Interim report
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Genel Energy PLC (GENL) Genel Energy PLC: Unaudited results for the period ended 30 June 2026 04-Aug-2026 / 07:00 GMT/BST 4 August 2026 Genel Energy plc - Unaudited results for the period ended 30 June 2026 Paul Weir, Chief Executive of Genel, said: “We remain firmly focused on delivering our clearly stated strategic objectives and in this period, we have demonstrated our ability to deliver on those objectives. In the first half of the year, the proposed recommended all- cash offer for Capricorn Energy has been a key priority and represents a significant step in our long-standing strategy to diversify geographically, in this case Egypt, a jurisdiction that we have targeted for some time. The acquisition will substantially broaden and diversify our cash generation, while maintaining a very strong balance sheet, underpinned by significant cash resources and low leverage. In Kurdistan, we continue to work closely with DNO towards normalising production and restoring exports. We will continue to calibrate activity levels based on above-ground conditions, the financial environment and well performance, each of which is subject to ongoing review. In Oman, we are progressing plans to drill two commitment wells on Block 54 in 2027, while in Somaliland we continue to advance preparations for the potentially transformational Toosan-1 exploration well. We see much positive potential in the coming six to twelve months.” Results summary ($ million unless stated) H1 2026 H1 2025 FY 2025 Average Brent oil price ($/bbl) 91 72 69 Average realised price ($/bbl) 31 33 32 Production (bopd, working interest ‘WI’) 6,600 19,600 17,520 Revenue 13.4 35.8 68.7 Production costs (9.4) (9.4) (21.0) EBITDAX1 (4.2) 25.3 43.3 Operating loss (15.3) (2.5) (10.3) Cash flow from operations 0.3 19.2 36.3 Capital expenditure 20.8 13.2 29.2 Production business netback after interest (23.9) 6.2 9.8 Free cash flow2 (25.4) 4.7 4.1 Cash 199.0 225.0 224.4 Total debt 92.0 92.0 92.0 Net cash3 108.1 134.4 133.7 Basic LPS from continuing operations (¢ per share) (6.3) (1.3) (4.6) Dividend (¢ per share) - - - 1. EBITDAX is operating loss adjusted for the add back of depreciation and amortisation, exploration expense, net write-off/impairment of oil and gas assets, netECL/reversal of ECL receivables and other non-cash items2. Free cash flow is reconciled on page 63. Reported cash less debt reported under IFRS (page 6) Summary On 2 July 2026, the boards of directors of Capricorn Energy plc (‘Capricorn Energy’), Genel Energy No.9 Limited and the Company announced that they had reached agreement on the terms and conditions of a recommended cash offer for the entire issued and to be issued ordinary share capital of Capricorn Energy, with the vote of Capricorn Energy’s shareholders to approve the scheme of arrangement expected to take place on 18 August 2026. Genel Energy No.9 Limited has received irrevocable undertakings approximately representing,
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in aggregate, 39.3% of Capricorn Energy’s issued share capital. Full details can be found on the Company’s website Gross average production of 26,400 bopd in H1 2026 (H1 2025: 78,400 bopd), significantly impacted by the suspension of production as a precautionary measure when hostilities between the United States, Israel and Iran commenced at the end of February Gross average production up to the date of suspension was 79,900 bopd compared to December 2025 gross average production of 80,700 bopd At Tawke, Drilling and Well intervention work resumed in April, and this was followed by a resumption of Production Operations towards the end of the period All production in the period was sold domestically Working interest average production of 6,600 bopd (H1 2025: 19,600 bopd) H1 2026 sales price average was $31/bbl (H1 2025: $33/bbl), with all cash due for domestic sales received in advance of sale Production business netback of negative $24 million (H1 2025: $6 million positive) and free cash outflow of $25 million (H1 2025: $5 million inflow), both impacted by suspended production and associated cash flows Net cash of $108 million at 30 June 2026 (31 December 2025: $134 million), comprised of: Cash of $199 million (31 December 2025: $224 million) Bond debt of $92 million due in 2030 (31 December 2025: $92 million) After the reporting date, $35 million of new bond debt was issued at price of 104% of nominal amount in July, implying a yield of 9.7%. This issuance brings total debt to $127 million, with the bond facility having capacity for up to $200 million Cash of $240 million at 31 July 2026 Balances with the Kurdistan Regional Government (‘KRG’) $88 million (under KBT pricing and excluding interest) remains overdue from the KRG, although this has been reduced by about $40 million of credit balances. We continue to work towards a plan for payment or settlement of amounts owed, and appropriate adjustment for price and interest Not included in the $40 million above, Genel Energy Miran Bina Bawi Limited, a subsidiary of the group, owes the KRG around $26 million relating to an arbitration costs award. The appeal against this award, held in April, was unsuccessful and there will be no further legal challenge A socially responsible contributor to the global energy mix: As part of the Genel20 Scholarship, Genel commenced the second phase of the Genel Scholars programme which, in addition to academic support, is now providing one-to-one mentorship from a Genel professional to students enrolled under the scholarship In Somaliland, Genel continued to engage with local communities through an emergency water distribution project and bolstering education facilities in the region Outlook The Company continues to progress towards building a business with a strong balance sheet that delivers resilient, reliable, repeatable, and diversified cash flows that support a dividend programme Proposed acquisition of Capricorn Energy Subject to satisfaction of regulatory conditions, we look forward to combining the businesses, with a long- term funding plan in place Tawke resilient cash generation Free cash flow from domestic sales at current production and price levels is expected to more than cover point-forward organisational costs Working with stakeholders to support the restart of exports and access to international pricing, more than doubling asset free cash flow Pursuit of circa net $50 million owed by the Kurdistan Regional Government Pre-production investment and derisking resources Incremental to the production business, the Company will invest up to $15 million over the year on its pre- production assets On Block 54 in Oman, in line with the 3-year initial exploration phase work plan, we continue to work towards acquiring 3D seismic and drilling two wells
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SL10B13 in Somaliland, we continue to make steady progress towards drilling the Toosan-1 prospect in 2027 Balance sheet strength We have maintained a very strong cash position through the period of suspended production Since the restart of production, we are cash generative and retain access to further available liquidity Enquiries: Genel Energy Luke Clements, CFO +44 20 7659 5100 Vigo Consulting Patrick d’Ancona +44 20 7390 0230 Genel will host a live presentation on the Investor Meet Company platform on Tuesday 4 August at 14:30 BST. The presentation is open to all existing and potentialshareholders. Questions can be submitted at any time during the live presentation. Investors can sign up to Investor Meet Company for free and add to meet Genel Energy plc via: https://www.investormeetcompany.com/genel-energy-plc/register-investor This announcement includes inside information. DisclaimerThis announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration andproduction business. While the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actualoutcome may be materially different owing to factors beyond the Company’s control or within the Company’s control where, for example, the Company decides on a changeof plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward looking statements. The information contained herein has not beenaudited and may be subject to