule \n\n\nAbout this report\n\nThis Half-Year Report 2026 is a summary of Woodside’s operations, activities\nand financial position as at 30 June 2026. Woodside Energy Group Ltd (ABN 55\n004 898 962) is the parent company of the Woodside group of companies. In this\nreport, unless otherwise stated, references to ‘Woodside’, ‘the\ncompany’, ‘the Group’, ‘we’, ‘us’ and ‘our’ refer to\nWoodside Energy Group Ltd and its controlled entities as a whole. The text\ndoes not distinguish between the activities of the parent company and those of\nits controlled entities, unless otherwise stated.\n\nReferences to ‘H1’ refer to the first half of the year, i.e. the period\nbetween 1 January 2026 and 30 June 2026. All dollar figures are expressed in\nUS currency unless otherwise stated. Production and sales volumes, reserves\nand resources are quoted as Woodside share. A glossary of key terms, units of\nmeasure and conversion factors is on pages 59 – 63.\n\nThis report should be read in conjunction with the Annual Report 2025 and, in\nrespect of climate and sustainability matters, the 2025 Climate and\nSustainability Summary, the Climate Transition Action Plan and 2023 Progress\nReport available at woodside.com.\n\nForward looking statements\n\nThis report contains forward-looking statements. These statements may relate\nto Woodside’s business, goals, targets, aspirations, plans, expectations,\nmarket conditions, results of operations and financial condition, including,\nbut not limited to, statements regarding the timing, completion and outcomes\nof transactions, construction costs and capital expenditures, supply and\ndemand for Woodside’s products, development, completion and execution of\nWoodside’s projects, the expected benefits, cash flows and rates of return\nor other future results of investments, strategies and transactions, the\npayment of future dividends and the amount thereof, future results of\nprojects, operating activities and new energy products, expectations and plans\nfor renewables production capacity and investments in, and development of,\nrenewables projects, expectations and guidance with respect to production,\nproduction costs and other costs, capital expenditure, abandonment\nexpenditure, exploration expenditure and gas hub exposure, trends in commodity\nprices and currency exchange rates, adoption and implementation of new\ntechnologies and expectations regarding the achievement of Woodside’s Scope\n1 and 2 greenhouse gas emissions target (on a net equity or gross equity basis\nas specified) and other climate and sustainability goals.\n\nAll statements, other than statements of historical or present facts, are\nforward-looking statements and generally may be identified by the use of\nforward-looking words such as “aim”, “anticipate”, “aspire”,\n“believe”, “enable”, “estimate”, “expect”, “forecast”,\n“foresee”, “guidance”, “intend”, “likely”, “may”,\n“objective”, “outlook”, “pathway”, “plan”, “position”,\n“potential”, “project”, “schedule”, “seek” “should”,\n“strategy”, “strive”, “target”, “will” and other similar words\nor expressions.\n\nForward-looking statements in this report are not guarantees of future events\nor performance, but are in the nature of future expectations that are based on\nmanagement’s current expectations and assumptions.\n\nThose statements and any assumptions on which they are based are subject to\nchange without notice and are subject to inherent known and unknown risks,\nuncertainties, contingencies and other factors, many of which are beyond the\ncontrol of Woodside, its related bodies corporate and their respective\nofficers, directors, employees, advisers or representatives.\n\nImportant factors that could cause actual results to differ materially from\nthose in the forward-looking statements and the assumptions on which they are\nbased include, but are not limited to, fluctuations in commodity prices,\nactual demand for Woodside products, currency fluctuations, geotechnical\nfactors, drilling and production results, gas commercialisation, development\nprogress, operating results, engineering estimates, reserve and resource\nestimates, loss of market, industry competition, pace of technology\ndevelopments, sustainability and environmental risks, climate related\ntransition and physical risks, safety and personnel risks, changes in\naccounting standards, economic and financial markets conditions in various\ncountries and regions, the actions of third parties, project delay or\nadvancement, regulatory approvals, political risks and the impact of armed\nconflict and political instability (such as the ongoing conflicts in Ukraine\nand in the Middle East) on economic activity and oil and gas supply and\ndemand, cost estimates, legislative, fiscal and regulatory developments,\nincluding those related to the imposition of tariffs and other trade\nrestrictions, and the effect of future regulatory or legislative actions on\nWoodside or the industries in which it operates, including potential changes\nto tax laws, the impact of general economic conditions, inflationary\nconditions, prevailing exchange rates and interest rates and conditions in\nfinancial markets, and risks associated with acquisitions, mergers,\ndivestitures and joint ventures, including difficulties integrating or\nseparating businesses, uncertainty associated with financial projections,\nrestructuring, increased costs and adverse tax consequences, and uncertainties\nand liabilities associated with acquired and divested properties and\nbusinesses.\n\nA more detailed summary of the key risks relating to Woodside and its business\ncan be found in the “Risk factors” section of Woodside’s most recent\nAnnual Report released to the Australian Securities Exchange and in\nWoodside’s most recent Annual Report on Form 20-F filed with the United\nStates Securities and Exchange Commission and available on the Woodside\nwebsite at https://www.woodside.com/investors/reports-investor-briefings\n(https://cts.businesswire.com/ct/CT?id=smartlink&url=https%3A%2F%2Fwww.woodside.com%2Finvestors%2Freports-investor-briefings&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=https%3A%2F%2Fwww.woodside.com%2Finvestors%2Freports-investor-briefings&index=5&md5=abce995c116ef0871b37f0ebaa25ae42)\n. You should review and have regard to these risks when considering the\ninformation contained in this report.\n\nIf any of the assumptions on which a forward-looking statement is based were\nto change or be found to be incorrect, this would likely cause outcomes to\ndiffer from the statements made in this report.\n\nInvestors are strongly cautioned that forward-looking statements are subject\nto significant uncertainties and may not prove to be correct. Actual results\nor performance may vary materially from those expressed in, or implied by, any\nforward-looking statements. None of Woodside nor any of its related bodies\ncorporate, nor any of their respective officers, directors, employees,\nadvisers or representatives, nor any person named in this report or involved\nin the preparation of the information in this report, makes any\nrepresentation, assurance, guarantee or warranty (either express or implied)\nas to the accuracy or likelihood of fulfilment of any forward-looking\nstatement, or any outcomes, events or results expressed or implied in any\nforward-looking statement in this report.\n\nAll forward-looking statements contained in this report reflect Woodside’s\nviews held as at the date of this report and, except as required by applicable\nlaw, neither Woodside, its related bodies corporate, nor any of their\nrespective officers, directors, employees, advisers or representatives nor any\nperson named in this report or involved in the preparation of the information\nin this report intends to, undertakes to, or assumes, any obligation to,\nprovide any additional information or update or revise any of these statements\nafter the date of this report, either to make them conform to actual results\nor as a result of new information, future events or results, changes in\nWoodside’s expectations or otherwise.\n\nPast performance (including historical financial and operational information)\nis given for illustrative purposes only. It is not necessarily, a reliable\nindicator of future performance, including future security prices.\n\nNon-IFRS Measures\n\nThroughout this report, a range of financial and non-financial measures are\nused to assess Woodside’s performance, including a number of financial\nmeasures that are not defined in, and have not been prepared in accordance\nwith, International Financial Reporting Standards (IFRS) and are not\nrecognised measures of financial performance or liquidity under IFRS (Non-IFRS\nFinancial Measures). These measures include EBIT, EBITDA excluding impairment,\nGearing, Underlying NPAT, Average realised price, Unit production cost, Net\ndebt, Liquidity, Free cash flow, Capital expenditure, Exploration expenditure,\nReturn on Equity, Return on average capital employed, Cash margin, Production\ncost margin, Other cash cost margin, Net tangible assets and Net tangible\nassets per ordinary security. These Non-IFRS Financial Measures are defined in\nthe glossary on pages 59 – 61 of this report. A quantitative reconciliation\nof these measures to the most directly comparable financial measure calculated\nand presented in accordance with IFRS can be found in the Alternative\nPerformance Measures section of this report on pages 55 – 58.\n\nWoodside’s management uses these measures to monitor Woodside’s financial\nperformance alongside IFRS measures to improve the comparability of\ninformation between reporting periods and business units and Woodside believes\nthat the Non-IFRS Financial Measures it presents provide a useful means\nthrough which to examine the underlying performance of its business.\n\nUndue reliance should not be placed on the Non-IFRS Financial Measures\ncontained in this report and these Non-IFRS Financial Measures should be\nconsidered in addition to, and not as a substitute for, or as superior to,\nmeasures of financial performance, financial position or cash flows reported\nin accordance with IFRS. Non-IFRS Financial Measures are not uniformly defined\nby all companies, including those in Woodside’s industry. Accordingly, they\nmay not be comparable with similarly titled measures and disclosures by other\ncompanies.\n\nClimate strategy and emissions data\n\nAll greenhouse gas emissions data in this report are estimates, due to the\ninherent uncertainty and limitations in measuring or quantifying greenhouse\ngas emissions, and our methodologies for measuring or quantifying greenhouse\ngas emissions may evolve as market practices continue to develop and data\nquality and quantity continue to improve.\n\nWoodside “greenhouse gas” or “emissions” information reported are\nScope 1 GHG emissions, Scope 2 GHG emissions, and/or Scope 3 greenhouse\nemissions, each on a net equity or gross equity basis as specified.\n\nFor more information on Woodside’s climate strategy, including references to\n‘lower-carbon’ and ‘lower-carbon services’ as part of that strategy,\nand emissions data, refer to the 2025 Climate and Sustainability Summary,\navailable on the Woodside website at https://www.woodside.com/sustainability\n(https://cts.businesswire.com/ct/CT?id=smartlink&url=https%3A%2F%2Fwww.woodside.com%2Fsustainability&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=https%3A%2F%2Fwww.woodside.com%2Fsustainability&index=6&md5=80867f3e1ac0fcc85f723fffb86616bf)\nand section 3.6 of Woodside’s 2025 Annual Report.\n\nNo express or implied prices\n\nThis report does not include any express or implied prices at which Woodside\nwill buy or sell financial products.\n (1) These are alternative performance measures which are non-IFRS measures \n that are unaudited. Refer to Alternative Performance Measures on pages 53-56 \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(2) The 2026 calculation has been updated to adjust for contributions \n from/(to) NCI and lease repayments. The 2025 comparative has been restated to \n be presented on the same basis. \n \n \n \n(3) 2025 sales volumes have been restated to include additional volumes of \n 0.19 MMboe and 6 MMscf/d to reflect pipeline gas volumes sold in MMBtu at a \n revised boe conversion factor, impacting realised price by ($0.1)/boe. \n \n \n \n(4) H1 2026 Total production volumes includes production of 85.0 MMboe from \n Woodside reserves and 1.5 MMboe from processing, comprising 1.0 MMboe from \n Beaumont New Ammonia and 0.5 MMboe from feed gas purchased from Pluto \n non-operating participants processed through the Pluto-KGP Interconnector. \n \n \n \n(5) 2026 full-year Total production volumes includes 2-3 MMboe from Beaumont \n New Ammonia (no change). \n \n \n \n(6) Consistent with 2025 Capital Markets Day, presented on a 3 year average \n for 2026-2028. Includes binding sales and purchases agreements only, \n Woodside’s equity share of Scarborough and Pluto LNG, Corpus Christi offtake \n volumes and assumes the Chevron asset swap is completed. \n \n \n \n(7) Louisiana LNG (90% Louisiana LNG LLC, 60% Louisiana LNG Infrastructure LLC \n and 20% Driftwood Pipeline LLC) capital expenditure adjusted for the cash \n contributions \n \n \n \nfrom Stonepeak Wallaby I Acquiror LP (Stonepeak) and Williams Louisiana LNG \n LLC (Williams). Scarborough (74.9% participating interest) and Pluto Train 2 \n (51% participating interest). Trion (60% participating interest). Excludes the \n final acquisition completion payment for Beaumont New Ammonia of $470 million. \n Completion of the asset swap with Chevron assumed to occur in Q4 2026. \n \n \n \n(8) Capital expenditure is reported on the basis of Woodside’s net ownership \n interests for each project as at 30 June 2026. Refer to pages 49-50 for \n details. \n \n \n \n(9) Calculated based on Woodside’s closing share price on 30 June 2026 of \n A$28.21 ($19.38) and a USD:AUD exchange rate of 0.6869. \n \n \n \n(10) This is an alternative performance measure which is a non-IFRS measure \n that is unaudited. Refer to Alternative Performance Measures on pages 53-56 \n for a reconciliation for these measures to Woodside’s financial statements \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(11) Net profit after tax attributable to equity holders of the parent. \n \n \n \n(12) The global operations effective income tax rate (EITR) of 28.5% (2025: \n 21.0%) is calculated as the Group’s income tax expense divided by profit \n before income tax. The underlying EITR is 29.6% when excluding the recognition \n of additional Pluto PRRT deferred tax asset, income tax deferred tax asset \n relating to US net operating losses and impairment losses. \n \n \n \n(13) Capital additions on property, plant and equipment, evaluation \n capitalised and other corporate spend. Excludes exploration capitalised and is \n presented net of capital contributions from non-controlling interests for the \n development of Louisiana LNG. \n \n \n \n(14) Exploration and evaluation expenditure and exploration capitalised less \n evaluation expenditure, amortisation of licence acquisition costs and prior \n year exploration expense written off. The 2025 comparative has been restated \n to be presented on the same basis. \n \n \n \n(15) Cash flow from operating activities less cash flow from investing \n activities, adjusted for the capital contributions from/(to) non-controlling \n interests and lease repayments. The 2025 comparative has been restated to be \n presented on the same basis. \n \n \n \n(16) Includes production of 85.0 MMboe from Woodside reserves and 1.5 MMboe \n from processing, comprising 1.0 MMboe from Beaumont New Ammonia and 0.5 MMboe \n from feed gas purchased from Pluto non-operating participants processed \n through the Pluto-KGP Interconnector. \n \n \n \n(17) The conversion factors used throughout this report are set out on page \n 60, unless otherwise stated. Sales volumes differ from production volumes \n primarily due to the timing of liftings and the exclusion of third-party \n purchased volumes. \n \n \n \n(18) 2025 sales volumes have been restated to include additional volumes of \n 0.19 MMboe and 6 MMscf/d to reflect pipeline gas volumes sold in MMBtu at a \n revised boe conversion factor, impacting realised price by ($0.1)/boe. \n \n \n \n(19) Comparisons are to half-year ended 30 June 2025. \n \n \n \n(20) This is an alternative performance measure which is a non-IFRS measure \n that is unaudited. Refer to Alternative Performance Measures on pages 53-56 \n for a reconciliation for these measures to Woodside’s financial statements \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(21) Calculated based on Woodside’s closing share price on 30 June 2026 of \n A$28.21 ($19.38) and a USD:AUD exchange rate of 0.6869. \n \n \n \n(22) These are alternative performance measures which are non-IFRS measures \n that are unaudited. Refer to Alternative Performance Measures on pages 53-56 \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(23) Net cash flow from / (used in) operating activities and net cash flow \n from/(used in) investing activities, adjusted for the capital contribution \n from/(to) non-controlling interests and lease repayments. \n \n \n \n(24) No change to the forecasted Trion project capital expenditure. Trion \n construction related vessel leases are for a term of 3 years. \n \n \n \n(25) Completion of the transaction is subject to conditions precedent. See \n “Woodside simplifies portfolio and unlocks long-term value” announced 19 \n December 2024 for details concerning the Australian asset swap. \n \n \n \n(26) Completion of the transaction is subject to conditions precedent. See \n “Woodside simplifies portfolio and unlocks long-term value” announced 19 \n December 2024 for details concerning the Australian asset swap. \n \n \n \n(27) See the announcement “Woodside completes Gippsland Basin operatorship \n transition” released 1 July 2026 for details. \n \n \n \n(28) Higher net production percentage reflects accelerated recovery of 100% \n Woodside-funded pre-FID costs under the PSC entitlement, driven by high oil \n price. \n \n \n \n(29) Beaumont New Ammonia production volume is 1.0 MMboe in H1 2026. \n \n \n \n(30) Lower-carbon ammonia is characterised here by the use of hydrogen with \n emissions abated by carbon, capture, and storage (CCS), with an expected \n ammonia lifecycle (Scope 1, 2 and 3) carbon emissions intensity of 0.8 \n tCO2/tNH3 (based on contracted intensity threshold with Linde) relative to \n unabated ammonia with a lifecycle (Scope 1, 2 and 3) carbon emissions \n intensity of 2.3 tCO2/tNH3 (Hydrogen Europe, 2023). \n \n \n \n(31) These are alternative performance measures which are non-IFRS measures \n that are unaudited. Refer to Alternative Performance Measures on pages 53-56 \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(32) The Project has received funding from the Hydrogen Fuelled Transport \n Project Funding Process as part of the Western Australian Government’s \n Renewable Hydrogen Strategy. \n \n \n \n(33) Completion of the transaction is subject to customary conditions \n precedent. See “Woodside Exercises Browse pre-emption right” announced on \n 12 June 2026. \n \n \n \n(34) See “Woodside rationalises global portfolio with Calypso divestment” \n released 6 August 2026 for details \n \n \n \n(35) See the media release “Bandit-1 Discovery off Louisiana” released 10 \n April 2026 for details. \n \n \n \n(36) Woodside uses the term lower-carbon to describe the characteristic of \n having lower levels of associated potential GHG emissions when compared to \n historical and/or current conventions or analogues, for example relating to an \n otherwise similar resource, process, production facility, product or service, \n or activity. When applied to Woodside's strategy, please see the definition of \n lower-carbon portfolio in the Glossary on pages 57-59. \n \n \n \n(37) Following completion of the Chevron asset swap announced in 2024, \n Woodside’s participating interest in Angel CCS will increase to 40%. \n \n \n \n(38) This metric is determined utilising Woodside’s risk matrix. When used \n to define impact to the environment, moderate impact is an impact on \n environmental features or areas of heightened sensitivity with a limited \n ability to recover. \n \n \n \n(39) For these purposes, “material topic” means a 2026 sustainability \n topic, determined as part of the 2025 materiality assessment process \n undertaken by Woodside. Classification of any topic as material through our \n materiality assessment process should not be read as a determination of \n whether that topic rises to the level of materiality of disclosure required by \n law, including the laws of Australia, and the US. However where applicable \n laws require the disclosure of risks that meet certain thresholds, Woodside \n has disclosed those risks. \n \n \n \n(40) Ms Westcott was appointed to the Board on 18 March 2026 \n \n \n \n(41) Mr Cutifani was appointed to the Board on 19 March 2026. \n \n \n \n(42) Mr Macfarlane’s retirement took effect from 23 April 2026. \n \n \n \n(43) Mr O’Neill’s resignation took effect on 1 July 2026. \n \n \n \n(44) Comparisons are to half-year ended 30 June 2025. \n \n \n \n(45) Includes lease assets and lease liabilities as a result of AASB 16/ IFRS \n 16 Leases. Net Tangible Assets per ordinary security is a non-IFRS measure. \n Refer to Alternative Performance Measures for a reconciliation for these \n measures to Woodside’s financial statements on pages 53 - 56. \n \n \n \n(46) UNEP, 1992. “Convention on Biological Diversity’ \n https://www.cbd.int/doc/legal/cbd-en.pdf \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=https%3A%2F%2Fwww.cbd.int%2Fdoc%2Flegal%2Fcbd-en.pdf&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=https%3A%2F%2Fwww.cbd.int%2Fdoc%2Flegal%2Fcbd-en.pdf&index=7&md5=0ed52156cee0a882f38b70c41927b7e7) \n . \n \n \n \n(47) See IFRS Foundation 2021: Climate Related Disclosures Prototype. Appendix \n A. The IFRS published a further consultation document subsequent to the 2021 \n prototype. As it did not contain an updated definition of Paris-Aligned \n scenarios Woodside has retained use of the previous edition. \n \n \n \n(48) IOGP Fatality and Permanent Impairment injury definitions | IOGP \n \n \n \n(49) Australian Clean Energy Regulator, 2023. “Corporate Emissions Reduction \n Transparency report 2023” \n https://cer.gov.au/markets/reports-and-data/corporate-emissions-reduction-transparency-report/corporate-emissions-reduction-transparency-report-2023/cert-report-2023-glossary \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=https%3A%2F%2Fcer.gov.au%2Fmarkets%2Freports-and-data%2Fcorporate-emissions-reduction-transparency-report%2Fcorporate-emissions-reduction-transparency-report-2023%2Fcert-report-2023-glossary&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=https%3A%2F%2Fcer.gov.au%2Fmarkets%2Freports-and-data%2Fcorporate-emissions-reduction-transparency-report%2Fcorporate-emissions-reduction-transparency-report-2023%2Fcert-report-2023 \n -glossary&index=8&md5=3b6315a60e39c40b4984a7a8960c0478) \n \n \n \n(50) World Resources Institute and World Business Council for Sustainable \n Development 2004. “GHG Protocol: a corporate accounting and reporting \n standard”. \n\n\nThis announcement was approved and authorised for release by Woodside’s\nDisclosure Committee.\n\n\n\nView source version on businesswire.com:\nhttps://www.businesswire.com/news/home/20260824865396/en/\n(https://www.businesswire.com/news/home/20260824865396/en/)\n\nINVESTORS\n\nVanessa Martin \n\nM: +61 477 397 961\n\nE: investor@woodside.com (mailto:investor@woodside.com)\n\nMEDIA\n\nChristine Abbott \n\nM: +61 484 112 469\n\nE: christine.abbott@woodside.com (mailto:christine.abbott@woodside.com)\n\nREGISTERED ADDRESS \n\nWoodside Energy Group Ltd \n\nACN 004 898 962\n\nMia Yellagonga\n\n11 Mount Street\n\nPerth WA 6000\n\nAustralia\n\nT +61 8 9348 4000\n\nwww.woodside.com\n(https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.woodside.com&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.woodside.com&index=9&md5=6fd48c197e71632333b47e25ae668960)\n\n\nCopyright Business Wire 2026","article_body_html":"","raw_payload":{"data":{"id":"nBwbQ4794a","title":"Woodside Energy Half-Year Report for Period Ended 30 June 2026","author":"Business Wire","ticker":"WDS","created":"2026-08-25T04:39:00.413Z","tickers":["WDS"],"exchange":"NYSE","article_body":"Woodside Energy Half-Year Report for Period Ended 30 June 2026\n\nWoodside Energy Group (ASX: WDS) (NYSE: WDS):\n\nThis press release features multimedia. View the full release here:\nhttps://www.businesswire.com/news/home/20260824865396/en/\n(https://www.businesswire.com/news/home/20260824865396/en/)\n\nDisciplined execution\n\nOperational excellence and project delivery\n\n\n * Recorded operating revenue of $7,446 million, up 13% from H1 2025.