Earnings release
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Q3 Report 2025 ITHACA ENERGY PLC RESULTS & TRADING UPDATE
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ITHACA ENERGY PLC 1Q3 REPORT 2025 Introduction 1 Q3 2025 at a glance 2 Operational and financial review 3 Statement of Directors’ responsibilities 12 Independent review report to Ithaca Energy plc 13 Financial statements 14 to 42 Unaudited condensed consolidated statement of profit or loss 14 Unaudited condensed consolidated statement of comprehensive income 15 Unaudited condensed consolidated statement of financial position 16 Unaudited condensed consolidated statement of changes in equity 18 Unaudited condensed consolidated statement of cash flows 19 Notes to the condensed consolidated financial statements 21 Non-GAAP measures 43 One year after. Celebrating a year of successful operations following the Eni UK Business Combination. Introduction You can also read our Annual Report online: investors.ithacaenergy.com Our Q3 YTD results for 2025 show what a pivotal period it has been for Ithaca Energy. The successful integration of Eni’s UK assets and our additional M&A success is reflected in our strong operational and financial performance.”
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2ITHACA ENERGY PLC Q3 REPORT 2025 Financial highlights YTD ADJUSTED EBITDAX 1 $1,501.2m (YTD 2024: $758.5m) YTD PRODUCTION 114.9 kboe/d (YTD 2024: 52.5 kboe/d) ADJUSTED NET DEBT 1 $1,063.8m at 30 Sept 25 (31 December 2024: $884.9m) YTD TIER 1 OR 2 PROCESS SAFETY EVENTS 0 (YTD 2024: 0) YTD SERIOUS INJURY AND FATALITY FREQUENCY 0 (YTD 2024: 0) AVAILABLE LIQUIDITY 1 $1,664.3m at 30 Sept 25 (31 December 2024: $1,015.1m) PRO FORMA LEVERAGE POSITION 1 – ADJUSTED NET DEBT TO PRO FORMA ADJUSTED EBITDAX 0.50x at 30 Sept 25 (31 December 2024: 0.45x) YTD (LOSS)/PROFIT FOR THE PERIOD 2 $(119.1)m (YTD 2024: profit of $134.7m) YTD NET CASH FLOW FROM OPERATING ACTIVITIES $1,279.6m (YTD 2024: $792.5m) YTD PRODUCTION SPLIT 58% liquids 38% operated (YTD 2024: 70% liquids; 49% operated) Q3 2025 at a glance Delivering reliable performance Operational highlights 1 Non-GAAP measure as set out on pages 43 to 46. 2 The loss for the period was principally due to a one-off, non-cash deferred tax charge of $327.6 million for the two-year extension of the Energy Profits Levy (EPL) to 31 March 2030.
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3ITHACA ENERGY PLC Q3 REPORT 2025 Inorganic E xpansion O rganic E xpansion 4. Focused International Expansion 1. Sustain and Optimise Production 3. Consolidation in Core UKCS Market 2. Unlock Material Organic Growth OpportunitiesValue creation and stakeholder returns Operational and financial review Q3 2025 strategic highlights Organic growth: Investing across our portfolio • Successful progression of Captain 13th well campaign and expected sanctioning of the 14th drilling campaign in Q4 2025, that will support further drilling activity at the end of 2026, reflecting the Group’s significant ongoing investment in the field • Captain flotel campaign ongoing with decision to extend the duration beyond the initial term. The material scopes of work being executed support the asset life extension programme including backlog reduction and optimisation activities • Cygnus infill well campaign continues with the first of the four firm wells (C12) expected to achieve first production in early December, and the second well spudding immediately thereafter. The Group has sanctioned further investment in the area for 2026, following our acquisition of an additional 46.25% from Spirit Energy, with the fourth well added to the ongoing campaign and further development wells being considered • First production from the fourth and final Seagull well (J4) was achieved in Q4, following a technical issue experienced in H1. The well is performing in line with expectations, however the delay to first production reduces the assets expected production contribution in FY 2025 • Material activity in the J Area following the decision to proceed with further value-led investment, with additional well activity sanctioned at Judy East Flank (JEF) and investment in Joanne well stimulation activity, based on continued strong J Area performance. Production start-up of the JEF well expected mid-December Organic growth: West of Shetland Area strategy momentum building • Rosebank development project progressing towards key milestones that are critical to achieving first production timeline of 2026/27: • Material progress toward achieving refreshed consents with the submission of an updated Environmental Statement in Q3, including the assessment of ‘Scope 3’ emissions associated with the project • 2025 offshore subsea installation scopes delivered on time and budget with excellent HSE statistics • Drilling activities scheduled to commence Q1 2026, as planned Continued strong execution across the Group’s strategic pillars, maximising value and returns for shareholders.
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4ITHACA ENERGY PLC Q3 REPORT 2025 Operational and financial review continued Q3 2025 strategic highlights continued • Floating Production Storage and Offloading (FPSO) refurbishment activity progressing at pace, with a target to sail away early 2026 in order to enable mooring in field during 2026 • Maintaining FPSO sail away date in Q1 2026, together with drilling and hook up and commissioning works, remains critical to achieving first production target of 2026/27. Cost updates from the Operator indicate that assuming key milestones are achieved, including limited carry over activities post FPSO sail away, the total project cost outturn forecasts do not need to be materially updated at this time and will be revisited post FPSO sail away • Continued Cambo project maturation towards final investment decision (FID) and potential farm-down, subject to fiscal and regulatory clarity: • Tenders for main project packages including FPSO Engineering, Procurement, Construction and Commissioning (EPCC) and Subsea, Umbilicals, Risers and Flowlines (SURF) activities have commenced, following the successful technical refresh of the project • Working towards submission of an updated Field Development Plan and Environmental Statement in Q4 2025, reflecting project optimisations • The Tornado project is progressing towards FID with tendering and advancement of the Environmental Statement, forming part of the Group’s wider West of Shetland gas strategy that has the potential to enable further exploration and appraisal in the area, subject to fiscal and regulatory clarity • 50% Farm-in to Shell’s Tobermory gas field announced today (19 Nov), forming part of the Group’s West of Shetland gas development strategy with the potential for significant synergies between the Tornado and Tobermory gas fields Inorganic growth: Pursuing consolidation strategy in UKCS, increasing stakes in key assets • Successful delivery of inorganic growth strategy with low-risk consolidation in core UKCS basin demonstrating the Group’s execution capabilities. • Acquisition of JAPEX UK completed 7 July 2025, increasing stake in well-understood, high-quality, long-life Seagull field from 35% to 50% and adding pro forma 2025 production of approximately 4 - 4.5 kboe/d. Completion payment in Q3 of $136 million (based on an effective date for the transaction of 1 January 2024 and after customary purchase price adjustments) • Acquisition of 46.25% stake in the Group’s operated Cygnus field from Spirit Energy completed 1 October 2025 in line with targeted completion date. The acquisition increased the Group’s stake in the high- margin, low-emission operated Cygnus gas field to 85%, adding circa 12.5 – 13.5 kboe/d net production on a pro forma basis, enhancing the gas weighting of the Group’s portfolio. Completion payment in Q4 of £115 million (based on an effective date for the transaction of 1 January 2025 and after customary purchase price adjustments) • Bolt-on acquisitions have been completed at attractive investment metrics, increasing the Group’s ownership stakes in key assets across its portfolio, where the Group believes additional upside potential exists Value creation and shareholder returns • First interim 2025 dividend of $167 million declared and paid in September 2025, representing a dividend per share of $0.101 • Acceleration of second interim dividend of $133 million, representing a dividend per share of $0.0804, announced today (19 November) and payable 18 December 2025, demonstrating the Group’s strong year-to-date performance and cash generation and taking the Group’s total 2025 cash distributions to $500 million • Reaffirming dividend for 2025, targeting $500 million for FY 2025 with the remaining tranche payable following the Group’s full year results announcement in March 2026 • Expansion of the Group’s free float to 13.6% from 10.6% following majority shareholder sell-down on a pro forma basis
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5ITHACA ENERGY PLC Q3 REPORT 2025 Operational and financial review continued Q3 2025 Operational highlights • Strong process safety performance with zero Tier 1 or Tier 2 events recorded in the first nine months of the year and a material reduction in Total Recordable Injury Rate (TRIR) from 2024, with 1.62 cases per million hours year to date from 2.89 YTD 2024 • Significant reduction in Greenhouse Gas (GHG) emission intensity of the Group’s portfolio, bringing our gross operated emissions intensity to 17.34 kgCO2e/boe from 20.14 kgCO2e/boe YTD 2024 • Unprecedented levels of turnaround activity (TAR) executed during Q3 across the Group’s operated and non-operated portfolio with material activity scopes concluded successfully during October • 12 out of 15 TARs were delivered on plan or better. Captain turnaround execution extended due to increased scope, with further investments made safeguarding longer-term environmental and operational performance. Return to full production achieved in the first week of November • Average YTD production of 114.9 kboe/d (YTD 2024: 52.5 kboe/d), reflecting heavy turnaround activity in Q3 in line with the Group’s expectations and as incorporated into full year production guidance • YTD 2025 production split 58% liquids, 42% gas and 38% operated, 62% non-operated reflecting the impact of the Eni UK Business Combination • Material improvement in production efficiency YTD across the Group’s operated and non- operated asset base, consistently achieving higher than 2024 average of 80% and 2024 industry average of 75%, and reflected in strong operational performance • New wells, including Jocelyn South and Talbot, continue to perform ahead of expectations
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6Q3 REPORT 2025ITHACA ENERGY PLC Q3 2025 Financial highlights Enhanced balance sheet with financial strength and flexibility to support future growth • Strong credit credentials highlighted by successful €450 million issuance of 5.5% senior notes, due 2031, with significant investor demand providing further financial firepower, optimising the Group’s financial structure and extending its debt maturity profile. Effective all-in USD interest rate of 6.7% • Liquidity position further supported by $300 million upsizing of the Group’s Reserves Based Lending (RBL) facility via accordion, with the addition of all new lending institutions • Low leverage position of 0.50x with significant available liquidity of $1.7 billion (31 December 2024: $1.0 billion), providing material financial firepower for growth • Adjusted net debt at end of the quarter of $1,063.8 million (31 December 2024: $884.9 million) • Rating agencies retained previous rating upgrades in October 2024 following the completion of the Business Combination with Eni UK, reflecting the enhanced strength of the enlarged Group Strong financial performance and cash generation • YTD adjusted EBITDAX of $1,501.2 million (YTD 2024: $758.5 million) • YTD profit before tax of $668.1 million (YTD 2024: $183.7 million). Q3 2025 profit before taxation of $154.6 million (Q3 2024: loss before taxation of $5.7 million) reflecting a full quarters contribution from the Eni UK Business Combination and a lower level of impairment charges partly offset by higher finance costs • YTD loss for the period of $119.1 million (YTD 2024: net profit of $134.7 million), reflecting primarily a one-off, non-cash deferred tax charge of $327.6 million due to the two-year extension of EPL to 31 March 2030. Q3 2025 profit for the period of $98.3 million (Q3 2024: $29.0 million) • YTD adjusted net income of $226.9 million (YTD 2024: $181.9 million) • YTD realised oil prices of $71/bbl before hedging and $73/bbl after hedging (YTD 2024: $84/bbl before hedging and $83/bbl after hedging) and gas prices of 88p/therm before hedging and 90p/therm after hedging (YTD 2024: 73p/therm before hedging and 110p/therm after hedging) • YTD operating costs of $600.1 million (YTD 2024: $415.6 million) reflecting a YTD opex per barrel of $19.1/boe (YTD 2024: $28.9/boe) demonstrates the Group’s focus on cost control and the high netback capability of the enlarged portfolio • YTD producing assets capex of $468 million (YTD 2024: $272 million) and Rosebank capex of $183 million (YTD 2024: $141 million) • YTD net cash flow from operating activities of $1,279.6 million (YTD 2024: $792.5 million) • As at 18 November 2025, the Group had 39.5 million barrels of oil equivalent (54% oil) hedged from Q4 2025 into 2027 at an average floor price of $68/bbl for oil swaps, $62/bbl for oil puts/collar floors, 98p/therm for gas swaps, and 81p/therm for gas puts/collar floors Operational and financial review continued
