Slides
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27 August 2026 2026 First Half Results Delivering the platform. Positioning for stronger cash generation and growth.
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Disclaimer This presentation has been prepared by Karoon Energy Ltd (Karoon or the Company). The information contained in this presentation is for information purposes only and does not constitute an offer to issue, or arrange to issue, securities or other financial products. This presentation contains summary information about the Company and its activities that is current as at the date of this presentation and remains subject to change without notice. This presentation should be read in conjunction with Karoon's other periodic and continuous disclosure announcements released to the Australian Securities Exchange which are available at: https://www.asx.com.au/markets/company/kar. This presentation does not, and does not purport to, contain all information necessary to make an investment decision in relation to Karoon. Accordingly, the information contained in this presentation is not investment or financial product advice and is not intended to be used as the basis for making an investment decision. The presentation has been prepared without taking into account the investment objectives, financial situation or other particular needs of any particular person. No representation or warranty, express or implied, is made as to the fairness, accuracy, completeness or correctness of the information, opinions and conclusions contained in this presentation. To the maximum extent permitted by law, none of Karoon, its directors, employees, representatives or agents (together, the Limited Parties), nor any other person accepts liability, including without limitation, any liability arising out of fault or negligence, for any loss arising from the use of the information contained in this presentation. In particular, no representation or warranty, express or implied is given as to the likelihood of achievement or reasonableness of any forecasts, prospects or returns contained in this presentation nor is any obligation assumed to update such information. Such forecasts, prospects or returns are by their nature subject to significant uncertainties and contingencies. This presentation is not a prospectus, product disclosure statement or other disclosure or offering document, and it has not been lodged with ASIC or the regulatory authority of any foreign jurisdiction. An investment in the Company is subject to investment and other known and unknown risks, some of which are beyond the control of Karoon. Karoon does not guarantee any particular rate of return or performance, nor does it guarantee the repayment of capital from the Company or any particular tax treatment. Before making an investment decision, you should consider, with or without the assistance of a financial or other independent professional adviser, whether an investment is appropriate in light of your particular investment needs, objectives and financial circumstances. Past performance is no guarantee of future performance. The distribution of this presentation in jurisdictions outside Australia may be restricted by law. Any recipient of this presentation outside Australia must seek advice on and observe any such restrictions. By attending an investor presentation or briefing, or accepting, accessing or reviewing this presentation, you acknowledge and agree to the terms set out in the "Disclaimer" section of this presentation. Certain figures, amounts, estimates and numbers are subject to the effect of rounding. Accordingly, the actual calculations of these figures, amounts, estimates and numbers may differ from those set out in this presentation. Forward looking statements This presentation may contain certain ‘forward‐looking statements’ with respect to the financial condition, results of operations and business of Karoon and certain plans and objectives of the management of Karoon. Forward looking statements can generally be identified by words such as ‘may’, ‘could’, ‘believes’, 'plan', 'will', 'likely', ‘estimates’, ‘targets’, ‘expects’, or ‘intends’ and other similar words that involve risks and uncertainties, which may include, but are not limited to, the outcome and effects of the subject matter of this presentation. Indications of, and guidance on, future exchange rates, capital expenditure, earnings and financial position and performance are also forward‐looking statements. You are cautioned not to place undue reliance on forward looking statements as actual outcomes may differ materially from forward‐looking statements. Any forward‐looking statements, opinions and estimates provided in this presentation necessarily involve uncertainties, assumptions, contingencies and other factors, and unknown risks may arise, many