\n\n * Delivered production of 478 Mboe/d (86.5 MMboe) and unit production costs of\n$8.8/boe.(1)\n\n * Progressed major projects with Scarborough 98%, Trion 64%, and Louisiana LNG\n28% complete.\n\n * Maintained high asset reliability, with operated LNG facilities achieving\n98.7% reliability, Sangomar 99.5%, and Shenzi 99.1%.\n\n * Safely executed the Pluto planned turnaround campaign on schedule and within\nbudget, including key integration activities supporting the Scarborough Energy\nProject, with more than 400,000 hours worked and zero lost-time injuries.\n\nDelivering value\n\n\n * Determined a fully franked interim dividend of 57 US cents per share (cps).\n\n * Achieved net profit after tax (NPAT) of $1,672 million (underlying NPAT $1,334\nmillion).(1)\n\n * Delivered EBITDA of $4,647 million from underlying base business.(1)\n\n * Delivered operating cash flow of $3,013 million and free cash flow of $352\nmillion.\n\n * Disciplined capital management resulted in strong liquidity of $8,189\nmillion.(1)\n\n * Gearing of 20.6%, marginally outside the target range of 10 - 20%, impacted by\n$655 million of new lease liabilities, a $419 million net cash outflow from\nhedge settlements, and a $101 million increase in trade receivables.(1)\n Comparative performance \n\n     H1 H1 Change   \n \n \n \n \n \n2026 \n2025 \n% \n Operating revenue $ million 7,446 6,590 13%   \n Underlying NPAT(1) $ million 1,334 1,247 7%   \n Free cash flow(1,2) $ million 352 136 159%   \n Average realised price(1,3) $/boe 74.0 61.7 20%     \n           2026 full-year guidance \n           Prior Current \n Total production volumes(45) MMboe 86.5 99.2 (13%) 172 - 186 174-185 \n Gas hub exposure(6) % 38.7% 24.2% 15% ~30 No change \n Capital expenditure(1,78) $ million 1,637 2,558 (36%) 4,000 - 4,500 No change \n Abandonment expenditure $ million 255 517 (51%) 500 - 800 No change \n Exploration expenditure(1) $ million 119 84 42% ~200 No change \n Production costs $ million 749 667 12% 1,500 - 1,800 No change \n Feed gas, services and processing costs $ million 238 92 159% 500 - 600 No change \n Property, plant and equipment depreciation and amortisation $ million 2,209 2,541 (13%) 4,200 - 4,700 No change \n\n\nThis page and the following 66 pages comprise the half-year information given\nto the ASX under Listing Rule 4.2A and should be read in conjunction with\nWoodside’s Annual Report 2025.\n Summary \n\n\nWoodside delivered strong half-year production of 478 thousand barrels oil\nequivalent per day (86.5 million barrels of oil equivalent total) and reported\na half-year net profit after tax (NPAT) of $1,672 million. Underlying NPAT was\n$1,334 million, compared to $1,247 million in the corresponding period in\n2025. Operating revenue rose 13% year-on-year to $7,446 million.\n\nDuring the half, the Middle East conflict disrupted the global supply of LNG\nand oil resulting in strengthening commodity prices and an increase in\ncustomer demand for products. Woodside’s Marketing and Trading division\ncontinued to optimise the portfolio to manage risk and maximise value while\nfulfilling customer commitments.\n\nThe directors have determined a fully franked interim dividend of 57 US cents\nper share (cps), representing an 80% payout ratio of underlying NPAT, and an\nannualised yield of 5.9%.(9)\n\nWoodside CEO Liz Westcott said the company delivered a resilient first half\nperformance, remaining a secure and reliable supplier to customers throughout\na period of global volatility.\n\n“We once again delivered strong production, cash flow and shareholder\nreturns, while continuing to execute the next phase of growth.\n\n“Keeping our people safe remains our highest priority. We recorded one high\nconsequence injury during the period while undertaking over 11 million work\nhours. This reinforces the need for ongoing focus on critical risk management,\nstrong safety leadership and disciplined execution of safe work practices\nacross our operations.\n\n“We maintained operational excellence at our assets. Operated LNG\nreliability was more than 98% and the planned turnaround at Pluto LNG was\ncompleted on budget and schedule, derisking the Scarborough Energy Project\nschedule in the process. We achieved exceptional performance at Sangomar,\nwhich produced at near nameplate capacity with 99.5% reliability.\n\n“The Scarborough Energy Project is now 98% complete and remains on track to\ndeliver first LNG cargo in the fourth quarter of 2026. During the half, we\ncompleted all upstream infrastructure, and subsequent to the period, achieved\nready for start-up and first gas at the floating production unit. Our focus\nremains on disciplined commissioning and start-up of all facilities to ensure\nsafe and reliable operations from day one.\n\n“The Trion Project offshore Mexico also made strong progress and is now 64%\ncomplete, targeting first oil in 2028. Key construction and drilling\nmilestones achieved in the first half included completion of the topsides lift\nonto the floating production unit and drilling of the first three of 24 subsea\nwells.\n\n“At Louisiana LNG, key milestones were achieved relating to the LNG tanks\nand marine infrastructure. The project’s foundation development was 28%\ncomplete at the end of the half, with first LNG targeted for 2029.\n\n“In July, Woodside assumed operatorship of the Gippsland Basin assets,\ncreating greater flexibility for future development opportunities while\nreinforcing our commitment to supporting energy security in the eastern\nAustralian domestic market.\n\n“We continued to deliver on our sustainability commitments during the half,\ntaking forward biodiversity initiatives in Western Australia and Louisiana,\nand enhancing methane emissions reporting across the Sangomar and North West\nShelf operations.\n\n“As we focus on Woodside’s next phase of disciplined delivery, we have\nannounced a series of actions to lift performance and sharpen our focus on\nvalue. We have set an annual cost savings target of $350 million from 2028 to\nbe delivered through the structured review of our business.”\n Financial summary \n\n Key metrics \n     H1 H1 Change \n     2026 2025 % \n Operating revenue $ million 7,446 6,590 13% \n EBITDA excluding impairment(10) $ million 4,647 4,600 1% \n EBIT(10) $ million 2,157 1,817 19% \n Net profit after tax (NPAT)(1112) $ million 1,672 1,316 27% \n Underlying NPAT(10) $ million 1,334 1,247 7% \n Net cash from operating activities $ million 3,013 3,339 (10%) \n Capital expenditure(10,13) $ million 1,637 2,558 (36%) \n Exploration expenditure(10,14) $ million 119 84 42% \n Free cash flow(10,15) $ million 352 136 159% \n Average realised price(10,18) US$/boe 74.0 61.7 20% \n Dividends distributed $ million 1,122 1,006 12% \n Interim dividend determined US cps 57 53 8% \n           \n Key ratios         \n Earnings per share US cps 88.2 69.4 27% \n Gearing(10) % 20.6 19.5 1% \n           \n Production volumes(16,17)         \n Gas MMboe 46.1 58.2 (21%) \n Liquids MMboe 39.4 41.0 (4%) \n Ammonia MMboe 1.0 - N/A \n Total MMboe 86.5 99.2 (13%) \n           \n Production volumes per day(17)         \n Gas MMscf/d 1,451 1,833 (21%) \n Liquids Mbbl/d 217 226 (4%) \n Ammonia kT/d 1.5 - N/A \n Total Mboe/d 478 548 (13%) \n           \n Sales volumes(17)         \n Gas(18) MMboe 58.5 63.9 (8%) \n Liquids MMboe 40.3 40.9 (1%) \n Ammonia MMboe 1.0 - N/A \n Total MMboe 99.8 104.8 (5%) \n           \n Sales volumes per day(17)         \n Gas(18) MMscf/d 1,843 2,012 (8%) \n Liquids Mbbl/d 223 226 (1%) \n Ammonia kT/d 1.4 - N/A \n   Mboe/d 551 579 (5%) \n\n Appendix 4D \n\n\nResults for announcement to the market\n\nMore information is available on page 48.\n         US$ million \n Revenue from ordinary activities Increased 13%(19) to 7,446 \n Profit from ordinary activities after tax attributable to members Increased 27%(19) to 1,672 \n Net profit for the period attributable to members Increased 27%(19) to 1,672 \n           \n Interim dividend - fully franked   57 US cps H1 2026   \n Record date for determining entitlements to the dividend   4 September 2026   \n\n Net profit after tax reconciliation \n\n\nThe following table summarises the variance between the H1 2025 and H1 2026\nresults for the contribution of each line item to NPAT.\n   US$m Primary reasons for variance \n 2025 H1 reported NPAT 1,316   \n Revenue from sale of products     \n Produced - price impact 755 Higher average realised prices. \n Produced - volume impact (307) Lower production due to cyclone impacts, Pluto planned turnaround and \n divestment of the Greater Angostura assets offset by first ammonia sales. \n Purchased - price and volume impact 440 Higher third-party LNG trading activity. \n Cost of sales (559) Higher third-party LNG trading activity, first ammonia production and Pluto \n planned turnaround. \n Perdaman embedded derivative (297) A non-cash unrealised loss of $135 million in H1 2026 compared to an \n unrealised gain of $162 million in H1 2025. \n Hedging (106) Pre-tax hedge losses of $64 million in H1 2026 compared to pre-tax hedge gains \n of $42 million in H1 2025. \n Restoration movement 450 Restoration provision updates primarily due to Stybarrow, Griffin and Minerva \n in 2025. \n Impairment losses (35) Pre-tax impairment for the Calypso Project offset by lower pre-tax impairment \n for the H2OK Project compared with H1 2025. \n Income tax and PRRT expense 62 Recognition of the Pluto PRRT and US income tax DTA in 2026 offset by higher \n taxable profits and recognition of the Louisiana LNG DTA in 2025. \n Other (47)   \n 2026 H1 reported NPAT 1,672   \n Underlying adjustments (338) Adjusted for the recognition of the Pluto PRRT and US income tax DTA benefits \n and the post-tax impairment of the Calypso and H2OK Projects. \n 2026 H1 underlying NPAT(20) 1,334   \n\n Capital management \n\n\nWoodside’s capital management framework provides us with the flexibility to\noptimise value and shareholder returns delivered from the portfolio of\nopportunities.\n\nInterim dividend and dividend reinvestment plan\n\nA 2026 fully franked interim dividend of 57 US cps has been determined,\nrepresenting an annualised dividend yield of 5.9% .(21) The total amount of\nthe interim dividend payment is $1,084 million which represents 80% of\nunderlying NPAT for the first half of 2026.(22)\n\nThe dividend reinvestment plan remains suspended.\n\nLiquidity and balance sheet\n\nIn H1 2026, Woodside generated $3,013 million of cash flow from operating\nactivities and delivered positive free cash flow of $352 million, which\nincludes the $1,725 million in capital contributions received from Stonepeak\nand Williams for the development of Louisiana LNG.(22,23)\n\nDuring this period, Woodside repaid a $600 million Syndicated Term Loan\napproximately 6 months prior to maturity.\n\nAt the end of the period, Woodside had cash and cash equivalents of $4,339\nmillion, liquidity of $8,189 million, and drawn debt of $11,450 million,\nincluding $800 million of ten-year bonds due in September 2026.(22)\n\nWoodside’s gearing as at 30 June 2026 was 20.6%, marginally outside the\ntarget range of 10 to 20%.(22 )Woodside’s gearing may at times fall outside\nthe target range as the balance sheet is managed through the investment cycle.\n\nNet debt and gearing were impacted by:\n\n\n * $655 million of lease liabilities recognised in the first half of 2026, for\nthe Woodside Bilangara LNG vessel and Trion construction related vessels.(24)\n\n * Net cash outflow of $419 million for hedge settlements.\n\n * Higher pricing driving a $101 million increase in trade receivables that were\nreceived in July 2026.\n\nWoodside’s commitment to an investment-grade credit rating remains unchanged\nand supports the aim of providing sustainable returns to shareholders, both\nnow from the strong existing business and in the future from the growth\nopportunities, in accordance with Woodside’s capital management framework.\n\nCommodity price risk management\n\nAs at 30 June 2026, approximately 62% of the 30 MMboe of 2026 oil-linked\nproduction previously hedged (at an average price of $74.23 per barrel) had\nbeen cash settled and 10 MMboe of 2027 oil-linked production was hedged at an\naverage price of $76.76 per barrel.\n\nCommodity swaps were used to continue managing risk associated with the Corpus\nChristi LNG volumes.\n\nFor the period ended 30 June 2026, pre-tax hedge losses of $64 million\nprimarily relating to Corpus Christi LNG hedges and foreign exchange hedges\nwere recognised, and hedge settlements resulted in a net cash outflow of $419\nmillion. The hedge settlement net cash outflow in H1 2026 is primarily due to\ntiming with oil-linked hedge losses cash settled ahead of the related revenue\nrecognition, and expected to be offset by higher revenue from Q2 price lag\nrealisation in H2 2026.\n\nEmbedded commodity derivative\n\nIn 2023, Woodside entered a revised long-term gas sale and purchase agreement\nwith Perdaman. A component of the selling price is linked to the price of\nurea, creating an embedded commodity derivative in the contract. The fair\nvalue of the embedded derivative is estimated using a Monte Carlo simulation\nmodel.\n\nAs there is no long-term urea forward curve, TTF continues to be used as a\nproxy to simulate the value of the derivative over the life of the contract.\nFor the half-year ended 30 June 2026, an unrealised loss of $135 million has\nbeen recognised through other expenses.\n Australian operations \n\n\nPluto LNG\n\nPluto LNG is a gas processing facility in the Pilbara region of Western\nAustralia, comprising an offshore platform and one onshore LNG processing\ntrain.\n\nWoodside’s share of production in H1 2026 was 20.6 MMboe. This was an 18%\ndecrease compared with 25.0 MMboe in H1 2025, primarily due to the impact of a\nplanned turnaround and Severe Tropical Cyclone Mitchell in the reporting\nperiod. H1 2026 production included 3.9 MMboe of Pluto gas processed at\nKarratha Gas Plant through the Interconnector.\n\nPluto LNG achieved reliability of 98.7% in H1 2026, reflecting the asset's\nstrong operating performance.\n\nIn H1 2026, drilling of the XNA-03 infill well was completed and preparations\ncontinue for start-up targeted for H2 2026.\n\nThe planned turnaround in May 2026 was successfully delivered safely, on\nschedule and within budget, including critical integration scopes supporting\nthe Scarborough Energy Project. The turnaround involved over 1,500 personnel\non site to deliver a safe lost time injury-free campaign with more than\n400,000 hours worked.\n\nWoodside is operator and holds a 90% participating interest.\n\nNorth West Shelf Project\n\nThe North West Shelf Project (NWS) consists of three offshore platforms and\nthe onshore Karratha Gas Plant (KGP) which includes four onshore LNG\nprocessing trains and two domestic gas trains.\n\nWoodside’s share of production in H1 2026 was 14.0 MMboe. This was a 7%\ndecrease compared with H1 2025 due to natural reservoir decline and impacts\nfrom Severe Tropical Cyclone Narelle.\n\nDespite these impacts, the NWS achieved LNG reliability of 98.7% in H1 2026,\nhighlighting the continued dependability and efficiency of the integrated\nfacilities.\n\nIn H1 2026, the NWS Joint Venture approved the drilling rig contract for the\nGreater Western Flank Phase 4 Project with drilling targeted to commence in\n2027, and targeting first production in 2028.\n\nPreparations are continuing for a planned turnaround for a single LNG Train\ntargeted to commence in September 2026.\n\nThe NWS is continuing with infrastructure retirement planning at KGP while\nmaintaining the capacity to provide processing services for third-party gas.\n\nDuring H1 2026, three legal proceedings continued in the Federal Court of\nAustralia, and one in the Western Australian Supreme Court, associated with\nthe NWS Project Extension Commonwealth and State environmental approvals.\nSubsequent to the period, hearings on the three Federal Court proceedings took\nplace in July 2026, and the Western Australian Supreme Court proceeding is\ncurrently scheduled in Q4 2026.\n\nWoodside is operator and holds a 33.33% participating interest.\n\nFollowing completion of the asset swap agreement with Chevron announced in\n2024, Woodside’s participating interest will increase to 50%. The asset swap\nremains targeted for completion in Q4 2026.(25)\n\nWheatstone and Julimar-Brunello\n\nWheatstone is an LNG processing facility near Onslow, Western Australia,\ncomprising an offshore production platform and two onshore LNG production\ntrains. It processes gas from several offshore gas fields, including Julimar\nand Brunello.\n\nWoodside’s share of Wheatstone production in H1 2026 was 4.4 MMboe. This was\na 30% decrease compared with H1 2025 due to the impacts of Severe Tropical\nCyclone Narelle.\n\nThe Julimar Phase 3 Project, a subsea tie-back to the existing Julimar field\nproduction system, completed its subsea construction and drilling campaign in\nH1 2026 and remains targeted for start-up in H2 2026.\n\nIn parallel, decommissioning of three Julimar–Brunello exploration wells\ncommenced in H1 2026. Completion of both activities are condition precedents\nto the Chevron asset swap.\n\nWoodside is operator and holds a 65% participating interest in the\nJulimar-Brunello fields.\n\nWoodside holds a 13% non-operating participating interest in the Wheatstone\nProject.\n\nFollowing completion of the asset swap agreement with Chevron announced in\n2024, Woodside will no longer have an interest in Wheatstone and\nJulimar-Brunello. The asset swap remains targeted for completion in Q4\n2026.(26)\n\nBass Strait\n\nBass Strait is located in the south east of Australia and produces gas through\na network of offshore platforms, pipelines and onshore processing facilities.\nThe Bass Strait assets include the Gippsland Basin Joint Venture (GBJV) and\nthe Kipper Unit Joint Venture (KUJV).\n\nWoodside’s share of production from Bass Strait was 8.4 MMboe in H1 2026, an\n8% decrease from H1 2025 predominantly due to reduced available capacity\nthrough scheduled maintenance programs and domestic gas demand.\n\nIn H1 2026, drilling of the five wells under the Turrum Phase 3 Project was\ncompleted. The Turrum Phase 3 Project is targeting delivery of gas to the\neastern Australian domestic gas market by H1 2027 from the Turrum and North\nTurrum fields with topsides modifications to the Marlin B platform.\n\nSubsequent to the period, on 1 July 2026, the transfer of operatorship of the\nBass Strait assets from ExxonMobil to Woodside occurred, following the\nsatisfaction of the conditions precedent to the transaction.(27)\n\nWoodside continues to progress technical maturation of four potential\ndevelopment wells that could deliver up to 200 PJ of sales gas to the market.\nTechnical maturity and the impact of the Federal Government’s new domestic\ngas reservation scheme will influence whether these opportunities are\nprogressed to a final investment decision. Subject to a final investment\ndecision, these would be developed solely by Woodside through the Bass Strait\ninfrastructure.\n\nWoodside became operator on 1 July 2026 and holds a 50% participating interest\nin the GBJV and a 32.5% participating interest in the KUJV.\n\nOther Australian oil and gas assets\n\nWoodside operates three floating production storage and offloading (FPSO)\nfacilities off the north west coast of Western Australia. These are the\nNgujima-Yin FPSO (Woodside participating interest: 60%), Pyrenees FPSO\n(Woodside participating interest: 40% in WA-43-L and 71.4% in WA-42-L) and\nOkha FPSO (Woodside participating interest: 50%).\n\nFollowing completion of the asset swap agreement with Chevron announced in\n2024, Woodside’s participating interest in the Okha FPSO will increase to\n66.67%. The asset swap remains targeted for completion in Q4 2026.(26)\n\nWoodside’s share of production from the FPSO assets was 2.2 MMboe in H1\n2026. This was a 39% decrease from H1 2025 primarily due to the planned\nshipyard maintenance and a subsea mooring system defect for the Okha FPSO and\nSevere Tropical Cyclone Narelle impacting in-field infrastructure at Pyrenees\nFPSO.\n\nWoodside also operates Macedon (Woodside participating interest: 71.4%), a gas\nproject located near Onslow, Western Australia which produces pipeline gas for\nthe Western Australian domestic gas market.\n\nWoodside’s share of production from Macedon was 4.0 MMboe, a 5% decrease\nfrom H1 2025 primarily reflecting natural field decline. The Macedon facility\ndelivered approximately 16% of the Western Australian domestic gas market\nsupply in H1 2026.\n\nWoodside Solar\n\nWoodside is progressing a potential opportunity to reduce gross Scope 1\ngreenhouse gas emissions at Pluto LNG by utilising solar energy from the\nproposed Woodside Solar Project.\n\nWoodside continued activities to progress the proposed Woodside Solar Project,\nincluding arrangements to secure access to new and existing common-user\ntransmission infrastructure required to transmit renewable energy to Pluto\nLNG. Development of this infrastructure is being led by the Western Australian\nGovernment and APA Group.\n International operations \n\n\nSangomar\n\nThe Sangomar Field Development Phase 1 is a deepwater project with a\nstand-alone FPSO facility moored approximately 100 km offshore Senegal.\n\nWoodside’s share of production was 15.0 MMboe in H1 2026, a 4% increase from\nH1 2025 due to continued strong reservoir performance, high reliability and\noptimisation of wells, flow lines and system hydraulics.\n\nIn H1 2026, Sangomar continued to deliver strong operational performance,\naveraging 99 Mbbl/d (100% basis, 83 Mbbl/d Woodside share) at 99.5% production\nreliability.(28) Reservoir performance continues to exceed expectations,\nparticularly in the S500 reservoirs. Greater-than-anticipated aquifer pressure\nsupport, combined with well and network optimisation has enabled an extended\ninitial production plateau and reduced the impact of reservoir decline.\nAlthough ongoing optimisation activities continue to moderate decline rates,\nproduction is expected to increasingly reflect the underlying reservoir\ndecline profile.\n\nH1 2026 sales of Sangomar crude oil were directed to Europe and South Asia\nduring the Middle East conflict, attracting strong premiums.\n\nEvaluation of future development opportunities is ongoing. A potential Phase 2\ndevelopment leveraging existing installed capacity would include wells\ntargeting the upper S400 reservoirs. Engagements are ongoing with Petrosen\n(18% participating interest) and the Senegalese Government for Phase 2.\n\nWoodside is operator and has an 82% participating interest.\n\nShenzi\n\nShenzi is a conventional offshore oil and gas field developed through a\ntension leg platform located offshore in the Gulf of America.\n\nWoodside’s share of production in H1 2026 was 4.1 MMboe at 99.1%\nreliability. This was a 12.8% decrease compared with H1 2025 due to natural\nfield decline and reduced pressure support from a major water injector.\n\nWoodside is operator and holds a 72% participating interest.\n\nAtlantis\n\nAtlantis is a conventional offshore oil and gas development in the Gulf of\nAmerica. It includes a semi-submersible facility and is one of the largest\nproducing fields in the United States.\n\nIn H1 2026, water injection commenced on a new well, and the Atlantis Major\nFacility Expansion Project progressed. Subsequent to the period, the Major\nFacility Expansion project achieved start-up. The project added subsea\ninfrastructure and upgraded water injection equipment.\n\nWoodside’s share of production in H1 2026 was 6.3 MMboe. This was a 5%\nincrease compared with H1 2025 due to high reliability and production from the\nDrill Center 1 Expansion which started production in H2 2025.\n\nWoodside holds a 44% non-operating participating interest.\n\nMad Dog\n\nMad Dog is an offshore conventional oil and gas field located in the Gulf of\nAmerica and is currently producing from two offshore facilities, A-Spar and\nArgos. The Argos facility was installed as part of the Mad Dog Phase 2\nProject, an ongoing development of the southern flank of the Mad Dog field.\n\nThe third and final Mad Dog Southwest Extension well was brought online in Q1\n2026, completing the project that began with production from the first\nproduction well in August 2025.\n\nWoodside’s share of production in H1 2026 was 5.8 MMboe. This was a 9%\nincrease compared with H1 2025 due to five new producing wells starting\nproduction over the last 12 months.\n\nWoodside holds a 23.9% non-operating participating interest.