further review. CEO STATEMENTGenel’s strategy is to build a business with resilient diversified cash flows that delivers sustainable value to shareholders. The Genel Board and Genel management have been resolute in their belief that this can best be achieved through strategic acquisitions which add substantial high-quality producing assets to its existing portfolio. Egypt was identified as one of Genel’s focus countries to expand its footprint and Genel has tracked and evaluated numerous opportunities in the country. The proposed all-cash acquisition of Capricorn announced at the start of July is a landmark transaction for the Company – a move that delivers our strategic intent, reshapes our company’s growth trajectory, diversifies our portfolio of oil and gas fields and begins our role as a partner in Egypt’s energy future. It brings high‑quality assets, material reserves, and a talented local workforce that together create immediate scale and opportunity for further onward investment and growth. By applying our technical and operational capabilities to these assets, we will work with the operator to accelerate production optimisation, replace reserves, and capture significant near‑term cash flow while preserving optionality for future development. Equally important, this transaction commences the start of a relationship with, and commitment to, Egypt, its hydrocarbon industry and its communities. We will work closely with government partners and host communities to ensure safe, environmentally responsible operations and to maximise local content and job creation, whilst maximising value creation for all stakeholders. Regarding the existing business, cash generation for the first half of the year was impacted by the temporary suspension of operations as a precautionary measure given the military action that commenced at the end of February. The security situation remains uncertain, with recent reports of more drone attacks and threats in the Kurdistan Region of Iraq. Production was restarted around the end of the period, and we continue to monitor the situation carefully together with the Operator and other stakeholders. We have taken careful action to protect our balance sheet and at the half year our reported cash was $199 million. Since the end of the period, we tapped our existing bond and raised a further $35 million at an implied yield of 9.7%, with the bond facility having capacity for further issuance up to $200 million. The Tawke PSC, operated by DNO, delivered exceptional performance up to the suspension of operations in February, with production consistently around 80,000 bopd and indications that the two fields can deliver more
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with the appropriate investment plan. We continue to work with all stakeholders to achieve the appropriate conditions to support safe operations and optimal investment. Operating costs of around $4/bbl and significant reserves mean that this asset will continue to provide significant cash generation well into the future. Up to the point of suspension, at average realised domestic sales prices of around $31/bbl, our 25% interest in the licence generated significant free cash flow that more than covered our spend. With regards to exports and accessing international pricing, we are encouraged by the progress we have seen with the process implemented with other IOCs since the second half of last year. We continue to work with DNO towards the export of Tawke production and full entitlement payment at international prices. This, together with unlocking appropriate investment activity, has the potential to more than double the revenue generation of this world class licence. In Oman on Block 54, we remain focused and are making good progress on delivering the two commitment wells in 2027, and we continue to work closely with the operator OQEP. In Somaliland we continue to work towards the right operational and commercial conditions to invest, with our partner OPIC (Taiwan), in the delivery of an exploration well on the highly prospective and potentially transformational SL10B13 licence. OPERATING REVIEW PRODUCING ASSETS Tawke PSC (Tawke and Peshkabir fields, 25% working interest, The year started with strong production across the Tawke licence, with two newly drilled wells brought onstream early in the period at Tawke field, and another spudded at Peshkabir field as the investment programme resumed following a near 3-year hiatus. Following the start of the regional conflict on 28 February, and specific threats made against oil and gas assets in the KRI, the operator halted all production and drilling activity as a precautionary safety measure. Development operations resumed on 9 April, with well intervention work and drilling recommencing, while production operations restarted on 28 June. (bopd) Gross production H1 2026 WI production H1 2026 WI production H1 2025 Tawke 26,400 6,600 19,600 Realised price for domestic sales in the period averaged $31/bbl until production suspension compared to $32/bbl for last year. Since the restart of production, realised price has been in the mid to upper $30s/bbl. PRE-PRODUCTION ASSETS Oman Block 54 (40% working interest) Having completed initial activity on the block at the turn of the year, work is now ongoing towards the acquisition of new 3D seismic data in H2 2026 along with the re-processing of existing 3D seismic data. This data will inform the determination of an optimal location for drilling of the first MWO exploration well on the licence in H1 2027. Somaliland - SL10B13 (51% working interest) Work towards drilling of the highly prospective Toosan-1 exploration well next year is ongoing. FINANCIAL RESULTS (all figures $ million) H1 2026 H1 2025 FY 2025
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Brent average oil price ($/bbl) 91 72 69 Field level realised price per barrel ($/bbl) 31 33 32 Average price per working interest barrel ($/bbl) 11 10 11 Working interest production (bopd) 6,600 19,600 17,520 Revenue 13.4 35.8 68.7 Other income 0.4 - 3.4 Production costs (9.4) (9.4) (21.0) Production capex (18.3) (12.5) (24.2) G&A (excl. non-cash) (8.6) (8.1) (16.9) Net cash interest1 (1.4) 0.4 (0.2) Production business netback after interest (23.9) 6.2 9.8 Pre-production capex (2.5) (0.7) (5.0) Net expense from discontinued operations - (0.4) (0.9) Working capital and other 1.0 (0.4) 0.2 Free cash flow (25.4) 4.7 4.1 Settlement of 2025 bonds - (65.8) (65.8) Issuance of new 2030 bonds - 90.5 90.5 Net change in cash (25.4) 29.4 28.8 Opening cash 224.4 195.6 195.6 Cash 199.0 225.0 224.4 Debt (90.9) (90.6) (90.7) Net cash 108.1 134.4 133.7 1 Net cash interest is bond interest payable less bank interest income (see note 5) Production of 6,600 bopd was lower than comparative period (H1 2025: 19,600 bopd) as a result of a near 4-month interruption arising from the regional security situation. All production has been sold domestically at an average price of $31/bbl (H1 2025: $33/bbl), which under the PSC equates to $11 (H1 2025: $10) per working interest barrel produced. As a result of interrupted production, revenue was $13 million (H1 2025: $36 million). Production costs of $9 million (H1 2025: $9 million) were in line with the prior period and production capex of $18 million (H1 2025: $13 million) was higher as a result of resumed investment drilling in Q4 2025. Cash general and administrative costs were $9 million, in line with the last period (H1 2025: $8 million). Interest income of $4 million (H1 2025: $4 million) and bond expense of $5 million (H1 2025: $4 million), with overall net interest cost of $1 million (H1 2025: $0.4 million income). The resulting production business netback of negative $24 million was lower than the positive $6 million generated in the last period as a result of lower revenue. Pre-production capex of $3 million (H1 2025: $1 million) was related to Oman and Somaliland assets. Free cash outflow of $25 million (H1 2025: $5 million inflow) was impacted by production interruption. EBITDAX and cash flow (all figures $ million) H1 2026 H1 2025 FY 2025 EBITDAX (4.2) 25.3 43.3 Interest received 3.7 4.4 8.9 Working capital 0.8 (10.5) (15.9) Operating cash flow 0.3 19.2 36.3 Producing asset cost recovered capex (16.0) (9.7) (18.9) Exploration and appraisal capex (4.2) (1.4) (4.5)