of which are outside the control of Karoon. The actual results, achievement or performance of Karoon may be materially different from any future results, achievement or performance expressed or implied by such forward looking statements. Forward‐looking statements including, without limitation, guidance on future plans, are provided as a general guide only and should not be relied upon as an indication or guarantee of future performance. Such forward looking statements speak only as of the date of this presentation. To the maximum extent permitted by law, Karoon disclaims any intent or obligation to update publicly any forward‐looking statements, whether as a result of new information, future events or results or otherwise. Guidance for the 12 months to 31 December 2026 is uncertain and subject to change. Guidance has been estimated on the basis of various risks and assumptions, including those “Key Risks” set out in Karoon’s 2025 Annual Report. References to future activities development, appraisal and exploration projects are subject to approvals such as government approvals, joint venture approvals and Karoon approvals. Karoon expresses no view as to whether all required approvals will be obtained. Guidance and forward‐looking statements in this presentation are based on oil price assumptions current as at the date of this presentation. Oil prices are highly volatile and subject to factors outside Karoon's control, including global supply and dem and, geopolitical events, and macroeconomic conditions. Actual prices may differ materially from those assumed, with consequent impact on the Company's financial performance, cash flows, capital expenditure and reserve valuations. Reserves disclosure Reserves and Resources estimates are prepared in accordance with the guidelines of the Petroleum Resources Management System (SPE‐PRMS) 2018 jointly published by the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), and American Association of Petroleum Geologists (AAPG) and Society of Petroleum Evaluation Engineers (SPEE). Unless otherwise stated, all petroleum resource estimates are quoted as at the effective date (i.e. 31 December 2025) of the Reserves and Resources Statement included in Karoon’s 2025 Annual Report. Oil and gas Reserves and Resource estimates are expressions of judgement based on knowledge, experience and industry practice. Estimates that were valid when originally calculated may alter significantly due to new information or when new techniques become available. Additionally, by their nature, reserves and resource estimates are imprecise and depend to some extent on interpretations, which may prove to be inaccurate. As further data becomes available through for instance production, the estimates are likely to change. This may result in alterations to production plans, which may in turn, impact the Company’s operations. Reserves and resource estimates are by nature forward looking statements and are the subject of the same risks as other forward‐looking statements. Resource volumetric estimates in MMboe have been rounded to one decimal place. Gas volumes are converted to barrels of oil equivalent (boe) on the basis of 6,000 scf = 1 boe. Karoon is not aware of any new information or data that materially affects the information included in the Reserves and Resources statement as at 31 Dec 2025. Authorisation This presentation has been authorised for release by the Board of Karoon Energy Ltd. 2
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Notes and Definitions 1. Karoon’s Reserves, Contingent and Prospective Resources as at 31 December 2025 are as disclosed in the 2025 Annual Report. Ka roon is not aware of any new information or data that materially affects these resource estimates. 2. Reserves and Resources estimates are prepared in accordance with the guidelines of the Petroleum Resources Management System (SPE‐PRMS) 2018 jointly published by the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG) and Society of Petroleum Evaluation Engineers (SPEE). All statements are net to Karoon’s interests (as defined below) and use a combination of deterministic and probabilistic methods. Asset and Project level Reserves and Resources have been arithmetically aggregated. There may be minor differences in addition, due to rounding. 3. For Reserves and Resources associated with assets in Brazil, Karoon’s reported net share is based on the Working Interest for each license. For Reserves and Resources associated with assets in the USA, Karoon’s reported net share is based on the Net Revenue Interest (NRI) for each license, well or reservoir, which is after the deducti on of relevant government and third‐party royalties. Resource volumetric estimates in MMboe have been rounded to one decimal place. Gas volumes are converted to barrels of oil equivalent (boe) on the basis of 6,000 scf = 1 boe. See the 2025 Annual Report released on 26 Feb 26 for full details. 