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7Q3 REPORT 2025ITHACA ENERGY PLC Operational and financial review continued Guidance and Outlook FY 2025 Management Guidance • Management reaffirms all previously provided guidance ranges for full year 2025, updated 19 August 2025 to reflect stronger 2025 outlook: • FY 2025 production in range of 119-125 kboe/d with production trending to the bottom end of the range, primarily due to the Group’s decision to extend the Captain shutdown to allow for increased scope and further investment into safeguarding longer-term environmental and operational performance, and the delayed start-up to three new high production wells to December 2025 • FY 2025 net operating cost guidance range of $790–840 million • FY 2025 net producing asset capital cost guidance range of $630-670 million (excluding pre-FID projects and Rosebank development) • FY 2025 net Rosebank development capex guidance range of $230-270 million • FY 2025 cash tax guidance range of $270-300 million, trending to the bottom end of the range • The Group uplifts its expected production exit rate in Q4 2025 from 140kboe/d to around 145kboe/d. Following the successful completion of the unprecedented TAR season and with three new high production wells expected on stream in December, the Group is entering 2026 with an increased installed total production system capacity
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8ITHACA ENERGY PLC Q3 REPORT 2025 Operational and financial review continued Summary of financial results Financial key performance indicators (KPIs) Q3 YTD 2025 Q3 YTD 2024 Adjusted EBITDAX1 ($m) 1,501.2 758.5 Profit before tax ($m) 668.1 183.7 Adjusted net income1 ($m) 226.9 181.9 (Loss)/profit for the period ($m) (119.1) 134.7 Net cash flow from operating activities ($m) 1,279.6 792.5 Unit operating expenditure1 ($/boe) 19.1 28.9 Q3 2025 Q4 2024 Available liquidity1 ($m) 1,664.3 1,015.1 Adjusted net debt1 ($m) 1,063.8 884.9 Adjusted net debt/pro forma adjusted EBITDAX1 0.50x 0.45x Other KPIs Q3 YTD 2025 Q3 YTD 2024 Total production (boe/d) 114,928 52,501 Tier 1 and 2 process safety events 0 0 Serious injury and fatality frequency 0 0 1. Non-GAAP measure – details of non-GAAP measures are set out on pages 43 to 46. Q3 YTD 2025 trading During YTD 2025, the Group has delivered average production of 114,928 boe/d (YTD 2024: 52,501 boe/d) which generated adjusted EBITDAX of $1,501.2 million (YTD 2024: $758.5 million). In addition, net cash flow from operating activities was $1,279.6 million (YTD 2024: $792.5 million) and profit before tax amounted to $668.1 million (YTD 2024: $183.7 million). The loss for the period of $119.1 million (YTD 2024: profit of $134.7 million) was primarily due to a one-off, non-cash deferred tax charge of $327.6 million arising on the substantive enactment during the period of the two-year extension of the 38% EPL rate to 31 March 2030. Financial performance: adjusted EBITDAX Adjusted EBITDAX is a key measure of operational performance delivery in the business and for YTD 2025 was $1,501.2 million (YTD 2024: $758.5 million). The improvement on YTD 2024 mainly reflects the higher production principally from the Eni UK Business Combination and improved operational performance, partly offset by lower overall realised commodity prices net of hedging. Scale. Stability. Strength.
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9ITHACA ENERGY PLC Q3 REPORT 2025 Operational and financial review continued Financial review continued Adjusted EBITDAX analysis Q3 YTD 2025 Q3 YTD 2024 FY 2024 Production kboe/d mmboe kboe/d mmboe kboe/d mmboe Oil 62 17 35 10 41 15 Gas 48 13 16 4 25 9 Condensate 5 1 2 1 3 1 Total production 115 31 53 15 69 25 Revenues1 $/boe $m $/boe $m $/boe $m Oil revenue 71 1,175 84 802 81 1,176 Gas revenue 67 812 61 261 64 599 Condensate revenue 46 64 42 27 48 47 Oil and gas hedging gains/other revenue 2 77 9 127 5 135 Total 68 2,128 85 1,217 77 1,957 Movement in oil and gas inventory 1 22 (1) (8) 3 84 Tanker costs (1) (15) (1) (14) (1) (18) Stella royalties – (1) – (1) – (2) Total value from production 68 2,134 83 1,194 79 2,021 Costs Operating costs excluding restructuring costs, tanker costs and net of tariff income (19) (600) (29) (415) (22) (570) Administrative expenses excluding restructuring costs (Q3 2025) and business combination costs (FY 2024) (1) (31) (2) (26) (2) (41) Foreign exchange (losses)/gains – (2) 1 6 – (5) Other operating costs in arriving at adjusted EBITDAX (20) (633) (30) (435) (24) (616) Adjusted EBITDAX2 48 1,501 53 759 55 1,405 1 Revenues in the above table exclude principally tariff income and premium payments on oil and gas derivative contracts. 2 Non-GAAP measure. Average realised oil prices for YTD 2025 were $71/boe before hedging and $73/boe after hedging (YTD 2024: $84/boe before hedging and $83/boe after hedging). Average realised gas prices for YTD 2025 were $67/boe both before and after hedging (YTD 2024: $61/boe before hedging and $92/boe after hedging). During YTD 2025, there was again a strong focus on operating costs which were $600.1 million (YTD 2024: $415.6 million). The reduction in unit operating expenditure per boe reflects improved operational performance as well as the acquired Eni UK and Seagull assets which have a significantly lower operating expenditure per boe than most legacy Ithaca assets.
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10ITHACA ENERGY PLC Q3 REPORT 2025 Financial performance: (loss)/profit for the period and adjusted net income Q3 YTD 2025 $m Q3 YTD 2024 $m Profit before taxation 668.1 183.7 Taxation (787.2) (49.0) (Loss)/profit for the period (119.1) 134.7 Impairment charges on development and production assets 29.4 104.0 Tax credit on impairment charges (12.8) (56.8) Restructuring costs 8.0 – Tax credit on restructuring costs (6.2) – EPL deferred tax impact of two-year extension of 38% rate to 31 March 2030 327.6 – Adjusted net income1 226.9 181.9 1 Non-GAAP measure. The increase in profit before taxation to $668.1 million reflects principally the impact of the Eni UK Business Combination and, in particular, the higher production in YTD 2025. As noted above, the loss for the period was primarily due to the one-off, non-cash deferred tax charge as a result of the substantive enactment during the period of the two-year extension of the 38% EPL tax rate to 31 March 2030. Subsequent events On 1 October 2025, the Group completed the acquisition of 46.25% of Spirit Energy’s interest in the Cygnus field for an initial consideration of £115 million thereby increasing the Group’s working interest in Cygnus from 38.75% to 85.0%. On 19 November 2025 the Group expects to announce the signing of a farm-in agreement with Shell UK for a 50% working interest in licences P2629 and P2630, located in the West of Shetland basin, containing the Tobermory discovery. Following the farm-in Shell UK will continue to hold a 50% stake in the Tobermory discovery and act as licence operator. Going concern Based on their assessment of the Group’s financial position over the period to 31 December 2026, the Directors believe that the Group will be able to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis of accounting in preparing the condensed consolidated financial statements. Further details are set out in note 3. Derivative financial instruments Derivative financial instruments are utilised to manage commodity price risk in a substantive financial hedging programme for future oil and gas production volumes. As at 30 September 2025, the following hedges were in place: Q4 2025 2026 2027 Oil Volume hedged (mmboe) 4.3 9.8 3.1 Weighted average floor hedged price ($/bbl) 71 66 66 Gas Volume hedged (mmboe) 4.0 11.8 1.4 Weighted average floor hedged price (p/therm) 89 86 85 Operational and financial review continued Financial review continued
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11ITHACA ENERGY PLC Q3 REPORT 2025 Principal risks and uncertainties The Group faces various risks that could result in events or circumstances that might threaten our business model, future performance, liquidity, solvency or reputation. Not all of these risks are completely within the control of the business and the Group may be affected by risks that have yet to manifest themselves or are not reasonably foreseeable at the present time. For those identified risks, the Group has mitigation strategies to minimise the likelihood of the risk and reduce the impact as far as is practicable. Depending on the nature of the risk, the Group may elect to take or tolerate risk, treat risk with mitigating actions, transfer risk to third parties, or eliminate risk by ceasing certain operations or activities. The Directors have reviewed the principal risks and uncertainties facing the Group and have concluded that those facing the Group for the remaining three months of the current financial year are unchanged from the risks set out in the 2024 Annual Report and Accounts, with the exception of the integration of the Eni UK upstream assets risk, which is no longer applicable, now that the integration has been successfully concluded. In reaching this conclusion, the Directors considered changes in the internal and external environment during the intervening period which could threaten the Group’s business model, future performance, liquidity, solvency or reputation. The principal risks and uncertainties are as follows: • Major HSE incident • Cyber security breach • Access to capital • Capital project execution • Commodity price volatility • Production delivery issues • Energy transition and Net Zero delivery • Workforce recruitment and retention • Supply chain capacity and capability • Governmental regulatory, political and fiscal • Major compliance breach Details of these principal risks and how they are being managed are set out on pages 101 to 108 of the 2024 Annual Report and Accounts. Operational and financial review continued Financial review continued
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12ITHACA ENERGY PLC Q3 REPORT 2025 Statement of Directors’ responsibilities The Directors confirm that, to the best of their knowledge: • Condensed consolidated financial statements have been prepared in accordance with IAS 34 Interim Financial Reporting as contained within United Kingdom adopted IFRS; • Q3 2025 results statement includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first nine months and description of principal risks and uncertainties for the remaining three months of the year); and • Q3 2025 results statement includes a fair review of the information required by DTR 4.2.8R (disclosure of material related parties’ transactions and changes therein) as set out in note 20. By order of the Board, Iain C S Lewis Director 18 November 2025
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13ITHACA ENERGY PLC Q3 REPORT 2025 Independent review report to Ithaca Energy plc Conclusion We have been engaged by the Company to review the condensed set of financial statements in the quarterly financial report for the three and nine months ended 30 September 2025 which comprises: • the condensed consolidated statement of profit or loss; • the condensed consolidated statement of comprehensive income; • the condensed consolidated statement of financial position; • the condensed consolidated statement of changes in equity; • the condensed consolidated statement of cash flows; and • the related notes 1 to 21 to the condensed consolidated financial statements. Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the quarterly financial report for the three and nine months ended 30 September 2025 is not prepared, in all material respects, in accordance with United Kingdom adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority. Basis for Conclusion We conducted our review in accordance with International Standard on Review Engagements (UK) 2410 ‘Review of Interim Financial Information Performed by the Independent Auditor of the Entity’ issued by the Financial Reporting Council for use in the United Kingdom (ISRE (UK) 2410). A review of interim financial information consists of making inquiries, 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 2, the annual financial statements of the Group are prepared in accordance with United Kingdom adopted international accounting standards. The condensed set of financial statements included in this quarterly financial report has been prepared in accordance with United Kingdom adopted International Accounting Standard 34 ‘Interim Financial Reporting’. Conclusion 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 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 entity to cease to continue as a going concern. Responsibilities of the Directors The Directors are responsible for preparing the quarterly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority. In preparing the quarterly 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 either intend to liquidate the Company 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 quarterly financial report, we are responsible for expressing to the Company a conclusion on the condensed set of financial statements in the quarterly financial report. Our Conclusion, including our Conclusion 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 This report is made solely to the Company in accordance with ISRE (UK) 2410. Our work has been undertaken so that we might state to the Company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company, for our review work, for this report, or for the conclusions we have formed. Deloitte LLP Statutory Auditor Glasgow, United Kingdom 18 November 2025
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14ITHACA ENERGY PLC Q3 REPORT 2025 Unaudited condensed consolidated statement of profit or loss For the three and nine months ended 30 September Three months ended 30 September Nine months ended 30 September Note 2025 $m 2024 $m 2025 $m 2024 $m Revenue 4 695.7 384.9 2,149.8 1,226.8 Cost of sales 5 (467.8) (282.5) (1,230.0) (823.9) Gross profit 227.9 102.4 919.8 402.9 Impairment (charges)/reversals on development and production assets 0.9 (68.5) (29.4) (104.0) Exploration and evaluation expenses 10 – (4.7) (0.1) (6.2) Administrative expenses (11.7) (14.9) (33.6) (34.9) Other (losses)/gains 6 (3.2) 17.9 (2.2) 44.1 Profit from operations before taxation, finance income and finance costs 213.9 32.2 854.5 301.9 Finance income 7 5.0 5.4 7.7 9.9 Finance costs 7 (64.3) (43.3) (194.1) (128.1) Profit/(loss) before taxation 154.6 (5.7) 668.1 183.7 Taxation 14 (56.3) 34.7 (787.2) (49.0) (Loss)/profit for the period 98.3 29.0 (119.1) 134.7 Three months ended 30 September Nine months ended 30 September Earnings per share (EPS) Note 2025 Cents 2024 Cents 2025 Cents 2024 Cents Basic 8 6.0 2.9 (7.2) 13.4 Diluted 8 5.9 2.9 (7.2) 13.3 The results above are entirely derived from continuing operations. The accompanying notes on pages 21 to 42 are an integral part of the condensed consolidated financial statements.