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Interest paid and other (5.5) (3.4) (8.8) Free cash flow (25.4) 4.7 4.1 EBITDAX of negative $4 million was lower than the comparative period (H1 2025: $25 million) due to lower revenue. EBITDAX is presented in order to illustrate the cash operating profitability of the Company and excludes the impact of costs attributable to exploration activity, which tend to be one-off in nature, and the non-cash costs relating to depreciation, amortisation, impairments, write-offs and share-based expenses. Free cash flow was $25 million outflow (H1 2025: $5 million inflow). Free cash flow is presented in order to illustrate the free cash generated for equity. Cash and debt Cash of $199 million decreased from the start of the year (31 December 2025: $224 million) as a result of negative free cash flow. The Company monitors its cash position, cash forecasts and liquidity on a regular basis. The Company holds surplus cash in treasury bills, time deposits or liquidity funds with a number of major financial institutions. Suitability of banks is assessed using a combination of sovereign risk, credit default swap pricing and credit rating. The nominal value of bond debt is $92 million (31 December 2025: $92 million). The bond debt matures in April 2030 and has two financial covenant maintenance tests: Financial covenant Test H1 2026 Equity ratio (Total equity/Total assets) > 30% 62% Minimum liquidity > $20 million $199 million Net assets Net assets at 30 June 2026 were $335 million (31 December 2025: $351 million) and consist primarily of oil and gas assets of $264 million (31 December 2025: $252 million), net trade receivables of $76 million (31 December 2025: $76 million) and net cash of $108 million (31 December 2025: $134 million). Going concern The Directors have assessed that the Company’s forecast liquidity provides adequate headroom over forecast expenditure for the 12 months following the signing of the half-year condensed consolidated financial statements for the period ended 30 June 2026 and consequently that the Company is considered a going concern. Further explanation is provided in note 1 to the financial statements. The Company has net cash of $108 million at the balance sheet date. Principal risks and uncertainties The Company is exposed to a number of risks and uncertainties that may seriously affect its performance, future prospects or reputation and may threaten its business model, future performance, solvency or liquidity. The following risks are the principal risks and uncertainties of the Company, which have not changed since year-end 2025: KRI Regional Oil and Gas Sector Risk: PSCs, access to exports, security; Development and Recovery of Oil Reserves; Commercial Terms and Payments for Kurdistan Production; Reserves Replacement and Additions; New Business Activity; Capital Structure and Financing; Attract and Maintain Organisational Capability; Environmental, Social and Governance Expectations; Regulatory and Compliance Failure; and Health and Safety. Further detail on these risks was provided in the 2025 Annual Report. Statement of directors’ responsibilities The directors confirm that these condensed interim financial statements have been prepared in accordance with International Accounting Standard 34, ‘Interim Financial Reporting’, as adopted by the European Union and that the interim management report includes a true and fair review of the information required by DTR 4.2.7R and DTR 4.2.8R, namely:
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an indication of important events that have occurred during the first six months and their impact on the condensed set of financial statements, and a description of the principal risks and uncertainties for the remaining six months of the financial year; and material related-party transactions in the first six months and any material changes in the related-party transactions described in the last annual report. The directors of Genel Energy plc are listed in the Genel Energy plc Annual Report for 31 December 2025. A list of current directors is maintained on the Genel Energy plc website: www.genelenergy.com By order of the Board Paul Weir CEO 3 August 2026 Luke Clements CFO 3 August 2026 Disclaimer This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company’s control or within the Company’s control where, for example, the Company decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward looking statements. Condensed consolidated statement of comprehensive income For the period ended 30 June 2026 Unaudited 6 months to 30 June 2026 Unaudited 6 months to 30 June 2025 Audited Year to 31 Dec 2025 Note $m $m $m Revenue 3 13.4 35.8 68.7 Other income 3 0.4 - 3.4 Production costs 4 (9.4) (9.4) (21.0) Depreciation and amortisation of oil assets 4 (9.9) (25.7) (50.0) Gross (loss) / profit (5.5) 0.7 1.1 Exploration expense 4 - (0.7) (0.3) Reversal of arbitration cost accrual 4 - 9.1 9.1 Expected credit loss (‘ECL’) of trade receivables 4 - (1.3) (1.3) General and administrative costs 4 (9.8) (10.3) (18.9) Operating loss (15.3) (2.5) (10.3) Operating loss is comprised of: EBITDAX (4.2) 25.3 43.3 Depreciation and amortisation 4 (10.1) (25.8) (50.1) Exploration expense 4 - (0.7) (0.3) Other non-cash (expense) / income (1.0) (1.3) (3.2) Finance income 5 3.7 4.4 8.9 Bond interest expense 5 (5.1) (4.0) (9.1) Net other finance expense 5 (0.7) (1.4) (2.2) Loss before income tax (17.4) (3.5) (12.7) Income tax expense 6 - - (0.1) Loss and total comprehensive expense from continuing operations (17.4) (3.5) (12.8) Profit from discontinued operations - 4.1 3.9
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(Loss) / Profit and total comprehensive (expense) / income (17.4) 0.6 (8.9) Attributable to: Owners of the parent (17.4) 0.6 (8.9) (17.4) 0.6 (8.9) (Loss) / Earnings per ordinary share ¢ ¢ ¢ From continuing operations: Basic 7 (6.3) (1.3) (4.6) Diluted 7 (6.3) (1.3) (4.6) From continuing and discontinued operations: Basic 7 (6.3) 0.2 (3.2) Diluted 7 (6.3) 0.2 (3.2) Adjusted Basic EPS / (LPS)1 7 (6.3) 0.3 (3.2) 1Adjusted basic LPS is loss and total comprehensive expense adjusted for the add back of net impairment/write-off of oil and gas assets and net ECL/reversal of ECL of receivables divided by weighted average number of ordinary shares. Condensed consolidated balance sheet At 30 June 2026 Unaudited 30 June 2026 Unaudited 30 June 2025 Audited 31 Dec 2025 Note $m $m $m Assets Non-current assets Intangible assets 8 84.4 80.6 82.7 Property, plant and equipment 9 181.1 182.4 171.5 Trade and other receivables 10 59.4 59.4 59.4 324.9 322.4 313.6 Current assets Trade and other receivables 10 20.2 18.7 23.0 Cash and cash equivalents 199.0 225.0 224.4 219.2 243.7 247.4 Total assets 544.1 566.1 561.0 Liabilities Non-current liabilities Trade and other payables (1.1) (1.6) (1.3) Provisions (27.2) (25.7) (26.3) Interest bearing loans 11 (90.9) (90.6) (90.7) (119.2) (117.9) (118.3) Current liabilities Trade and other payables (89.8) (87.3) (91.7) (89.8) (87.3) (91.7) Total liabilities (209.0) (205.2) (210.0) Net assets 335.1 360.9 351.0 Owners of the parent Share capital 43.8 43.8 43.8 Share premium account 3,863.9 3,863.9 3,863.9 Accumulated losses (3,572.6) (3,546.8) (3,556.7) Total equity 335.1 360.9 351.0
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Condensed consolidated statement of changes in equity For the period ended 30 June 2026 Share capital $m Share premium $m Accumulated losses $m Total equity $m At 1 January 2025 43.8 3,863.9 (3,550.4) 357.3 Profit and total comprehensive income - - 0.6 0.6 Contributions by and distributions to owners Share-based payments - - 3.0 3.0 At 30 June 2025 (Unaudited) 43.8 3,863.9 (3,546.8) 360.9 At 1 January 2025 43.8 3,863.9 (3,550.4) 357.3 Loss and total comprehensive expense - - (8.9) (8.9) Contributions by and distributions to owners Share-based payments - - 2.6 2.6 At 31 December 2025 (Audited) and 1 January 2026 43.8 3,863.9 (3,556.7) 351.0 Loss and total comprehensive expense - - (17.4) (17.4) Contributions by and distributions to owners Share-based payments - - 1.5 1.5 At 30 June 2026 (Unaudited) 43.8 3,863.9 (3,572.6) 335.1 Condensed consolidated cash flow statement For the period ended 30 June 2026 Note Unaudited 30 June 2026 Unaudited 30 June 2025 Audited31 Dec 2025 $m $m $m Cash flows from operating activities (Loss) /Profit for the period (17.4) 0.6 (8.9) Adjustments for: Net finance expense 5 2.1 1.1 2.4 Taxation 6 - - 0.1 Depreciation and amortisation 4 10.1 25.8 50.1 Exploration expense 4 - 0.7 0.3 Net impairments, write-off/(write-back) 4 - (3.3) (3.5) Other non-cash items (share-based payment cost) 1.0 2.1 1.9 Changes in working capital: Decrease / (Increase) in trade and other receivables 3.7 0.8 (3.8) Decrease in trade and other payables (2.8) (12.9) (11.0) Cash (used in) / generated from operations (3.3) 14.9 27.6 Interest received 5 3.7 4.4 8.9 Taxation paid (0.1) (0.1) (0.2) Net cash generated from operating activities 0.3 19.2 36.3 Cash flows from investing activities Additions of intangible assets (4.2) (1.4) (4.5)