\n\nBeaumont New Ammonia\n\nBeaumont New Ammonia (BNA) is a 1.1 Mtpa ammonia synthesis plant located in\nBeaumont, Texas. First production of ammonia commenced in December 2025 and\nWoodside assumed operational control of BNA in March 2026 following successful\ncompletion of performance testing and handover from OCI Global.\n\nWoodside's production in H1 2026 was 279 kT with reliability of 87.6%\nincluding the start-up and commissioning period.(29) Production remained below\ncapacity due to feedstock constraints arising from construction delays at\nthird-party suppliers, with Q2 production averaging 69% of capacity. These\nconstraints are expected to continue into 2027. Lower-carbon ammonia\nproduction remains targeted for 2027, subject to commissioning of Linde’s\nlow-carbon hydrogen facilities and startup of ExxonMobil’s CCS\ninfrastructure, including approval of the relevant CCS permitting process.(30)\n\nWoodside is operator and holds a 100% participating interest.\n Marketing and Trading \n\n\nRevenue and trading\n\nRevenue increased 13% to $7,446 million in H1 2026, reflecting higher average\nrealised prices. Stronger commodity prices amid global supply disruptions,\ntogether with realisation of premiums increased the average realised price to\n$74.0/boe, up 20% compared with H1 2025.\n\nPortfolio optimisation activities captured higher value opportunities across\nmultiple trades, including redirecting Woodside cargoes to higher price\nmarkets, and using third-party purchases to meet long-term customer\ncommitments. The value from these activities are realised as cargoes are\ndelivered, resulting in fluctuations in earnings between reporting periods.\nFurther value from trading activities in H1 2026 is expected to be realised in\nH2 2026.\n\nThe marketing segment delivered EBIT of $54 million in H1 2026, representing\napproximately 3% of total EBIT.(31) Pre-tax hedge losses of $62 million were\nrecognised in the segment, primarily relating to Corpus Christi LNG hedges,\nreducing EBIT.\n\nIn H1 2026, approximately 39% of LNG sold was linked to gas hub indices\nimpacted by lower volumes available due to the Pluto planned turnaround.\n\nShipping\n\nWoodside has signed five long-term time charter parties for LNG vessels all\ncommencing in 2029, and added the Woodside Bilangara to Woodside’s fleet of\nLNG vessels during the period to support the start-up of the Scarborough\nEnergy Project, bringing Woodside’s total number of long-term chartered\nvessels on the water to nine.\n\nPipeline gas\n\nThroughout H1 2026, Western Australia domestic gas spot volume pricing held\nsteady at approximately A$5.50/GJ, not impacted by fluctuations in global\nmarkets.\n\nWoodside executed incremental pipeline gas sales agreements for 58.6 PJ to be\ndelivered to the Western Australian market from 2026 to 2029, including an\nagreement for the supply of 31.1 PJ with Alcoa.\n\nWoodside also executed incremental pipeline gas sales agreements for 47 PJ to\nbe delivered to the east coast of Australia across 2026, 2027 and 2028.\n\nOn the east coast of Australia, Woodside commenced an expression of interest\nfor 20 PJ of Bass Strait supply across 2027 and 2028 and is progressing in\nline with its obligations under its Ministerial Exemption to the Gas Market\nCode. Interest has been received from a wide variety of gas users including\npower generators, retailers and manufacturers with final offers expected in Q3\n2026.\n\nA total of 1,271 TJ of Trucked LNG, equivalent to approximately 1,200\ntrailers, was delivered in H1 2026 to customers in northern Western Australia.\nSince the commencement of operations at the Pluto LNG Truck Loading Facility\nin 2019, Woodside has delivered 6,892 trailers of LNG (7,100 TJ), offering a\nlower-carbon alternative to diesel.\n\nThe Australian Government has released a draft framework for its proposed\nDomestic Gas Reservation Scheme. Woodside is participating in the consultation\nprocess and will continue engaging with government and industry on the design\nof the scheme. It is important that the final arrangements support national\nenergy security, economic growth and ongoing investment in the new gas supply,\nhelping maintain Australia’s position as a reliable energy supplier to\ndomestic and international customers.\n Projects \n\n\nScarborough Energy Project\n\nThe Scarborough gas field is located in the Carnarvon Basin, approximately 375\nkm off the coast of Western Australia.\n\nThe development includes installation of a floating production unit (FPU) with\neight wells drilled in the initial phase and 13 wells drilled over the life of\nthe Scarborough field. Expansion of the Pluto LNG facility includes\nconstruction of a second LNG train (Pluto Train 2), installation of additional\ndomestic gas processing facilities and supporting infrastructure, and\nmodifications to Pluto Train 1 to allow it to process Scarborough gas.\n\nThe project includes the construction of an integrated remote operations\ncentre (IROC) at Woodside’s headquarters. The IROC will have the capacity to\noperate the FPU and the Pluto LNG facility from Perth.\n\nThe project was 98% complete at the end of H1 2026, excluding Pluto Train 1\nmodifications. First LNG cargo is on-track for Q4 2026.\n\nThe FPU achieved significant milestones throughout the first half of 2026. All\nupstream infrastructure is now in place, following completion of FPU mooring\nand hook up to the subsea production system. Subsequent to the period,\nupstream commissioning and preparations for the introduction of hydrocarbons\nwas completed, and the FPU achieved ready for start-up status and first gas.\n\nConstruction and commissioning activities at the Pluto Train 2 site continued,\nincluding completion of the gas turbine generator synchronisation with the\nPluto site power grid and mechanical runs of three of the six liquefaction\ncompressors.\n\nModifications which will allow processing of Scarborough gas through Pluto\nTrain 1 have been ongoing, including successful execution of tie-ins during\nthe Pluto Train 1 planned turnaround in the reporting period. The final module\nfor Pluto Train 1 modifications departed the fabrication yard in Thailand and\nsubsequent to the period, arrived at site. Civil, structural, piping and\nelectrical works continue.\n\nWoodside is operator and holds a 74.9% participating interest in Scarborough,\na 51% participating interest in Pluto Train 2 and a 90% participating interest\nin Pluto Train 1.\n\nTrion\n\nTrion is an offshore oil development located in Mexico, approximately 180 km\noff the Mexican coastline and 30 km south of the United States/Mexico maritime\nborder. The development includes a 24 subsea well development, a\nsemi-submersible FPU capable of producing and transferring 100,000 barrels of\noil per day, and a floating storage and offloading (FSO) facility.\n\nThe project was 64% complete at the end of H1 2026. First oil is targeted for\n2028.\n\nDrilling of 24 subsea wells commenced in March 2026 with three production\nwells drilled during the period.\n\nThe FPU achieved key H1 2026 milestones, including completion of topsides and\nliving quarters lifts onto the hull, and commencement of integration and\npre-commissioning. FSO construction with dry mega block assembly in dry dock\ncontinue to progress in accordance with plan. Fabrication and testing of the\ndisconnectable buoy of the FSO has been completed\n\nSubsea equipment fabrication, including drill centre and central manifolds,\nthree trees, static umbilicals, mooring systems and anchor piles, has been\ncompleted and delivered to Mexico ahead of installation commencing in Q3 2026.\nRemaining subsea production system components are progressing to plan and are\nin the final stages of fabrication.\n\nWoodside is the operator and holds a 60% participating interest.\n\nLouisiana LNG\n\nLouisiana LNG is a fully permitted, under-construction LNG production and\nexport terminal located near Lake Charles, Louisiana. The project is\nstructured as a scalable development with a total permitted capacity of 27.6\nMtpa across five LNG trains and supporting infrastructure.\n\nIn April 2025, Woodside approved an FID to develop the foundation phase of the\nproject, comprising three LNG trains with a capacity of 16.5 Mtpa.\n\nThe foundation development was 28% complete at the end of the period, with\nTrain 1 35% complete, Train 2 25% complete, and Train 3 18% complete. The\nproject is targeting first LNG in 2029.\n\nKey construction progressed during the period included structural steel\nerection and commencement of above-ground piping installation, advancement of\nLNG tanks, and marine infrastructure works, including commissioning of the\nmaterial offloading facility and commencement of dredging.\n\nBechtel sources structural steel for Louisiana LNG from its fabrication\nfacility in the United Arab Emirates. In response to ongoing supply chain\nrisks associated with disruptions in the Middle East, the project is\nproactively assessing and implementing mitigation measures, including\nalternative logistics routes and fabrication sources, to support continuity of\nsteel supply and maintain planned construction schedules beyond 2026.\n\nWoodside completed the transition of Driftwood Pipeline LLC operatorship to\nWilliams, with execution of the Line 200 lateral pipeline progressing under\nWilliams as operator, including advancing engineering, procurement, and right\nof way activities.\n\nWith foundational transportation and storage capacity secured in 2025,\nWoodside continued to advance feed gas procurement in line with its gas supply\nstrategy.\n\nOngoing engagement with high-quality counterparties for equity participation\nand LNG offtake continues to support progress on the Louisiana LNG sell-down\nprocess.\n\nWoodside is operator with a 90% interest in Louisiana LNG LLC. Louisiana LNG\nLLC owns a 60% interest in Louisiana LNG Infrastructure LLC and Woodside is\noperator. Woodside has a 20% non-operating interest in Driftwood Pipeline LLC.\n\nHydrogen Refueller @H2Perth\n\nThe Hydrogen Refueller @H2Perth is a self-contained hydrogen production,\nstorage and refuelling station located in Perth, Western Australia.(32)\n\nCommissioning activities continued on site and the facility has now been\nhanded over to Woodside from the contractor following successful leak testing\nand cold commissioning. Ready for start-up is now targeted for Q3 2026 and\nfirst hydrogen production is targeted for Q4 2026.\n\nWoodside is operator and holds a 100% participating interest.\n Decommissioning \n\n\nWoodside continued execution of planned decommissioning activities in H1 2026,\nspending approximately $274 million across its portfolio.\n\nIn H1 2026, well decommissioning activities continued across multiple assets,\nincluding commencing offshore plug and abandonment (P&A) operations for\neight subsea wells across the North West Shelf and Julimar-Brunello fields,\nwith P&A completed for two wells so far.\n\nOffshore execution has also progressed at the Stybarrow and Griffin fields in\nnorth-west Western Australia. At Stybarrow, more than 18 km of flexible\nflowlines and umbilicals were removed in H1 2026, while approximately 8 km of\nflexible flowlines have been removed from Griffin.\n\nFollowing the completion of planned infrastructure recovery from Enfield in\n2025, a final seabed survey was completed in H1 2026, with results planned to\nbe submitted to the regulator in H2 2026. Consultation with relevant persons\nfor the development of the Environment Plan to remove the remaining Minerva\ninfrastructure was also completed during H1 2026.\n\nAt Bass Strait, GBJV made strong progress on P&A activities during the\nperiod, completing plugging operations on the West Kingfish and Cobia platform\nwells and commencing platform rig operations on the Halibut and Tuna\nplatforms. This completed all P&A activities for platforms scheduled for\nremoval in Bass Strait Offshore Platform Removal Campaign 1, which is set to\ncommence in Q3 2027.\n\nPreparation for the campaign also advanced, with the National Offshore\nPetroleum Safety and Environmental Management Authority accepting the\nEnvironmental Plan and upgrades commencing at the onshore reception centre at\nBarry Beach Marine Terminal.\n Developments and Exploration \n\n\nBrowse\n\nThe Browse development comprises the Calliance, Brecknock and Torosa gas and\ncondensate fields located approximately 425 km north of Broome, Western\nAustralia.\n\nDuring H1 2026, work continued to advance regulatory approvals, advance\ntechnical definition and progress commercial arrangements for processing\nBrowse volumes through the Karratha Gas Plant. Contractors were engaged to\nprogress pre-FEED engineering scopes for the FPSO facilities. Invitations to\ntender for the design and construction of the Browse FPSO facilities were\nissued that will provide market pricing and schedule assumptions to inform a\nFEED entry decision. Engineering studies commenced to assess downstream\nmodifications required for processing Browse gas at Karratha Gas Plant with a\nthree-train development concept.\n\nThe gas processing agreement has been progressed, and will establish the\ncommercial framework and terms for processing Browse gas at the North West\nShelf Project’s Karratha Gas Plant.\n\nWoodside continued to engage with regulators as it progresses the primary\nenvironmental approvals for Browse. In June 2026, following a determination by\nthe Federal Environment Minister that the Browse CCS Project can be assessed\nwholly under the amended Environment Protection and Biodiversity Conservation\nAct 1999 (Cth), Woodside submitted a revised environmental referral to the\nCommonwealth regulator. The resubmission does not involve any significant\nchanges to the nature, scope or intent of the project.\n\nIn June 2026, Woodside exercised its pre-emption right to acquire CNPC's\n10.67% interest in the Browse Joint Venture (BJV). The terms of the\ntransaction include an amount payable on completion of $225 million plus\nreimbursement of CNPC's BJV cash call contributions from 30 June 2025 to\ncompletion. A contingent payment of $175 million is payable upon a final\ninvestment decision for the development of all of the Brecknock, Calliance and\nTorosa fields on or before 30 June 2032.(33)\n\nSubsequent to the period, the Browse to NWS Project was granted State\nSignificant Project status under the Lead Agency Framework by the Western\nAustralian State Government. State Significant Project status provides the\nhighest level of support, helping coordinate engagement on approvals and\nproject development.\n\nWoodside is operator and holds a 30.6% participating interest. Woodside’s\nequity interest in the BJV after completion of the acquisition of CNPC’s\ninterest will increase from 30.6% to 41.27%.\n\nSunrise\n\nThe Sunrise development comprises the Sunrise and Troubadour gas and\ncondensate fields, located approximately 450 km north-west of Darwin and 150\nkm south of Timor-Leste.\n\nThe Sunrise Joint Venture participants continued to engage with the\nGovernments of Timor-Leste and Australia to advance the fiscal and regulatory\nframeworks supporting the potential development of Sunrise.\n\nTechnical and commercial activities progressed under the Timor-Leste\nCooperation Agreement to support maturation of a potential Timor‑based LNG\nconcept.\n\nWoodside is operator and holds a 33.44% participating interest.\n\nCalypso\n\nCalypso is a discovered resource located approximately 220 km off the coast of\nTrinidad in 2,100m water depth.\n\nWoodside is operator and holds a 70% participating interest. Subsequent to the\nperiod, Woodside entered an agreement to divest its 70% operated interest in\nCalypso to joint venture participant bp.(34)\n\nLiard\n\nThe Liard field is an unconventional gas field located in British Columbia,\nCanada.\n\nWoodside holds a 50% non-operating participating interest.\n\nExploration\n\nWoodside’s exploration activities focused on maturing current opportunities,\nconsistent with its disciplined exploration strategy.\n\nIn the US, Woodside was awarded 10 blocks from Gulf of America Lease Sales Big\nBeautiful Gulf 1 and Big Beautiful Gulf 2. Woodside also participated in the\nBandit-1 well which reached total depth during H1 2026 and resulted in a\nMiocene discovery.(35) Post-well analysis continues in order to inform a\npotential appraisal decision. Woodside continued to actively manage its\nacreage position across the central and western Gulf of America.\n\nWoodside continued to pursue disciplined portfolio optimisation, including\nexiting blocks no longer considered prospective. In Australia, the expiry of\nexploration permit WA-28-P concluded 57 years of exploration activity on the\npermit. Woodside also allowed its Marine XX permit to expire offshore the\nRepublic of Congo following the completion of its permit terms.\n\nH2Perth\n\nThe H2Perth Project is a proposal to develop Australia’s first\ncommercial-scale liquid hydrogen production and export facility in Western\nAustralia, located in the Rockingham Industry Zone and Kwinana.\n\nIn May 2026, the Environmental Protection Agency approved Woodside’s\napplication under section 43A of the Environmental Protection Act 1986 (WA) to\namend the proposal for the Project from its previous concept of a liquified\nhydrogen and ammonia production facility to a liquefied hydrogen only\nfacility.\n\nWoodside is operator and holds a 100% participating interest.\n\nNeoSmelt\n\nThe NeoSmelt project aims to demonstrate a potential lower-emissions\nsteelmaking pathway for Pilbara iron ores, involving Direct Reduced Iron and\nElectric Smelting Furnace (DRI-ESF) technology.(36)\n\nDuring the reporting period, work on the pilot plant continued, with the\ndesign phase now approximately 90% complete.\n\nWoodside holds a 20% non-operating participating interest. The other\nparticipants in the project are BHP, BlueScope, Mitsui Iron Ore Development\nand Rio Tinto.\n Carbon solutions \n\n\nCarbon capture and storage (CCS)\n\nWoodside progressed proposed CCS opportunities in Australia and the\nAsia-Pacific, including the operated Angel CCS (Woodside participating\ninterest: 20%) and non-operated Bonaparte CCS opportunities (Woodside\nparticipating interest: 21%).(37)\n\nIn H1 2026, the proposed Angel CCS Project completed engineering studies as\npart of pre-FEED and commenced domestic and international engagement with\npotential customers for CCS services.\n\nThe Bonaparte CCS Assessment Joint Venture, operated by INPEX with\nTotalEnergies and Woodside continues to progress pre-FEED activities.\n\nCarbon credits portfolio\n\nDuring H1 2026, environmental planting activities under Woodside’s Native\nReforestation Project, including site preparation and seedling installation,\nwere carried out on Woodside-owned properties in Western Australia and New\nSouth Wales. Approximately 4,400 hectares are forecast to be planted in 2026\nand these activities were 25% complete at the end of H1 2026.\n Climate and Sustainability \n\n\nHealth, safety and wellbeing\n\nThere were zero fatalities recorded in H1 2026, and zero Tier 1 or Tier 2\nprocess safety events. One high-consequence injury was recorded during the\nperiod, across more than 11 million work hours. The year-to-date lost time\ninjury frequency rate was 0.17, compared with 0.26 for full-year 2025, and the\ntotal recordable injury rate was 2.09, compared to 1.64 recorded for full-year\n2025.\n\nSubsequent to the period, a sustainability focus session was held on 22 July\n2026 with investors on Woodside’s approach to process safety.\n\nIndigenous Peoples cultural heritage and engagement\n\nWoodside continued to engage with around 43 Traditional Owner representative\nbodies in Australia to discuss current and potential future activities. This\nincluded consultation on the Browse to North West Shelf Geophysical and\nGeotechnical Surveys and Minerva Field Decommissioning Environment Plans. In\naddition, archaeological and ethnographic surveys with some Traditional\nCustodians were also undertaken.\n\nSubsequent to the period, the Global Indigenous Peoples Strategy (2025-2030)\nwas launched and is now available on Woodside's website.\n\nSocial and economic impact\n\nWoodside published its 2025 Social Contribution Report in April 2026. The\nreport highlighted the positive impacts of Woodside’s A$39.8 million social\ncontribution in 2025, which was directed through strategic partnerships,\nphilanthropy initiatives, the value of time employees spent volunteering, and\npayments required by government regulations or contractual agreements with\nIndigenous Peoples.\n\nWoodside paid over A$1 billion in Australian taxes, royalties and levies to\nthe Federal and State governments in H1 2026. Additionally Woodside paid more\nthan US$450 million in international corporate taxes, royalties and production\nentitlements in H1 2026 (excludes Australia).\n\nEnvironment and biodiversity\n\nIn H1 2026, there were zero hydrocarbon or hazardous non-hydrocarbon spills\nthat resulted in a moderate environmental impact.(38)\n\nDuring the half, Woodside launched the Sam Houston Jones Restoration Project,\nsupporting restoration of threatened habitats and key wildlife species in\nLouisiana.\n\nIn H1 2026, the Watheroo Biodiversity Project in Western Australia was also\nformally launched, with the establishment of a long-term funding agreement\nwith Department of Biodiversity, Conservation and Attractions.\n\nClimate and the energy transition\n\nIn Q1 2026, Woodside published AASB S2 climate-related disclosures in the 2025\nAnnual Report.\n\nWoodside Sustainability Briefing 2026 was held on 16 March 2026, highlighting\nWoodside’s 2025 sustainability performance with regards to its 2025 material\ntopics.(39) This included content relevant to its 2025 material sustainability\ntopics.\n\nIn H1 2026, Woodside submitted its second annual Oil and Gas Methane\nPartnership 2.0 (OGMP2.0) implementation plan to the United Nations\nEnvironment Programme (UNEP), including first-time Level 5 reporting for\nLéopold Sédar Senghor FPSO and Karratha Gas Plant methane emissions. Level 5\nis OGMP 2.0’s highest data quality standard, requiring reconciliation of\ngranular source-level estimates with independent site-level measurements.\n Directors’ Report \n\n\nThe directors of Woodside Energy Group Ltd present their report (including the\nreview of operations of Woodside Energy Group Ltd and its controlled entities\n(Group) set out on pages 1 – 15 which forms part of this report) together\nwith the Half-Year Financial Statements of the Group.\n\nBoard of directors\n\nThe names of directors in office during or since the end of the 2026 half-year\nare as follows:\n Mr Richard Goyder, AO (Chair) Ms Liz Westcott (CEO and Managing Director) (40) \n Mr Larry Archibald Mr Ashok Belani \n Mr Arnaud Breuillac Ms Swee Chen Goh \n Mr Ben Wyatt, AO Ms Angela Minas \n Mr Mark Cutifani, CBE(41) Ms Ann Pickard \n Mr Ian Macfarlane (retired)(42) Mr Tony O’Neill (resigned)(43) \n\n\nRounding of amounts\n\nWoodside Energy Group Ltd is an entity to which the Australian Securities and\nInvestments Commission (ASIC) Corporations (Rounding in Financial/Directors’\nReports) Instrument 2026/183 (ASIC Instrument 2026/183) applies. Amounts in\nthis report have been rounded in accordance with ASIC Instrument 2026/183.\nThis means that amounts contained in this report have been rounded to the\nnearest million dollars, unless otherwise stated.\n\nAuditor’s Independence Declaration\n\nThe Auditor’s Independence Declaration, as required under section 307C of\nthe Corporations Act 2001, is set out on page 17 and forms part of this\nreport.\n\nSigned in accordance with a resolution of the directors.\n\nR J Goyder, AO\n\nChair\n\nMelbourne, Victoria\n\n25 August 2026\n Auditor’s Independence Declaration to the Directors of Woodside Energy Group \n Ltd \n\n\nAuditor’s Independence Declaration\n\nAs lead auditor of Woodside Energy Group Ltd's financial report for the\nhalf-year ended 30 June 2026, I declare that, to the best of my knowledge and\nbelief, there have been:\n\n\n 1. no contraventions of the auditor independence requirements of the Corporations\nAct 2001 in relation to the review of the financial report; and\n\n 2. no contraventions of any applicable code of professional conduct in relation\nto the review of the financial report.