4. The reference point for Reserves calculation is at the fiscal meter situated on the respective production facility. Undeveloped Reserves are expected to be recovered: (1) from new wells on undrilled acreage, (2) from deepening or sidetracking existing wells to a different reservoir, or (3) where a relatively large expenditure is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. 5. Prospective Resources relate to undiscovered accumulations and are the estimated quantities of petroleum that may potentially be recoverable by the application of a future development project(s). These estimates have both an associated risk of discovery and a risk of development, as well as volumetric uncertainty. Furthermore, exploration and appraisal drilling, testing and evaluation is required to determine the existence of potentially economic quantities of moveable hydrocarbons. 6. Unless otherwise stated, the financial information in this presentation has been extracted from, or derived from, Karoon Energy Ltd’s reviewed condensed consolidated interim financial statements for the half‐year ended 30 June 2026, which have been prepared in accordance with Australian Accounting Standard AASB 134 Interim Financial Reporting and IAS 34 Interim Financial Reporting as issued by the International Accounting Standards Board. Any non‐IFRS financial measures in this presentation are identified as such and, unless otherwise stated, have not been subject to audit or review. Reconciliations to the most directly comparable IFRS financial measures are provided where applicable. 7. EBITDAX (earnings before interest, tax, depreciation, depletion, amortisation and exploration expense), underlying EBITDAX, underlying net profit before income tax and underlying net profit after income tax are non‐ IFRS measures that are unaudited but are derived from financial statements, which have been subject to review by the Company’s auditor. These measures are presented to provide further insight into Karoon’s performance. Refer to the 2026 Half Year Report for reconciliation to statutory EBITDAX and NPAT. 8. Safety data quoted in this report does not include the Who Dat, Dome Patrol and Abilene fields in the US, which are operated by LLOG. 9. FPSO efficiency is defined as the proportion of actual and potential production. 10. Net Zero is a condition in which human‐caused residual GHG emissions are balanced by human‐led removals over a specified period and within specified boundaries, achieved by reducing emissions at their source and counter‐balancing residual emissions through carbon dioxide removal. Scope 1 & 2 emissions are defined in Karoon's 2025 Sustainability Report, aligned with the GHG Protocol and industry reporting guidelines (ISO Net Zero Guidelines (IWA 42:2022)) 11. Scope 1 emissions are offset by the surrender of Verified Carbon Units (VCU) . Associated definitions and calculations set out in 2025 Sustainability Report. 12. Unless stated otherwise, all statements, calculations and conclusionary data is for the 6 months ended 30 June 2026 or, as at 3 0 June 2026. 13. Dividend payout ratio is defined as dividends declared as a proportion of underlying NPAT. 3
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Carri Lockhart 2026 Half Year Highlights CEO and Managing Director
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Next phase focused on capturing value and building scale 1H26 major work programs delivered Execution positions Karoon for higher production and structurally lower costs Delivered in 1H26 • Baúna FPSO operatorship transition • FPSO revitalisation and maintenance (turnaround) • SPS‐92 production restored in late June • PRA‐2 back online early July • A1‐ST successfully drilled and brought online in early July Advancing in 2H26 • Lower capital intensity at Baúna • Baúna reservoir enhancement, production & cost optimisation • Neon concept maturation to reduce capital intensity • Brazil exploration farm‐down • Who Dat East sanctioned on 12 August • G1‐ST drilling planned in 4Q261 Building next phase • Neon progression towards FID • Who Dat South maturation and infill optionality • Brazil exploration portfolio maturation • Remediation of Who Dat • Reinvestment focused on returns per share 5 1. Subject to relevant approvals.
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Safeguarding operations and delivering shareholder value 2026 first half operational and financial summary 1. Net Working Interest. 1H26 production on a Net Revenue Interest (after third party royalties) was 3.02 MMboe. 2. Refer to note 8, slide 3 ‘Notes and definitions’. 3. Non IFRS term. Refer to note 6, slide 3 ‘Notes and definitions’. 4. Fully franked. Refer to ASX release 2026 Half Year Results dated 27 August 2026 for details. Operational Financial Production (NWI) 1 3.17 MMboe Total sales volumes 3.08 MMboe Underlying NPAT3 US$29.2m Underlying EBITDAX3 US$129.7m Baúna FPSO efficiency2 97% Revenue US$244.9m Unit production cost (NWI) $18.8/boe Interim dividend4 AUD 1.2¢/share 6