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Additions of property, plant and equipment (16.0) (9.7) (18.9) Net cash used in investing activities (20.2) (11.1) (23.4) Cash flows from financing activities Bond repayment 11 - (65.8) (65.8) Issuance of new bond 11 - 90.5 90.5 Lease payments (0.4) (0.4) (0.7) Interest paid (5.1) (3.0) (8.1) Net cash (used in) / generated from financing activities (5.5) 21.3 15.9 Net (decrease) / increase in cash and cash equivalents (25.4) 29.4 28.8 Cash and cash equivalents at the beginning of the period 224.4 195.6 195.6 Cash and cash equivalents at the end of the period 199.0 225.0 224.4 Notes to the consolidated financial statements 1. Basis of preparation Genel Energy Plc – registration number: 107897 (the Company), is a public limited company incorporated and domiciled in Jersey with a listing on the London Stock Exchange. The address of its registered office is 26 New Street, St Helier, Jersey, JE2 3RA. The half-year condensed consolidated financial statements for the six months ended 30 June 2026 are unaudited and have been prepared in accordance with the Disclosure Guidance and Transparency Rules of the Financial Conduct Authority, with Article of 106 of the Companies (Jersey) Law 1991 and with IAS 34 ‘Interim Financial Reporting’ as adopted by the European Union and were approved for issue on 3 August 2026. They do not comprise statutory accounts within the meaning of Article 105 of the Companies (Jersey) Law 1991. The half-year condensed consolidated financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2025, which have been prepared in accordance with IFRS as adopted by the European Union. The same accounting policies and methods of computation are followed in the interim financial report as compared with the 31 December 2025 annual financial statements. The annual financial statements for the year ended 31 December 2025 were approved by the board of directors on 17 March 2026. The report of the auditors was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under the Article 113A of Companies (Jersey) Law 1991. The financial information for the year to 31 December 2025 has been extracted from the audited accounts. Items included in the financial information of each of the Company's entities are measured using the currency of the primary economic environment in which the entity operates (the functional currency). The consolidated financial statements are presented in US dollars to the nearest million ($ million) rounded to one decimal place, except where otherwise indicated. Going concern The Company regularly evaluates its financial position, cash flow forecasts and its compliance with financial covenants by considering multiple combinations of oil price, discount rates, production volumes, payments, capital and operational spend scenarios. The Company has reported cash of $199 million, with debt of $92 million maturing in April 2030 and significant headroom on both the equity ratio and minimum liquidity financial covenants. Although agreements have been reached between the Federal Government of Iraq, the Kurdistan Regional Government and a group of international oil companies to resume exports of crude oil produced in Kurdistan through the Iraq-Türkiye Pipeline, the Company has elected not to participate for now. As a result, the Company is currently selling in the domestic market at lower prices and lower volumes than are available from exports, with significantly reduced cash generation. On 2 July 2026, the boards of directors of Capricorn Energy plc (‘Capricorn Energy’), Genel Energy No.9 Limited and the Company announced that they had reached agreement regarding the terms and conditions of a recommended cash offer for the entire issued and to be issued ordinary share capital of Capricorn Energy. The acquisition value implies a value for the entire issued and to be issued ordinary share capital of Capricorn Energy of approximately $360 million on a fully diluted basis. The consideration will be funded by a combination of a dividend paid by Capricorn Energy to its shareholders, new debt of $125 million, with the remainder of $160 million funded from the Company’s cash. On 3 July 2026, the Company raised $35 million of new debt through a tap issue under the outstanding senior unsecured bonds. Total bond debt owed by the Company at the time of reporting is therefore increased from $92 million to $127 million. The Directors have assessed that there are no material uncertainties that lead to significant doubt that the Company can continue as a going concern in the foreseeable future, a period not less than 12 months from the date of this report. The Directors have made this assessment after consideration of the Company’s forecast cash flows and related assumptions, including appropriate stress testing of the identified uncertainties, noting that even with continued domestic sales and completion of the acquisition, the Company’s forecast liquidity provides
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adequate headroom over its forecast expenditure for the 12 months following the signing of the half-year condensed consolidated financial statements for the period ended 30 June 2026 and consequently that the Company is considered a going concern. 2. Summary of material accounting policies The accounting policies adopted in preparation of these half-year condensed consolidated financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December 2025. The preparation of these half-year condensed consolidated financial statements in accordance with IFRS requires the Company to make judgements and assumptions that affect the reported results, assets and liabilities. Where judgements and estimates are made, there is a risk that the actual outcome could differ from the judgement or estimate made. The Company has assessed the following as being areas where changes in judgements or estimates could have a significant impact on the financial statements. Significant estimates The following are the critical estimates that the directors have made in the process of applying the Group accounting policies and that have the most significant effect on the amounts recognised in the financial statements. These are same with those disclosed in the annual financial statements for the year ended 31 December 2025. Estimation of hydrocarbon reserves and resources and associated production profiles and costs Estimates of hydrocarbon reserves and resources are inherently imprecise and are subject to future revision. The Company’s estimation of the quantum of oil and gas reserves and resources and the timing of its production, cost and monetisation impact the Company’s financial statements in a number of ways, including: testing recoverable values for impairment; the calculation of depreciation, amortisation and assessing the cost and likely timing of decommissioning activity and associated costs. This estimation also impacts the assessment of going concern. Proved and probable reserves are estimates of the amount of hydrocarbons that can be economically extracted from the Company’s assets.The Company estimates its reserves using standard recognised evaluation techniques which are based on Petroleum ResourcesManagement System 2018. Assets assessed as having proven and probable reserves are generally classified as property, plant andequipment as development