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15ITHACA ENERGY PLC Q3 REPORT 2025 Three months ended 30 September Nine months ended 30 September Note 2025 $m 2024 $m 2025 $m 2024 $m (Loss)/profit for the period 98.3 29.0 (119.1) 134.7 Items that may be reclassified to profit and loss Fair value gains/(losses) on cash flow hedges 18 (30.3) 9.1 252.2 (104.6) Fair value gains on cost of hedging 18 0.6 18.0 87.9 2.7 Fair value gains on investments 4.4 – 4.4 – Deferred tax (charge)/credit on cash flow hedges, cost of hedging and investments 14 19.7 (20.8) (268.7) 70.0 Other comprehensive income/(expense) (5.6) 6.3 75.8 (31.9) Total comprehensive (expense)/income for the period 92.7 35.3 (43.3) 102.8 The accompanying notes on pages 21 to 42 are an integral part of the financial statements. Unaudited condensed consolidated statement of comprehensive income For the three and nine months ended 30 September
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16ITHACA ENERGY PLC Q3 REPORT 2025 Note 2025 $m 2024 $m Assets Current assets Inventories 285.4 283.8 Other financial assets 11.3 11.3 Trade and other receivables 9 459.3 417.6 Decommissioning reimbursements 9 27.0 23.2 Prepayments 29.3 42.2 Derivative financial instruments 19 137.0 33.0 Cash and cash equivalents 574.3 165.1 1,523.6 976.2 Non-current assets Goodwill 13 1,146.3 1,129.5 Exploration and evaluation assets 10 620.2 612.5 Property, plant and equipment 11 4,451.7 4,188.4 Deferred tax assets 14 552.4 1,224.2 Investments 42.7 – Decommissioning reimbursements 9 126.2 144.2 Derivative financial instruments 19 117.8 – 7,057.3 7,298.8 Total assets 8,580.9 8,275.0 Liabilities and equity Current liabilities Borrowings 15 (28.1) (13.0) Trade and other payables (684.6) (566.5) Current tax payable (383.3) (247.1) Decommissioning liabilities 16 (123.9) (152.7) Lease liabilities (61.8) (19.4) Contingent and deferred consideration 17 (109.4) (303.5) Derivative financial instruments 19 (9.7) (130.5) (1,400.8) (1,432.7) Unaudited condensed consolidated statement of financial position As at 30 September 2025 and 31 December 2024
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17ITHACA ENERGY PLC Q3 REPORT 2025 Note 2025 $m 2024 Restated1 $m Non-current liabilities Borrowings 15 (1,610.5) (1,011.9) Decommissioning liabilities 16 (2,650.7) (2,502.4) Lease liabilities (16.8) (20.7) Other provisions (36.8) (36.2) Contingent and deferred consideration 17 (227.1) (209.7) Derivative financial instruments 19 (2.7) (21.0) (4,544.6) (3,801.9) Total liabilities (5,945.4) (5,234.6) Net assets 2,635.5 3,040.4 Shareholders’ equity Share capital 20.0 20.0 Share premium 308.8 308.8 Merger reserve 852.8 852.8 Capital contribution reserve 181.9 181.9 Own shares (7.0) (9.6) Share-based payment reserve 20.3 18.8 Cash flow hedge reserve 39.8 (15.7) Cost of hedging reserve 10.2 (9.1) Fair value through OCI reserve 1.0 – Retained earnings 1,207.7 1,692.5 Total equity 2,635.5 3,040.4 1 The excess over the nominal value of the shares issued on the completion of the Eni UK Business Combination on 3 October 2024 of $852.8 million has been reclassified from share premium to merger reserve. The accompanying notes on pages 21 to 42 are an integral part of the financial statements. Approved on behalf of the Board on 18 November 2025: Iain C S Lewis Director Unaudited condensed consolidated statement of financial position continued As at 30 September 2025 and 31 December 2024
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18ITHACA ENERGY PLC Q3 REPORT 2025 Share capital $m Share premium $m Merger reserve $m Capital contribution reserve $m Own shares $m Share-based payment reserve $m Cash flow hedge reserve $m Cost of hedging reserve $m Fair value through OCI reserve $m Retained earnings $m Total $m Balance at 1 January 2024 11.6 308.9 – 181.9 (12.4) 15.5 39.8 4.1 – 1,972.0 2,521.4 Dividends paid – – – – – – – – – (233.0) (233.0) Share-based payments – – – – 1.9 2.8 – – – – 4.7 Comprehensive income/(expense) for the period: Profit for the period – – – – – – – – – 134.7 134.7 Other comprehensive expense – – – – – – (30.5) (1.4) – – (31.9) Total comprehensive income/(expense) for the period – – – – – – (30.5) (1.4) – 134.7 102.8 Balance at 30 September 2024 11.6 308.9 – 181.9 (10.5) 18.3 9.3 2.7 – 1,873.7 2,395.9 Balance at 31 December 2024 as previously stated 20.0 1,161.6 – 181.9 (9.6) 18.8 (15.7) (9.1) – 1,692.5 3,040.4 Reclassification1 – (852.8) 852.8 – – – – – – – – Balance at 31 December 2024 and 1 January 2025 as restated 20.0 308.8 852.8 181.9 (9.6) 18.8 (15.7) (9.1) – 1,692.5 3,040.4 Dividends paid – – – – – – – – – (365.7) (365.7) Share-based payments – – – – 2.6 1.5 – – – – 4.1 Comprehensive (expense)/income for the period: Loss for the period – – – – – – – – – (119.1) (119.1) Other comprehensive income – – – – – – 55.5 19.3 1.0 – 75.8 Total comprehensive (expense)/income for the period – – – – – – 55.5 19.3 1.0 (119.1) (43.3) Balance at 30 September 2025 20.0 308.8 852.8 181.9 (7.0) 20.3 39.8 10.2 1.0 1,207.7 2,635.5 1 The excess over the nominal value of the shares issued on the completion of the Eni UK Business Combination on 3 October 2024 of $852.8 million has been reclassified from share premium to merger reserve. The accompanying notes on pages 21 to 42 are an integral part of the financial statements. Unaudited condensed consolidated statement of changes in equity For the nine months ended 30 September
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19ITHACA ENERGY PLC Q3 REPORT 2025 Three months ended 30 September Nine months ended 30 September Note 2025 $m 2024 $m 2025 $m 2024 $m Cash provided by/(used in) operating activities: Profit before tax 154.6 (5.7) 668.1 183.7 Adjustments for: Depletion, depreciation and amortisation 11 171.3 119.7 610.2 372.6 Exploration and evaluation expenses 10 – 4.7 0.1 6.2 Impairment charges/(reversals) on development and production assets (0.9) 68.5 29.4 104.0 Fair value remeasurements of contingent consideration 17 3.0 (9.1) 17.6 (36.5) Loan fee amortisation 7 2.6 1.2 7.9 3.4 Fair value gains on financial instruments 18 (4.5) (1.0) (18.8) (1.8) Accretion on deferred consideration and decommissioning liabilities less accretion on decommissioning reimbursements 7 29.1 19.1 94.7 56.6 Finance costs 7 32.5 23.0 91.5 68.1 Finance income 7 (5.0) (5.4) (7.7) (9.9) Changes in provisions 1.1 – 2.8 – Movements in cash flow hedges not yet settled (5.3) – (8.9) – Other non-cash income (9.5) – (9.5) – Unrealised foreign exchange (1.7) (2.7) (2.1) (2.9) Share-based payment expenses 1.3 1.8 4.1 4.7 Decommissioning expenditure (29.0) (22.2) (83.7) (53.5) Operating cash flows before movements in working capital 339.6 191.9 1,395.7 694.7 Decrease in inventories 88.5 0.1 3.5 10.0 Decrease/(increase) in trade and other receivables 1.6 (12.7) 1.9 69.6 Increase/(decrease) in trade and other payables (46.7) (0.3) 13.9 (8.8) Operating cash flows 383.0 179.0 1,415.0 765.5 Taxation (paid)/repaid (130.5) 51.5 (152.2) 26.6 Settlements of foreign exchange and commodity derivative financial instruments 9.1 (3.2) 9.1 (9.5) Finance income 7 5.0 5.4 7.7 9.9 Net cash from operating activities 266.6 232.7 1,279.6 792.5 Unaudited condensed consolidated statement of cash flows For the three and nine months ended 30 September
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20ITHACA ENERGY PLC Q3 REPORT 2025 Three months ended 30 September Nine months ended 30 September 2025 $m 2024 $m 2025 $m 2024 $m Cash used in investing activities: Capital expenditure (249.9) (81.7) (616.0) (292.1) JAPEX UK E&P Limited acquisition payments, net of cash acquired (120.0) – (140.3) – Other investment in listed oil and gas shares (14.8) – (38.3) – Deferred consideration payments (70.0) – (200.0) – Contingent consideration payments – (2.8) (1.6) (21.8) Net cash used in investing activities (454.7) (84.5) (996.2) (313.9) Cash used in financing activities: Dividends paid (166.4) (99.4) (365.7) (233.0) Payments for lease liabilities (principal) (15.7) (2.0) (27.3) (22.1) Drawdown of RBL loan 140.0 150.0 200.0 150.0 Repayment of RBL loan (140.0) – (140.0) – Net proceeds of Senior Notes 2031 523.9 – 523.9 – Bank interest and charges (18.7) (36.6) (73.0) (78.5) Interest rate swaps – – – (0.6) Net cash used in financing activities 323.1 12.0 117.9 (184.2) Currency translation differences relating to cash 0.7 2.6 7.9 2.9 Increase in cash and cash equivalents 135.7 162.8 409.2 297.3 Cash and cash equivalents, beginning of period 438.6 287.7 165.1 153.2 Cash and cash equivalents, end of period 574.3 450.5 574.3 450.5 1 Gross proceeds of $529.6 million less fees and other costs of $5.7 million. The accompanying notes on pages 21 to 42 are an integral part of the condensed consolidated financial statements. Unaudited condensed consolidated statement of cash flows continued For the three and nine months ended 30 September
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21ITHACA ENERGY PLC Q3 REPORT 2025 1. General information Ithaca Energy plc (the Group or Ithaca Energy), is a public Company, limited by shares, incorporated and domiciled in the UK and is a Group involved in the development and production of oil and gas in the North Sea. The Group’s registered office is 33 Cavendish Square, London, United Kingdom, W1G 0PP. 2. Basis of preparation The condensed consolidated financial statements are prepared in accordance with United Kingdom adopted International Accounting Standard 34 Interim Financial Reporting. The condensed consolidated financial statements for the three and nine months ended 30 September 2025 do not include all the information required for a full annual report and do not constitute statutory accounts within the meaning of section 434(3) of the Companies Act 2006. The condensed consolidated financial statements for the three and nine months ended 30 September 2025 are not audited but have been reviewed by the auditor whose review report is set out on page 13. The accounting policies adopted in the preparation of the Q3 2025 condensed consolidated financial statements are consistent with those adopted and disclosed in the Group’s 2024 Annual Report and Accounts. Comparative information for the year ended 31 December 2024 has been taken from the statutory accounts for that year, a copy of which has been delivered to the Registrar of Companies. The auditor’s report on those accounts was not qualified, did not include a reference to any matters to which the auditors drew attention by way of emphasis and did not contain any statements under section 498(2) or (3) of the Companies Act 2006. A number of amendments to existing standards and interpretations were effective from 1 January 2025 but there was no impact on the Q3 2025 condensed consolidated financial statements. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective. The condensed consolidated financial statements are presented in US Dollars as this is the functional currency of the business. All values are presented in millions ($m) rounded to one decimal place, except when otherwise indicated. In terms of segmental reporting, the Group currently operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area, being presently the North Sea. The Group’s segmental reporting structure remained in place for all periods presented and is consistent with the way in which the Group’s activities are reported to the Board and to the Chief Decision Making Officer. The Group’s activities are considered to represent an individual operating segment due to the to the activities of the Group being homogeneous and such operations existing in a single geographical area that is governed by the same regulations. These Q3 2025 condensed consolidated financial statements are to be read in conjunction with Ithaca Energy’s Annual Report and Accounts for the year ended 31 December 2024, which contains additional accounting policy disclosures. Prior period reclassification The excess of the fair value over the nominal value of the shares issued on the completion of the Eni UK Business Combination on 3 October 2024 was classified incorrectly to share premium and has been reclassified to merger reserves in order to comply with section 612 of the Companies Act 2006. Details of amounts as previously stated, prior period reclassifications and amounts as restated were: Statement of financial position as at 31 December 2024: As previously stated Prior period reclassification As restated Share premium ($m) 1,161.6 (852.8) 308.8 Merger reserve ($m) – 852.8 852.8 3. Accounting policies Basis of measurement The condensed consolidated financial statements have been prepared on a going concern basis using the historical cost convention, except for the revaluation of certain financial assets and financial liabilities (under IFRS) to fair value, including derivative instruments. Historical cost is generally based on the fair value consideration given in exchange for the assets or liabilities. Going concern Management closely monitors the funding position of the Group including monitoring compliance with covenants and available facilities to ensure sufficient headroom is maintained to fund operations. Management have considered a number of risks applicable to the Group that may have an impact on the Group’s ability to continue as a going concern. Short-term and long-term cash forecasts are prepared on a weekly and quarterly basis respectively along with any related sensitivity analysis. This allows proactive management of any business risk including liquidity risk. The Directors consider the preparation of the condensed consolidated financial statements on a going concern basis to be appropriate. This is due to the following key factors: • Continuing robust commodity price backdrop and a well hedged portfolio over the next 12 months; • Reserves Based Lending (RBL) liquidity headroom of $1,220million ($80 million drawn compared to $1.3 billion available including 2031 bond issued in Q3 2025), plus $159 million of cash at the end of October 2025; and • Strong operational performance and well-diversified portfolio. Notes to the condensed consolidated financial statements
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22ITHACA ENERGY PLC Q3 REPORT 2025 3. Accounting policies continued Going concern continued Cash flow forecast – base case assumptions: Q4 2025 2026 Average oil price $/bbl 65 65 Average gas price p/th 80 80 Average hedged oil price (including floor price for zero cost collars) $/bbl 71 66 Average hedged gas price (including floor price for zero cost collars) p/th 89 86 Owing to the ongoing fluctuations in commodity demand and price volatility, management prepared sensitivity analysis to the forecasts and applied a number of plausible downside scenarios, including decreases in production of 10%, reduced sales prices of 20% and increases in operating and capital expenditures of 10%. Management aggregated these scenarios to create a reasonable combined worst-case scenario. The sensitivity analysis showed that, without any consideration of the mitigation strategies within management’s control, there was no reasonably possible scenario that would result in the business being unable to meet its liabilities as they fell due. Further mitigation strategies within the control of management include the reduction in uncommitted capital expenditure and variable operating cost savings in the low production scenario. The analysis demonstrated that the Group would still continue to comply with financial covenants and have sufficient liquidity to continue trading throughout the period to 31 December 2026. Based on their assessment of the Group’s financial position in the period to 31 December 2026, the Directors believe that the Group will be able to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis of accounting in preparing the condensed consolidated financial statements. Use of judgements and estimates In preparing these Q3 2025 condensed consolidated financial statements, management has made judgements and estimates that affect the application of accounting policies and the reported amounts of assets and liabilities and income and expenses. Actual results may differ from these estimates. The significant judgements made by management in applying the Group’s accounting policies, and the key sources of estimation uncertainty are the same as those described on pages 197 to 200 of the Group’s 2024 Annual Report and Accounts. Judgements and estimates made in assessing the impact of climate change and the energy transition have not changed for the Q3 2025 consolidated condensed financial statements. Details of these are set out on pages 188 and 189 of the 2024 Annual Report and Accounts. The critical accounting judgements applied in the preparation of the Q3 2025 condensed consolidated financial statements are impairment charges on oil and gas assets, and whether or not there have been indications of impairment in respect of the Rosebank field. Impairment charges on development and production assets for the period ended 30 September 2025 were $29.4 million (Q3 2024: $104.0 million) and comprised a charge of $25.6 million principally in relation to decommissioning cost estimate changes on assets which have either been fully written off or have ceased production and a charge of $3.8 million in relation to fixed asset additions during the period on assets which have been fully written off. Details of sensitivities in relation to impairment charges are set out in note 19 on page 213 of the 2024 Annual Report and Accounts. Management has reviewed the pre-tax carrying value of the Rosebank field of $819 million or post-tax $403 million (31 December 2024: pre-tax $617 million or post-tax $304 million). Although the first phase of the Rosebank development had been sanctioned by the NSTA, it was subject to Judicial Review proceedings. On 30 January 2025, the Court of Session ruled that this consent had been unlawfully given in relation to the sanctioning of the Rosebank field development and that a new consent application would be required, which included Scope 3 emissions. It did, however, permit the project to progress as planned whilst this new consent is sought from the Regulators but that no oil could be extracted without this new consent. The revised Environmental Statement has now been submitted and we await the next stage of the process. Whilst the outcome of the Judicial Review could be construed as an indicator of impairment, management has no reason to believe that this further consent will not be forthcoming, and further management believe that the most likely outcome will be that the further consent will be granted and that the project will continue progressing as planned with first oil anticipated in 2026/27. As a result, no impairment charge is required. Notes to the condensed consolidated financial statements continued
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23ITHACA ENERGY PLC Q3 REPORT 2025 4. Revenue Three months ended 30 September Nine months ended 30 September 2025 $m 2024 $m 2025 $m 2024 $m Oil sales 419.2 255.7 1,175.4 802.1 Gas sales 201.5 90.4 812.1 260.8 Condensate sales 16.5 8.8 63.8 27.5 Other income 30.4 3.2 47.2 12.9 Realised gains/(losses) on oil derivative contracts 7.9 0.5 28.8 (6.9) Premium payments on oil derivative contracts – (0.5) – (0.4) Realised gains on gas derivative contracts 20.3 28.0 22.7 133.2 Premium payments on gas derivative contracts (0.1) (1.2) (0.2) (2.4) 695.7 384.9 2,149.8 1,226.8 The majority of payment terms are on a specified monthly date, as detailed in the initial contract. Otherwise, payment is due within 30 days of the invoice date. No significant judgements have been made in determining the timing of satisfaction of performance obligations, the transactions price and the amounts allocated to performance obligations. Other income relates principally to tariff income receivable in the period. Revenue from two customers (30 September 2024: two customers) exceeds 10% of the Group’s consolidated revenue arising from hydrocarbon sales for the nine months ended 30 September 2025, representing $1,250.9 million and $760.8 million respectively (nine months ended 30 September 2024: $890.2 million and $114.1 million respectively). Revenue from contracts with customers derives largely from customers within a single geographical region, being the United Kingdom. Revenue from contracts with customers outwith the United Kingdom is immaterial and is therefore not disclosed separately. 5. Cost of sales Three months ended 30 September Nine months ended 30 September 2025 $m 2024 $m 2025 $m 2024 $m Movement in oil and gas inventory (77.1) (2.4) 21.9 (7.5) Operating costs of hydrocarbon activities (219.1) (160.1) (640.4) (442.3) Royalties (0.3) (0.3) (1.3) (1.5) Depreciation on right-of-use assets (note 11) (15.6) (2.6) (26.4) (21.3) Depletion, depreciation and amortisation (note 11) (155.7) (117.1) (583.8) (351.3) (467.8) (282.5) (1,230.0) (823.9) Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca Energy holds a 100% interest in the Stella and Harrier fields. Notes to the condensed consolidated financial statements continued
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24ITHACA ENERGY PLC Q3 REPORT 2025 6. Other gains and losses Three months ended 30 September Nine months ended 30 September 2025 $m 2024 $m 2025 $m 2024 $m Gains on financial instruments (note 18) 4.7 9.9 17.2 8.2 Fair value remeasurements of contingent consideration (3.0) 9.1 (17.6) 36.5 Net foreign exchange losses (4.9) (1.1) (1.8) (0.6) (3.2) 17.9 (2.2) 44.1 7. Finance costs and finance income Three months ended 30 September Nine months ended 30 September 2025 $m 2024 $m 2025 $m 2024 $m Loan interest and charges (15.4) (8.5) (42.9) (25.1) Senior notes interest (15.9) (14.3) (46.0) (42.1) Loan fee amortisation (2.6) (1.2) (7.9) (3.4) Interest on lease liabilities (1.3) (0.2) (2.6) (0.9) Accretion on deferred consideration and decommissioning liabilities less accretion on decommissioning reimbursements (29.1) (19.1) (94.7) (56.6) Total finance costs (64.3) (43.3) (194.1) (128.1) Finance income 5.0 5.4 7.7 9.9 During the nine months to 30 September 2025, $9.6 million of interest was capitalised into qualifying assets (nine months to 30 September 2024: $3.3 million). 8. Earnings per share The calculation of basic earnings per share is based on the (loss)/profit after tax and the weighted average number of ordinary shares in issue during the period. Basic and diluted earnings per share are calculated as follows: Three months ended 30 September Nine months ended 30 September 2025 $m 2024 $m 2025 $m 2024 $m Earnings for the period Earnings for the purpose of basic and diluted earnings per share 98.3 29.0 (119.1) 134.7 Number of shares (million) Weighted average number of ordinary shares for the purpose of basic earnings per share 1,648.4 1,006.8 1,648.4 1,006.8 Dilutive potential ordinary shares 14.4 9.9 14.4 9.9 Weighted average number of ordinary shares for the purpose of diluted earnings per share 1,662.8 1,016.7 1,662.8 1,016.7 Earnings per share (cents) Basic 6.0 2.9 (7.2) 13.4 Diluted 5.9 2.9 (7.2) 13.3 Notes to the condensed consolidated financial statements continued