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Balance sheet positioned to support ongoing shareholder returns and reinvestment in growth 1. Capital returned reflects cash dividends paid and on‐market buybacks executed. 1H26 excludes the 2026 interim dividend and buy backs after 30 June 2026. Capital allocation: self-funding returns and growth Capital returned since first dividend in 20241 (US$m) Over same timeframe, US$509m invested to optimise base business and drive future growth • Baúna FPSO acquisition, maintenance and revitalisation work • Production restoration at Baúna • Who Dat infill development activities • Sanctioned Who Dat East project • Progressing Neon towards FID • Building extensive Brazilian exploration acreage position 0 50 100 150 US$m 24.2 35.3 15.6 US$75m Dividends 37.2 45.1 15.3 US$98m Buybacks US$173m Total returned 2024 2025 1H26 Total 7
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45,392 80,323 61,707 60,658 61,983 65,952 60,378 57,859 48,221 ‐‐ 5.0 10.0 15.0 20.0 25.0 0 20,000 40,000 60,000 80,000 100,000 30 Jun 22 31 Dec 22 30 Jun 23 31 Dec 23 30 Jun 24 31 Dec 24 30 Jun 25 31 Dec 25 30 Jun 26 Intensity (kgCO2e/boe) Absolute emissions (tCO2e) Absolute emissions Emissions intensity Zero recordable personal injuries across >1.1 million work hours1 in 1H26 Continued progress in safety performance -- 1 9 7 5 4 -- 2 -- -- -- 2 4 6 8 10 2022 2023 2024 2025 1H26 High potential incidents Lost Time Injuries (LTI) 0.85 -- 0.77 0.16 -- -- 0.25 0.50 0.75 1.00 2022 2023 2024 2025 1H26 Numer of injuries pe 200,000 hours No injuries in CY23 No injuries in 1H26 Total Recordable Injury Rate1 Lost Time Injuries & High Potential Incidents1 Karoon Scope 1 & 2 Emissions (absolute and intensity) 1. Does not include data relating to the Who Dat, Dome Patrol and Abilene fields in the US, which are operated by LLOG. 2. Em ission and safety numbers are unaudited for 1H26 1H262 1H26 8 30 Jun 262
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Financial Eric Williams EVP & CFO
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Production and sales underpin underlying NPAT and capital returns Financial snapshot 2026 first half financial results • Higher realised prices partially offset lower sales volumes • Continued shareholder returns despite peak investment period: • AUD 1.2 ¢/share 2026 interim dividend declared • US$15.3m via on ‐market share buyback program • Cumulative buyback since 2H24:13.3% of issued shares • Self funding and liquidity of US$363.6 million • Financial benefits from restored production and lower FPSO costs expected to become more visible in 2H26 1. Non IFRS term. Refer to note 7, slide 3 ‘Notes and Definitions’. 2. Gearing defined as Net debt/(Net debt+equity). 3. Fully franked. Refer to ASX release 2026 Half Year Results dated 27 August 2026 for details. Underlying NPAT1 US$29.2m Underlying EBITDAX1 US$129.7m Interim dividend3 AUD 1.2 ¢/share Revenue US$244.9m Gearing2 21% Average realised liquids price US$80.65 boe 10
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308.3 ‐66.5 30.2 ‐39.0 11.9 244.9 1H25 Sales Volume Realised Price Sales Volume Realised Price 1H26 US$ million 0 50 100 150 200 250 300 350 1H25 vs 1H26 2026 first half revenue bridge Strong realised pricing partly offset lower 1H volumes during planned revitalisation work Who DatBaúna 11
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- 20 40 60 80 100 120 140 160 180 2025 Act 2026 Budget 2027 target $US million FPSO A&O Charter + Service FPSO A&O TSA FPSO KAR operatorship 80% 85% 90% 95% 100% 2025 2026 2027 Increasing FPSO efficiency2 Benefits of owning and operating FPSO being realised FPSO ownership changes Baúna cost base On track to reduce direct production costs by US$30‐40 million annually • Greater control as owner/operator • Decouples costs from performance by eliminating uptime bonus payments • Structurally lowers costs by eliminating lease payments and materials cost mark ‐up • Further opportunity through enhancing logistics, maintenance cycles planning, repair activities and other operating optimising initiatives Estimated US$30-40m annualised cost 1. Indicative only, not a forecast or guidance. 2. Refer to slide 3, ‘Notes and definitions’ for FPSO efficiency definition. 20261 20271 Target 90 ‐ 95% 20261 20271 12