\n N M Henry   Perth, Western Australia \n \nPartner \n25 August 2026 \n \nPricewaterhouseCoopers \n     \n pwc.com.au   PricewaterhouseCoopers, ABN 52 780 433 757 \n \n \n \nBrookfield Place, Level 15, 125 St Georges Terrace, PERTH WA 6000, \n \n \n \nGPO Box D198, PERTH WA 6840 \n \n \n \nT: +61 8 9238 3000, F: +61 8 9238 3999, www.pwc.com.au \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.pwc.com.au&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.pwc.com.au&index=1&md5=887b31b74b98ff31b725a32425bd7c7f) \n \n \n \n  \n \n \n \nLiability limited by a scheme approved under Professional Standards \n Legislation. \n\n\nHALF-YEAR FINANCIAL STATEMENTS\n\nfor the half-year ended 30 June 2026\n\nCONTENTS\n CONDENSED CONSOLIDATED INCOME STATEMENT 20 \n CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME 21 \n CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION 22 \n CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS 23 \n CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY 24 \n NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 25 \n A. Earnings for the period 27 \n A.1 Segment revenue and expenses 27 \n A.2 Finance costs 28 \n A.3 Dividends paid and proposed 28 \n A.4 Earnings per share 28 \n A.5 Taxes 29 \n B. Production and growth assets 30 \n B.1 Exploration and evaluation assets 30 \n B.2 Property, plant and equipment 31 \n B.3 Impairment of exploration and evaluation assets, property, plant and 32 \n equipment and goodwill \n B.4 Intangible assets 33 \n B.5 Transactions with equity holders of the Group 34 \n C. Debt and capital 35 \n C.1 Interest-bearing liabilities and financing facilities 35 \n C.2 Contributed equity 36 \n D. Other assets and liabilities 37 \n D.1 Segment assets and liabilities 37 \n D.2 Provisions 38 \n D.3 Other financial assets and liabilities 39 \n E. Other items 41 \n E.1 Contingent liabilities and assets 41 \n E.2 New standards and interpretations 41 \n E.3 Events after the end of the reporting period 41 \n E.4 Subsidiaries 42 \n DIRECTORS’ DECLARATION 44 \n INDEPENDENT AUDITOR’S REVIEW REPORT 45 \n\n\nSignificant changes in the current reporting period\n\nThe financial performance and position of the Group were affected by the\nfollowing:\n\n\n * Geopolitical developments in the Middle East contributed to increased\nvolatility in oil and LNG prices and broader market uncertainty during the\nperiod. The full impact of higher LNG prices has not yet been realised due to\nlagged pricing mechanisms.\n\n * In July 2025, the Group completed the disposal of the Greater Angostura assets\nin Trinidad and Tobago to Perenco Energies International Limited (Perenco),\nwhich impacted revenue for the first half of 2026 relative to the comparative\nperiod, when the assets contributed $145m of revenue.\n\n * The Group recognised an additional $596 million in Pluto PRRT deferred tax\nassets and a $90 million income tax deferred tax asset relating to heritage\nWoodside US net operating loss carryforwards (Refer to Note A.5).\n\n * As at 30 June 2026, the Group recognised impairment losses of $178 million,\ncomprising $135 million on the Calypso exploration and evaluation asset\nfollowing the decision to divest its 70% operated interest in the Calypso\nProject, and $43 million on the H2OK Project following the decision to retire\nthe assets (Refer to Note B.3).\n\n * The Group recognised $138 million of other income from the release of deferred\nincome associated with the Pluto Train 2 Global Infrastructure Partners (Pluto\nTrain 2 GIP) transaction, reflecting updated expectations that potential\nconstruction cost overruns and liquidated damages will not crystallise.\n\n * The Group recognised approximately $655 million of new lease liabilities,\nprimarily relating to the three-year leases for the Trion drilling campaign\nand the Woodside Bilangara vessel.\n CONDENSED CONSOLIDATED INCOME STATEMENT \n \n \n \n  \n \n \n \nfor the half-year ended 30 June 2026 \n   \n     2026 2025 \n   Notes US$m US$m \n Operating revenue A.1 7,446 6,590 \n Cost of sales A.1 (4,604) (4,045) \n Gross profit   2,842 2,545 \n Other income A.1 264 379 \n Other expenses A.1 (771) (964) \n Impairment losses A.1 (178) (143) \n Profit before tax and net finance costs   2,157 1,817 \n Finance income   123 106 \n Finance costs A.2 (245) (169) \n Profit before tax   2,035 1,754 \n Petroleum resource rent tax (PRRT) benefit/(expense) A.5 305 (71) \n Income tax expense A.5 (667) (353) \n Profit after tax   1,673 1,330 \n Profit attributable to:       \n Equity holders of the parent   1,672 1,316 \n Non-controlling interest E.4 1 14 \n Profit for the period   1,673 1,330 \n Basic earnings per share attributable to equity holders of the parent (US A.4 88.2 69.4 \n cents) \n Diluted earnings per share attributable to equity holders of the parent (US A.4 87.3 68.8 \n cents) \n   \n The accompanying notes form part of the half-year financial statements. \n\n CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME \n \n \n \n  \n \n \n \nfor the half-year ended 30 June 2026 \n   \n   2026 2025 \n   US$m US$m \n Profit for the period 1,673 1,330 \n Other comprehensive (loss)/income     \n Items that may be reclassified to the income statement in subsequent periods:     \n (Losses)/gains on cash flow hedges (526) 289 \n Gains on cash flow hedges reclassified to the income statement (72) (16) \n Tax recognised within other comprehensive income 149 (57) \n Items that will not be reclassified to the income statement in subsequent     \n periods: \n Remeasurement gain on defined benefit plan 3 2 \n Net loss on financial instruments at fair value through other comprehensive — (33) \n income \n Other comprehensive (loss)/income for the period, net of tax (446) 185 \n Total comprehensive income for the period 1,227 1,515 \n Total comprehensive income attributable to:     \n Equity holders of the parent 1,226 1,501 \n Non-controlling interest 1 14 \n Total comprehensive income for the period 1,227 1,515 \n   \n The accompanying notes form part of the half-year financial statements. \n\n CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION \n \n \n \n  \n \n \n \nas at 30 June 2026 \n   \n     30 June 2026 31 December 2025 \n   Notes US$m US$m \n Current assets       \n Cash and cash equivalents   4,339 5,712 \n Receivables   1,928 1,751 \n Inventories   579 693 \n Other financial assets D.3 119 229 \n Tax receivable   184 114 \n Other assets   47 123 \n Total current assets   7,196 8,622 \n Non-current assets       \n Receivables   771 823 \n Inventories   371 288 \n Other financial assets D.3 109 64 \n Exploration and evaluation assets B.1 710 790 \n Property, plant and equipment B.2 47,797 46,555 \n Deferred tax assets   3,288 2,658 \n Lease assets   1,795 1,428 \n Investments accounted for using the equity method   272 260 \n Intangible assets B.4 4,856 4,853 \n Other assets   516 160 \n Total non-current assets   60,485 57,879 \n Total assets   67,681 66,501 \n Current liabilities       \n Payables   1,779 1,841 \n Interest-bearing liabilities C.1 983 782 \n Other financial liabilities D.3 148 8 \n Provisions D.2 1,238 1,212 \n Tax payable   500 539 \n Lease liabilities   303 159 \n Other liabilities   229 876 \n Total current liabilities   5,180 5,417 \n Non-current liabilities       \n Interest-bearing liabilities C.1 10,387 11,181 \n Deferred tax liabilities   1,273 1,182 \n Other financial liabilities D.3 363 212 \n Provisions D.2 6,397 6,655 \n Tax payable   10 10 \n Lease liabilities   1,995 1,600 \n Other liabilities   352 401 \n Total non-current liabilities   20,777 21,241 \n Total liabilities   25,957 26,658 \n Net assets   41,724 39,843 \n Equity       \n Issued and fully paid shares C.2 29,036 29,036 \n Shares reserved for employee share plans C.2 (72) (82) \n Other reserves   6,034 6,382 \n Retained earnings   1,053 578 \n Equity attributable to equity holders of the parent   36,051 35,914 \n Non-controlling interest E.4 5,673 3,929 \n Total equity   41,724 39,843 \n   \n The accompanying notes form part of the half-year financial statements. \n\n CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS \n \n \n \n  \n \n \n \nfor the half-year ended 30 June 2026 \n   \n     2026 2025 \n   Notes US$m US$m \n Cash flows from/(used in) operating activities       \n Profit after tax for the period   1,673 1,330 \n Adjustments for:       \n Non-cash items       \n Depreciation and amortisation   2,223 2,555 \n Depreciation of lease assets   89 85 \n Change in fair value of derivative financial instruments   176 (206) \n Net finance costs   122 63 \n Tax expense   362 424 \n Impairment losses B.3 178 143 \n Restoration movement   (5) 445 \n Other   (143) (99) \n Changes in assets and liabilities       \n (Increase)/decrease in trade and other receivables   (65) 122 \n Decrease/(increase) in inventories   31 (65) \n Decrease in provisions   (129) (112) \n (Decrease)/increase in other assets and liabilities   (363) 103 \n Decrease in trade and other payables   (62) (186) \n Cash generated from operations   4,087 4,602 \n Interest received   109 89 \n Borrowing costs relating to operating activities   (84) (5) \n Income tax and PRRT paid   (825) (782) \n Payments for restoration   (274) (565) \n Net cash from operating activities   3,013 3,339 \n Cash flows (used in)/from investing activities       \n Cash paid relating to business combination(1)   (470) — \n Payments for capital and exploration expenditure   (3,673) (4,881) \n Reimbursements received from external parties for capital expenditure   181 236 \n Borrowing costs relating to investing activities   (297) (330) \n Deposits received from disposal of non-current assets   — 21 \n (Contributions to)/dividends from associates   (27) 17 \n Net cash used in investing activities   (4,286) (4,937) \n Cash flows (used in)/from financing activities       \n Proceeds from borrowings C.1 — 4,849 \n Repayment of borrowings C.1 (602) (2,900) \n Purchases of shares relating to employee share plans   — (26) \n Repayment of the principal portion of lease liabilities   (111) (108) \n Borrowing costs relating to lease liabilities   (1) (1) \n Contributions from/to non-controlling interests(2)   1,737 1,843 \n Dividends paid   (1,122) (1,006) \n Net cash (used in)/from financing activities   (99) 2,651 \n Net (decrease)/increase in cash held   (1,372) 1,053 \n Less: Cash and cash equivalents classified within assets held for sale   — (108) \n Cash and cash equivalents at the beginning of the period   5,712 3,923 \n Effects of exchange rate changes   (1) 12 \n Cash and cash equivalents at the end of the period   4,339 4,880 \n 1. Relates to the final acquisition completion payment for Beaumont New Ammonia. \n \n2. Includes capital contribution of $1,668 million (2025: $1,870 million) from \n Stonepeak and $57 million (2025: nil) from Williams for the development of \n Louisiana LNG. Refer to Note B.5 for the transactions with equity holders of \n the Group. \n The accompanying notes form part of the half-year financial statements. \n\n CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY \n \n \n \n  \n \n \n \nfor the half-year ended 30 June 2026 \n   \n   Issued and fully paid shares Reserved shares Employee benefits reserve Non-controlling interest reserve Foreign currency translation reserve Hedging reserve Distributable profits reserve Other reserve Retained earnings Equity holders of the parent Non-controlling interest Total equity \n Notes C.2 C.2                 E.4   \n   US$m US$m US$m US$m US$m US$m US$m US$m US$m US$m US$m US$m \n At 1 January 2026 29,036 (82) 287 (373) 795 188 5,557 (72) 578 35,914 3,929 39,843 \n Profit for the period — — — — — — — — 1,672 1,672 1 1,673 \n Other comprehensive (loss)/income — — — — — (449) — — 3 (446) — (446) \n Total comprehensive (loss)/income for the period — — — — — (449) — — 1,675 1,226 1 1,227 \n Transfers — — — — — — 1,200 — (1,200) — — — \n Transactions with non-controlling interests(1) — — — (20) — — — — — (20) 1,754 1,734 \n Employee share plan redemptions — 10 (10) — — — — — — — — — \n Share-based payments (net of tax) — — 53 — — — — — — 53 — 53 \n Dividends paid — — — — — — (1,122) — — (1,122) (11) (1,133) \n At 30 June 2026 29,036 (72) 330 (393) 795 (261) 5,635 (72) 1,053 36,051 5,673 41,724 \n At 1 January 2025 29,001 (58) 281 — 795 1 3,069 (38) 2,348 35,399 754 36,153 \n Profit for the period — — — — — — — — 1,316 1,316 14 1,330 \n Other comprehensive income/(loss) — — — — — 216 — (33) 2 185 — 185 \n Total comprehensive income/(loss) for the period — — — — — 216 — (33) 1,318 1,501 14 1,515 \n Transfers — — — — — — 3,000 — (3,000) — — — \n Transactions with non-controlling interests(1) — — — (270) — — — — — (270) 2,140 1,870 \n Employee share plan purchases — (26) — — — — — — — (26) — (26) \n Employee share plan redemptions — 13 (13) — — — — — — — — — \n Share-based payments (net of tax) — — 41 — — — — — — 41 — 41 \n Dividends paid — — — — — — (1,006) — — (1,006) (40) (1,046) \n At 30 June 2025 29,001 (71) 309 (270) 795 217 5,063 (71) 666 35,639 2,868 38,507 \n 1. Represents the difference between the amount of the adjustment to \n non-controlling interest and any consideration received. Refer to Note B.5 for \n the transactions with equity holders of the Group. \n \n The accompanying notes form part of the half-year financial statements. \n\n\nNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS\n\nfor the half-year ended 30 June 2026\n\nAbout these statements\n\nWoodside Energy Group Ltd (Woodside or the Group) is a for-profit entity\nlimited by shares, incorporated and domiciled in Australia. Its shares are\npublicly traded on the Australian Securities Exchange (ASX) and on the New\nYork Stock Exchange (NYSE) (in the form of Woodside American Depositary\nShares). The nature of the operations and principal activities of the Group\nare described in the Australia Operations, International Operations, Marketing\nand Trading, Projects, Decommissioning, Developments and Exploration and\nCarbon Solutions sections.\n\nThe condensed consolidated half-year financial statements were authorised for\nissue in accordance with a resolution of the directors on 25 August 2026.\n\nStatement of compliance\n\nThe condensed consolidated half-year financial statements are condensed\ngeneral purpose financial statements, which have been prepared in accordance\nwith Australian Accounting Standard (AASB) 134 Interim Financial Reporting as\nissued by the Australian Accounting Standards Board and the Australian\nCorporations Act 2001. These condensed consolidated half-year financial\nstatements also comply with International Accounting Standard (IAS) 34 Interim\nFinancial Reporting as issued by the International Accounting Standards Board.\n\nThe condensed consolidated half-year financial statements do not include all\nnotes of the type normally included in annual financial statements.\nAccordingly, these condensed consolidated half-year financial statements are\nto be read in conjunction with the Financial Statements within the Annual\nReport for the year ended 31 December 2025 (2025 Financial Statements).\n\nThe Group’s accounting policies are materially consistent with those\ndisclosed in the Group’s 2025 Financial Statements. Adoption of new or\namended standards and interpretations effective 1 January 2026 did not result\nin any significant changes to the Group’s accounting policies. Refer to Note\nE.2 for more details.\n\nThe significant accounting estimates and judgements are consistent with those\ndisclosed in the 2025 Financial Statements. Estimates have been revised, where\nrequired, to reflect current market conditions including the impact of climate\nchange.\n\nCurrency\n\nThe functional and presentation currency of Woodside and all its material\nsubsidiaries is US dollars.\n\nTransactions in foreign currencies are initially recorded in the functional\ncurrency of the transacting entity at the exchange rates ruling at the date of\ntransaction. Monetary assets and liabilities denominated in foreign currencies\nat the reporting date are translated at the rates of exchange ruling at that\ndate. Exchange differences in the consolidated financial statements are taken\nto the condensed consolidated income statement.\n\nRounding of amounts\n\nThe amounts contained in the condensed consolidated half-year financial\nstatements have been rounded to the nearest million dollars under the option\navailable to the Group under Australian Securities and Investments Commission\n(ASIC) Corporations (Rounding in Financial/Directors’ Reports) Instrument\n2026/183 dated 24 March 2026, unless otherwise stated.\n\nBasis of preparation\n\nThe condensed consolidated half-year financial statements have been prepared\non an historical cost basis, except for derivative financial instruments and\ncertain other financial assets and financial liabilities, which have been\nmeasured at fair value adjusted for changes in fair value attributable to the\nrisks that are being hedged in effective hedge relationships. Where not\ncarried at fair value, if the carrying value of financial assets and financial\nliabilities does not approximate their fair value, the fair value has been\nincluded in the notes to the condensed consolidated half-year financial\nstatements.\n\nThe condensed consolidated half-year financial statements comprise the\nfinancial results of the Group for the period ended 30 June 2026. Subsidiaries\nare fully consolidated from the date on which control is obtained by the Group\nand cease to be consolidated from the date at which the Group ceases to have\ncontrol.\n\nThe material subsidiaries of the Group apply the same reporting period and\naccounting policies as the parent company in preparation of the condensed\nconsolidated half-year financial statements. All intercompany balances and\ntransactions, including unrealised profits and losses arising from intra-group\ntransactions, have been eliminated in full.\n\nNon-controlling interests are allocated their share of the net profit after\ntax in the condensed consolidated income statement; their share of other\ncomprehensive income, net of tax, in the condensed consolidated statement of\ncomprehensive income; and are presented within equity in the condensed\nconsolidated statement of financial position, separately from parent\nshareholders’ equity.\n\nComparative information\n\nThe condensed consolidated half-year financial statements provide comparative\ninformation in respect of the previous period. Where required, a\nreclassification of items in the financial statements of the previous period\nhas been made in accordance with the classification of items in the condensed\nconsolidated half-year financial statements of the current period. Refer to\nNote A.1 for more details.\n\nReporting segments\n\nRefer to the 2025 Financial Statements for details of the Group’s operating\nsegment information.\n\nA. Earnings for the period\n\nA.1 Segment revenue and expenses\n   Australia International Marketing Corporate Consolidated \n   2026 2025 2026 2025 2026 2025 2026 2025 2026 2025 \n   US$m US$m US$m US$m US$m US$m US$m US$m US$m US$m \n Liquified natural gas 2,189 2,417 — — 836 522 — — 3,025 2,939 \n Pipeline gas 565 564 20 141 — — — — 585 705 \n Crude oil and condensate 784 683 2,515 2,011 142 13 — — 3,441 2,707 \n Natural gas liquids 115 90 17 18 2 9 — — 134 117 \n Ammonia — — 171 — — — — — 171 — \n Revenue from sale of products 3,653 3,754 2,723 2,170 980 544 — — 7,356 6,468 \n Intersegment revenue(1) (101) (9) — — 101 9 — — — — \n Processing and services revenue 88 109 — — — — — — 88 109 \n Shipping and other revenue — — — — 2 13 — — 2 13 \n Other revenue (13) 100 — — 103 22 — — 90 122 \n Operating revenue(2) 3,640 3,854 2,723 2,170 1,083 566 — — 7,446 6,590 \n Production costs(3) (539) (399) (210) (268) — — — — (749) (667) \n Feed gas, services and processing costs(3) (92) (92) (146) — — — — — (238) (92) \n Royalties, excise and levies (134) (126) (9) (30) — — — — (143) (156) \n Insurance (16) (19) (11) (8) — — (6) (10) (33) (37) \n Inventory movement (77) (7) 23 6 — — — — (54) (1) \n Costs of production (858) (643) (353) (300) — — (6) (10) (1,217) (953) \n Property, plant and equipment depreciation (1,032) (1,170) (1,150) (1,340) — — (27) (31) (2,209) (2,541) \n Shipping and direct sales costs (70) (36) (53) (41) (54) (43) — — (177) (120) \n Trading costs (101) (88) — — (871) (322) — — (972) (410) \n Other hydrocarbon costs (10) (6) — — — — — — (10) (6) \n Other (14) (15) (5) — — — — — (19) (15) \n Other cost of sales (195) (145) (58) (41) (925) (365) — — (1,178) (551) \n Cost of sales (2,085) (1,958) (1,561) (1,681) (925) (365) (33) (41) (4,604) (4,045) \n Gross profit/(loss) 1,555 1,896 1,162 489 158 201 (33) (41) 2,842 2,545 \n Other income(4) 230 82 8 67 12 (9) 14 239 264 379 \n Exploration and evaluation expenditure (26) (10) (73) (71) — — — — (99) (81) \n Amortisation of permit acquisitions — — (4) (3) — — — — (4) (3) \n Write-offs — — (1) — — — — — (1) — \n Exploration and evaluation (26) (10) (78) (74) — — — — (104) (84) \n General, administration and other costs (28) (15) (46) (8) — (1) (168) (237) (242) (261) \n Amortisation of intangible assets — — (1) — — — (9) (11) (10) (11) \n Depreciation of lease assets (12) (18) (3) (1) (44) (39) (30) (27) (89) (85) \n Restoration movement 3 (443) 2 (2) — — — — 5 (445) \n Other(5) (58) (19) (26) (2) (72) (8) (175) (49) (331) (78) \n Other costs (95) (495) (74) (13) (116) (48) (382) (324) (667) (880) \n Other expenses (121) (505) (152) (87) (116) (48) (382) (324) (771) (964) \n Impairment losses(6) — — (135) — — — (43) (143) (178) (143) \n Profit/(loss) before tax and net finance costs 1,664 1,473 883 469 54 144 (444) (269) 2,157 1,817 \n 1. Intersegment revenue reflects the margin recognised on products and services \n transferred between segments. \n \n2. Operating revenue includes revenue from contracts with customers of $7,444 \n million (2025: $6,577 million) and sub-lease income of $2 million (2025: $13 \n million) disclosed within shipping and other revenue. \n \n3. In 2026, feed gas, services and processing-related costs are presented \n separately to better reflect underlying activities of the Group. In the 2025 \n Financial Statements, these costs were included within production costs. \n \n4. Includes $138 million of released deferred income associated with the Pluto \n Train 2 GIP transaction and other income not associated with the ongoing \n operations of the business. The 2025 amount includes a $162 million unrealised \n fair value gain on the Perdaman-related embedded derivatives, $32 million net \n gain on hedging activities, fees, recoveries and other income not associated \n with the ongoing operations of the business. \n \n5. Includes $135 million unrealised fair value loss on the Perdaman-related \n embedded derivatives, $71 million net loss on hedging activities and other \n items not associated with the ongoing operations of the business. \n \n6. Includes $135 million (2025: nil) relating to the impairment of the Calypso \n exploration and evaluation asset and $43 million (2025: $143 million) relating \n to the impairment of the H2OK Project. Refer to Note B.3 for details on \n impairment. \n\n\nA.2 Finance costs\n   2026 2025 \n   US$m US$m \n Interest on interest-bearing liabilities 303 281 \n Interest on lease liabilities 65 51 \n Accretion charge 156 148 \n Other finance costs 17 29 \n Less: Borrowing costs capitalised against qualifying assets (296) (340) \n Total finance costs 245 169 \n\n\nA.3 Dividends paid and proposed\n\nWoodside Energy Group Ltd, the parent entity, paid and proposed dividends as\nset out below:\n   2026 2025 \n   US$m US$m \n (a) Dividends paid during the financial year     \n Prior year fully franked final dividend US$0.59, paid on 27 March 2026 (2025: 1,122 1,006 \n US$0.53, paid on 2 April 2025) \n (b) Dividend determined subsequent to the reporting period (not recorded as a     \n liability) \n Current year fully franked interim dividend US$0.57 to be paid on 25 September 1,084 1,006 \n 2026 \n \n \n \n(2025: US$0.53 to be paid on 24 September 2025) \n\n\nA.4 Earnings per share\n   2026 2025 \n Profit attributable to equity holders of the parent (US$m) 1,672 1,316 \n Weighted average number of shares on issue for basic earnings per share 1,896,068,066 1,895,162,804 \n Effect of dilution from contingently issuable shares 19,457,286 17,049,593 \n Weighted average number of shares on issue adjusted for the effect of dilution 1,915,525,352 1,912,212,397 \n Basic earnings per share (US cents) 88.2 69.4 \n Diluted earnings per share (US cents) 87.3 68.8 \n Earnings per share is calculated by dividing the profit for the period \n attributable to ordinary equity holders of the parent by the weighted average \n number of shares on issue during the period. The weighted average number of \n shares makes allowance for shares reserved for employee share plans. Diluted \n earnings per share is calculated by adjusting basic earnings per share by the \n number of ordinary shares that would be issued on conversion of all the \n dilutive potential ordinary shares into ordinary shares. \n\n\nA.5 Taxes\n   2026 2025 \n   US$m US$m \n Reconciliation of income tax expense/(benefit)     \n Profit before tax 2,035 1,754 \n PRRT benefit/(expense) 305 (71) \n Profit before income tax 2,340 1,683 \n Income tax expense calculated at 30% 702 505 \n Effect of tax rate differentials 41 42 \n Effect of deferred tax assets not recognised 50 12 \n Effect of tax benefits