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25ITHACA ENERGY PLC Q3 REPORT 2025 9. Trade and other receivables and decommissioning reimbursements Current 30 September 2025 $m 31 December 2024 $m Trade receivables 10.5 19.0 Other receivables 12.6 23.0 Joint operations receivables 177.0 106.0 Accrued income 259.2 269.6 459.3 417.6 Materially all trade and other receivables, including receivables from joint operations are not overdue by more than 90 days. The credit risk associated with trade receivables, joint operations receivables, accrued income and other receivables is considered to be insignificant. No ECL has been recognised in the current or prior year. Accrued income mainly comprises amounts due, but not yet invoiced, for the sale of oil and gas. Non-current 30 September 2025 $m 31 December 2024 $m Decommissioning reimbursements 126.2 144.2 Current 30 September 2025 $m 31 December 2024 $m Decommissioning reimbursements 27.0 23.2 Movements on decommissioning reimbursements were as follows: 30 September 2025 $m 31 December 2024 $m At beginning of period 167.4 195.5 Accretion net of tax at 30% 4.8 7.4 Reimbursements received (19.2) (22.5) Change in reimbursement estimates 0.2 (13.0) At end of period 153.2 167.4 Notes to the condensed consolidated financial statements continued
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26ITHACA ENERGY PLC Q3 REPORT 2025 9. Trade and other receivables and decommissioning reimbursements continued The decommissioning reimbursements represent the equal and opposite of decommissioning liabilities, net of tax, associated with the Heather and Strathspey fields, and relates to a contractual agreement as part of the CNSL acquisition. As part of the terms of the acquisition of what is now Ithaca Oil and Gas Limited (IOGL), Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of IOGL in relation to these interests. The Group pays the liabilities in respect of Heather and Strathspey, and then receives full reimbursement from Chevron. As these payments are virtually certain, they have been accounted for under IAS 37 as a reimbursement asset. 10. Exploration and evaluation assets $m At 1 January 2024 548.4 Additions 36.3 Change in decommissioning estimates 4.4 Business combinations 48.0 Write-offs/relinquishments (24.6) At 31 December 2024 and 1 January 2025 612.5 Additions 31.8 Change in decommissioning estimates 0.2 Transfers to development and production assets (note 11) (24.2) Write-offs/relinquishments (0.1) At 30 September 2025 620.2 Following completion of geotechnical evaluation activity, certain North Sea licences were declared unsuccessful and certain prospects were declared non-commercial. This resulted in the carrying value of these licences being fully written off to $nil with $0.1 million being expensed in the period to 30 September 2025 (year to 31 December 2024: $24.6 million). The transfer to development and production assets during the nine months to 30 September 2025 relates to the successful commencement of production on Jocelyn South. The principal component of exploration and evaluation assets at 30 September 2025 is the Cambo field with a pre-tax carrying value of $409 million (31 December 2024: $391 million). Notes to the condensed consolidated financial statements continued
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27ITHACA ENERGY PLC Q3 REPORT 2025 11. Property, plant and equipment Right-of-use operating assets $m Development and production assets $m Other fixed assets $m Total $m Cost At 1 January 2024 156.2 7,976.8 47.6 8,180.6 Additions 136.2 483.5 0.5 620.2 Business combinations 18.7 997.9 – 1,016.6 Change in decommissioning estimates – 54.6 – 54.6 At 31 December 2024 and 1 January 2025 311.1 9,512.8 48.1 9,872.0 Additions 157.9 563.4 6.6 727.9 Business combinations – 59.6 – 59.6 Change in decommissioning estimates – 65.5 – 65.5 Transfers from exploration and evaluation assets (note 10) – 24.2 – 24.2 At 30 September 2025 469.0 10,225.5 54.7 10,749.2 Depletion, depreciation, amortisation and impairment At 1 January 2024 (85.5) (4,808.7) (28.1) (4,922.3) Depletion, depreciation and amortisation charge for the year (26.8) (568.1) (5.3) (600.2) Impairment charge – (161.1) – (161.1) At 31 December 2024 and 1 January 2025 (112.3) (5,537.9) (33.4) (5,683.6) Depletion, depreciation and amortisation charge for the period (26.4) (578.3) (5.5) (610.2) Impairment charge (3.7) – – (3.7) At 30 September 2025 (142.4) (6,116.2) (38.9) (6,297.5) Net book value at 31 December 2024 198.8 3,974.9 14.7 4,188.4 Net book value at 30 September 2025 326.6 4,109.3 15.8 4,451.7 Additions to right-of-use assets in the period to 30 September 2025 and the year to 31 December 2024 principally relate to modifications to the Rosebank FPSO and will begin to be depreciated on commencement of production. The related lease will commence on delivery of the FPSO to the joint venture partners at first oil, which is currently anticipated to be 2026/27. The Rosebank field development is still subject to further approvals from the Regulators and further details are set out in note 3. Other fixed assets include buildings, computer equipment, office equipment and furniture and fittings. Notes to the condensed consolidated financial statements continued
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28ITHACA ENERGY PLC Q3 REPORT 2025 12. Business Combinations The Business Combination in the year to 31 December 2024 comprised the acquisition of 100% of each of Eni Elgin/Franklin Limited, Eni UKCS Limited, Eni Energy E&P Limited and Eni Energy E&P UKCS Limited. The Business Combination in 2025 reflects the acquisition of 100% of the issued share capital of JAPEX UK E&P Limited which completed on 7 July 2025 for a total cash consideration of $156.4 million. As a result of this acquisition the Group’s working interest in the Seagull field increased from 35% to 50%. The provisional fair values of the identifiable assets and liabilities at the dates of completion of the Business Combinations were: 2025 $m 2024 $m Property, plant and equipment (note 11) 59.6 1,016.6 Exploration and evaluation assets (note 10) – 48.0 Cash 16.1 107.5 Inventory 3.5 62.3 Trade and other receivables 11.6 178.0 Total assets excluding deferred tax 90.8 1,412.4 Trade and other payables (10.7) (281.7) Decommissioning provisions (note 16) (12.4) (651.0) Other provisions – (34.9) Lease liabilities – (22.0) Total liabilities excluding deferred tax (23.1) (989.6) Deferred tax asset (note 14) 87.3 846.4 Deferred tax liability (note 14) – (549.1) Total identifiable net assets at fair value 155.0 720.1 Consideration satisfied by the issue of new shares – 861.3 Cash consideration 156.4 – Deferred consideration – 204.4 Total consideration 156.4 1,065.7 Goodwill arising on Business Combinations (note 13) 1.4 345.6 Net cash flows relating to Business Combinations (acquisition payments less cash acquired) (140.3) 107.5 Notes to the condensed consolidated financial statements continued
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29ITHACA ENERGY PLC Q3 REPORT 2025 12. Business combinations continued From the date of acquisition, the JAPEX UK business contributed $35.1 million of revenue and $15.5 million of profit before tax in the period to 30 September 2025. Had this Business Combination completed on 1 January 2025, it would have contributed $77.3 million of revenue and $33.4 million of profit before tax for the period to 30 September 2025. From the date of the Business Combination, the Eni UK businesses contributed $290.1 million of revenue and $195.0 million of profit before tax in the year to 31 December 2024. Had the Business Combination completed on 1 January 2024, the Eni UK businesses would have contributed $1,014.0 million of revenue and $598.4 million of profit before tax for the 2024 financial year. There were no significant third-party costs associated with the Seagull acquisition in the period ended 30 September 2025. Business Combination related costs in the year to 31 December 2024 amounted to $16.3 million, comprising principally professional fees and other direct costs, and were included within ‘administrative expenses’. The fair values of the oil and gas assets and the intangible assets of the JAPEX UK and the Eni UK businesses have been determined using valuation techniques based on discounted cash flows using forward curve commodity prices and estimates of long-term commodity prices reflective of market conditions at the completion dates, discount rates based on observable market data and cost and production profiles generally consistent with the proved and probable reserves acquired with each asset. The decommissioning liabilities recognised have been estimated based on internal engineering estimates for operated assets and operator cost estimates for non-operated assets, with reference to observable market data. The goodwill generated on both Business Combinations is largely the result of the IFRS requirement to recognise a deferred tax liability on the fair value of the property, plant and equipment and exploration and evaluation assets acquired through the Business Combination, despite these assets being recognised on a post-tax basis. 13. Goodwill 30 September 2025 $m 31 December 2024 $m At beginning of period 1,129.5 783.9 Additions (note 12) 1.4 345.6 Revisions to 2024 additions1 15.4 – At end of period 1,146.3 1,129.5 1 Revisions to 2024 additions comprise an increase in trade and other payables of $9.6 million, a reduction in deferred tax assets of $18.3 million (note 14) partly offset by a reduction in current tax payable of $12.5 million. The opening goodwill of $784 million relates to historic business combinations comprising principally Chevron in 2019 and Summit in 2022. The additions to goodwill in the period ended 30 September 2025 relates to the JAPEX UK business and in the year to 31 December 2024 relates to the Eni UK businesses, as detailed in note 12. The goodwill is not tax deductible on either the JAPEX UK or Eni UK Business Combination. Goodwill is monitored, and tested for impairment, at the operating segment level, being the North Sea (the entire Group portfolio of oil and gas assets). This is consistent with the operating segment view of the business, which is presented to the Board and the Chief Decision Maker. The Group’s activities are considered to be an individual operating segment due to the uniform nature of the Group’s operations within a single geographical area, overseen by the same management and subject to the same regulations. The fair value estimate is categorised as level 3 in the fair value hierarchy. An annual impairment tests was performed at 31 December 2024. This review was carried out on a fair value less cost of disposal basis using risk-adjusted cash flow projections from the approved business plans, including the same commodity prices, life of field cost profiles and production volumes used for impairment of oil and gas assets, discounted at a post-tax discount rate of 10.0%. Assumptions and estimates in the Group impairment models are detailed in note 3 to the 2024 Annual Report and Accounts. The recoverable amount of the North Sea CGU at 31 December 2024 was $418.8 million higher than its carrying amount, including goodwill, and hence no impairment was recorded. An increase of 1% in the discount rate assumption would not result in a post-tax impairment of goodwill. Details of further sensitivities are provided in note 3. Notes to the condensed consolidated financial statements continued
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30ITHACA ENERGY PLC Q3 REPORT 2025 14. Taxation Three months ended 30 September Nine months ended 30 September 2025 $m 2024 $m 2025 $m 2024 $m Current tax Current corporation tax (charge)/credit 3.2 1.6 (52.6) 4.6 True-up in respect of prior years 26.8 (50.3) 26.1 26.0 Current EPL tax charge (24.8) (15.2) (286.0) (87.9) Total current tax (charge)/credit 5.2 (63.9) (312.5) (57.3) Deferred tax True-up in respect of prior years (14.4) 31.6 3.6 (27.6) Group tax (charge)/credit in the condensed consolidated statement of profit or loss (52.1) 43.9 (501.0) 0.3 Group tax (charge)/credit in the condensed consolidated statement of other comprehensive income 19.7 (20.8) (268.7) 70.0 Total deferred tax (charge)/credit (46.8) 54.7 (766.1) 42.7 Deferred PRT credit in the condensed consolidated statement of profit or loss 5.0 23.1 22.7 35.6 Total tax (charge)/credit through the condensed consolidated statement of profit or loss (56.3) 34.7 (787.2) (49.0) The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows: Three months ended 30 September Nine months ended 30 September 2025 $m 2024 $m 2025 $m 2024 $m Accounting profit/(loss) before tax 154.6 (5.7) 668.1 183.7 At tax rate of 40% (2024: 40%) (61.8) 2.3 (267.2) (73.5) Non-deductible (expense)/income 3.6 20.4 (8.9) 15.5 Financing costs not allowed for SCT (3.7) (16.0) (8.8) (16.4) Ring Fence Expenditure Supplement 3.9 4.4 12.2 13.1 Deferred tax effect of investment allowance 25.2 9.1 47.3 8.9 True-up in respect of prior years 12.4 (18.7) 29.7 (1.6) Deferred tax on EPL (16.1) 11.7 (307.8) 54.6 Current tax on EPL (24.8) (15.2) (286.1) (88.0) Net deferred tax PRT 3.0 13.9 13.6 21.4 Share schemes – – – (2.1) Income taxed at different rates 1.8 22.8 (11.2) 19.1 Total tax (charge)/credit recorded in the condensed consolidated statement of profit or loss (56.3) 34.7 (787.2) (49.0) Notes to the condensed consolidated financial statements continued