or producing assets and depreciated using the units of production methodology. The Company considers itsbest estimate for future production and quantity of oil within an asset based on a combination of internal and external evaluations and usesthis as the basis of calculating depreciation and amortisation of oil and gas assets and testing for impairment under IAS 36. Hydrocarbons that are not assessed as reserves are considered to be resources and the related assets are classified as exploration and evaluation assets. These assets are expenditures incurred before technical feasibility and commercial viability is demonstrable. Estimates of resources for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and being depleted and are likely to contain estimates and judgements with a wide range of possibilities. These assets are considered for impairment under IFRS 6. Once a field commences production, the amount of proved reserves will be subject to future revision once additional information becomes available through, for example, the drilling of additional wells or the observation of long-term reservoir performance under producing conditions. As those fields are further developed, new information may lead to revisions. Assessment of reserves and resources are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves. Where the Company has updated its estimated reserves and resources any required disclosure of the impact on the financial statements is provided in the following sections. Estimation of oil and gas asset values (note 8 and 9) Estimation of the asset value of oil and gas assets is calculated from a number of inputs that require varying degrees of estimation. Principally oil and gas assets are valued by estimating the future cash flows based on a combination of reserves and resources, costs of appraisal, development and production, production profile, climate-related risks, exporting and future sales price and discounting those cash flows at an appropriate discount rate. Future costs of appraisal, development and production are estimated taking into account the level of development required to produce those reserves and are based on past costs, experience and data from similar assets in the region, future petroleum prices and the planned development of the asset. However, actual costs may be different from those estimated. Discount rate is assessed by the Company using various inputs from market data, external advisers and internal calculations. A post tax nominal discount rate of 14% (YE 2025: 14%) derived from the Company’s weighted average cost of capital (WACC) is used when assessing the impairment testing of the Company’s oil assets at year-end. Risking factors are also used alongside the discount rate when the Company is assessing exploration and appraisal assets. Estimation of future oil price and netback price The estimation of future oil price has a significant impact throughout the financial statements, primarily in relation to the estimation of the recoverable value of property, plant and equipment and intangible assets. It is also relevant to the assessment of ECL and going concern. The Company’s assumption of average Brent oil price for future years is based on a range of publicly available market estimates and is summarised in the table below. $/bbl 2026 2027 2028 2029 2030 HY2026 assumption 80 70 70 75 75
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YE2025 assumption 65 67 70 75 75 HY2025 assumption 65 70 75 75 75 The netback price is used to value the Company’s revenue, trade receivables and its forecast cash flows used for impairment testing and viability. It is the aggregation of reference oil price average less transportation costs, handling costs and quality adjustments. Effective for export sales from 1 September 2022 up to March 2023, sales were priced by the Ministry of Natural Resources (‘MNR’) under a new pricing formula based on the realised sales price for KRI blend crude (‘KBT’) during the delivery month, rather than dated Brent. The Company did not agree on this new pricing formula and continued to invoice based on the agreed formula using reference Brent price. The Company does not have direct visibility on the components of the netback price realised for its oil because sales are managed by the KRG, but the latest payments were based on the netback price provided by the KRG. Therefore, the export revenue from 1 September 2022 was recognised in accordance with IFRS15 using KBT pricing, resulting in the recognition of $10 million less of revenue in that period. Since the export pipeline closure in March 2023 the Company has sold its production domestically and at lower realised oil prices than previously achieved through export. Estimation of the recoverable value of deferred receivables and trade receivables (note 10) As of 30 June 2026, the Company is owed six months of payments for the sales from October 2022 to March 2023. Management has compared the carrying value of trade receivables with the present value of the estimated future cash flows based on a number of collection scenarios. The ECL provision relating to these receivables is based on the weighted average of these scenarios. The weighting is applied based on expected repayment timing. The result of this assessment is an ECL provision of $11.8 million (31 December 2025: $11.8 million). Sensitivities of the ECL has been provided in note 10. Decommissioning provision Decommissioning provisions are calculated from a number of inputs such as costs to be incurred in removing production facilities and site restoration at the end of the producing life of each field which is considered as the mid-point of a range of cost estimation. These inputs are based on the Company’s best estimate of the expenditure required to settle the present obligation at the end of the period inflated at 2% (2025: 2%) and discounted at 4% (2025: 4%). 10% increase in cost estimates would increase the existing provision by c.$3 million and 1% increase in discount rate would decrease the existing provision by c.$3 million, the combined impact would be c.$0.3m. The cash flows relating to the decommissioning and abandonment provision are expected to occur in 2036. Other estimates The following are the other estimates that the directors have made in the process of applying the Company’s accounting policies and that have effect on the amounts recognised in the financial statements. Taxation Under the terms of the KRI PSCs, corporate income tax due is paid on behalf of the Company by the KRG from the KRG's own share of revenues, resulting in no corporate income tax payment required or expected to be made by the Company. It is not known at what rate tax is paid, but it is estimated that the current tax rate would be between 15% and 40%. If this rate of tax on taxable profit was known it would result in a gross up of revenue with a corresponding debit entry to taxation expense with no net impact on the income statement or on cash. In addition, it would be necessary to assess whether any deferred tax asset or liability was required to be recognised. New standards The following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2026 and have been endorsed in 2025: Annual Improvements Volume 11 (issued on 18 July 2024) Contracts Referencing Nature-dependent Electricity – Amendments to IFRS 9 and IFRS 7 (issued on 18 December 2024) Amendments to the Classification and Measurement of Financial Instruments – Amendments to IFRS 9 and IFRS 7 (issued on 30 May 2024). These standards did not have a material impact on the Company’s results or financial statements disclosures in the current reporting period. The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective and/or have not yet been endorsed by the EU: IFRS 18 Presentation and Disclosure in Financial Statements (issued on 9 April 2024) IFRS 20 Regulatory Assets and Regulatory Liabilities (issued on 27 May 2026) IFRS 19 Subsidiaries without Public Accountability: Disclosures (issued on 9 May 2024) Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates: Translation to a Hyperinflationary Presentation Currency (issued on 13 November 2025) Amendments to IFRS 19 Subsidiaries without Public Accountability: Disclosures (issued on 21 August 2025).