previously unrecognised (90) (193) \n Foreign exchange impact on tax expense/(benefit) 28 (35) \n Adjustment to prior years (41) 4 \n Other (23) 18 \n Income tax expense 667 353 \n   \n The global operations effective income tax rate (EITR) of 28.5% (2025: 21.0%) \n is calculated as the Group’s income tax expense divided by profit before \n income tax. The underlying EITR is 29.6% when excluding the recognition of \n additional Pluto PRRT deferred tax asset, income tax deferred tax asset \n relating to US net operating losses and impairment losses. \n \n \n \n  \n \n \n \nDuring the period, the Group recognised an additional PRRT deferred tax asset \n of $596 million ($417 million post tax) for the Pluto project, reflecting \n increased expected utilisation of available PRRT deductions driven by the \n higher pricing environment. The Group also recognised a $90 million income tax \n deferred tax asset in respect of heritage Woodside US net operating loss \n carryforwards, as utilisation of those losses is now considered probable. \n\n\nB. Production and growth assets\n\nB.1 Exploration and evaluation assets\n   Asia Pacific Americas Africa Total \n   US$m US$m US$m US$m \n Half-year ended 30 June 2026         \n Carrying amount at 1 January 2026 582 207 1 790 \n Additions 18 47 — 65 \n Amortisation of licence acquisition costs — (4) — (4) \n Expensed — (1) — (1) \n Impairment(1) — (135) — (135) \n Transferred exploration and evaluation (5) — — (5) \n Carrying amount at 30 June 2026 595 114 1 710 \n           \n Year ended 31 December 2025         \n Carrying amount at 1 January 2025 571 149 1 721 \n Additions 17 67 — 84 \n Amortisation of licence acquisition costs — (5) — (5) \n Expensed — (4) — (4) \n Transferred exploration and evaluation (6) — — (6) \n Carrying amount at 31 December 2025 582 207 1 790 \n 1. Refer to Note B.3 for details of impairment of the Calypso exploration and \n evaluation asset. \n\n\nB.2 Property, plant and equipment\n   Land and buildings Oil and gas properties Projects in development(1) Other plant and equipment Total \n   US$m US$m US$m US$m US$m \n Half-year ended 30 June 2026           \n Carrying amount at 1 January 2026 744 23,091 22,437 283 46,555 \n Additions(2) — 9 3,492 — 3,501 \n Disposals at written down value — — (12) — (12) \n Impairment loss(3) — — (43) — (43) \n Completions and transfers(4) 136 398 (2,010) 1,481 5 \n Depreciation (32) (2,135) — (42) (2,209) \n Carrying amount at 30 June 2026 848 21,363 23,864 1,722 47,797 \n At 30 June 2026           \n Historical cost 2,035 59,227 24,389 2,201 87,852 \n Accumulated depreciation and impairment (1,187) (37,864) (525) (479) (40,055) \n Carrying amount 848 21,363 23,864 1,722 47,797 \n Year ended 31 December 2025           \n Carrying amount at 1 January 2025 734 25,787 15,926 189 42,636 \n Adjustment to purchase price allocation (21) — (9) — (30) \n Additions — 657 8,658 10 9,325 \n Disposals at written down value (6) (44) (143) (3) (196) \n Impairment loss — — (143) — (143) \n Completions and transfers 98 1,609 (1,852) 151 6 \n Depreciation (61) (4,918) — (64) (5,043) \n Carrying amount at 31 December 2025 744 23,091 22,437 283 46,555 \n At 31 December 2025           \n Historical cost 1,899 58,820 22,919 720 84,358 \n Accumulated depreciation and impairment (1,155) (35,729) (482) (437) (37,803) \n Carrying amount 744 23,091 22,437 283 46,555 \n 1. Projects in development include the fair value ascribed to future phases of \n certain projects acquired through business combinations. \n \n2. Includes $3,243 million of capital additions, $296 million of capitalised \n borrowing costs, and $26 million relating to changes in restoration provision \n assumptions. Included within capital additions is $1,595 million relating to \n the Louisiana LNG Project. \n \n3. Refer to Note B.3 for details of impairment of the H2OK Project. \n \n4. Primarily reflects the transfer of the Beaumont New Ammonia (BNA) Project \n carrying amount from projects in development to other plant and equipment \n following completion in March 2026.  \n \n \n   \n The Group has capital commitments contracted for, but not provided for in the \n financial statements, of $9,699 million (31 December 2025: $11,957 million). \n Capital commitments relate predominantly to the Louisiana LNG and Trion \n Projects (31 December 2025: Louisiana LNG, Trion and Scarborough Energy \n Projects). Capital commitments for Louisiana LNG totalling $8,170 million (31 \n December 2025: $9,986 million) are shared between the Group, Stonepeak and \n Williams based on their respective interests in the project. Under the \n transaction arrangements, Stonepeak has committed up to $5,700 million to fund \n its share of the capital expenditure associated with the foundation \n development of Louisiana LNG. Refer to Note B.5 for details of the sell-down \n arrangement with Stonepeak and the contributions made by Stonepeak to date. \n\n\nB.3 Impairment of exploration and evaluation assets, property, plant and\nequipment and goodwill\n\nImpairment of Calypso exploration and evaluation asset\n\nAs at 30 June 2026, the Calypso exploration and evaluation asset was assessed\nas not fully recoverable following the Group's decision to pursue a divestment\nof its 70% operated interest in the Calypso Project. Consequently, an\nimpairment loss of $135 million (2025: nil) was recognised in the\nInternational segment of Note A.1 for the half-year ended 30 June 2026. Refer\nto Note E.3 for details of the subsequent agreement to sell the Group's\ninterest in the Calypso Project.\n\nImpairment of H2OK Project\n\nAs at 30 June 2026, the remaining H2OK Project assets were assessed as not\nrecoverable following the decision to retire the assets. Consequently, an\nimpairment loss before tax of $43 million (2025: $143 million) was recognised\nin the Corporate segment of Note A.1 for the half-year ended 30 June 2026\nreducing the carrying value of the assets to nil.\n\nB.4 Intangible assets\n   Goodwill Contract assets Software Total \n   US$m US$m US$m US$m \n Half-year ended 30 June 2026         \n Carrying amount at 1 January 2026 3,952 714 187 4,853 \n Additions – – 18 18 \n Amortisation – (2) (8) (10) \n Disposals – (5) – (5) \n Carrying amount at 30 June 2026 3,952 707 197 4,856 \n At 30 June 2026         \n Cost 4,429 796 238 5,463 \n Accumulated amortisation and impairment (477) (89) (41) (607) \n Carrying amount 3,952 707 197 4,856 \n Year ended 31 December 2025         \n Carrying amount at 1 January 2025 3,866 757 203 4,826 \n Adjustment to purchase price allocation 86 30 – 116 \n Additions – – 2 2 \n Amortisation – (73) (18) (91) \n Carrying amount at 31 December 2025 3,952 714 187 4,853 \n At 31 December 2025         \n Cost 4,429 814 220 5,463 \n Accumulated amortisation and impairment (477) (100) (33) (610) \n Carrying amount 3,952 714 187 4,853 \n   \n\n\nB.5 Transactions with equity holders of the Group\n\nSell-down arrangement with Stonepeak\n\nDuring 2025, the Group and Stonepeak entered into an agreement for Stonepeak\nto acquire a 40% interest in Louisiana LNG Infrastructure LLC, a subsidiary\nwithin the Group. Stonepeak will provide up to $5,700 million towards the\nexpected capital expenditure for the foundation development of Louisiana LNG\non an accelerated basis, contributing 75% of the expected project capital\nexpenditure in both 2025 and 2026. As at 30 June 2026, total payment of $4,262\nmillion was received.\n\nUnder the agreement, the Group still controls Louisiana LNG Infrastructure\nLLC, while Stonepeak now holds a non-controlling interest. Transactions that\ndo not result in the Group's loss of control are treated as equity\ntransactions. When ownership percentages change, the carrying amounts of both\ncontrolling and non-controlling interests are adjusted based on their relative\ninterest in the subsidiary. Any difference between the adjustment to\nnon-controlling interests and consideration received is recorded in a separate\nequity reserve. Stonepeak’s non-controlling interest percentage is based on\nthe proportion of total contributions to date and will fluctuate during the\nconstruction phase. The non-controlling interest percentage will to revert to\n40% when the project starts generating revenue. Refer to Note E.4\nSubsidiaries.\n\nC. Debt and capital\n\nC.1 Interest-bearing liabilities and financing facilities\n   Bilateral facilities Syndicated facilities JBIC facility US bonds Medium term notes Total \n   US$m US$m US$m US$m US$m US$m \n Half-year ended 30 June 2026             \n At 1 January 2026 (4) 2,232 1,000 8,535 200 11,963 \n Repayments(1) — (600) — — — (600) \n Transaction costs capitalised and amortised (1) 2 — 6 — 7 \n Carrying amount at 30 June 2026 (5) 1,634 1,000 8,541 200 11,370 \n Current (2) (4) — 789 200 983 \n Non-current (3) 1,638 1,000 7,752 — 10,387 \n Carrying amount at 30 June 2026 (5) 1,634 1,000 8,541 200 11,370 \n Undrawn balance at 30 June 2026 2,650 1,200 — — — 3,850 \n Year ended 31 December 2025             \n At 1 January 2025 495 2,233 1,000 6,069 200 9,997 \n Drawdowns 1,400 — — 3,500 — 4,900 \n Repayments (1,900) — — (1,000) — (2,900) \n Transaction costs capitalised and amortised 1 (1) — (34) — (34) \n Carrying amount at 31 December 2025 (4) 2,232 1,000 8,535 200 11,963 \n Current (2) (5) — 789 — 782 \n Non-current (2) 2,237 1,000 7,746 200 11,181 \n Carrying amount at 31 December 2025 (4) 2,232 1,000 8,535 200 11,963 \n Undrawn balance at 31 December 2025 2,350 1,200 — — — 3,550 \n 1. In June 2026, the Group settled the $600 million syndicated facility that was \n executed on 17 January 2020. \n\n\nThere were no new covenants or other material changes to interest-bearing\nliabilities and financing facilities.\n\nFair value\n\nThe carrying amounts of interest-bearing liabilities approximate their fair\nvalues, with the exception of the Group’s unsecured bonds and the\nmedium-term notes. The unsecured bonds have a carrying amount of $8,541\nmillion (31 December 2025: $8,535 million) and a fair value of $8,636 million\n(31 December 2025: $8,665 million). The medium-term notes have a carrying\namount of $200 million (31 December 2025: $200 million) and a fair value of\n$198 million (31 December 2025: $197 million). Fair value is determined by\nreference to quoted market prices for these instruments and is classified as\nLevel 1 within the fair value hierarchy.\n\nC.2 Contributed equity\n\nIssued and fully paid shares\n   Number of shares US$m \n Half-year ended 30 June 2026     \n Opening balance 1,901,100,143 29,036 \n Amounts as at 30 June 2026 1,901,100,143 29,036 \n Year ended 31 December 2025     \n Opening balance 1,898,749,771 29,001 \n Shares issued 2,350,372 35 \n Amounts as at 31 December 2025 1,901,100,143 29,036 \n\n\nAll shares are a single class with equal rights to dividends, capital\ndistributions and voting. The Company does not have authorised capital nor par\nvalue in respect of its issued shares.\n\nReserved shares\n\nReserved shares are the Company’s own equity instruments, which are used in\nemployee share-based payment arrangements or the Dividend Reinvestment Plan\n(DRP). The DRP was suspended on 27 February 2023. These shares are deducted\nfrom equity.\n   Number of shares US$m \n Half-year ended 30 June 2026     \n Opening balance 5,283,450 (82) \n Vested/allocated during the half-year (644,610) 10 \n Amounts as at 30 June 2026 4,638,840 (72) \n Year ended 31 December 2025     \n Opening balance 3,080,842 (58) \n Purchases during the year 5,700,372 (88) \n Vested/allocated during the year (3,497,764) 64 \n Amounts as at 31 December 2025 5,283,450 (82) \n\n\nD. Other assets and liabilities\n\nD.1 Segment assets and liabilities\n   30 June 2026 31 December 2025 \n   US$m US$m \n (a) Segment assets     \n Australia 30,569 30,541 \n International 26,885 24,773 \n Marketing 1,094 965 \n Corporate 9,133 10,222 \n   67,681 66,501 \n       \n   30 June 2026 31 December 2025 \n   US$m US$m \n (b) Segment liabilities     \n Australia 6,899 7,252 \n International 2,856 2,531 \n Marketing 1,297 1,054 \n Corporate 14,905 15,821 \n   25,957 26,658 \n Corporate assets mainly comprise cash and cash equivalents, deferred tax \n assets, new energy assets in development and lease assets. Corporate \n liabilities mainly comprise interest-bearing liabilities, deferred tax \n liabilities and lease liabilities. \n\n\nD.2 Provisions\n   Restoration(1) Employee benefits Other Total \n   US$m US$m US$m US$m \n Half-year ended 30 June 2026         \n At 1 January 2026 6,886 669 312 7,867 \n Change in provision (229) (86) (73) (388) \n Unwinding of present value discount 156 — — 156 \n Carrying amount at 30 June 2026 6,813 583 239 7,635 \n At 30 June 2026         \n Current 765 373 100 1,238 \n Non-current 6,048 210 139 6,397 \n Carrying amount 6,813 583 239 7,635 \n Year ended 31 December 2025         \n At 1 January 2025 6,526 654 367 7,547 \n Adjustment to purchase price allocation — — 100 100 \n Change in provision 254 11 (138) 127 \n Unwinding of present value discount 283 5 — 288 \n Disposals (177) (1) (17) (195) \n Carrying amount at 31 December 2025 6,886 669 312 7,867 \n At 31 December 2025         \n Current 637 449 126 1,212 \n Non-current 6,249 220 186 6,655 \n Carrying amount 6,886 669 312 7,867 \n 1. 2026 change in provision is due to provisions used of $255 million, a revision \n of discount rates of $90 million offset by changes in foreign exchange rates \n of $92 million and changes in estimates of $24 million. 2025 change in \n provision is due to changes in estimates of $898 million, changes in foreign \n exchange rates of $233 million offset by provisions used of $823 million and a \n revision of discount rates of $54 million. \n\n\nD.3 Other financial assets and liabilities\n   30 June 2026 31 December 2025 \n   US$m US$m \n Other financial assets     \n Financial instruments at fair value through profit and loss     \n Derivative financial instruments designated as hedges 152 217 \n Other financial assets 18 14 \n Financial instruments at fair value through other comprehensive income     \n Other financial assets 58 62 \n Total other financial assets 228 293 \n Current 119 229 \n Non-current 109 64 \n Net carrying amount 228 293 \n Other financial liabilities     \n Financial instruments at fair value through profit and loss     \n Derivative financial instruments designated as hedges 130 7 \n Embedded derivative 347 212 \n Other financial liabilities 34 1 \n Total other financial liabilities 511 220 \n Current 148 8 \n Non-current 363 212 \n Net carrying amount 511 220 \n\n\nHedging activities\n\nAs at 30 June 2026, the Group had the following principal unrealised commodity\nhedging positions:\n\n\n * 36 MMboe of oil production volumes hedged at an average price of $75 per\nbarrel through to 2027.\n\n * Corpus Christi LNG volumes hedged through Henry Hub (HH) and Title Transfer\nFacility (TTF) commodity swap contracts.\n\nThe following table presents the Group’s derivative financial instruments\ndesignated as hedges, measured and recognised at fair value:\n   30 June 2026 31 December 2025 \n   US$m US$m \n Brent commodity swaps (cash flow hedges) 103 114 \n HH natural gas commodity swaps (cash flow hedges) (26) (4) \n TTF LNG commodity swaps (cash flow hedges) (63) 66 \n Interest rate swaps (cash flow hedges) (1) — 15 \n Foreign exchange forwards (cash flow hedges) 8 19 \n Total derivative financial instruments asset designated as hedges 22 210 \n 1. During June 2026, the Group early settled the $600 million syndicated \n facility, being the underlying hedged item. Accordingly, the associated \n hedging instrument ceased to be designated as a hedge. Refer to Note C.1. \n\n\nEmbedded commodity derivative\n\nIn 2023, the Group entered into a revised long-term gas sale and purchase\ncontract (GSPA) with Perdaman, where a component of the selling price is\nlinked to the price of urea. The contract was assessed to contain an embedded\ncommodity derivative that is required to be separated and recognised at fair\nvalue through profit and loss. The carrying value of the embedded derivative\nat 30 June 2026 amounted to a net liability of $347 million (31 December 2025:\nnet liability of $212 million). The derivative is remeasured to fair value at\neach reporting date. For the half-year ended 30 June 2026, an unrealised loss\nof $135 million has been recognised through other expense (30 June 2025:\nunrealised gain of $162 million through other income).\n\nD.3 Other financial assets and liabilities (continued)\n\nFair value\n\nExcept for the other financial assets and other financial liabilities set out\nin this note, there are no other material financial assets or financial\nliabilities carried at fair value. Other financial assets and other financial\nliabilities set out in this note are classified as Level 2 on the fair value\nhierarchy with market observable inputs, with the exception of the embedded\ncommodity derivative which has been classified as Level 3 on the fair value\nhierarchy with no market observable inputs. Refer to key estimates and\njudgements for further details. During the period, there were no\nreclassifications between the fair value hierarchy levels.\n\nThere were no changes to the Group’s valuation processes, valuation\ntechniques and types of inputs used in the fair value measurements during the\nperiod.\n\nFinancial risk factors\n\nThe Group’s activities expose its financial instruments to a variety of\nmarket risks, including foreign exchange, commodity price and interest rate\nrisk. The half-year financial statements does not include all financial risk\nmanagement information and disclosures required in the Annual Report and, as\nsuch, should be read in conjunction with the Group’s 2025 Financial\nStatements. There have been no significant changes in risk management policies\nsince 31 December 2025. Refer to the embedded commodity derivative key\nestimates and judgements section below for the sensitivity assessment on\ndiscount rates and pricing.\n\nKey estimates and judgements\n\n(a) Embedded commodity derivative\n\nThe fair value of the Perdaman embedded derivative has been estimated using a\nMonte Carlo simulation model. The assessment requires management to make\ncertain assumptions about the model inputs, including forecast cash flows,\ndiscount rate, credit risk and volatility. These assumptions require\nsignificant judgement and are subject to risk and uncertainty, and hence\nchanges in economic conditions can affect the assumptions. The present value\nof the embedded derivative was estimated using the assumptions set out below.\n\n\n * Inflation rate – 2.50%.\n\n * Discount rate – a pre-tax interest rate curve (range: 5.04% to 8.07%).\n\n * Domestic gas pricing – forecast sales are subject to urea pricing. Price\nassumptions are based on the best market information available at measurement\ndate and derived from short- and long-term views of global supply and demand,\nbuilding upon past experience of the industry and consistent with external\nsources. The long-term urea price is determined with reference to the\nprevailing gas hub (TTF) prices available in the market.\n\nThe embedded derivative is most sensitive to changes in discount rates and\npricing, which may result in unrealised gains or losses recognised in other\nincome/expenses. The nominal impacts of the effects of changes to discount\nrate and long-term price assumptions are estimated as follows. The valuation\nis over a contract period of 20 years and the below change in assumptions\napplies a linear increase or decrease in inputs over the life of the contract.\nA spot increase is not represented by the sensitivity below.\n   Change in assumption(1) US$m   \n   TTF sales price: increase of 10% 179   \n   TTF sales price: decrease of 10% (177)   \n   Discount rate: increase of 1.5%(2) (182)   \n   Discount rate: decrease of 1.5%(2) 223   \n   1. Amounts shown represent the change of the present value of the contract   \n keeping all other variables constant. \n \n2. A change of 1.5% represents 150 basis points. \n\n\nE. Other items\n\nE.1 Contingent liabilities and assets\n   2026 2025 \n Contingent liabilities at reporting date US$m US$m \n Contingent liabilities 340 322 \n Total disclosed contingent liabilities 340 322 \n\n\nContingent liabilities relate predominantly to possible obligations whose\nexistence will only be confirmed by the occurrence or non-occurrence of\nuncertain future events, and therefore the Group has not provided for such\namounts in these financial statements. The Group operates in complex tax and\nlegislative regimes. The amounts disclosed above include estimates made in\nrelation to ongoing disputes with various tax and government authorities.\nAssessing the value of contingent liabilities requires a high degree of\njudgement. The contingent liabilities relating to tax matters are estimated\nbased on notices received from authorities before interest and penalties. The\npossibility of further claims related to the same matters cannot be ruled out\nand the judicial processes may take extended periods to conclude.\nAdditionally, there are a number of other claims and possible claims that have\narisen in the course of business against entities in the Group, the outcome of\nwhich cannot be estimated at present and for which no amounts have been\nincluded in the table above.\n\nThe Group has contingent assets of $31 million as at 30 June 2026 (31 December\n2025: $30 million).\n\nE.2 New standards and interpretations\n\nNew and amended accounting standards adopted\n\nA number of amended standards became applicable for the current reporting\nperiod, including the amendments to AASB/IFRS 7 and AASB/IFRS 9 disclosed in\nFinancial Statements within the Annual Report for the year ended 31 December\n2025. The Group did not make any significant changes to its accounting\npolicies and did not make retrospective adjustments as a result of adopting\nthese amended standards. These amendments did not materially impact the\naccounting policies or amounts disclosed in the condensed consolidated\nhalf-year financial statements of the Group.\n\nNew standards and interpretations not yet adopted\n\nCertain new accounting standards, amendments to accounting standards and\ninterpretations have been published that are not mandatory for the 30 June\n2026 reporting period and have not been early adopted by the Group. Except for\nAASB 18/IFRS 18 Presentation and Disclosure in Financial Statements, these\npronouncements are not expected to have a material impact on the Group’s\nconsolidated financial statements in the current or future reporting periods.\nAASB/IFRS 18 will replace AASB 101/IAS 1 Presentation of Financial Statements,\nintroducing new requirements that will help to achieve comparability of the\nfinancial performance of similar entities and provide more relevant\ninformation and transparency to users. Even though AASB/IFRS 18 will not\nimpact the recognition or measurement of items in the financial statements,\nits impacts on presentation and disclosure are expected to be pervasive,\nparticularly those related to the consolidated income statement and providing\nmanagement-defined performance measures within the financial statements.\nManagement is currently assessing the detailed implications of applying the\nnew standard on the Group’s financial statements. The Group will apply the\nnew standard from its mandatory effective date of 1 January 2027.\nRetrospective application is required.\n\nE.3 Events after the end of the reporting period\n\nOperatorship of Bass Strait assets\n\nOn 29 July 2025, the Group agreed with ExxonMobil Australia (ExxonMobil) to\nassume operatorship of the Bass Strait production assets, the Longford Gas\nPlant, the Long Island Point gas liquids processing facility and associated\npipeline infrastructure. The Group’s and ExxonMobil’s equity interest in\nthe Joint Venture’s assets and current decommissioning plans and provisions\nremain unchanged. The transaction was completed and effective on 1 July 2026,\nsubsequent to the report date.\n\nAs part of the transaction, Woodside acquired ExxonMobil’s employing entity\nfor the Bass Strait employees which includes employee-related assets and\nliabilities for the consideration of $1. The employee expenses will continue\nto be funded by the Bass Strait joint venture partners based on their equity\ninterests. The acquisition of the employing entity will to be treated as a\nbusiness combination and will be accounted for in the 2026 Annual Report.\n\nE.3 Events after the end of the reporting period (continued)\n\nBrowse Joint Venture pre-emption right\n\nOn 12 June 2026, the Group exercised its pre-emption right to acquire a 10.67%\nparticipating interest in the Browse Joint Venture. The acquisition\nconsideration comprises a payment of $225 million, reimbursement of certain\njoint venture cash call contributions and a contingent payment of $175 million\nsubject to specified future conditions. The transaction is subject to\ncustomary conditions precedent, including regulatory approvals, and had not\ncompleted at the reporting date. Upon completion, the Group's participating\ninterest in the Browse Joint Venture will increase to 41.27%.