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31ITHACA ENERGY PLC Q3 REPORT 2025 14. Taxation continued The Company is UK tax resident. The effective rate of tax applicable for UK ring fence oil and gas activities in both 2025 and 2024 was 40% (excluding the Energy Profits Levy), consisting of a Ring Fence Corporation Tax rate of 30% and the supplementary charge of 10%. Items affecting the tax charge include interest income taxed at non-oil and gas tax rate of 25%, true-ups in respect of prior years resulting from filing of prior year tax returns, a 10% uplift on ring fence losses, Ring Fence Expenditure Supplement increasing the losses available to offset future profits subject to Ring Fence Corporation Tax and Supplementary Charge. In addition, investment allowance, a 62.5% uplift on capital expenditure, is available reducing the profits subject to the supplementary charge only. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK, however, deferred PRT assets are recognised reflecting the expected carry back of losses to periods in which PRT was payable at 50%. The Energy Profits Levy was enacted on 14 July 2022 with further changes announced on 17 November 2022 such that the Levy was increased to 35% from 1 January 2023 until 31 March 2028 increasing the effective UK ring fence oil and gas tax rate to 75%. On 6 March 2024, it was announced that EPL will be extended by one year to 31 March 2029 and on 29 July 2024, it was announced that there would be a further extension to March 2030 and that the rate would increase from 35% to 38% from 1 November 2024. The impact of this was a charge to the consolidated statement of profit or loss of $58.1 million in the year to 31 December 2024. The extension to 31 March 2030 was substantively enacted on 3 March 2025 and had an impact of $327.6 million on the tax charge for the period ended 31 March 2025. Deferred tax at 30 September 2025 and 31 December 2024 relates to the following: 30 September 2025 $m 31 December 2024 $m Deferred corporation tax liability (2,765.4) (2,197.5) Deferred corporation tax asset 3,153.0 3,279.6 Deferred PRT asset 164.8 142.1 Net deferred tax asset 552.4 1,224.2 Deferred tax assets primarily relate to decommissioning liabilities, brought-forward tax losses and accumulated losses and profits related to derivative contracts. Deferred tax liabilities primarily relate to accelerated capital allowances on property, plant and equipment, and accumulated losses and profits related to derivative contracts. Deferred tax balances are presented net as they arise in the same jurisdiction and the Group has a legally-enforceable right to offset as well as an intention to settle on a net basis. There are unrecognised allowances of up to circa $143 million (31 December 2024: circa $147 million) that have no expiry date and could be recognised in future periods if future revenue from oil and gas activities increases and/or further actions are undertaken. Non-oil and gas losses of $281 million (31 December 2024: $217 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset these losses. The net movement on deferred tax in the condensed consolidated statement of financial position, including deferred PRT, is as follows: 30 September 2025 $m 31 December 2024 $m At beginning of period 1,224.2 704.7 Profit or loss (charge)/credit (474.7) 27.4 Other comprehensive income (charge)/credit (268.7) 195.7 Deferred tax on decommissioning reimbursements 2.6 (0.9) Business combinations1 69.0 297.3 At end of period 552.4 1,224.2 1 Current year acquisitions of $87.3 million (note 12) less revisions to 2024 acquisitions of $18.3 million (note 13). Notes to the condensed consolidated financial statements continued
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32ITHACA ENERGY PLC Q3 REPORT 2025 14. Taxation continued The net movement on deferred tax through the condensed consolidated statement of profit or loss and condensed consolidated statement of comprehensive income, excluding PRT, relates to the following: Nine months ended 30 September 2025 $m 2024 $m Accelerated capital allowances (407.6) 51.6 Tax losses (156.2) (114.2) Decommissioning provision 42.9 41.5 Deferred PRT (9.1) (14.2) Hedging1 (282.9) 74.4 Share schemes – (2.0) Other timing differences (6.6) – Investment allowances 53.4 5.6 (766.1) 42.7 1 Hedging relates to deferred tax on derivatives designated as cash flow hedges and used for economic hedges. Gross deferred corporation tax liabilities Hedges $m Other timing differences $m Deferred corporation tax on deferred PRT $m Accelerated tax depreciation $m Total $m At 1 January 2024 (107.7 ) – (36.7) (1,723.6) (1,868.0) Business combinations – – – (549.1) (549.1) True-up in respect of prior years – – – (16.0) (16.0) Origination and reversal of temporary differences 201.5 – (20.1) 148.0 329.4 Reclassification to deferred corporation tax assets (93.8) – – – (93.8) At 31 December 2024 and 1 January 2025 – – (56.8) (2,140.7) (2,197.5) Business combinations – – – (11.6) (11.6) True-up in respect of prior years – (3.8) – (3.8) (7.6) Origination and reversal of temporary differences (282.9) – (9.1) (350.5) (642.5) Reclassification from deferred corporation tax assets 93.8 – – – 93.8 At 30 September 2025 (189.1) (3.8) (65.9) (2,506.6) (2,765.4) Notes to the condensed consolidated financial statements continued
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33ITHACA ENERGY PLC Q3 REPORT 2025 14. Taxation continued Gross deferred corporation tax assets Share schemes $m Decommissioning provision $m Other provisions $m Tax losses $m Hedges $m Total $m At 1 January 2024 4.0 721.7 – 1,755.2 – 2,480.9 Business combinations – 257.4 21.4 567.6 – 846.4 True-up in respect of prior years – – – (5.0) – (5.0) Origination and reversal of temporary differences 0.9 60.8 – (198.2) – (136.5) Reclassification from deferred corporation tax liabilities – – – – 93.8 93.8 At 31 December 2024 and 1 January 2025 4.9 1,039.9 21.4 2,119.6 93.8 3,279.6 Business combinations – 5.0 – 75.6 – 80.6 True-up in respect of prior years – – – 11.2 – 11.2 Origination and reversal of temporary differences – 42.8 – (167.4) – (124.6) Reclassification to deferred corporation tax liabilities – – – – (93.8) (93.8) At 30 September 2025 4.9 1,087.7 21.4 2,039.0 – 3,153.0 Deferred PRT asset Total $m At 1 January 2024 91.7 Origination and reversal of temporary differences 50.4 At 31 December 2024 and 1 January 2025 142.1 Origination and reversal of temporary differences 22.7 At 30 September 2025 164.8 The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 30 September 2025 of $387 million and $165 million, respectively (31 December 2024: $1,082 million and $142 million, respectively) are supported by estimates of the Group’s future taxable income, based on the same price and cost assumptions as used for impairment testing. The Group has undertaken and will undertake further restructuring exercises to move certain assets between Group entities. Existing restructuring exercises have now been substantially completed. The recoverability of the deferred corporation tax asset is supported by this restructuring. The DTA relating to losses within the Group are expected to unwind against taxable profits before the end of 2029. An EPL (or Levy) was enacted on 14 July 2022, applying a Levy of 25% to the profits of oil and gas companies until 31 December 2025 or earlier if prices return to normalised levels. On 17 November 2022, the Levy was increased to 35% and extended to 31 March 2028 regardless of oil and gas prices. The Levy is charged on oil and gas profits calculated on the same basis as RFCT, however, excludes relief for decommissioning and finance costs. RFCT losses and investment allowance are not available to offset the EPL. On 9 June 2023 an Energy Security Investment Mechanism price floor was announced which would remove the EPL if both average oil and gas prices fall to, or below, $71.40 per barrel for oil and £0.54 per therm for gas, for two consecutive quarters. It is not currently forecast that this price floor will be met for both oil and gas prices and, therefore, there is currently no impact from this on tax carrying values. On 6 March 2024, an extension of the Levy until 31 March 2029 was announced and on 29 July 2024, it was announced that there would be a further extension to March 2030 and that the rate would increase from 35% to 38% from 1 November 2024, of which only the rate increase had been enacted at 31 December 2024. The two-year extension to 31 March 2030 was substantively enacted on 3 March 2025 and resulted in a deferred tax charge of $327.6 million in the condensed consolidated statement of profit or loss in Q1 2025. Notes to the condensed consolidated financial statements continued
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34ITHACA ENERGY PLC Q3 REPORT 2025 15. Borrowings 30 September 2025 $m 31 December 2024 $m Current Accrued interest costs on borrowings (41.1) (23.2) Unamortised short-term bank fees 7.5 6.6 Unamortised short-term senior notes fees 5.5 3.6 Total current borrowings (28.1) (13.0) Non-current Accrued interest costs on borrowings (15.4) – RBL facility (210.0) (150.0) Senior unsecured notes 2029 (750.0) (750.0) Senior unsecured notes 2031 (528.1) – Project capital expenditure facility (150.0) (150.0) Unamortised long-term bank fees 22.8 24.6 Unamortised long-term senior notes fees 20.2 13.5 Total non-current borrowings (1,610.5) (1,011.9) In September 2025, the Group issued €450 million of 5.50% senior unsecured notes due September 2031. These senior unsecured notes were swapped to US Dollars at an all-in effective interest rate of approximately 6.7%. Details of covenants under the RBL are set out in note 20 to the 2024 Annual Report and Accounts. The Group was in compliance with all financial covenants relating to the RBL facility in all periods presented. Notes to the condensed consolidated financial statements continued