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1H26 (US$m) US$58.4m Operating Cash Flow 46.5 60.7 27.4 30.9 US$184.2m 18.0 1H26 Net cash used US$125.8m O&G Assets (FPSO flotel & revitalisation) O&G assets (incl SPS‐92, A1‐ST and other) Exploration, evaluation & plant Petrobras contingent payment Dividends1 & share buybacks Foreign currency change 2H26(F) (US$m) Non ‐recurring investment strengthens the business 1H26 investment for future cash generation Non‐recurring investment strengthens business • 1H26 capital deployed to complete FPSO revitalisation, restore key Baúna wells and bring A1 ‐ST online • Peak investment period substantially complete: • Lower 2H26 capex expected to support stronger free cash generation • Balance sheet retained flexibility while funding major work programs and shareholder returns • Maintained shareholder distributions, with US$30.9m of dividends paid and share repurchases in 1H26 4 Cash draw reflects investment phase 1. Dividends paid comprise the 2025 final dividend. 2. Subject to final technical evaluation, contract execution and relevant JV and regulatory approvals. 3. Capital expenditure is derived fr om CY26 guidance less capex in 1H26. Refer to ASX release 2026 First Half Results on 27 August 2026. 4. Includes 2025 final dividend, paid in Mar ch 2026, and 1H26 on‐market share buy back. 13 58.4 Investing, financing and FX cashflow Capital expenditure3 Who Dat East, G1‐ST2 and other
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14 1. As at 30 June 2026. 2. Available amount is subject to a semi‐annual redetermination process and a straight amortising facility profile from 31 March 2026 to maturity. Details can be found in the ASX release dated 16 November 2023. 3. Indicative only, not guidance and subject to realised oil prices. • US$363.6m total liquidity (30 June 2026) • Diversified capital sources: • US$350m high yield bond + US$283.3m RBL2 • Lower 2H26 capex supports stronger free cash flow • Disciplined capital returns aligned with liquidity and growth priorities Maintaining balance sheet capable of funding growth is key priority 528.2 681.2 452.1 546.1 363.6 1 0 150 300 450 600 750 1H24 2H24 1H25 2H25 1H26 Cash Undrawn RBL facility Liquidity Transitioning from investment to cash generation in 2H26 Financial capacity to fund next stage of growth Liquidity (US$m) 2H26+ cash flow expected to benefit from revitalisation and maintenance work at Baúna and returning wells to production 3
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Cargoes sold to EU eligible for lower Brazilian Export Tax Optimising pricing through market selection Quality crude and flexible market access enables optimisation of cargo value • Cargoes to European Union qualify for preferential 3.97% after ‐tax export tax rate (6% pre ‐tax) under Mercosur –European Union trade framework • Two 1H26 cargoes subject to export tax, one sold to EU at lower tax rate • Considering export tax impact when selecting end market, to maximise realised pricing Background : Brazilian government introduced 120 day 7.92% after ‐tax (12% pre‐tax) temporary tax on crude oil exports, effective 12 March 2026. Subsequently extended by 60 days on 9 July 2026 15
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Prioritise shareholder returns while preserving capacity to fund value‐accretive growth Cash generation & capital prioritisation Operating cash flow Non-discretionary capital spend Sustaining capex and mandatory capital commitments¹ Maintain strong, flexible balance sheet Free cash flow 1. Capital commitments such as contractual commitments including contingent payments to Petrobras. 2. Refer to ASX release dated 29 June 2026 titled "Commencement of a further on‐market share buyback". Growth investments Required to meet strict investment hurdles and generate meaningful value accretion Value-driven capital allocation Capital returns 20% ‐ 40% Underlying NPAT Discretionary additional returns eg on‐market buybacks² Fund base business, protect financial flexibility and allocate free cash flow to highest value use Capital allocation framework unchanged 16
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Operational Update Carri Lockhart CEO and Managing Director
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Enhancing asset value through active reservoir management and cost optimisation • Entered 2H26 as integrated Operator of Baúna Complex, with full control of FPSO, infrastructure and reservoir development • Sustaining asset integrity and performance • In 2H26, recommence water injection for reservoir pressure support • Focus on additional operating cost reductions • Identify near‐ field exploration opportunities Baúna - production and cost optimisation Focus areas for 2H26 and beyond 1H26 production 2.4 MMbbl 1H26 revenue US$197.7 million 18
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78% 83% 85% 97% 91% 93% 99% 96% 97% 70% 75% 80% 85% 90% 95% 100% 2Q24 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 Investment translating into sustained operating performance Baúna FPSO efficiency exceeding target Focused on operational excellence and remaining within or above target 90‐95% efficiency range • FPSO efficiency exceeded target in last three quarters, driven by 2025 and 2026 FPSO revitalisation and maintenance programs • Currently producing at approximately 20,000 ‐ 21,000 bopd 1.FPSO efficiency defined as the proportion of actual and potential production. Target range Consistently exceeding target 2025 Flotel campaign 2026 Flotel campaign Quarterly FPSO efficiency 19