\n\nCalypso divestment\n\nSubsequent to the reporting date, the Group entered into an agreement to sell\nits 70% operated interest in the Calypso Project to bp. Completion of the\ntransaction is subject to customary conditions precedent, including government\nand regulatory approvals, and is expected to occur by the end of 2026. The\ntransaction comprises fixed and contingent consideration. As disclosed in Note\nB.3, an impairment loss of $135 million was recognised as at 30 June 2026\nfollowing the Group's decision to divest its interest in the Calypso Project.\n\nE.4 Subsidiaries\n\nSubsidiaries with non-controlling interests\n\nThe Group has two Australian subsidiaries and two International subsidiaries\nwith non-controlling interests (NCI).\n Name of entity Principal place of business % held by NCI NCI parties \n Burrup Facilities Company Pty Ltd Australia 10.00% Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd \n Burrup Train 1 Pty Ltd Australia 10.00% Kansai Electric Power Australia Pty Ltd and MidOcean Pluto Pty Ltd \n Louisiana LNG Infrastructure LLC(1) United States 62.87% Stonepeak \n Louisiana LNG LLC United States 10.00% Williams \n 1. The non-controlling interest in Louisiana LNG Infrastructure LLC is \n measured at its proportionate share of the subsidiary’s net assets. The \n proportion of net assets each member is entitled to upon liquidation varies \n prior to operations commencement. Prior to this milestone, entitlements are \n determined in proportion to the cumulative capital contributions made by each \n member. The NCI percentage is expected to revert to 40% when the project \n commences operations. \n\n\nE.4 Subsidiaries (continued)\n\nThe summarised financial information (including consolidation adjustments but\nbefore intercompany eliminations) of subsidiaries with NCI is as follows:\n   Burrup Facilities Company Pty Ltd Burrup Train 1 Pty Ltd Louisiana LNG Infrastructure LLC Louisiana LNG LLC Total \n   US$m US$m US$m US$m US$m \n Half-year ended 30 June 2026           \n Current assets 379 314 678 339 1,710 \n Non-current assets 4,694 2,551 7,315 2,738 17,298 \n Current liabilities (45) (36) (448) (251) (780) \n Non-current liabilities (542) (299) (84) (31) (956) \n Net assets 4,486 2,530 7,461 2,795 17,272 \n Accumulated balance of NCI 449 253 4,691 280 5,673 \n (Loss)/Profit (21) 19 3 (5) (4) \n (Loss)/Profit allocated to NCI (2) 2 2 (1) 1 \n Dividends paid to NCI (1) (10) — — (11) \n Year ended 31 December 2025           \n Current assets 288 225 260 118 891 \n Non-current assets 4,810 2,729 5,402 2,331 15,272 \n Current liabilities (38) (39) (318) (143) (538) \n Non-current liabilities (544) (306) (86) (37) (973) \n Net assets 4,516 2,609 5,258 2,269 14,652 \n Accumulated balance of NCI 452 261 2,989 227 3,929 \n Profit/(Loss) 76 117 — (2) 191 \n Profit allocated to NCI 8 11 — — 19 \n Dividends paid to NCI (36) (24) — — (60) \n\n\nDIRECTORS’ DECLARATION\n\nfor the half-year ended 30 June 2026\n\nIn accordance with a resolution of directors of Woodside Energy Group Ltd, we\nstate that:\n\nIn the opinion of the directors:\n a)   the financial statements and notes of the Group are in accordance with the Australian Corporations Act 2001, including: \n     i.   giving a true and fair view of the Group’s financial position as at 30 June \n 2026 and of its performance for the half-year ended on that date; and \n     ii.   complying with Australian Accounting Standard AASB 134 and International \n Accounting Standard IAS 34 Interim Financial Reporting and the Corporations \n Regulations 2001; \n b)   there are reasonable grounds to believe that Woodside Energy Group Ltd will be able to pay its debts as and when they become due and payable. \n\n\nOn behalf of the Board\n\nR J Goyder, AO\n\nChair of the Board\n\nMelbourne, Victoria\n\n25 August 2026\n\nE M Westcott\n\nChief Executive Officer and Managing Director\n\nSydney, New South Wales\n\n25 August 2026\n\nINDEPENDENT AUDITOR’S REVIEW REPORT\n\nIndependent auditor's review report to the members of Woodside Energy Group\nLtd\n\nReport on the half-year financial report\n\nConclusion\n\nWe have reviewed the half-year financial report of Woodside Energy Group Ltd\n(the Company) and the entities it controlled during the half-year (together\nthe Group), which comprises the condensed consolidated statement of financial\nposition as at 30 June 2026, the condensed consolidated income statement,\ncondensed consolidated statement of comprehensive income, condensed\nconsolidated statement of changes in equity and condensed consolidated\nstatement of cash flows for the half-year ended on that date, selected\nexplanatory notes and the directors’ declaration.\n\nBased on our review, which is not an audit, we have not become aware of any\nmatter that makes us believe that the accompanying half-year financial report\nof Woodside Energy Group Ltd does not comply with the Corporations Act 2001\nincluding:\n\n\n 1. giving a true and fair view of the Group’s financial position as at 30 June\n2026 and of its performance for the half-year ended on that date; and\n\n 2. complying with Accounting Standard AASB 134 Interim Financial Reporting and\nthe Corporations Regulations 2001.\n\nBasis for conclusion\n\nWe conducted our review in accordance with ASRE 2410 Review of a Financial\nReport Performed by the Independent Auditor of the Entity (ASRE 2410). Our\nresponsibilities are further described in the Auditor’s responsibilities for\nthe review of the half-year financial report section of our report.\n\nWe are independent of the Group in accordance with the auditor independence\nrequirements of the Corporations Act 2001 and the ethical requirements of the\nAccounting Professional & Ethical Standards Board’s APES 110 Code of\nEthics for Professional Accountants (including Independence Standards) (the\nCode) that are relevant to the audit of the annual financial report in\nAustralia. We have also fulfilled our other ethical responsibilities in\naccordance with the Code.\n pwc.com.au PricewaterhouseCoopers, ABN 52 780 433 757 \n \n \n \nBrookfield Place, Level 15, 125 St Georges Terrace, PERTH WA 6000, \n \n \n \nGPO Box D198, PERTH WA 6840 \n \n \n \nT: +61 8 9238 3000, F: +61 8 9238 3999, www.pwc.com.au \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.pwc.com.au&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.pwc.com.au&index=2&md5=18a568a9b89674de676e0dbca05b0c44) \n \n \n \n  \n \n \n \nLiability limited by a scheme approved under Professional Standards \n Legislation. \n\n\nResponsibilities of the directors for the half-year financial report\n\nThe directors of the Company are responsible for the preparation of the\nhalf-year financial report, in accordance with Australian Accounting Standards\nand the Corporations Act 2001, including giving a true and fair view, and for\nsuch internal control as the directors determine is necessary to enable the\npreparation of the half-year financial report that is free from material\nmisstatement whether due to fraud or error.\n\nAuditor's responsibilities for the review of the half-year financial report\n\nOur responsibility is to express a conclusion on the half-year financial\nreport based on our review. ASRE 2410 requires us to conclude whether we have\nbecome aware of any matter that makes us believe that the half-year financial\nreport is not in accordance with the Corporations Act 2001 including giving a\ntrue and fair view of the Group’s financial position as at 30 June 2026 and\nof its performance for the half-year ended on that date, and complying with\nAccounting Standard AASB 134 Interim Financial Reporting and the Corporations\nRegulations 2001.\n\nA review of a half-year financial report consists of making enquiries,\nprimarily of persons responsible for financial and accounting matters, and\napplying analytical and other review procedures. A review is substantially\nless in scope than an audit conducted in accordance with Australian Auditing\nStandards and consequently does not enable us to obtain assurance that we\nwould become aware of all significant matters that might be identified in an\naudit. Accordingly, we do not express an audit opinion.\n\nPricewaterhouseCoopers\n N M Henry   Perth, Western Australia \n \nPartner \n25 August 2026 \n\n Appendix 4D \n\n\nDividends\n Ex-dividend date 3 September 2026     \n Record date for the interim dividend 4 September 2026     \n         \n Date the dividend is payable 25 September 2026     \n     Current period Previous corresponding period(44) \n Interim dividend - fully franked US cents per share 57 53 \n None of these dividends are foreign sourced.     \n\n\nWoodside dividends are determined in US dollars. However, shareholders will\nreceive their dividend in Australian dollars unless their registered address\nis in the United Kingdom (in which case they will receive their dividend in\nBritish pounds), in the United States of America (in which case they will\nreceive their dividend in US dollars) or in New Zealand (in which case they\nwill receive their dividend in NZ dollars).\n\nShareholders who reside outside of the United States can elect to receive\ntheir dividend electronically in US dollars, payable into a US financial\ninstitution account. Shareholders who reside outside of the United States, the\nUnited Kingdom, New Zealand and Australia may elect to receive their dividend\nelectronically in their local currency using Global Wire Payment Service from\nthe Company's share registry, Computershare Investor Services Pty Ltd.\n\nShareholders should contact the Company's share registry if they wish to alter\ntheir dividend currency for future dividend payments. Contact details are\navailable on Woodside's website on the Shareholder Information section of the\nInvestors page. Shareholders must make an election to alter their dividend\ncurrency on or before 5.00pm AWST on 7 September 2026.\n\nNet Tangible Assets per ordinary security\n   Current period Previous corresponding period(44) \n   US$ US$ \n Net Tangible Assets (US$ per ordinary security)(45) 16.41 16.19 \n\n\nDetails of Associates and Joint Venture Entities\n   Percentage of ownership interest held at end of period or date of disposal   \n   \n Name of Entity Current period Previous corresponding period(44)   \n North West Shelf Gas Pty Ltd 33.33% 33.33%   \n North West Shelf Liaison Company Pty Ltd —% 33.33%   \n China Administration Company Pty Ltd 33.33% 33.33%   \n International Gas Transportation Company Limited —% 33.33%   \n North West Shelf Shipping Service Company Pty Ltd —% 33.33%   \n North West Shelf Lifting Coordinator Pty Ltd 33.33% 33.33%   \n Blue Ocean Seismic Services Limited 16.17% 16.17%   \n Oakbio Inc 25.32% 25.32%   \n Iwilei District Participating Parties, LLC 14.96% 14.96%   \n Caesar Oil Pipeline Company, LLC 25.00% 25.00%   \n Cleopatra Gas Gathering Company LLC 22.00% 22.00%   \n Marine Well Containment Company LLC 12.92% 12.05%   \n Driftwood Pipeline, LLC 20.00% —%   \n\n Shareholder information \n\n\nKey announcements 2026\n January Fourth quarter 2025 report \n February Woodside Releases Annual Reserves Statement \n Woodside Releases Full-Year 2025 Results \n Full-Year 2025 Results Briefing Transcript \n Annual Report 2025 [and US Annual Report 2025 (Form 20-F)] \n March Sustainability Briefing 2026 \n Liz Westcott Appointed Woodside CEO \n Appointment of Director to Woodside Board \n Woodside assumes control of Beaumont New Ammonia operations \n April 2026 Annual General Meeting voting results \n First quarter 2026 report \n June Woodside exercises Browse pre-emption right \n July Second quarter 2026 report \n August Half-Year 2026 results \n\n\nEvents calendar 2026-2027\n\nKey calendar dates for Woodside shareholders in 2026-2027. Please note dates\nare subject to review.\n August 25 Half-Year 2026 results \n September 3 Ex-dividend date for interim dividend (Australian Securities Exchange) \n 4 Ex-dividend date for interim dividend (New York Stock Exchange) \n 4 Record date for interim dividend \n 25 Payment date for interim dividend \n October 21 Third quarter 2026 report \n November 5 2026 Capital Markets Day (Australia) \n 12 2026 Capital Markets Day (United States) \n December 31 Year-end 2026 \n January 28 Fourth quarter 2026 report \n February 23 2026 Annual Report \n\n\nBusiness directory\n Registered office: Postal address: \n Woodside Energy Group Ltd GPO Box D188 \n Mia Yellagonga Perth WA 6840 \n 11 Mount Street Australia \n Perth WA 6000   \n Australia T: +61 8 9348 4000 \n\n\nInvestor enquiries\n\nInvestors seeking information on the company should contact Investor Relations\nat:\n Postal address:     \n Investor Relations T: ‘+61 8 9348 4000 \n GPO Box D188 E: investor@woodside.com (mailto:investor@woodside.com) \n Perth WA 6840 W: woodside.com \n Australia     \n\n\nShare registry enquiries\n\nInvestors seeking information about their shareholding should contact the\ncompany’s share registry:\n Registered office: Postal address: \n Computershare Investor Services Pty Limited GPO Box D182 \n Level 17 Perth WA 6840 \n 221 St Georges Terrace   \n Perth WA 6000 T: 1300 558 507 (within Australia) \n     ‘+61 3 9415 4632 (outside Australia) \n   E: web.queries@computershare.com.au (mailto:web.queries@computershare.com.au) \n   W: investorcentre.com/wds \n\n\nThe share registry can assist with queries on share transfers, dividend\npayments, the dividend reinvestment plan, notification of tax file numbers and\nchanges of name, address or bank account details.\n\nDetails of shareholdings can be checked by visiting the share registry website\nat www.investorcentre.com/wds\n(https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.investorcentre.com%2Fwds&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.investorcentre.com%2Fwds&index=3&md5=ed88d10be1b8401de7555647332d6ce4)\n.\n\nDetails of the authorised depositary bank for Woodside’s American Depositary\nReceipt programme can be found on the website.\n Assets \n\n\nProducing facilities\n\nAustralia\n Asset Role Equity Product \n Pluto LNG Operator 90 % LNG, pipeline gas and condensate \n North West Shelf(1) Operator 33.33 % LNG, pipeline gas, condensate and NGLs \n Wheatstone(1) Non-operator 13 % LNG, pipeline gas and condensate \n Julimar-Brunello Operator 65 % \n Okha FPSO(1) Operator 50 % Crude oil \n Ngujima-Yin FPSO Operator 60 % Crude oil \n Bass Strait Operator(2) 32.5—50% Pipeline gas, condensate and NGLs \n Pyrenees FPSO Operator 40—71.4% Crude oil \n Macedon Operator 71.4 % Pipeline gas \n 1. In December 2024, Woodside entered into an asset swap with Chevron, refer to \n “Woodside simplifies portfolio and unlocks long-term value” announced 19 \n December 2024 for details. \n \n2. Subsequent to the period, Woodside assumed operatorship of the Bass Strait \n assets. Refer to “Woodside completes Gippsland Basin operatorship \n transition” announced on 1 July 2026. \n\n\nInternational\n Asset Role Equity Product \n Sangomar Operator 82 % Crude oil \n Greater Shenzi Operator 72 % Crude oil, pipeline gas, condensate and NGLs \n Atlantis Non-operator 44 % Crude oil, pipeline gas, condensate and NGLs \n Mad Dog Non-operator 23.9 % Crude oil, pipeline gas, condensate and NGLs \n Beaumont New Ammonia Operator 100 % Ammonia \n   \n\n\nProjects\n\nPost FID\n Asset Role Equity Product \n Scarborough Operator 74.9% LNG and pipeline gas \n Pluto Train 2 Operator 51.0% LNG and pipeline gas \n Trion Operator 60.0% Crude oil \n Louisiana LNG LLC Operator 90.0% LNG \n Louisiana LNG Infrastructure LLC Operator 60.0% LNG \n Hydrogen Refueller@H2Perth Operator 100% Hydrogen \n\n\nDevelopments\n Asset Role Equity Product \n Calypso Operator 70% Gas \n Browse Operator 30.60%(1) LNG, pipeline gas and condensate \n Greater Scarborough(2) Operator 100% Gas \n Liard Non-operator 50% Gas \n Sunrise Operator 33.44% LNG, pipeline gas and condensate \n 1. In June 2026, Woodside pre-empted the sale of CNPC’s stake in Browse. Refer \n to “Woodside exercises Browse pre-emption right” announced 12 June 2026 \n for details. \n \n2. “Greater Scarborough” includes the Jupiter and Thebe fields. \n\n\nNew energy opportunities(1)\n Asset Role Equity Product \n H2Perth Operator 100% Hydrogen \n NeoSmelt Non-operator 20% Iron \n Woodside Solar(2) Proponent 100% Solar energy \n 1. Subject to a final investment decision and regulatory approvals. Excludes \n acquisitions subsequent to the period. \n \n2. Solar generation, battery services and transmission access and services will \n be supplied to Woodside under contracts with third parties. \n \n \n   \n\n\nGreenhouse gas assessment permits\n Country Permit Role Joint venture Comment \n Australia G-7-AP Non-operator Bonaparte CCS Assessment Joint Venture Located in the Bonaparte Basin off the north-west coast of the Northern \n Territory \n G-8-AP Operator Browse Joint Venture For carbon capture and storage evaluation for Browse \n G-10-AP Operator Angel CCS Joint Venture(1) Located in the Northern Carnarvon basin off the north-west coast of Western \n Australia \n G-18-AP Non-operator Greenhouse Gas Assessment Permit G-18-AP Joint Venture Located in the Northern Carnarvon Basin off the north-west coast of Western \n Australia \n G-19-AP Operator(2) Gippsland Basin Joint Venture Located in the Gippsland Basin off the coast of Victoria \n 1. In December 2024, Woodside entered into an asset swap with Chevron, refer to \n “Woodside simplifies portfolio and unlocks long-term value” announced 19 \n December 2024 for details. \n \n2. Subsequent to the period, Woodside assumed operatorship of the Bass Strait \n assets. Refer to “Woodside completes Gippsland Basin operatorship \n transition” announced on 1 July 2026. \n \n \n   \n\n\nExploration\n Country Permit Role Equity Product \n Asia - Pacific         \n Australia WA-404-P Operator 100% Gas prone basin \n WA-550-P Operator 100% Gas prone basin \n WA-554-P Operator 100% Gas prone basin \n Europe         \n Ireland FEL 5/13 Operator 100% - Exit initiated Oil or gas prone basin \n Africa         \n Egypt Tiba Block Non-operator 40% Oil and gas prone basin \n North EI Dabaa Offshore (Block 4) Non-operator 27% Oil or gas prone basin \n Caribbean         \n Barbados Bimshire   60% - Exit initiated Oil or gas prone basin \n North America         \n United States EB 550, EB 594, EB 636, EB 637, EB 638, GB 721, GB 780, GB 821, GB 824, GB Operator 100% Oil prone basin \n 825, GB 866, KC 259, KC 297, KC 301, KC 343, KC 431, KC 859, KC 903, KC 904, \n KC 905, KC 948, KC 949, WR 577, WR 751, WR 795, WR 796 \n WR 443, WR 444, WR 488 Operator 80% Oil prone basin \n GC 124 Operator 75% Oil prone basin \n EB 699, AC 36, AC 80 Operator 70% Oil prone basin \n GC 282, GC 237 Non-operator 50% Oil prone basin \n AC 125, AC 126, AC 81 Operator 45% Oil prone basin \n GC 598 Non-operator 40% Oil prone basin \n AT 453 Non-operator 30% Oil prone basin \n GC 870 Non-operator 24% Oil prone basin \n GC 680, GC 723, GC 724, GC 679, GC 768 Non-operator 18% Oil prone basin \n\n Alternative Performance Measures \n\n\nWoodside uses various alternative performance measures (APM) which are\nnon-IFRS measures that are unaudited but derived from the Half-Year Financial\nStatements. Although certain non-IFRS data has been extracted or derived from\nthe Half-Year financial statements, this data has not been audited or reviewed\nby Woodside’s independent auditors. These measures are presented to provide\nfurther insight into Woodside’s performance. See Non-IFRS Measures on page\n65 for more information.\n\nAPMs and their nearest respective IFRS measure.\n APMs derived from the condensed consolidated income statement and other notes 30 June 2026 30 June 2025 \n   US$m US$m \n EBIT/EBITDA excluding impairment     \n Net profit after tax 1,673 1,330 \n Adjusted for:     \n Finance income (123) (106) \n Finance costs 245 169 \n PRRT expense/(benefit) (305) 71 \n Income tax expense 667 353 \n EBIT 2,157 1,817 \n Adjusted for:     \n Property, plant and equipment depreciation 2,209 2,541 \n Amortisation of licence acquisition costs 4 3 \n Amortisation of intangible assets 10 11 \n Depreciation of lease assets 89 85 \n Impairment losses 178 143 \n EBITDA excluding impairment 4,647 4,600 \n       \n Underlying NPAT     \n Net profit after tax attributable to equity holders of the parent 1,672 1,316 \n Adjusted for the following exceptional items:     \n Less: Pluto DTA recognition (417) — \n Less: USA DTA recognition (90) — \n Add: Impairment loss (post-tax) 169 113 \n Less: Louisiana DTA recognition — (182) \n Underlying NPAT 1,334 1,247 \n       \n Average realised price(1)     \n Adjusted revenue from sale of products(2) 7,381 6,468 \n Sales volumes (MMboe) 99.8 104.8 \n Average realised price (US$ per boe) 74.0 61.7 \n       \n Unit production cost(3)     \n Production costs 749 667 \n Production (reserves) volumes (MMboe)(4) 85.0 98.6 \n Unit production cost (US$ per boe) 8.8 6.8 \n 1. 2025 sales volumes have been restated to include additional volumes of 0.19 \n MMboe to reflect pipeline gas volumes sold in MMBtu at a revised boe \n conversion factor, impacting realised price by ($0.1)/boe \n \n2. Adjusted revenue from sale of products comprises of revenue from sale of \n products of $7,356 million and provisional price adjustments of $25 million, \n which is included in other income (refer to Note A.1). \n \n3. The calculation has been updated to exclude feed gas, services and processing \n costs and processing volumes. The 2025 comparative has been restated to be \n presented on the same basis. \n \n4. 