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35ITHACA ENERGY PLC Q3 REPORT 2025 16. Decommissioning liabilities 30 September 2025 $m 31 December 2024 $m Balance at beginning of period (2,655.1) (1,859.7) Business combination additions (12.4) (651.0) Accretion (92.9) (93.4) Additions and revisions to estimates (97.9) (145.1) Decommissioning provision utilised 83.7 94.1 Balance at end of period (2,774.6) (2,655.1) Current Balance at beginning of period (152.7) (107.0) Balance at end of period (123.9) (152.7) Non-current Balance at beginning of period (2,502.4) (1,752.7) Balance at end of period (2,650.7) (2,502.4) The total future decommissioning liability represents the estimated cost to decommission, in situ or by removal, the Group’s net ownership interest in all wells, infrastructure and facilities, based upon forecast timing in future periods. The Group uses a nominal discount rate of 3.77% for the first five years and 4.75% thereafter (31 December 2024: 4.38% for the first five years and 4.86% thereafter) and an inflation rate of 2.0% (31 December 2024: 2.0%) over the varying lives of the assets to calculate the present value of the decommissioning liabilities. Revisions to estimates in the nine months ended 30 September 2025 and the year ended 31 December 2024 were due to changes in both cost estimates and discount rate assumptions. The estimated Q4 2025 and Q1 to Q3 2026 decommissioning spend of $124 million (31 December 2024: estimated 2025 decommissioning spend of $153 million) has been treated as a current liability as at 30 September 2025. Although the Group currently expects to incur decommissioning costs over the next 40 years, it is estimated that approximately 37% (31 December 2024: 40%) of the decommissioning liability relates to assets which are expected to cease production in the next five years and includes spend for assets that will be reimbursed (see note 9 for further details). A reduction or an increase in the nominal discount rate used of 1% would increase or decrease the decommissioning liabilities by approximately $286 million and $247 million respectively (31 December 2024: $288 million and $247 million respectively). 17. Contingent and deferred consideration Current 30 September 2025 $m 31 December 2024 $m Contingent consideration (75.8) (75.0) Deferred consideration payable to related party for business combination (33.6) (160.2) Marubeni deferred consideration – (68.3) (109.4) (303.5) Notes to the condensed consolidated financial statements continued
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36ITHACA ENERGY PLC Q3 REPORT 2025 17. Contingent and deferred consideration continued Non-current 30 September 2025 $m 31 December 2024 $m Contingent consideration (179.4) (165.5) Deferred consideration payable to related party for business combination (47.7) (44.2) (227.1) (209.7) 30 September 2025 $m 31 December 2024 $m Cash flows relating to contingent and deferred considerations (201.6) (23.0) Movement in contingent consideration is as follows: 30 September 2025 $m 31 December 2024 $m At beginning of period (240.5) (296.4) Payments made 1.6 23.0 Fair value remeasurements (16.3) 32.9 At end of period (255.2) (240.5) Movement in deferred consideration is as follows: 30 September 2025 $m 31 December 2024 $m At beginning of period (272.7) (63.9) Additions – (204.5) Payments made 200.0 – Accretion (8.6) (4.3) At end of period (81.3) (272.7) Cash outflows in the nine months ended 30 September 2025 were $201.6 million (year to 31 December 2024: $23.0 million) and comprised mainly an Eni UK and Marubeni deferred consideration payments of $130.0 million and $70.0 million respectively. Changes in fair value of contingent consideration in the six months ended 30 September 2025 relate principally to management’s regular reassessment of the likelihood of certain milestones and other events occurring. Notes to the condensed consolidated financial statements continued
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37ITHACA ENERGY PLC Q3 REPORT 2025 18. Financial instruments Details of valuation methodologies are set out on page 229 of the 2024 Annual Report and Accounts. All of the Group’s assets are pledged as security against borrowings. The accounting classification of each category of financial instruments and their carrying amounts as at 30 September 2025 are set out below: Measured at amortised cost $m Mandatorily measured at fair value through profit or loss $m Measured at fair value through other comprehensive income $m Derivatives designated in hedge relationships $m Total carrying amount $m Financial assets Cash and cash equivalents 574.3 – – – 574.3 Other financial assets 11.3 – – – 11.3 Trade and other receivables 448.0 – – – 448.0 Investments – – 42.7 – 42.7 Derivative financial instruments – 11.6 – 243.2 254.8 Financial liabilities Borrowings (1,638.6) – – – (1,638.6) Trade and other payables – excluding deferred income, inventory overlift and bonus/holiday pay accruals (640.1) – – – (640.1) Lease liability (78.6) – – – (78.6) Contingent and deferred consideration (81.3) (255.2) – – (336.5) Derivative financial instruments – (0.3) – (12.1) (12.4) (1,375.1) Notes to the condensed consolidated financial statements continued
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38ITHACA ENERGY PLC Q3 REPORT 2025 18. Financial instruments continued The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2024 are set out below: Measured at amortised cost $m Mandatorily measured at fair value through profit or loss $m Derivatives designated in hedge relationships $m Total carrying amount $m Financial assets Cash and cash equivalents 165.1 – – 165.1 Other financial assets 11.3 – – 11.3 Trade and other receivables – excluding VAT receivable 411.1 – – 411.1 Derivative financial instruments – – 33.0 33.0 Financial liabilities Borrowings (1,024.9) – – (1,024.9) Trade and other payables – excluding deferred income, inventory overlift and bonus/holiday pay accruals (439.7) – – (439.7) Lease liability (40.2) – – (40.2) Contingent and deferred consideration (272.7) (240.5) – (513.2) Derivative financial instruments – (7.5) (144.0) (151.5) (1,549.0) The following table presents the Group’s material financial instruments measured at fair value for each hierarchy level as at 30 September 2025: Level 1 $m Level 2 $m Level 3 $m Total fair value $m Investments – – 42.7 42.7 Contingent consideration – – (255.2) (255.2) Derivative financial instrument asset – 254.8 – 254.8 Derivative financial instrument liability – (12.4) – (12.4) Movements in level 3 contingent consideration in the nine months to 30 September 2025 were as follows: $m At 1 January 2025 (239.3) Payments – Fair value remeasurements (15.9) At 30 September 2025 (255.2) Notes to the condensed consolidated financial statements continued
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39ITHACA ENERGY PLC Q3 REPORT 2025 18. Financial instruments continued Movements in level 3 investments in the nine months to 30 September 2025 were as follows: $m At 1 January 2025 – Additions 38.3 Fair value remeasurements 4.4 At 30 September 2025 42.7 The following table presents the Group’s material financial instruments measured at fair value for each hierarchy level as at 31 December 2024: Level 1 $m Level 2 $m Level 3 $m Total fair value $m Contingent consideration – (1.2) (239.3) (240.5) Derivative financial instrument asset – 33.0 – 33.0 Derivative financial instrument liability – (151.5) – (151.5) Movements in level 3 financial instruments in the 12 months to 31 December 2024 were as follows: $m At 1 January 2024 (272.3) Cash settlements 15.0 Fair value remeasurements 18.0 At 31 December 2024 (239.3) Level 3 contingent consideration is valued on a discounted cash flow basis with the key inputs being commodity prices, the probability of certain future events occurring (‘trigger events’) and the discount rate. The forecast cash flows are discounted at a rate of 6.49% (31 December 2024: 6.33%). Management has considered alternative scenarios to assess the valuation of the contingent consideration including, but not limited to, the key accounting estimate relating to the oil price. A reduction or increase in the price assumptions of 20% are considered to be reasonably possible changes. A 20% reduction in the oil price would result in a decrease in contingent consideration of $nil (31 December 2024: $nil) as the forecast price is already at a level which is lower than the trigger price. A 20% increase in the oil price would lead to an increase in contingent consideration of $3.8 million (31 December 2024: $21.7 million). The following table summarises the sensitivity of the Group’s profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date resulting from a 20% change in the probability of a trigger event occurring, risking of project and conditions being met for payment of contingent consideration, with all other variables held constant. The impact on equity is the same as the impact on profit before tax. Change in probability 30 September 2025 $m 31 December 2024 $m 20% decrease in probability 79.4 84.2 20% increase in probability (63.2) (7 7.1) Notes to the condensed consolidated financial statements continued
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40ITHACA ENERGY PLC Q3 REPORT 2025 18. Financial instruments continued The following table summarises the sensitivity of the Group’s profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date resulting from a 1% decrease in discount rate, with all other variables held constant. The impact on equity is the same as the impact on profit before tax. Change in discount rate 30 September 2025 $m 31 December 2024 $m 1% decrease in discount rate (6.1) (5.7) A 1% increase in discount rate would broadly have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. The table below presents the gains or losses on financial instruments that have been recognised in the condensed consolidated statement of profit or loss as disclosed in note 6. Three months ended 30 September Nine months ended 30 September 2025 $m 2024 $m 2025 $m 2024 $m Revaluation of forex forward contracts (0.8) 1.0 7.9 0.1 Revaluation of forex collars 5.3 – 10.9 – Revaluation of interest rate swaps – – – (0.6) Revaluation of commodity hedges – – – 2.3 Total revaluation gains on financial instruments 4.5 1.0 18.8 1.8 Realised (losses)/gains on forex forward contracts 0.2 8.9 (1.6) 7.3 Realised gains on interest rate swaps – – – 0.6 Realised losses on commodity hedges – – – (1.5) Total gains on financial instruments 4.7 9.9 17.2 8.2 Cash flow hedge reserve The table below presents the movements in financial instruments that have been recognised through the condensed consolidated statement of comprehensive income relating to the cash flow hedge reserve: Three months ended 30 September Nine months ended 30 September Cash flow hedge reserve 2025 $m 2024 $m 2025 $m 2024 $m At beginning of period 46.4 7.2 (15.7) 39.8 Change in fair value of derivative instruments 2.6 42.7 316.4 28.6 Amounts recycled to revenue (28.2) (33.6) (51.5) (133.2) Amounts recycled to operating costs (3.7) – (7.5) – Amounts recycled to dividends (0.2) – (4.2) – Other movements (0.8) – (1.0) – Amount per the condensed consolidated statement of comprehensive income (30.3) 9.1 252.2 (104.6) Deferred tax on movement in period 23.7 (7.0) (196.7) 74.1 Cash flow hedge reserve at 30 September 39.8 9.3 39.8 9.3 Notes to the condensed consolidated financial statements continued
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41ITHACA ENERGY PLC Q3 REPORT 2025 18. Financial instruments continued Cost of hedging reserve The table below presents the movements in financial instruments that have been disclosed through the condensed consolidated statement of comprehensive income relating to the cost of hedging reserve: Three months ended 30 September Nine months ended 30 September Cost of hedging reserve 2025 $m 2024 $m 2025 $m 2024 $m At beginning of period 10.1 (1.5) (9.1) 4.1 Change in fair value of the intrinsic value of derivative instruments 0.5 16.3 87.7 – Amounts recycled to revenue – premium payments on oil derivative contracts – 0.5 – 0.4 Amounts recycled to revenue – premium payments on gas derivative contracts 0.1 1.2 0.2 2.3 Amount per the condensed consolidated statement of comprehensive income 0.6 18.0 87.9 2.7 Deferred tax on movement in period (0.5) (13.8) (68.6) (4.1) Cost of hedging reserve at 30 September 10.2 2.7 10.2 2.7 19. Derivative financial instruments The net carrying amount of each category of derivative is set out below: 30 September 2025 $m 31 December 2024 $m Oil swaps – cash flow hedge 34.5 19.8 Oil collars – cash flow hedge 14.2 6.6 Gas swaps – cash flow hedge 72.2 (49.5) Gas collars – cash flow hedge 64.3 (81.2) FX forwards – cash flow hedge 12.1 0.2 FX forwards – non-cash flow hedge 0.5 (7.5) FX collars – cash flow hedge 38.9 (6.9) FX collars – non-cash flow hedge 10.9 – Cross currency interest rate swaps – cash flow hedge (5.2) – 242.4 (118.5) Notes to the condensed consolidated financial statements continued