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• Continued strong topside reliability (~97% in 1H26) • Successful A1 sidetrack well came online in July, currently producing ~2,200 boepd NRI 1 • Who Dat East sanctioned on 12 August 2026 • G1‐ST drilling planned for 4Q26, pending JV and regulatory approval, with first production in 1H27 • Targeting Who Dat South appraisal sidetrack in 2027 • E riser remediation targeted for 4Q27 Optimising operations through reliable topside performance and capital‐efficient production additions 1. Net Revenue Interest (NRI) is after the deduction of relevant government and third‐party royalties. Focus areas for 2H26 and beyond 1H26 production 0.62 MMboe 1H26 revenue US$47.2 million Who Dat 20
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JV approves Who Dat East project1 • Final Investment Decision (FID) approved by Joint Venture on 12 August 2026 • Initial one well development via 29km tieback to Who Dat FPS • IRR2 : >20% IRR (mid ‐case) • First oil: 2H28 (target) • Initial gross production rate of ~6,500 bopd liquids & 50 MMscf/d gas • ~2,600 bopd & 20 MMscf/d gas NRI3 • Estimated capital cost US$155 – 165m net to KAR 1. See ASX release dated 12 August 2026 for more information. 2. Project economic metrics are based on the current development mid case concept and assumes project execution substantially in accordance with the approved schedule and budget. The analysis also assumes timely receipt of regulatory approvals, contractor performance consistent with expectations and no material adverse changes in commodity prices, exchange rates or operating conditions. Actual outcomes may differ materially if internal assumptions prove incorrect. 3. Karoon’s NRI interest is currently ~40%. Once the approved royalty relief is exhausted this will revert to ~32%. Planned 29 km tieback via subsea pipeline High‐return growth leveraging existing infrastructure Value ‐accretive development with first production expected in 2H28 21
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TURNAROUND 28 DAYS + 1 RAMP UP Concept Reset • Phased development with lower initial capital • 3 producers + 1 gas injector • Greater Neon upside preserved through staged expansion options 2H 2026 Validate + Secure (Pre-FEED) • Commence project execution Decision Gate 2 Move into FEED 4Q26 Target • Confirm selected concept • Technical and commercial scopes verified • Recommence farm‐down process to secure partner Project Sanction 2027 Target FID1H 2026 • Evaluation of potential facilities • Basis of Design • Structure key commercial terms 1. Timeline and scope of each stage gate is indicative only and subject to change. Reducing initial capital intensity while maintaining flexibility for future expansion Optimising Neon development concept 1 Proposed timeline from concept reset to FID 22
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Maturing exploration/appraisal opportunities to underpin long term, value accretive, growth Basin exploration in Brazil and USA Existing acreage positions create multiple pathways for resource additions Brazil Santos Basin portfolio (100% KAR) Deepwater and Esmeralda blocks near Baúna and Neon provide high potential, longer‐term optionality USA Who Dat hub opportunities (infrastructure-led) Discoveries and prospects located near established Who Dat processing and export infrastructure 23
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SPS-92 WELL WORKOVER, ESP REPLACEMENT A compelling investment Asset and cost advantage • Both Baúna and Who Dat are high‐quality, low‐cost assets in tier‐1 jurisdictions • 1H25 and 26 Baúna work programs and operatorship transition have delivered higher uptime and lower operating costs • Oil‐weighted (97% oil/liquids in 1H26) • Organisation in place to drive performance and growth Quality assets. Financial discipline. Growth opportunities. Together, they drive shareholder value Financial strength • Peak 1H26 investment period nearly complete, expected to drive improved production and FCF in 2H26 • Strong balance sheet, with focus on maintaining liquidity to underpin growth opportunities • Disciplined capital allocation framework including shareholder returns Growth pathway • Who Dat East ‐ value accretive development sanctioned, online 2H28 • Neon ‐ concept reset targeting lower capital intensity and higher returns • Infrastructure and basin‐led exploration/appraisal acreage provide multiple opportunities for future growth 24 Disciplined delivery. Financial strength. Growth enabled.