2026 Includes production volumes of 86.5 MMboe, adjusted for processing \n volumes of 1.5 MMboe. \n \n \n   \n\n APMs derived from the condensed consolidated statement of cash flows and other 30 June 2026 30 June 2025 \n notes \n   US$m US$m \n Free cash flow     \n Net cash from operating activities 3,013 3,339 \n Net cash used in investing activities (4,286) (4,937) \n Adjusted for:     \n Contributions from/(to) NCI 1,737 1,843 \n Lease repayments (112) (109) \n Free cash flow(1) 352 136 \n       \n Liquidity     \n Cash and cash equivalents 4,339 4,880 \n Add: Available undrawn facilities 3,850 3,550 \n Liquidity 8,189 8,430 \n 1. The 2026 calculation has been updated to adjust for contributions from/(to) \n NCI and lease repayments. The 2025 comparative has been restated to be \n presented on the same basis. \n\n APMs derived from the condensed consolidated statement of financial 30 June 2026 30 June 2025 \n \n \n \nposition and other notes \n   US$m US$m \n Capital expenditure     \n Capital additions on evaluation 24 29 \n Capital additions on property, plant and equipment 3,243 4,372 \n Less: Cash contributions from participants (1,725) (1,870) \n Capital additions on other 95 27 \n Capital expenditure 1,637 2,558 \n Acquisitions 470 — \n Capital expenditure and acquisitions 2,107 2,558 \n       \n Exploration expenditure     \n Exploration and evaluation expenditure 104 84 \n Adjusted for:     \n Evaluation expenditure (22) (2) \n Amortisation expense (4) (3) \n Prior year expense written off (1) — \n Exploration capitalised 42 5 \n Exploration expenditure(1) 119 84 \n Capital and exploration expenditure(1) 1,756 2,642 \n       \n Net tangible assets per ordinary security     \n Net assets 41,724 38,507 \n Adjusted for:     \n Goodwill (3,952) (3,952) \n Non-controlling interest (5,673) (2,868) \n Other intangible assets (904) (939) \n Net tangible assets 31,195 30,748 \n Number of issued and fully paid shares 1,901,100,143 1,898,749,771 \n Net tangible assets per ordinary security (US$ per ordinary security) 16.41 16.19 \n       \n Gearing     \n Interest-bearing liabilities (Current and non-current) 11,370 11,954 \n Lease liabilities (Current and non-current) 2,298 1,583 \n Adjusted for:     \n Cash and cash equivalents (4,339) (4,880) \n Net debt 9,329 8,657 \n Equity attributable to equity holders of the parent 36,051 35,639 \n Total net debt and equity attributable to equity holders of the parent 45,380 44,296 \n Gearing (%) 20.6% 19.5% \n 1. The 2026 calculation has been updated to adjust for evaluation expenditure. \n The 2025 comparative has been restated to be presented on the same basis. \n\n APMs derived from the condensed consolidated income statement and 30 June 2026 30 June 2025 \n \n \n \nstatement of financial position \n   US$m US$m \n Annualised return on equity     \n Annualised net profit after tax attributable to equity holders of the parent 3,344 2,632 \n Equity attributable to equity holders of the parent 36,051 35,639 \n Annualised return on equity (%) 9.3% 7.4% \n       \n Annualised return on average capital employed     \n Annualised profit before tax and net finance costs 4,314 3,634 \n Opening non-current liabilities 21,241 19,254 \n Closing non-current liabilities 20,777 21,828 \n Average non-current liabilities 21,009 20,541 \n Opening equity 39,843 36,153 \n Closing equity 41,724 38,507 \n Average equity(1) 40,784 37,330 \n Total average non-current liabilities and equity 61,793 57,871 \n Annualised return on average capital employed (%) 7.0% 6.3% \n\n APMs derived from other notes 30 June 2026 30 June 2025 \n   US$m US$m \n Revenue from sale of products (excluding marketing segment) 6,376 5,924 \n       \n Cash margin (excluding marketing segment)     \n Gross profit 2,684 2,344 \n Adjusted for:     \n Other 19 15 \n Property, plant and equipment depreciation 2,209 2,541 \n Other revenue 13 (100) \n Cash margin (excluding marketing segment) 4,925 4,800 \n Cash margin % 77.2% 81.0% \n       \n Production costs (excluding marketing segment)(2) 749 667 \n Production cost margin % 11.7% 11.3% \n       \n Other cash costs (excluding marketing segment):     \n Feed gas, services and processing costs(2) 238 92 \n Royalties, excise and levies 143 156 \n Insurance 33 37 \n Inventory movement 54 1 \n Shipping and direct sales costs 123 77 \n Trading costs 101 88 \n Other hydrocarbon costs 10 6 \n Total other cash costs (excluding marketing segment) 702 457 \n Other cash cost margin % 11.0% 7.7% \n 1. The calculation has been updated to use total equity rather than equity \n attributable to equity holders of the parent. The 2025 comparative has been \n restated to be presented on the same basis. \n \n2. Production costs has been updated to exclude and present feed gas, services \n and processing costs separately. The 2025 comparative has been restated to be \n presented on the same basis. \n\n Notes \n\n\nGlossary\n Term Definition \n $, $m US dollars unless otherwise stated, millions of dollars \n 1P Proved reserves \n 2C Best Estimate of Contingent resources \n 2P Proved plus Probable reserves \n Abate/abatement Avoidance, reduction or removal of an amount of carbon dioxide or equivalent \n Aim Woodside uses this term to describe a result that plans or actions are \n intended to achieve \n Aspiration Woodside uses this term to describe an aspiration to seek the achievement of \n an outcome but where achievement of the outcome is subject to material \n uncertainties and contingencies such that Woodside considers there is not yet \n a suitable defined plan or pathway to achieve that outcome \n ASX Australian Securities Exchange \n Average realised price Revenue from sale of products and provisional pricing adjustments ($ million) \n divided by sales volume (MMboe) \n A$, AUD Australian dollars \n Biodiversity Biological diversity means the variability among living organisms from all \n sources including, inter alia, terrestrial, marine and \n \n \n \nother aquatic ecosystems and the ecological complexes of which they are a \n part; this includes diversity within species, \n \n \n \nbetween species and of ecosystems(46) \n Board The Board of Directors of Woodside Energy Group Ltd \n Brent Intercontinental Exchange (ICE) Brent Crude deliverable futures contract (oil \n price) \n Capital expenditure Capital additions on property, plant and equipment and evaluation capitalised. \n Excludes exploration capitalised and adjusted for the capital contribution \n from partners for the development of Louisiana LNG \n Capital expenditure and acquisitions Includes capital expenditure and acquisition consideration. \n Carbon credit A tradeable financial instrument that is issued by a carbon-crediting program. \n A carbon credit represents a greenhouse gas \n \n \n \nemission reduction to, or removal from, the atmosphere equivalent to 1 tCO2-e, \n calculated as the difference in emissions from \n \n \n \na baseline scenario to a project scenario. Carbon credits are uniquely \n serialised, issued, tracked and retired or administratively \n \n \n \ncancelled by means of an electronic registry operated by an administrative \n body, such as a carbon-crediting program \n Cash margin Gross profit/loss adjusted for other cost of sales, property, plant and \n equipment depreciation and amortisation and other revenue. Excludes the \n marketing segment. Cash margin % is calculated as cash margin divided by \n revenue from sale of products (excluding marketing segment) \n CCS Carbon capture and storage \n CCUS Carbon capture utilisation and storage \n CO(2) Carbon dioxide \n CO(2)-e CO(2) equivalent. The universal unit of measurement to indicate the global \n warming potential of each of the seven greenhouse \n \n \n \ngases, expressed in terms of the global warming potential of one unit of \n carbon dioxide. It is used to evaluate releasing (or \n \n \n \navoiding releasing) any greenhouse gas against a common basis(47) \n Condensate Hydrocarbons that are gaseous in a reservoir but that condense to form liquids \n as they rise to the surface \n cps Cents per share \n DTA Deferred tax asset \n DRP Dividend reinvestment plan \n EBIT Calculated as profit before income tax, PRRT and net finance costs \n EBITDA excluding impairment Calculated as profit before income tax, PRRT, net finance costs, depreciation \n and amortisation, impairment losses, \n \n \n \nimpairment reversals \n Emissions Emissions refers to emissions of greenhouse gases unless otherwise stated \n EPS Earnings per share \n Exploration expenditure Includes exploration and evaluation expenditure less evaluation expenditure, \n amortisation of licence acquisition costs, prior year exploration expense \n written off and exploration capitalised. \n FEED Front-end engineering design \n FID Final investment decision \n FPSO Floating production storage and offloading \n FPU Floating production unit \n Free cash flow Net cash flow from/(used in) operating activities and net cash flow from/(used \n in) investing activities, adjusted for the capital contribution from/(to) \n non-controlling interests and lease repayments. \n Gearing Net debt divided by the total of net debt and equity attributable to equity \n holders of the parent \n GHG or greenhouse gas The seven greenhouse gases listed in the Kyoto Protocol are: carbon dioxide \n (CO2); methane (CH4); nitrous oxide (N2O); \n \n \n \nhydrofluorocarbons (HFCs); nitrogen trifluoride (NF3); perfluorocarbons \n (PFCs); and sulphur hexafluoride (SF6) \n Goal Woodside uses this term to broadly encompass its targets and aspirations \n Gross margin Gross profit divided by operating revenue. Gross profit excludes income tax, \n PRRT, net finance costs, other income and other \n \n \n \nexpenses \n H1, H2 Halves of the calendar year (H1 is 1 January to 30 June and H2 is 1 July to 31 \n December) \n High consequence injury A high-consequence injury is a work-related injury that results in a fatality \n or permanent impairment injury. Woodside’s definition for HCI has changed in \n 2025 to align with the IOGP Fatality and Permanent Impairment definition. This \n definition was adopted to focus attention on the highest risks to people. In \n the previous reporting period, the HCI definition included long-term disabling \n injuries (i.e where the person will make a full recovery, but recovery exceeds \n 180 days) in HCI statistics which focused disproportionate effort towards \n injury management, access to treatment and privacy issues(48) \n IFRS International Financial Reporting Standards. For more information see \n www.ifrs.org \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.ifrs.org&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.ifrs.org&index=4&md5=647764e6fd14284c38b187cb400fcf2d) \n . \n Indigenous Peoples There is diversity within the Indigenous communities in the areas where we are \n active. When communicating with wide audience. Woodside uses the term \n “Indigenous Peoples” to refer to Traditional Owners and Traditional \n Custodians. At a local level, Woodside will be guided by the community about \n the appropriate terms of reference. Following internal and external \n stakeholder feedback, Woodside has updated our reference from First Nations to \n Indigenous Peoples because First Nations is not a globally accepted or widely \n used term beyond Australia. Indigenous Peoples aligns with the United Nations \n Declaration on the Rights of Indigenous Peoples (UNDRIP) language and is the \n recognised collective term in international law \n JV Joint venture \n KGP Karratha Gas Plant \n Liquidity Total cash and cash equivalents and available undrawn debt facilities less \n restricted cash \n LNG Liquefied natural gas \n Lower-carbon Woodside uses this term to describe the characteristic of having lower levels \n of associated potential GHG emissions when \n \n \n \ncompared to historical and/or current conventions or analogues, for example \n relating to an otherwise similar resource, \n \n \n \nprocess, production facility, product or service, or activity \n Lower-carbon ammonia Lower-carbon ammonia is characterised here by the use of hydrogen with \n emissions abated by carbon, capture, and storage \n \n \n \n(CCS), with an expected ammonia lifecycle (Scope 1, 2 and 3) carbon emissions \n intensity of 0.8 tCO2/tNH3 (based on \n \n \n \ncontracted intensity threshold with Linde) relative to unabated ammonia with a \n lifecycle (Scope 1, 2 and 3) carbon emissions \n \n \n \nintensity of 2.3 tCO2/tNH3 (Hydrogen Europe, 2023) \n Lower-carbon portfolio For Woodside, a lower-carbon portfolio is one from which the net equity Scope \n 1 and 2 greenhouse gas emissions, which \n \n \n \nincludes the use of offsets, are being reduced towards targets, and into which \n new energy products and lower-carbon services \n \n \n \nare planned to be introduced as a complement to existing and new investments \n in oil and gas. Our Climate Policy sets out the \n \n \n \nprinciples that we believe will assist us achieve this aim \n Lower-carbon services Woodside uses this term to describe technologies, such as CCUS or offsets that \n could be used by customers to reduce their \n \n \n \nnet greenhouse gas emissions \n Major Project Status Major Project Status is the Australian Government’s recognition of a \n project’s national strategic importance \n Material Topic For the purposes of Woodside's 2026 sustainability disclosures we determine \n which topics are material. For these purposes, “material topic” means a \n 2026 sustainability topic, determined as part of the 2025 materiality \n assessment process undertaken by Woodside. Classification of any topic as \n material through our materiality assessment process should not be read as a \n determination of whether that topic rises to the level of materiality of \n disclosure required by law, including the laws of Australia, and the US. \n However where applicable laws require the disclosure of risks that meet \n certain thresholds, Woodside has disclosed those risks. \n Net debt Interest-bearing liabilities and lease liabilities less cash and cash \n equivalents \n Net equity greenhouse gas emissions Woodside’s equity share of net greenhouse gas emissions which includes the \n utilisation of carbon credits as offsets \n Net greenhouse gas emissions Woodside has set its Scope 1 and 2 greenhouse gas emissions reduction target \n on a net basis, allowing for both direct emissions reductions from its \n operations and emissions reduction achieved from the utilisation of carbon \n credits as offsets (including credits relating to avoidance, reduction and/or \n removal activities). Net greenhouse gas emissions are equal to an entity’s \n gross greenhouse gas \n \n \n \nemissions reduced by the number of retired carbon credits.(49) \n Net profit attributable to Net profit after tax excluding non-controlling interests from the Group’s \n \n operations \n \nequity holders of the \n \n \n \nparent \n Net tangible assets The Group’s net assets less goodwill, non-controlling interest and other \n intangible assets \n Net tangible assets per Net tangible assets divided by the number of issued and fully paid shares \n \n \n \nordinary security \n New energy Woodside uses this term to describe energy technologies, such as hydrogen or \n ammonia, that are emerging in scale but \n \n \n \nwhich are expected to grow during the energy transition due to having lower \n greenhouse gas emissions at the point of use \n \n \n \nthan conventional fossil fuels \n NGLs Natural gas liquids \n NH(3) Ammonia \n NPAT Net profit after tax attributable to equity holders of the parent \n NWS North West Shelf \n NYSE New York Stock Exchange \n Offsets The compensation for an entity’s greenhouse gas emissions within its scope \n by achieving an equivalent amount of emission \n \n \n \nreductions or removals outside the boundary or value chain of that entity \n Operator, Operated and Oil and gas joint venture participants will typically appoint one company as \n \n the operator, which will hold the contractual authority to manage joint \n \nnon-operated venture activities on behalf of the joint venture participants. Where Woodside \n is the operator of a joint venture in which it holds an equity share, this \n report refers to that joint venture as being operated. Where another company \n is the operator of a joint venture in which Woodside holds an equity share, \n this report refers to that joint venture as being non-operated \n Other cash cost margin Other cash costs include feed gas, services and processing costs; royalties, \n excise and levies; insurance; inventory movement; shipping and direct sales \n costs; trading costs; and other hydrocarbon costs. Excludes the marketing \n segment. Other cash cost margin % is calculated as other cash costs divided by \n revenue from sale of products (excluding marketing segment) \n Production cost margin Production cost margin % is calculated as production costs divided by revenue \n from sale of products. Excludes the marketing segment \n PRRT Petroleum resources rent tax \n PSC Production sharing contract \n Return on average capital employed Annualised profit before tax and net finance costs divided by total average \n non-current liabilities and total equity \n Return on equity Annualised net profit after tax attributable to equity holder of the parent \n divided by equity attributable to equity holders of the parent \n Revenue from ordinary Revenue from the sale of products, processing and services revenue and \n \n shipping and other revenue \n \nactivities \n Scope 1 greenhouse gas Direct greenhouse gas emissions. These occur from sources that are owned or \n \n controlled by the company, for example, emissions from \n \nemissions \n \n \ncombustion in owned or controlled boilers, furnaces, vehicles, etc.; emissions \n from chemical production in owned or controlled \n \n \n \nprocess equipment. Woodside estimates greenhouse gas emissions, energy values \n and global warming potentials are \n \n \n \nestimated in accordance with the relevant reporting regulations in the \n jurisdiction where the emissions occur (e.g. Australian \n \n \n \nnational Greenhouse and Energy Reporting (nGER), US EPA Greenhouse Gas \n Reporting Program (GHGRP)). Australian \n \n \n \nregulatory reporting principles have been used for emissions in jurisdictions \n where regulations do not yet exist(5) \n Scope 2 greenhouse gas Electricity indirect greenhouse gas emissions. Scope 2 accounts for GHG \n \n emissions from the generation of purchased electricity \n \nemissions \n \n \nconsumed by the company. Purchased electricity is defined as electricity that \n is purchased or otherwise brought into the \n \n \n \norganisational boundary of the company. Scope 2 emissions physically occur at \n the facility where electricity is generated. \n \n \n \nWoodside estimates greenhouse gas emissions, energy values and global warming \n potentials are estimated in accordance \n \n \n \nwith the relevant reporting regulations in the jurisdiction where the \n emissions occur (e.g. Australian national Greenhouse and \n \n \n \nEnergy Reporting (nGER), US EPA Greenhouse Gas Reporting Program (GHGRP)). \n Australian regulatory reporting principles \n \n \n \nhave been used for emissions in jurisdictions where regulations do not yet \n exist(5) \n Scope 3 greenhouse gas Other indirect greenhouse gas emissions. Scope 3 is a reporting category that \n \n allows for the treatment of all other indirect emissions. \n \nemissions \n \n \nScope 3 emissions are a consequence of the activities of the company but occur \n from sources not owned or controlled by the \n \n \n \ncompany. Some examples of Scope 3 activities are extraction and production of \n purchased materials; transportation of \n \n \n \npurchased fuels; and use of sold products and services. Please refer to the \n Climate data table on our website for further information on the Scope 3 \n emissions categories reported by Woodside(50) \n Starting base Woodside uses a starting base of 6.22 Mt CO2-e which is representative of the \n gross annual average equity Scope 1 and 2 greenhouse gas emissions over \n 2016-2020 and which may be adjusted (up or down) for potential equity changes \n in producing or sanctioned assets with a final investment decision prior to \n 2021. Net equity emissions include the utilisation of carbon credits as \n offsets \n Sustainability (including References to sustainability (including sustainable and sustainably) are used \n \n with reference to Woodside’s Sustainability \n \nsustainable and \n \n \n \nCommittee and sustainability related Board policies, as well as in the context \n \nsustainably) of Woodside’s aim to ensure its business is \n \n \n \nsustainable from a long-term perspective, considering a range of factors \n including economic (including being able to sustain \n \n \n \nour business in the long term by being low cost and profitable), environmental \n (including considering our environmental impact \n \n \n \nand striving for a lower carbon portfolio), social (including supporting our \n license to operate), and regulatory (including ongoing \n \n \n \ncompliance with relevant legal obligations). Use of the terms \n ‘sustainability’, ‘sustainable’ and ‘sustainably’ is not intended \n to \n \n \n \nimply that Woodside will have no adverse impact on the economy, environment, \n or society, or that Woodside will achieve any \n \n \n \nparticular economic, environmental, or social outcomes \n Target Woodside uses this term to describe an intention to seek the achievement of an \n outcome, where Woodside considers that it \n \n \n \nhas developed a suitably defined plan or pathway to achieve that outcome \n Tier 1 process safety event A typical Tier 1 process safety event is loss of containment of hydrocarbons \n greater than 500 kg (in any one-hour period) \n Tier 2 process safety event A typical Tier 2 process safety event is loss of containment of hydrocarbons \n greater than 50 kg but less than 500 kg (in any \n \n \n \none-hour period) \n Traditional Custodian A person or group responsible for maintaining and passing on cultural \n knowledge and practices for a culturally defined area of land or sea \n Traditional Owner An Indigenous person or group directly descended from the original inhabitants \n of a culturally defined area of land or sea \n TTF Title transfer facility \n Underlying NPAT Net profit after tax from the Group’s operations excluding any exceptional \n items \n Unit production cost or Production costs excluding feed gas, services and processing costs ($ million) \n \n divided by reserves production volume (MMboe) \n \nUPC \n US, USA United States of America \n USD US dollars \n WA Western Australia \n\n\nConversion factors\n Product Unit Conversion factor \n Natural gas 5,700 scf 1 boe \n Condensate 1 bbl 1 boe \n Oil 1 bbl 1 boe \n Natural gas liquids 1 bbl 1 boe \n Ammonia 1 metric tonne 3.68 boe \n\n Facility Unit LNG conversion factor \n Karratha Gas Plant 1 tonne 8.08 boe \n Pluto LNG Gas Plant 1 tonne 8.34 boe \n Wheatstone 1 tonne 8.27 boe \n The LNG conversion factor from tonne to boe is specific to volumes produced at \n each facility and is based on gas composition which may change over time. \n\n\nUnits of measure\n Term Definition \n bbl barrel \n bcf billion cubic feet of gas \n boe barrel of oil equivalent \n GJ gigajoule \n kT thousand metric tonnes \n Mbbl thousand barrels \n MMbbl million barrels \n Mbbl/d thousand barrels per day \n Mboe thousand barrels of oil equivalent \n Mboe/d thousand barrels of oil equivalent per day \n MMboe million barrels of oil equivalent \n MMscf million standard cubic feet of gas \n MMscf/d million standard cubic feet of gas per day \n Mtpa million tonnes per annum \n PJ petajoules \n scf standard cubic feet of gas \n TJ terajoule \n\n\nAbout this report\n\nThis Half-Year Report 2026 is a summary of Woodside’s operations, activities\nand financial position as at 30 June 2026. Woodside Energy Group Ltd (ABN 55\n004 898 962) is the parent company of the Woodside group of companies. In this\nreport, unless otherwise stated, references to ‘Woodside’, ‘the\ncompany’, ‘the Group’, ‘we’, ‘us’ and ‘our’ refer to\nWoodside Energy Group Ltd and its controlled entities as a whole. The text\ndoes not distinguish between the activities of the parent company and those of\nits controlled entities, unless otherwise stated.\n\nReferences to ‘H1’ refer to the first half of the year, i.e. the period\nbetween 1 January 2026 and 30 June 2026. All dollar figures are expressed in\nUS currency unless otherwise stated. Production and sales volumes, reserves\nand resources are quoted as Woodside share. A glossary of key terms, units of\nmeasure and conversion factors is on pages 59 – 63.\n\nThis report should be read in conjunction with the Annual Report 2025 and, in\nrespect of climate and sustainability matters, the 2025 Climate and\nSustainability Summary, the Climate Transition Action Plan and 2023 Progress\nReport available at woodside.com.\n\nForward looking statements\n\nThis report contains forward-looking statements. These statements may relate\nto Woodside’s business, goals, targets, aspirations, plans, expectations,\nmarket conditions, results of operations and financial condition, including,\nbut not limited to, statements regarding the timing, completion and outcomes\nof transactions, construction costs and capital expenditures, supply and\ndemand for Woodside’s products, development, completion and execution of\nWoodside’s projects, the expected benefits, cash flows and rates of return\nor other future results of investments, strategies and transactions, the\npayment of future dividends and the amount thereof, future results of\nprojects, operating activities and new energy products, expectations and plans\nfor renewables production capacity and investments in, and development of,\nrenewables projects, expectations and guidance with respect to production,\nproduction costs and other costs, capital expenditure, abandonment\nexpenditure, exploration expenditure and gas hub exposure, trends in commodity\nprices and currency exchange rates, adoption and implementation of new\ntechnologies and expectations regarding the achievement of Woodside’s Scope\n1 and 2 greenhouse gas emissions target (on a net equity or gross equity basis\nas specified) and other climate and sustainability goals.\n\nAll statements, other than statements of historical or present facts, are\nforward-looking statements and generally may be identified by the use of\nforward-looking words such as “aim”, “anticipate”, “aspire”,\n“believe”, “enable”, “estimate”, “expect”, “forecast”,\n“foresee”, “guidance”, “intend”, “likely”, “may”,\n“objective”, “outlook”, “pathway”, “plan”, “position”,\n“potential”, “project”, “schedule”, “seek” “should”,\n“strategy”, “strive”, “target”, “will” and other similar words\nor expressions.\n\nForward-looking statements in this report are not guarantees of future events\nor performance, but are in the nature of future expectations that are based on\nmanagement’s current expectations and assumptions.\n\nThose statements and any assumptions on which they are based are subject to\nchange without notice and are subject to inherent known and unknown risks,\nuncertainties, contingencies and other factors, many of which are beyond the\ncontrol of Woodside, its related bodies corporate and their respective\nofficers, directors, employees, advisers or representatives.