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42ITHACA ENERGY PLC Q3 REPORT 2025 19. Derivative financial instruments continued Maturity analysis of derivative financial instruments 30 September 2025 $m 31 December 2024 $m Non-current assets 117.8 – Current assets 137.0 33.0 Non-current liabilities (2.7) (21.0) Current liabilities (9.7) (130.5) 242.4 (118.5) Derivative financial instruments that are with counterparties included within the RBL are subject to Master Netting Agreements, this includes the majority of the Group’s derivative financial instruments as at 30 September 2025 and 31 December 2024. The terms of the Master Netting Arrangements create a legally enforceable right of offset that comes into effect only on the occurrence of a specified event of default or termination event or other events not expected to happen in the normal course of business. Although the Group has the ability to net settle certain transactions with certain counterparties where an election has been made, this is not considered to be significant at 30 September 2025 or 31 December 2024. Accordingly, the Group has not offset any derivatives balances in the statement of financial position in any of the periods presented. 20. Related-party transactions The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey), which owns 50.5% (31 December 2024: 52.2%) of the issued share capital of Ithaca Energy plc. The registered office address of DKL Energy Limited is 47 Esplanade, St Helier, JE1 0BD, Jersey. Eni UK Limited, an indirect wholly owned subsidiary of Eni S.p.A., owns 35.9% (31 December 2024: 37.2%) of the issued share capital of Ithaca Energy plc. Transactions between the company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note. There have been no significant changes to related party transactions since 31 December 2024, with the exception of: • Amounts owed to related parties decreased, on an undiscounted basis, by $130.0 million of deferred consideration payments made in Q1 2025; • Sales to related parties in the nine months to 30 September 2025 amounted to $760.8 million; and • Amounts owed by related parties increased by $29.9 million to $141.5 million at 30 September 2025. Further details of related-party transactions are set out in note 32 of the 2024 Annual Report and Accounts. The ultimate parent of the Group is Delek Group Limited (incorporated in Israel), an independent E&P Company listed on the Tel Aviv Stock Exchange. There were no related-party transactions with Delek Group Limited in either the period ended 30 September 2025 or the period ended 30 September 2024. 21. Subsequent events On 1 October 2025, the Group completed the acquisition of 46.25% of Spirit Energy’s interest in the Cygnus field for an initial consideration of £115 million thereby increasing the Group’s working interest in Cygnus from 38.75% to 85.0%. On 19 November 2025 the Group expects to announce the signing of a farm-in agreement with Shell UK for a 50% working interest in licences P2629 and P2630, located in the West of Shetland basin, containing the Tobermory discovery. Following the farm-in Shell UK will continue to hold a 50% stake in the Tobermory discovery and act as licence operator. Notes to the condensed consolidated financial statements continued
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43ITHACA ENERGY PLC Q3 REPORT 2025 The Group uses certain performance metrics that are not specifically defined under United Kingdom-adopted International Financial Reporting Standards or other generally accepted accounting principles. These measures are considered to be important as they track both operational and financial performance, and are used to manage the business and to provide an objective comparison to Ithaca Energy’s peer group. These non-GAAP measures, which are presented in the Q3 2025 condensed consolidated financial statements, are set out below. Adjusted EBITDAX: earnings before finance income, finance costs, taxation charges, premium payments on oil and gas derivative contracts, restructuring costs, revaluation gains or losses on financial instruments, depletion depreciation and amortisation, impairment charges on development and production assets, exploration and evaluation expenses and fair value remeasurements of contingent consideration. The Group believes that adjusted EBITDAX is a useful measure for stakeholders because it is a measure closely tracked by management to evaluate the Group’s operating performance and to make financial, strategic and operating decisions, and because it may help stakeholders to better understand and evaluate, in the same manner as management, the underlying trends in the Group’s operational performance on a comparable basis, period-on-period. Adjusted EBITDAX is reconciled to (loss)/profit for the period as follows: Nine months ended 30 September 2025 $m 2024 $m (Loss)/profit for the period (119.1) 134.7 Taxation charge (note 14) 787.2 49.0 Depletion, depreciation and amortisation (note 11) 610.2 372.6 Impairment charges on development and production assets 29.4 104.0 Finance income (7.7) (9.9) Finance costs 194.1 128.1 Premium payments on oil and gas derivative contracts (note 4) 0.2 2.8 Business combination costs – 9.3 Restructuring costs 8.0 – Revaluation gains on financial instruments (note 18) (18.8) (1.8) Exploration and evaluation expenses (note 10) 0.1 6.2 Fair value remeasurements of contingent consideration (note 6) 17.6 (36.5) Adjusted EBITDAX 1,501.2 758.5 Adjusted net income: profit after tax excluding non-cash impairment charges and restructuring costs, the tax effect of these items and one-off, non-cash deferred tax charges arising on changes to EPL. Adjusted net income, which is presented as it eliminates items which distort period-on-period comparisons, is reconciled to (loss)/profit for the period as follows: Nine months ended 30 September 2025 $m 2024 $m (Loss)/profit for the period (119.1) 134.7 Impairment charges on development and production assets 29.4 104.0 Tax credit on impairment charges (12.8) (56.8) Restructuring costs 8.0 – Tax credit on restructuring costs (6.2) – One-off, non-cash deferred tax charge for two-year extension of the 38% EPL rate to 31 March 2030 327.6 – Adjusted net income 226.9 181.9 Non-GAAP measures
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44ITHACA ENERGY PLC Q3 REPORT 2025 Adjusted basic earnings per share (EPS): Adjusted net income divided by average shares for the period of 1,648.4 million (Q3 2024: 1,006.8 million). Nine months ended 30 September 2025 2024 Adjusted basic EPS (cents) 13.8 18.1 Adjusted net debt: consists of amounts outstanding under the RBL facility, senior unsecured loan notes and project capital expenditure facility less cash and cash equivalents, and excludes intragroup debt arrangements or liabilities represented by letters of credit and surety bonds. Adjusted net debt, which excludes accrued interest on borrowings, lease liabilities and unamortised fees, comprises: 30 September 2025 $m 31 December 2024 $m RBL drawn facility (210.0) (150.0) Senior unsecured notes 2029 (750.0) (750.0) Senior unsecured notes 2031 (528.1) – Project capital expenditure facility (150.0) (150.0) Cash and cash equivalents 574.3 165.1 Adjusted net debt (1,063.8) (884.9) Pro forma leverage ratio: adjusted net debt at the end of the period divided by pro forma adjusted EBITDAX for the preceding 12 months including $nil of adjusted EBITDAX generated by the Eni UK businesses prior to acquisition (year to 31 December 2024: including $580.3 million of adjusted EBITDAX from the Eni UK businesses from 1 January 2024 to 2 October 2024). The pro forma leverage ratio is considered to be an important measure as it is indicative of the borrowing potential of the Group. The calculations are as follows: 30 September 2025 $m 31 December 2024 $m Adjusted net debt ($m) 1,063.8 884.9 Pro forma adjusted EBITDAX ($m) 2,147.7 1,985.3 Pro forma leverage ratio 0.50x 0.45x Pro forma EBITDAX1 comprises: 30 September 2025 $m 31 December 2024 $m EBITDAX year ended 31 December 2024 1,405.0 1,405.0 EBITDAX Q3 2025 1,501.2 – EBITDAX Q3 2024 (758.5) – Eni UK EBITDAX – 580.3 2,147.7 1,985.3 1 Pro forma EBITDAX does not include the results of the JAPEX UK business from 1 October 2024 to 6 July 2025. Non-GAAP measures continued
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45ITHACA ENERGY PLC Q3 REPORT 2025 Available liquidity: the sum of cash and cash equivalents on the balance sheet and the undrawn amounts available to the Group using existing approved third-party facilities, excluding letters of credit. Available liquidity is regarded as a key measure as it is indicative of the financial capacity of the Group. Available liquidity comprises: 30 September 2025 $m 31 December 2024 $m Cash and cash equivalents 574.3 165.1 Undrawn borrowing facilities 1,090.0 850.0 Available liquidity 1,664.3 1,015.1 Group free cash flow: net cash flow from operating activities less cash used in investing activities, adjusting for acquisition payments, deferred consideration and cash acquired through business combinations, less bank interest and charges and interest rate swaps. This measure is considered a useful indicator of the Group’s ability to make strategic investments, repay the Group’s debt and meet other payment obligations. Group free cash flow reconciles to net cash flow from operating activities as follows: Nine months ended 30 September 2025 $m 2024 $m Net cash flow from operating activities 1,279.6 792.5 Net cash used in investing activities (655.9) (313.9) Bank interest and charges (73.0) (78.5) Interest rate swaps – (0.6) Group free cash flow 550.7 399.5 Unit operating expenditure: operating costs (excluding over/underlift) including tariff expense but excluding restructuring costs and tanker costs and net of tariff income, divided by net production for the period. This measure is considered a useful indicator of ongoing operating costs and is also used to compare performance between assets. Operating costs for this calculation are as follows: Nine months ended 30 September 2025 2024 Operating costs of hydrocarbon activities ($m) per note 5 640.4 442.3 Less restructuring costs1 ($m) (4.6) – Less tanker costs included within operating costs of hydrocarbon activities ($m) (14.5) (13.8) Less tariff income ($m) (21.2) (12.9) Operating costs used to calculate unit operating expenditure ($m) 600.1 415.6 Production (mmboe) 31.38 14.39 Unit operating expenditure ($/boe) 19.1 28.9 1 Restructuring costs are $8.0 million of which $4.6 million is included within operating costs of hydrocarbon activities and $3.4 million is included within administrative expenses. Non-GAAP measures continued
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46ITHACA ENERGY PLC Q3 REPORT 2025 Other key performance indicators DDA rate per barrel: depletion, depreciation and amortisation charge for the period divided by net production for the period. DDA per barrel was: Nine months ended 30 September 2025 2024 Depletion, depreciation and amortisation ($m) 610.2 372.6 Production (mmboe) 31.38 14.39 DDA ($/boe) 19.4 25.9 Production: total hydrocarbons produced related to Ithaca Energy’s equity in operated and non-operated fields divided by the number of days in the period. Production YTD 2025 was 114,928 boe/d (YTD 2024: 52,501 boe/d). Tier 1 and 2 process safety events: process safety incidents as defined by API 465 Process Safety-Recommended Practice On Key Performance Indicators. There were no Tier 1 or 2 process safety events recorded in YTD 2025 (YTD 2024: 0). Serious injury and fatality frequency: the number of serious injuries resulting in permanent impairment, as defined by IOGP, per million hours worked. There were no such incidents in YTD 2025 (YTD 2024: 0). Non-GAAP measures continued