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Nothing has been early adopted, and these standards are not expected to have a material impact on the Company’s results or financials statement disclosures in the periods they become effective except for IFRS 18 which will impact the presentation and disclosure in the financial statements. 3. Segmental information The Company has two reportable business segments: Production and Pre-production. Capital allocation decisions for the production segment are considered in the context of the cash flows expected from the production and sale of crude oil. The production segment is comprised of the producing fields on the Tawke PSC (Tawke and Peshkabir fields) which are located in the KRI and currently make sales only to the domestic buyers. The pre-production segment is comprised of exploration activity, principally located in Somaliland and Oman. ‘Other’ includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items. For the 6-month period ended 30 June 2026 Production Pre- production Other Total $m $m $m $m Revenue from contracts with customers (domestic) 13.4 - - 13.4 Other income 0.4 - - 0.4 Cost of sales (19.3) - - (19.3) Gross loss (5.5) - - (5.5) General and administrative costs - - (9.8) (9.8) Operating loss (5.5) - (9.8) (15.3) Operating loss is comprised of EBITDAX 4.4 - (8.6) (4.2) Depreciation and amortisation (9.9) - (0.2) (10.1) Other non-cash expenses - - (1.0) (1.0) Finance income - - 3.7 3.7 Bond interest expense - - (5.1) (5.1) Other finance expense (0.5) - (0.2) (0.7) Loss before income tax (6.0) - (11.4) (17.4) Capital expenditure 18.3 2.5 - 20.8 Total assets 308.7 39.5 195.9 544.1 Total liabilities (82.9) (26.3) (99.8) (209.0) Total assets and liabilities in the other segment are predominantly cash and debt balances. For the 6-month period ended 30 June 2025
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Production Pre- production Other Total $m $m $m $m Revenue from contracts with customers (domestic) 35.8 - - 35.8 Cost of sales (35.1) - - (35.1) Gross profit 0.7 - - 0.7 Exploration expense - (0.7) - (0.7) ECL of trade receivables (1.3) - - (1.3) Arbitration cost accrual - - 9.1 9.1 General and administrative costs - - (10.3) (10.3) Operating loss (0.6) (0.7) (1.2) (2.5) Operating loss is comprised of EBITDAX 26.4 - (1.1) 25.3 Depreciation and amortisation (25.7) - (0.1) (25.8) Exploration expense - (0.7) - (0.7) ECL of trade receivables (1.3) - - (1.3) Finance income - - 4.4 4.4 Bond interest expense - - (4.0) (4.0) Other finance expense (0.4) - (1.0) (1.4) Loss before income tax from continuing operations (1.0) (0.7) (1.8) (3.5) Profit from discontinued operations 4.1 - - 4.1 Profit / (Loss) before income tax 3.1 (0.7) (1.8) 0.6 Capital expenditure 12.5 0.7 - 13.2 Total assets 313.9 27.0 225.2 566.1 Total liabilities (75.8) (0.2) (129.2) (205.2) Sarta and Taq Taq PSC figures have been disclosed as discontinued operation. Total assets and liabilities in the other segment are predominantly cash and debt balances. For the 12-month period ended 31 December 2025 Production Pre- production Other Total $m $m $m $m Revenue from contracts with customers (domestic) 68.7 - - 68.7 Other income 3.4 - - 3.4 Cost of sales (71.0) - - (71.0) Gross profit 1.1 - - 1.1 Exploration expense - (0.3) - (0.3) ECL of trade receivables (1.3) - - (1.3) Arbitration cost reversal - - 9.1 9.1 General and administrative costs - - (18.9) (18.9) Operating loss (0.2) (0.3) (9.8) (10.3) Operating loss is comprised of EBITDAX 51.1 - (7.8) 43.3 Depreciation and amortisation (50.0) - (0.1) (50.1) Exploration expense - (0.3) - (0.3) Other non-cash expenses (1.3) - (1.9) (3.2) Finance income - - 8.9 8.9 Bond interest expense - - (9.1) (9.1) Other finance expense (1.1) - (1.1) (2.2) Loss before income tax from continuing operations (1.3) (0.3) (11.1) (12.7) Profit from discontinued operations 3.9 - - 3.9 Profit / (Loss) before income tax 2.6 (0.3) (11.1) (8.8)
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Capital expenditure 24.2 5.0 - 29.2 Total assets 301.8 37.4 221.8 561.0 Total liabilities (79.5) (27.8) (102.7) (210.0) Sarta and Taq Taq PSC figures have been disclosed as discontinued operation. Total assets and liabilities in the other segment are predominantly cash and debt balances. 4. Operating loss 6 months to 30 June 2026 6 months to 30 June 2025 Year to 31 December 2025 $m $m $m Production costs (9.4) (9.4) (21.0) Depreciation of oil and gas property, plant and equipment (8.9) (23.0) (45.0) Amortisation of oil and gas intangible assets (1.0) (2.7) (5.0) Cost of sales (19.3) (35.1) (71.0) Exploration expense - (0.7) (0.3) Movement in ECL of trade receivables (note 2,10) - (1.3) (1.3) Arbitration cost reversal - 9.1 9.1 Corporate cash costs (3.6) (3.5) (9.1) Other operating costs (5.0) (4.6) (7.8) Corporate share-based payment expense (1.0) (2.1) (1.9) Depreciation and amortisation of corporate assets (0.2) (0.1) (0.1) General and administrative expenses (9.8) (10.3) (18.9) 5. Finance expense and income 6 months to 30 June 2026 6 months to 30 June 2025 Year to 31 December 2025 $m $m $m Bond interest (5.1) (4.0) (9.1) Other finance expense (non-cash) (0.7) (1.4) (2.2) Finance expense (5.8) (5.4) (11.3) Bank interest income 3.7 4.4 8.9 Finance income 3.7 4.4 8.9 Net finance expense (2.1) (1.0) (2.4) Bond interest payable is the cash interest cost of the Company’s bond debt. Other finance expense (non-cash) primarily relates to the discount unwind on the bond and the asset retirement obligation provision. 6. Income tax expense Current tax expense is incurred on profits of service companies. Under the terms of the KRI PSCs, the Company is not required to pay any cash corporate income taxes as explained in note 2.