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Q&A
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Appendix and Glossary
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Appendix 1: Underlying NPAT1 drivers 27 1. Underlying EBITDAX, NPAT & underlying pre‐tax profit reflects the Company's assessment of financial performance. These are non‐IFRS measures which are unaudited but derived from figures in the financial statements. Refer to slide 28 for reconciliation of these underlying adjustments. These measures are presented to provide further insight into Karoon’s performance. US$ million 1H26 1H25 % Change Six months to: 30 June 2026 30 June 2025 Revenue 244.9 308.3 ‐21 Operating costs (59.6) (54.3) 10 Carbon credit costs (1.0) (1.4) ‐29 Royalties and other government take (29.0) (23.3) 24 FPSO right‐of‐use asset depreciation included in EBITDAX ‐ (14.2) na Change in inventories 5.70 17.2 ‐67 Transportation costs (7.1) (10.2) ‐30 Sundry income ‐ 0.1 ‐100 Business development and other project costs (1.4) (0.8) 75 Corporate costs (19.1) (16.7) 14 Share‐based payment expense (3.7) (0.9) 311 Finance charges on FPSO lease liabilities ‐ (3.3) na Underlying EBITDAX¹ 129.7 200.5 ‐35 Depreciation and amortisation reported, excluding former FPSO ROU depreciation (57.1) (89.2) ‐36 Add back: SPS‐92 prior‐period depreciation correction 7.0 ‐ na Net interest and other finance costs (30.6) (29.2) 5 Exploration and evaluation expenditure expensed (2.4) (4.7) ‐49 Underlying net profit before tax¹ 46.6 77.4 ‐40 Underlying income tax expense (17.4) (32.4) ‐46 Underlying net profit after tax¹ 29.2 45.0 ‐35 • Underlying NPAT down 35% on 1H25 primarily due to lower sales volumes and increased royalties due to Brazilian export tax, partly offset by higher realised prices, and lower DD&A and production costs following FPSO purchase. • Underlying effective tax rate decreased to 37.5% (41.8% in 1H25), compared with applicable statutory rate (34% Brazil, 30% in Australia and 26.5% in the US/ Louisiana) primarily reflecting less adverse net FX related tax impacts than in 1H25.
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Appendix 2: Reconciliation of underlying results1 to statutory results 28 1. Underlying EBITDAX (earnings before interest, tax, depreciation, depletion, amortisation, exploration and costs of unsuccessful wells) and underlying net profit after tax are non‐ IFRS measures. 2. Flotel costs relate to flotel utilised to accommodate additional workforce for the extended maintenance campaigns. 3. Costs of unsuccessful exploratory wells in 1H25 of US$13.2m post ‐tax relates to the Who Dat West (MC‐629‐ 1) well. 4. Change in fair value of contingent consideration recognises movement each year due to revaluation of Petrobras contingent consideration. 5. The provision for local content obligations has been excluded from underlying results because it relates to a discrete assessment of historical local content requirements associated with exploration activities undertaken in prior periods on specified blocks. The provision is not attributable to current ‐period production or sales and is not considered indicative of the costs ordinarily incurred in generating the Group’s current operating results. 6. Corporate relocation relates to the costs associated with moving key corporate head office roles from Melbourne to Houston and Rio de Janeiro. 7. Hedges required by syndicated loan facility were entered into for the period March 2024 to December 2025. None were entered in 1H26. 8. Deferred tax impact and gain on right disposal of right of use asset relates to non ‐cash adjustments associated with the acquisition of the Baúna FPSO. 9. Includes a prior period correction of US$4.6 million after tax relating to depreciation of the SPS ‐92 Electrical Submersible Pump (ESP) installed in 2022 following its replacement in 2026 and the derecognition of the remaining carrying value of the ESP of US$1.2 million pre ‐tax (US$0.8 million after tax). 10. Cumulative translation adjustment impact on deferred tax expense reflects a non ‐monetary movement in deferred tax expense due to FX fluctuations to the Brazilian asset base, denominated in REAL (BRL), and the reporting currency, which is US$. This adjustment will occur each reporting period in line with the movement in conversion rates between BRL and US$. 1H26 1H25 NPAT EBITDAX NPAT EBITDAX Statutory results 26.7 115.4 71.0 227.1 Flotel costs2 ‐ ‐ 13.9 21.1 Unsuccessful exploratory wells3 ‐ ‐ 13.2 ‐ Change in fair value of contingent consideration4 7.1 10.7 (11.2) (17.0) Local content obligations5 1.5 2.2 ‐ ‐ Corporate relocation costs6 1.6 2.3 2.3 3.1 Realised losses /(gains) on cash flow hedges7 0 0 0.8 1.3 Foreign exchange losses/(gains) (3.3) (6.7) 0.2 0.2 FPSO transition costs 3.0 4.6 ‐ ‐ Gain on disposal of right‐of‐use asset ‐ Baúna FPSO8 ‐ ‐ (35.3) (35.3) Deferred tax asset write off – Baúna FPSO8 ‐ ‐ 18.4 ‐ SPS‐92 workover derecognition and prior‐period correction9 5.4 1.2 ‐ ‐ Cumulative translation adjustment impact on deferred tax10 (12.8) ‐ (28.3) ‐ Total adjustments 2.5 14.3 (26.0) (26.6) Underlying results1 29.2 129.7 45.0 200.5