\n\nImportant factors that could cause actual results to differ materially from\nthose in the forward-looking statements and the assumptions on which they are\nbased include, but are not limited to, fluctuations in commodity prices,\nactual demand for Woodside products, currency fluctuations, geotechnical\nfactors, drilling and production results, gas commercialisation, development\nprogress, operating results, engineering estimates, reserve and resource\nestimates, loss of market, industry competition, pace of technology\ndevelopments, sustainability and environmental risks, climate related\ntransition and physical risks, safety and personnel risks, changes in\naccounting standards, economic and financial markets conditions in various\ncountries and regions, the actions of third parties, project delay or\nadvancement, regulatory approvals, political risks and the impact of armed\nconflict and political instability (such as the ongoing conflicts in Ukraine\nand in the Middle East) on economic activity and oil and gas supply and\ndemand, cost estimates, legislative, fiscal and regulatory developments,\nincluding those related to the imposition of tariffs and other trade\nrestrictions, and the effect of future regulatory or legislative actions on\nWoodside or the industries in which it operates, including potential changes\nto tax laws, the impact of general economic conditions, inflationary\nconditions, prevailing exchange rates and interest rates and conditions in\nfinancial markets, and risks associated with acquisitions, mergers,\ndivestitures and joint ventures, including difficulties integrating or\nseparating businesses, uncertainty associated with financial projections,\nrestructuring, increased costs and adverse tax consequences, and uncertainties\nand liabilities associated with acquired and divested properties and\nbusinesses.\n\nA more detailed summary of the key risks relating to Woodside and its business\ncan be found in the “Risk factors” section of Woodside’s most recent\nAnnual Report released to the Australian Securities Exchange and in\nWoodside’s most recent Annual Report on Form 20-F filed with the United\nStates Securities and Exchange Commission and available on the Woodside\nwebsite at https://www.woodside.com/investors/reports-investor-briefings\n(https://cts.businesswire.com/ct/CT?id=smartlink&url=https%3A%2F%2Fwww.woodside.com%2Finvestors%2Freports-investor-briefings&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=https%3A%2F%2Fwww.woodside.com%2Finvestors%2Freports-investor-briefings&index=5&md5=abce995c116ef0871b37f0ebaa25ae42)\n. You should review and have regard to these risks when considering the\ninformation contained in this report.\n\nIf any of the assumptions on which a forward-looking statement is based were\nto change or be found to be incorrect, this would likely cause outcomes to\ndiffer from the statements made in this report.\n\nInvestors are strongly cautioned that forward-looking statements are subject\nto significant uncertainties and may not prove to be correct. Actual results\nor performance may vary materially from those expressed in, or implied by, any\nforward-looking statements. None of Woodside nor any of its related bodies\ncorporate, nor any of their respective officers, directors, employees,\nadvisers or representatives, nor any person named in this report or involved\nin the preparation of the information in this report, makes any\nrepresentation, assurance, guarantee or warranty (either express or implied)\nas to the accuracy or likelihood of fulfilment of any forward-looking\nstatement, or any outcomes, events or results expressed or implied in any\nforward-looking statement in this report.\n\nAll forward-looking statements contained in this report reflect Woodside’s\nviews held as at the date of this report and, except as required by applicable\nlaw, neither Woodside, its related bodies corporate, nor any of their\nrespective officers, directors, employees, advisers or representatives nor any\nperson named in this report or involved in the preparation of the information\nin this report intends to, undertakes to, or assumes, any obligation to,\nprovide any additional information or update or revise any of these statements\nafter the date of this report, either to make them conform to actual results\nor as a result of new information, future events or results, changes in\nWoodside’s expectations or otherwise.\n\nPast performance (including historical financial and operational information)\nis given for illustrative purposes only. It is not necessarily, a reliable\nindicator of future performance, including future security prices.\n\nNon-IFRS Measures\n\nThroughout this report, a range of financial and non-financial measures are\nused to assess Woodside’s performance, including a number of financial\nmeasures that are not defined in, and have not been prepared in accordance\nwith, International Financial Reporting Standards (IFRS) and are not\nrecognised measures of financial performance or liquidity under IFRS (Non-IFRS\nFinancial Measures). These measures include EBIT, EBITDA excluding impairment,\nGearing, Underlying NPAT, Average realised price, Unit production cost, Net\ndebt, Liquidity, Free cash flow, Capital expenditure, Exploration expenditure,\nReturn on Equity, Return on average capital employed, Cash margin, Production\ncost margin, Other cash cost margin, Net tangible assets and Net tangible\nassets per ordinary security. These Non-IFRS Financial Measures are defined in\nthe glossary on pages 59 – 61 of this report. A quantitative reconciliation\nof these measures to the most directly comparable financial measure calculated\nand presented in accordance with IFRS can be found in the Alternative\nPerformance Measures section of this report on pages 55 – 58.\n\nWoodside’s management uses these measures to monitor Woodside’s financial\nperformance alongside IFRS measures to improve the comparability of\ninformation between reporting periods and business units and Woodside believes\nthat the Non-IFRS Financial Measures it presents provide a useful means\nthrough which to examine the underlying performance of its business.\n\nUndue reliance should not be placed on the Non-IFRS Financial Measures\ncontained in this report and these Non-IFRS Financial Measures should be\nconsidered in addition to, and not as a substitute for, or as superior to,\nmeasures of financial performance, financial position or cash flows reported\nin accordance with IFRS. Non-IFRS Financial Measures are not uniformly defined\nby all companies, including those in Woodside’s industry. Accordingly, they\nmay not be comparable with similarly titled measures and disclosures by other\ncompanies.\n\nClimate strategy and emissions data\n\nAll greenhouse gas emissions data in this report are estimates, due to the\ninherent uncertainty and limitations in measuring or quantifying greenhouse\ngas emissions, and our methodologies for measuring or quantifying greenhouse\ngas emissions may evolve as market practices continue to develop and data\nquality and quantity continue to improve.\n\nWoodside “greenhouse gas” or “emissions” information reported are\nScope 1 GHG emissions, Scope 2 GHG emissions, and/or Scope 3 greenhouse\nemissions, each on a net equity or gross equity basis as specified.\n\nFor more information on Woodside’s climate strategy, including references to\n‘lower-carbon’ and ‘lower-carbon services’ as part of that strategy,\nand emissions data, refer to the 2025 Climate and Sustainability Summary,\navailable on the Woodside website at https://www.woodside.com/sustainability\n(https://cts.businesswire.com/ct/CT?id=smartlink&url=https%3A%2F%2Fwww.woodside.com%2Fsustainability&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=https%3A%2F%2Fwww.woodside.com%2Fsustainability&index=6&md5=80867f3e1ac0fcc85f723fffb86616bf)\nand section 3.6 of Woodside’s 2025 Annual Report.\n\nNo express or implied prices\n\nThis report does not include any express or implied prices at which Woodside\nwill buy or sell financial products.\n (1) These are alternative performance measures which are non-IFRS measures \n that are unaudited. Refer to Alternative Performance Measures on pages 53-56 \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(2) The 2026 calculation has been updated to adjust for contributions \n from/(to) NCI and lease repayments. The 2025 comparative has been restated to \n be presented on the same basis. \n \n \n \n(3) 2025 sales volumes have been restated to include additional volumes of \n 0.19 MMboe and 6 MMscf/d to reflect pipeline gas volumes sold in MMBtu at a \n revised boe conversion factor, impacting realised price by ($0.1)/boe. \n \n \n \n(4) H1 2026 Total production volumes includes production of 85.0 MMboe from \n Woodside reserves and 1.5 MMboe from processing, comprising 1.0 MMboe from \n Beaumont New Ammonia and 0.5 MMboe from feed gas purchased from Pluto \n non-operating participants processed through the Pluto-KGP Interconnector. \n \n \n \n(5) 2026 full-year Total production volumes includes 2-3 MMboe from Beaumont \n New Ammonia (no change). \n \n \n \n(6) Consistent with 2025 Capital Markets Day, presented on a 3 year average \n for 2026-2028. Includes binding sales and purchases agreements only, \n Woodside’s equity share of Scarborough and Pluto LNG, Corpus Christi offtake \n volumes and assumes the Chevron asset swap is completed. \n \n \n \n(7) Louisiana LNG (90% Louisiana LNG LLC, 60% Louisiana LNG Infrastructure LLC \n and 20% Driftwood Pipeline LLC) capital expenditure adjusted for the cash \n contributions \n \n \n \nfrom Stonepeak Wallaby I Acquiror LP (Stonepeak) and Williams Louisiana LNG \n LLC (Williams). Scarborough (74.9% participating interest) and Pluto Train 2 \n (51% participating interest). Trion (60% participating interest). Excludes the \n final acquisition completion payment for Beaumont New Ammonia of $470 million. \n Completion of the asset swap with Chevron assumed to occur in Q4 2026. \n \n \n \n(8) Capital expenditure is reported on the basis of Woodside’s net ownership \n interests for each project as at 30 June 2026. Refer to pages 49-50 for \n details. \n \n \n \n(9) Calculated based on Woodside’s closing share price on 30 June 2026 of \n A$28.21 ($19.38) and a USD:AUD exchange rate of 0.6869. \n \n \n \n(10) This is an alternative performance measure which is a non-IFRS measure \n that is unaudited. Refer to Alternative Performance Measures on pages 53-56 \n for a reconciliation for these measures to Woodside’s financial statements \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(11) Net profit after tax attributable to equity holders of the parent. \n \n \n \n(12) The global operations effective income tax rate (EITR) of 28.5% (2025: \n 21.0%) is calculated as the Group’s income tax expense divided by profit \n before income tax. The underlying EITR is 29.6% when excluding the recognition \n of additional Pluto PRRT deferred tax asset, income tax deferred tax asset \n relating to US net operating losses and impairment losses. \n \n \n \n(13) Capital additions on property, plant and equipment, evaluation \n capitalised and other corporate spend. Excludes exploration capitalised and is \n presented net of capital contributions from non-controlling interests for the \n development of Louisiana LNG. \n \n \n \n(14) Exploration and evaluation expenditure and exploration capitalised less \n evaluation expenditure, amortisation of licence acquisition costs and prior \n year exploration expense written off. The 2025 comparative has been restated \n to be presented on the same basis. \n \n \n \n(15) Cash flow from operating activities less cash flow from investing \n activities, adjusted for the capital contributions from/(to) non-controlling \n interests and lease repayments. The 2025 comparative has been restated to be \n presented on the same basis. \n \n \n \n(16) Includes production of 85.0 MMboe from Woodside reserves and 1.5 MMboe \n from processing, comprising 1.0 MMboe from Beaumont New Ammonia and 0.5 MMboe \n from feed gas purchased from Pluto non-operating participants processed \n through the Pluto-KGP Interconnector. \n \n \n \n(17) The conversion factors used throughout this report are set out on page \n 60, unless otherwise stated. Sales volumes differ from production volumes \n primarily due to the timing of liftings and the exclusion of third-party \n purchased volumes. \n \n \n \n(18) 2025 sales volumes have been restated to include additional volumes of \n 0.19 MMboe and 6 MMscf/d to reflect pipeline gas volumes sold in MMBtu at a \n revised boe conversion factor, impacting realised price by ($0.1)/boe. \n \n \n \n(19) Comparisons are to half-year ended 30 June 2025. \n \n \n \n(20) This is an alternative performance measure which is a non-IFRS measure \n that is unaudited. Refer to Alternative Performance Measures on pages 53-56 \n for a reconciliation for these measures to Woodside’s financial statements \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(21) Calculated based on Woodside’s closing share price on 30 June 2026 of \n A$28.21 ($19.38) and a USD:AUD exchange rate of 0.6869. \n \n \n \n(22) These are alternative performance measures which are non-IFRS measures \n that are unaudited. Refer to Alternative Performance Measures on pages 53-56 \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(23) Net cash flow from / (used in) operating activities and net cash flow \n from/(used in) investing activities, adjusted for the capital contribution \n from/(to) non-controlling interests and lease repayments. \n \n \n \n(24) No change to the forecasted Trion project capital expenditure. Trion \n construction related vessel leases are for a term of 3 years. \n \n \n \n(25) Completion of the transaction is subject to conditions precedent. See \n “Woodside simplifies portfolio and unlocks long-term value” announced 19 \n December 2024 for details concerning the Australian asset swap. \n \n \n \n(26) Completion of the transaction is subject to conditions precedent. See \n “Woodside simplifies portfolio and unlocks long-term value” announced 19 \n December 2024 for details concerning the Australian asset swap. \n \n \n \n(27) See the announcement “Woodside completes Gippsland Basin operatorship \n transition” released 1 July 2026 for details. \n \n \n \n(28) Higher net production percentage reflects accelerated recovery of 100% \n Woodside-funded pre-FID costs under the PSC entitlement, driven by high oil \n price. \n \n \n \n(29) Beaumont New Ammonia production volume is 1.0 MMboe in H1 2026. \n \n \n \n(30) Lower-carbon ammonia is characterised here by the use of hydrogen with \n emissions abated by carbon, capture, and storage (CCS), with an expected \n ammonia lifecycle (Scope 1, 2 and 3) carbon emissions intensity of 0.8 \n tCO2/tNH3 (based on contracted intensity threshold with Linde) relative to \n unabated ammonia with a lifecycle (Scope 1, 2 and 3) carbon emissions \n intensity of 2.3 tCO2/tNH3 (Hydrogen Europe, 2023). \n \n \n \n(31) These are alternative performance measures which are non-IFRS measures \n that are unaudited. Refer to Alternative Performance Measures on pages 53-56 \n and Non-IFRS Measures on page 63 for more information. \n \n \n \n(32) The Project has received funding from the Hydrogen Fuelled Transport \n Project Funding Process as part of the Western Australian Government’s \n Renewable Hydrogen Strategy. \n \n \n \n(33) Completion of the transaction is subject to customary conditions \n precedent. See “Woodside Exercises Browse pre-emption right” announced on \n 12 June 2026. \n \n \n \n(34) See “Woodside rationalises global portfolio with Calypso divestment” \n released 6 August 2026 for details \n \n \n \n(35) See the media release “Bandit-1 Discovery off Louisiana” released 10 \n April 2026 for details. \n \n \n \n(36) Woodside uses the term lower-carbon to describe the characteristic of \n having lower levels of associated potential GHG emissions when compared to \n historical and/or current conventions or analogues, for example relating to an \n otherwise similar resource, process, production facility, product or service, \n or activity. When applied to Woodside's strategy, please see the definition of \n lower-carbon portfolio in the Glossary on pages 57-59. \n \n \n \n(37) Following completion of the Chevron asset swap announced in 2024, \n Woodside’s participating interest in Angel CCS will increase to 40%. \n \n \n \n(38) This metric is determined utilising Woodside’s risk matrix. When used \n to define impact to the environment, moderate impact is an impact on \n environmental features or areas of heightened sensitivity with a limited \n ability to recover. \n \n \n \n(39) For these purposes, “material topic” means a 2026 sustainability \n topic, determined as part of the 2025 materiality assessment process \n undertaken by Woodside. Classification of any topic as material through our \n materiality assessment process should not be read as a determination of \n whether that topic rises to the level of materiality of disclosure required by \n law, including the laws of Australia, and the US. However where applicable \n laws require the disclosure of risks that meet certain thresholds, Woodside \n has disclosed those risks. \n \n \n \n(40) Ms Westcott was appointed to the Board on 18 March 2026 \n \n \n \n(41) Mr Cutifani was appointed to the Board on 19 March 2026. \n \n \n \n(42) Mr Macfarlane’s retirement took effect from 23 April 2026. \n \n \n \n(43) Mr O’Neill’s resignation took effect on 1 July 2026. \n \n \n \n(44) Comparisons are to half-year ended 30 June 2025. \n \n \n \n(45) Includes lease assets and lease liabilities as a result of AASB 16/ IFRS \n 16 Leases. Net Tangible Assets per ordinary security is a non-IFRS measure. \n Refer to Alternative Performance Measures for a reconciliation for these \n measures to Woodside’s financial statements on pages 53 - 56. \n \n \n \n(46) UNEP, 1992. “Convention on Biological Diversity’ \n https://www.cbd.int/doc/legal/cbd-en.pdf \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=https%3A%2F%2Fwww.cbd.int%2Fdoc%2Flegal%2Fcbd-en.pdf&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=https%3A%2F%2Fwww.cbd.int%2Fdoc%2Flegal%2Fcbd-en.pdf&index=7&md5=0ed52156cee0a882f38b70c41927b7e7) \n . \n \n \n \n(47) See IFRS Foundation 2021: Climate Related Disclosures Prototype. Appendix \n A. The IFRS published a further consultation document subsequent to the 2021 \n prototype. As it did not contain an updated definition of Paris-Aligned \n scenarios Woodside has retained use of the previous edition. \n \n \n \n(48) IOGP Fatality and Permanent Impairment injury definitions | IOGP \n \n \n \n(49) Australian Clean Energy Regulator, 2023. “Corporate Emissions Reduction \n Transparency report 2023” \n https://cer.gov.au/markets/reports-and-data/corporate-emissions-reduction-transparency-report/corporate-emissions-reduction-transparency-report-2023/cert-report-2023-glossary \n (https://cts.businesswire.com/ct/CT?id=smartlink&url=https%3A%2F%2Fcer.gov.au%2Fmarkets%2Freports-and-data%2Fcorporate-emissions-reduction-transparency-report%2Fcorporate-emissions-reduction-transparency-report-2023%2Fcert-report-2023-glossary&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=https%3A%2F%2Fcer.gov.au%2Fmarkets%2Freports-and-data%2Fcorporate-emissions-reduction-transparency-report%2Fcorporate-emissions-reduction-transparency-report-2023%2Fcert-report-2023 \n -glossary&index=8&md5=3b6315a60e39c40b4984a7a8960c0478) \n \n \n \n(50) World Resources Institute and World Business Council for Sustainable \n Development 2004. “GHG Protocol: a corporate accounting and reporting \n standard”. \n\n\nThis announcement was approved and authorised for release by Woodside’s\nDisclosure Committee.\n\n\n\nView source version on businesswire.com:\nhttps://www.businesswire.com/news/home/20260824865396/en/\n(https://www.businesswire.com/news/home/20260824865396/en/)\n\nINVESTORS\n\nVanessa Martin \n\nM: +61 477 397 961\n\nE: investor@woodside.com (mailto:investor@woodside.com)\n\nMEDIA\n\nChristine Abbott \n\nM: +61 484 112 469\n\nE: christine.abbott@woodside.com (mailto:christine.abbott@woodside.com)\n\nREGISTERED ADDRESS \n\nWoodside Energy Group Ltd \n\nACN 004 898 962\n\nMia Yellagonga\n\n11 Mount Street\n\nPerth WA 6000\n\nAustralia\n\nT +61 8 9348 4000\n\nwww.woodside.com\n(https://cts.businesswire.com/ct/CT?id=smartlink&url=http%3A%2F%2Fwww.woodside.com&esheet=54594210&newsitemid=20260824865396&lan=en-US&anchor=www.woodside.com&index=9&md5=6fd48c197e71632333b47e25ae668960)\n\n\nCopyright Business Wire 2026"},"type":"article","timestamp":"2026-08-25T04:39:00.618993214Z","server_sent_at_ms":1787632740618},"received_at":"2026-08-25T04:39:01.086Z","source_url":"https://www.businesswire.com/news/home/20260824865396/en/"},"analysis":{"id":"115472","press_release_id":"126530","analysis_json":{"industry":{"label":"Oil, Gas & Consumable Fuels","sector":"Energy"},"redFlags":["Gearing of 20.6% marginally outside the 10-20% target range","One high-consequence injury recorded during the period","Net cash outflow of $419 million from hedge settlements","Impairment loss of $135 million on Calypso exploration asset"],"eventType":"earnings","narrative":"Woodside Energy delivered a resilient first half performance with operating revenue increasing 13% to $7.45 billion, driven by higher average realized prices and strong marketing activity.\n\nFree cash flow surged 159% to $352 million, enabling the board to declare an 8% increase in the interim dividend to 57 US cents per share, fully franked.\n\nMajor growth projects remain on track, with the Scarborough Energy Project now 98% complete and targeting first LNG cargo in the fourth quarter of 2026, while the Trion project offshore Mexico reached 64% completion.","sentiment":"bullish","agentHooks":{"shouldPost":true,"suggestedAngle":"Strong FCF generation supports a dividend hike as major projects approach completion."},"keyFigures":{"revenue":7446000000,"guidance":"2026 total production volumes 174-185 MMboe; 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The company declared an increased interim dividend and reported significant progress on major growth projects like Scarborough, signaling continued momentum."},"tickerRelevance":{"others":[{"ticker":"XOM","relevance":"partner"},{"ticker":"CVX","relevance":"partner"},{"ticker":"BP","relevance":"counterparty"}],"primary":"WDS"},"globalImportance":45,"audienceRelevance":45,"eventTypeSecondary":["dividend","operations_update"],"importanceComponents":{"tickerTier":"Large-Cap Energy","eventGravity":"Solid earnings beat with dividend increase","sectorWeight":"Energy"}},"event_type":"earnings","event_type_secondary":["dividend","operations_update"],"sentiment":"bullish","material_impact_score":4,"narrative":"Woodside Energy delivered a resilient first half performance with operating revenue increasing 13% to $7.45 billion, driven by higher average realized prices and strong marketing activity.\n\nFree cash flow surged 159% to $352 million, enabling the board to declare an 8% increase in the interim dividend to 57 US cents per share, fully franked.\n\nMajor growth projects remain on track, with the Scarborough Energy Project now 98% complete and targeting first LNG cargo in the fourth quarter of 2026, while the Trion project offshore Mexico reached 64% completion.","key_figures":{"revenue":7446000000,"guidance":"2026 total production volumes 174-185 MMboe; CapEx $4.0-4.5 billion","customDimensions":{"ebitda":4647000000,"free_cash_flow":352000000,"gearing_percent":20.6,"underlying_npat":1334000000,"interim_dividend_usd":0.57,"net_profit_after_tax":1672000000,"production_mboe_per_day":478,"realised_price_usd_per_boe":74}},"named_entities":{"people":[{"name":"Liz Westcott","role":"CEO"},{"name":"Richard Goyder","role":"Chair"}],"products":["Scarborough Energy Project","Trion Project","Louisiana LNG","Pluto LNG","Sangomar","Beaumont New Ammonia","Calypso Project"],"companies":[{"name":"Woodside Energy Group","ticker":"WDS"},{"name":"Stonepeak","relationship":"partner"},{"name":"Williams","relationship":"partner"},{"name":"Bechtel","relationship":"contractor"},{"name":"ExxonMobil","relationship":"partner"},{"name":"Chevron","relationship":"partner"},{"name":"bp","relationship":"counterparty"}],"dollarAmounts":[{"amount":"$7,446 million","context":"H1 2026 operating revenue"},{"amount":"$1,672 million","context":"H1 2026 NPAT"},{"amount":"$352 million","context":"H1 2026 free cash flow"},{"amount":"57 US cents","context":"Interim dividend per share"},{"amount":"$1,725 million","context":"Capital contributions received from Stonepeak and Williams"},{"amount":"$225 million","context":"Consideration for Browse pre-emption right"},{"amount":"$135 million","context":"Impairment of Calypso exploration asset"}]},"model_name":"glm-4.7","prompt_hash":"sha256:727b4b9429a443af","schema_hash":"sha256:05005c02d9cffac9","created_at":"2026-08-25T04:41:08.340Z","global_importance":45,"audience_relevance":45,"importance_components":{"tickerTier":"Large-Cap Energy","eventGravity":"Solid earnings beat with dividend increase","sectorWeight":"Energy"}},"durationMs":127166,"modelName":"glm-4.7"}}