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7. Earnings / (Loss) per share Basic Basic earnings / (loss) per share is calculated by dividing the profit / (loss) attributable to owners of the parent by the weighted average number of shares in issue during the period. 6 months to 30 June 2026 6 months to 30 June 2025 Year to 31 December 2025 Loss from continuing operations ($m) (17.4) (3.5) (12.8) Profit from discontinued operations ($m) - 4.1 3.9 (Loss) / Profit attributable to owners of the parent ($m) (17.4) 0.6 (8.9) Weighted average number of ordinary shares – number 1 275,641,436 275,382,490 275,454,531 Basic LPS – cents (from continuing operations) (6.3) (1.3) (4.6) Basic EPS – cents (from discontinuing operations) - 1.5 1.4 Basic (LPS) / EPS – cents (6.3) 0.2 (3.2) 1 Excluding shares held as treasury shares and by the Employee Benefit Trust Diluted The Company purchases shares in the market to satisfy share plan requirements so diluted earnings per share is adjusted for performance shares, restricted shares, share options and deferred bonus plans not included in the calculation of basic earnings per share. Because the Company reported a loss from continuing operations for the period ended 30 June 2026, the performance shares, restricted shares and share options are anti-dilutive and therefore diluted LPS is the same as basic LPS. 6 months to 30 June 2026 6 months to 30 June 2025 Year to 31 December 2025 Loss from continuing operations ($m) (17.4) (3.5) (12.8) Profit from discontinued operations ($m) - 4.1 3.9 (Loss) / Profit attributable to owners of the parent ($m) (17.4) 0.6 (8.9) Weighted average number of ordinary shares – number1 275,641,436 275,382,490 275,454,531 Adjustment for performance shares, restricted shares, share options and deferred bonus plans - - - Weighted average number of ordinary shares and potential ordinary shares 275,641,436 275,382,490 275,454,531 Diluted LPS – cents (from continuing operations) (6.3) (1.3) (4.6) Diluted EPS – cents (from discontinuing operations) - 1.5 1.4 Diluted (LPS) / EPS – cents (6.3) 0.2 (3.2) 1 Excluding shares held as treasury shares and by the Employee Benefit Trust Adjusted Basic EPS / (LPS) Adjusted basic LPS is loss and total comprehensive expense adjusted for the add back of net impairment/write-off of oil and gas assets and net ECL/reversal of ECL of receivables divided by weighted average number of ordinary shares. 6 months to 30 June 2026 6 months to 30 June 2025 Year to 31 December 2025 (Loss) / Profit attributable to owners of the parent ($m) (17.4) 0.6 (8.9) Add back of ECL/reversal of ECL of receivables - 0.1 0.1 (Loss) / Profit attributable to owners of the parent ($m) – adjusted (17.4) 0.7 (8.8) Weighted average number of ordinary shares – number 1 275,641,436 275,382,490 275,454,531 Adjusted basic (LPS) / EPS – cents (6.3) 0.3 (3.2) 1 Excluding shares held as treasury shares and by the Employee Benefit Trust 8. Intangible assets Exploration and evaluation assets Tawke RSA Total $m $m $m Net book value at 01 January 2025 25.9 56.4 82.3
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Additions 0.7 - 0.7 Other1 0.3 - 0.3 Amortisation charge for the period - (2.7) (2.7) Net book value at 30 June 2025 26.9 53.7 80.6 Net book value at 01 January 2025 25.9 56.4 82.3 Additions 5.0 - 5.0 Other1 0.4 - 0.4 Amortisation charge for the period - (5.0) (5.0) Net book value at 31 December 2025 and 1 January 2026 31.3 51.4 82.7 Additions 2.5 - 2.5 Other1 0.2 - 0.2 Amortisation charge for the period - (1.0) (1.0) Net book value at 30 June 2026 34.0 50.4 84.4 1 Other line includes non-cash share-based payment costs. 30 June 2026 30 June 2025 31 Dec 2025 Book value $m $m $m Somaliland PSC Exploration 29.0 26.4 27.6 Oman PSC Exploration 5.0 0.5 3.7 Exploration and evaluation assets 34.0 26.9 31.3 Tawke capacity building payment waiver 50.4 53.7 51.4 Tawke RSA assets 50.4 53.7 51.4 Intangible assets include the Receivable Settlement Agreement (‘RSA’) effective from 1 August 2017, which was entered into in exchange for trade receivables due from KRG for Taq Taq and Tawke past sales. The RSA was recognised at cost and is amortised on a units of production basis in line with the economic lives of the rights acquired. 9. Property, plant and equipment Producing assets Other assets Total $m $m $m Net book value at 01 January 2025 189.6 1.5 191.1 Additions 12.5 0.1 12.6 Right-of-use assets - 1.8 1.8 Other1 0.6 - 0.6 Depreciation charge for the period (23.0) (0.7) (23.7) Net book value at 30 June 2025 179.7 2.7 182.4 Net book value at 01 January 2025 189.6 1.5 191.1
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Additions 24.2 0.2 24.4 Right-of-use assets - 1.8 1.8 Other1 0.6 - 0.6 Depreciation charge for the year (45.0) (1.4) (46.4) Net book value at 31 December 2025 and 1 January 2026 169.4 2.1 171.5 Additions 18.3 - 18.3 Other1 0.6 - 0.6 Depreciation charge for the period (8.9) (0.4) (9.3) Net book value at 30 June 2026 179.4 1.7 181.1 1 Other line includes non-cash asset retirement obligation provision and share-based payment costs. 30 June 2026 30 June 2025 31 Dec 2025 Book value $m $m $m Tawke PSC Oil production 179.4 179.7 169.4 The sensitivities below provide an indicative impact on net recoverable value of a change in netback price, discount rate, production or pipeline reopening, assuming no change to any other inputs. Sensitivities Tawke CGU $m Long term netback price +/- $5/bbl +/- 17 Discount rate +/- 1% +/- 11 Production +/- 10% +/- 28 Domestic sales for 1 more year - 17 10. Trade and other receivables 30 June 2026 30 June 2025 31 Dec 2025 $m $m $m Trade receivables – non-current 59.4 59.4 59.4 Trade receivables – current 16.6 16.6 16.6 Other receivables and prepayments 3.6 2.1 6.4 79.6 78.1 82.4 As of 30 June 2026, the Company is owed six months of payments (31 December 2025: six months). Period when sale made Overdue 2023 Overdue 2022 Total nominal ECL provision Trade receivables $m $m $m $m $m 30 June 2026 40.2 47.6 87.8 (11.8) 76.0 31 December 2025 40.2 47.6 87.8 (11.8) 76.0 30 June 2025 40.2 47.6 87.8 (11.8) 76.0
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Movement on trade receivables in the period 30 June 2026 $m 30 June 2025 $m 31 Dec 2025 $m Carrying value at the beginning of the period 76.0 85.0 85.0 Revenue from contracts with customers 13.4 35.8 68.7 Cash for domestic sales (13.4) (35.8) (68.7) Write-off of Sarta receivables - (8.9) (8.9) Reversal of previous year’s expected credit loss (note 2) - 1.2 1.2 Expected credit loss for current period (note 2) - (1.3) (1.3) Carrying value at the end of the period 76.0 76.0 76.0 Recovery of the carrying value of the receivable All trade receivables relate to export sales from Tawke PSC as the domestic sales are on a cash and carry basis. As explained in note 1, the booked nominal receivable value of $87.8 million has been recognised based on KBT due to IFRS 15 requirements and it would be $10 million higher under Brent pricing mechanism. The Company expects to recover the full value of receivables owed from the KRG under Brent pricing mechanism, but the terms of recovery are not determined yet. An explanation of the assumptions and estimates in assessing the net present value of the deferred receivables are provided in note 2. Total $m Booked nominal balance to be recovered 87.8 Estimated net present value of total cash flows 76.0 Sensitivities/Scenarios As set out in note 2, the recoverability of the overdue trade receivables is based on a number of different collection scenarios. We consider that the ultimate resolution will include full consideration of all balances between the two counterparties. A 1% increase / decrease in the discount rate would result in a c.