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Appendix 3: 2026 Guidance 29 2026 Calendar Year1, 2 Guidance as at 27 August 2026 PRODUCTION3 Brazil MMbbl 6.0 – 6.7 Who Dat (NRI) MMboe 1.2 – 1.5 Total production MMboe 7.2 – 8.2 UNDERLYING OPERATING COSTS Unit production costs (NWI)4 US$/boe 12 – 15 Exploration expenses, Business Development, share‐ based payments US$m 10 – 14 Unit DD&A (NWI)5 US$/boe 15 – 17 Finance costs and interest (net of interest income)5 US$m 60 – 70 Other operating costs6 US$m 37 – 41 INVESTMENT EXPENDITURE Baúna7 US$m 89 – 97 Who Dat8 US$m 87 – 105 Exploration and appraisal (Neon, Santos Basin) US$m 14 – 16 Other capex 8 US$m 3 – 4 Total capex US$m 193 – 222 Petrobras contingent consideration9 US$m 28 NOTES 1. Numbers may not add due to rounding. 2. Guidance is subject to various risks (including “Key Risks” set out in the 2025 Annual Report). 3. Production assumes drilling results and expected future development projects, including well interventions, are delivered in accordance with their currently expected schedules and work scopes. 4. Unit Production Costs: based on daily operating costs associated with Baúna and Who Dat production. Excludes carbon costs and non‐ oil and gas related depreciation and is based on Karoon’s Net Working Interest production. Excludes one off FPSO transition costs and corporate office relocation costs. 5. Finance costs and interest includes interest expense, amortisation of loan transaction costs, commitment fees, bank fees, surety bond costs, withholding tax related to intra‐group and cross ‐border cash movements, and the unwind of restoration and abandonment provision net of interest income. 6. Other operating costs include staff costs, IT, other corporate and Business Unit overhead costs and non‐ oil and gas related depreciation. Excludes royalties and other government take, social investment/sponsorships in lieu of tax, foreign exchange gains/losses, hedge costs and non ‐underlying transaction costs. 7. The cost of the 2026 Baúna FPSO revitalisation campaign is guided separately. 8. CY26 capex includes the A1 and G1 sidetracks and the 2026 portion of the recently approved Who Dat East development . 9. The 2025 Petrobras contingent payment was made in late January 2026. 2026 full year guidance has been revised to reflect sanction of the Who Dat East development, which has increased investment expenditure in the second half of 2026 by US$15 – 20 million. The guidance table does not include the following: • US$49 ‐ 53 million of flotel and FPSO integrity costs. The flotel campaign was completed in 1H26, for US$46.5 million, with additional integrity costs expected to be incurred in 2H26. • One off FPSO transition costs of US$6m. • US$3 ‐ 4 million related to relocating corporate head office roles from Melbourne to the USA (Houston) and Brazil (Rio de Janeiro).
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Glossary 30 Term Definition 1H26 Half year ended 30 June 2026 1H25 Half year ended 30 June 2025 AASB Australian Accounting Standards Board. ANP Agência Nacional do Petróleo, Gás Natural e Biocombustíveis. Baúna or Baúna Project Concession BM‐S‐40 containing the producing Baúna, Piracaba and Patola light oil fields in Brazil. bbl or barrel Barrel of oil = 42 United States gallons; equivalent to approximately 159 litres Boe Barrel of oil equivalent. 1 Boe = 6000 scf natural gas Boepd Barrels of oil equivalent per day Bopd Barrels of oil per day BRL Brazilian Real CY Calendar year D&A Depreciation and amortisation D,D&A Depreciation, depletion and amortisation EBITDAX Earnings before interest, tax, depreciation, amortisation, exploration and costs of unsuccessful wells Emissions intensity Total Scope 1 and 2 Greenhouse Gas (GHG) (kgCO2e) divided by the total production (boe) of the equivalent period. FEED Front End Engineering and Design FID Final Investment Decision FPS Floating, production and storage vessel FPSO Floating, production, storage and offloading vessel Free cash flow from operations Operating cash flows less lease liability payments and investing cashflows net of the Who Dat and Baúna FPSO acquisition Gearing Gearing is defined as net debt / (net debt + book value of equity) JV Joint Venture Karoon Karoon Energy Ltd and its subsidiaries kgCO2e/boe Kilograms of carbon dioxide equivalent per barrel of oil equivalent Leverage Leverage is based on net debt divided by underlying EBITDAX for the last twelve months