$0.7 million change in the ECL provision. Each three-month delay in settlement would result in a c.$0.9 million increase in the ECL provision. A combined three-month delay and a 1% increase in the discount rate would result in a c.$1.6 million change in the ECL provision. The discount rate applied is the discount rate considered to represent the effective interest rate on this instrument. 11. Interest bearing loans and net cash 1 Jan 2026 Discount unwind Free cash flow 30 June 2026 $m $m $m $m 2030 Bond 11% coupon (non-current) (90.7) (0.2) - (90.9) Cash 224.4 - (25.4) 199.0 Net cash 133.7 (0.2) (25.4) 108.1 As of 30 June 2026, the fair value of the $92 million of bonds held by third parties is $97 million (31 December 2025: $96 million). The bonds maturing in 2030 have two financial covenants: Financial covenant Test H1 2026 H1 2025 YE 2025 Equity ratio > 30% 62% 64% 60% Minimum liquidity > $20m $199.0m $225.0m $195.6m 1 Jan 2025 Discount unwind Purchase/ issuance of bond Free cash flow 30 June 2025 $m $m $m $m $m 2025 Bond 9.25% coupon (current) (64.9) (0.9) 65.8 - - 2030 Bond 11% coupon (non-current) - (0.1) (90.5) - (90.6) Cash 195.6 - 24.7 4.7 225.0 Net cash 130.7 (1.0) - 4.7 134.4
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1 Jan 2025 Discount unwind Purchase/ issuance of bond Free cash flow 31 Dec 2025 $m $m $m $m $m 2025 Bond 9.25% coupon (current) (64.9) (0.9) 65.8 - - 2030 Bond 11% coupon (non-current) - (0.2) (90.5) - (90.7) Cash 195.6 - 24.7 4.1 224.4 Net cash 130.7 (1.1) - 4.1 133.7 12. Capital commitments Under the terms of its production sharing contracts (‘PSC’s) and joint operating agreements (‘JOA’s), the Company has certain commitments that are generally defined by activity rather than spend. The Company’s capital programme for the next few years is explained in the operating review and is in excess of the activity required by its PSCs and JOAs. 13. Events occurring after the reporting period On 2 July 2026, the boards of directors of Capricorn Energy plc (‘Capricorn Energy’), Genel Energy No.9 Limited and the Company announced that they had reached agreement regarding the terms and conditions of a recommended cash offer for the entire issued and to be issued ordinary share capital of Capricorn Energy. The acquisition value implies a value for the entire issued and to be issued ordinary share capital of Capricorn Energy of approximately $360 million on a fully diluted basis. The consideration will be funded by a combination of a dividend paid by Capricorn Energy to its shareholders, new debt of $125 million, with the remainder of $160 million funded from the Company’s cash which has been set aside and committed to the transaction. On 3 July 2026, the Company raised $35 million of new debt through a tap issue under the outstanding senior unsecured bonds. Total bond debt owed by the Company at the time of reporting is therefore increased from $92 million to $127 million. INDEPENDENT REVIEW REPORT TO GENEL ENERGY PLC Conclusion Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half- yearly financial report for the six months ended 30 June 2026 is not prepared, in all material respects, in accordance with International Accounting Standard 34 “Interim Financial Reporting” as adopted by the European Union, Article 106 of the Companies (Jersey) Law 1991 and the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority. We have been engaged by Genel Energy Plc (“the company”) to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2026 which comprise of the following: Condensed consolidated statement of comprehensive income, Condensed consolidated balance sheet, Condensed consolidated statement of changes in equity, Condensed consolidated cash flow statement and the related explanatory notes that have been reviewed. Basis for conclusion We conducted our review in accordance with the International Standard on Review Engagements (UK) 2410, “Review of Interim Financial Information Performed by the Independent Auditor of the Entity” (“ISRE (UK) 2410”). A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion. As disclosed in note 1, the annual financial statements of the Group are prepared in accordance with International Financial Reporting Standards as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, “Interim Financial Reporting” as adopted by the European Union, Article 106 of the Companies (Jersey) Law 1991 and the Disclosure, Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority. Conclusions relating to going concern Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for conclusion section of this report, nothing has come to our attention to suggest that the directors have inappropriately adopted the going concern basis of
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accounting or that the directors have identified material uncertainties relating to going concern that are not appropriately disclosed. This conclusion is based on the review procedures performed in accordance with ISRE (UK) 2410, however future events or conditions may cause the Group to cease to continue as a going concern. Responsibilities of directors The directors are responsible for preparing the half-yearly financial report in accordance with the the International Accounting Standard 34 “Interim Financial Reporting” as adopted by the European Union, Article 106 of the Companies (Jersey) Law 1991 and the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority. In preparing the half-yearly financial report, the directors are responsible for assessing the Group’s ability to continue as a going concern,disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors eitherintend to liquidate the Group or to cease operations, or have no realistic alternative but to do so. Auditor’s responsibilities for the review of the financial information In reviewing the half-yearly report, we are responsible for expressing to the Company a conclusion on the condensed set of financial statement in the half-yearly financial report. Our conclusion, including our Conclusions Relating to Going Concern, are based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report. Use of our report Our report has been prepared in accordance with the terms of our engagement to assist the Company in meeting the requirements of the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority and for no other purpose. No person is entitled to rely on this report unless such a person is a person entitled to rely upon this report by virtue of and for the purpose of our terms of engagement or has been expressly authorised to do so by our prior written consent. Save as above, we do not accept responsibility for this report to any other person or for any other purpose and we hereby expressly disclaim any and all such liability. BDO LLP Chartered Accountants London, UK 3 August 2026 BDO LLP is a limited liability partnership registered in England and Wales (with registered number OC305127). Dissemination of a Regulatory Announcement that contains inside information in accordance with the Market Abuse Regulation (MAR), transmitted by EQS Group. The issuer is solely responsible for the content of this announcement. View original content: EQS News ISIN: JE00B55Q3P39, NO0010894330 Category Code:IR TIDM: GENL LEI Code: 549300IVCJDWC3LR8F94 Sequence No.:438429 EQS News ID:2376572 End of AnnouncementEQS News Service