Interim report
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RNS Number : 9366TEnergean PLC09 September 2026 Energean plc("Energean" or the "Company") Results for the Half Year Ended 30 June 2026 London, 9 September 2026 - Energean plc (LSE: ENOG, TASE: אנאגis pleased to announce its half-year results for the six months ended 30 June 2026 ("H1 2026"). Highlights: · Strong recovery since the re-start of production in Israel and increase in liquids revenues.· Reduction in net debt and cash cost of production and increase in free cash flow.· As operator, Energean has commissioned the second oil train, completed the first Katlan heavy-lift and drilled and completed two deepwater development wells.· Egypt concession merger terms agreed, enhancing cash flow and unlocking new growth opportunities.· ~$1.4 billion new GSPA signed with Sorek, demonstrating gas demand growth in Israel. Mathios Rigas, Chief Executive Officer of Energean, commented: "Energean has entered the second half of 2026 from a position of real strength. Free cash flow rose 35% year-on-year to $250 million in H1 2026, profit after tax increased 45% to $160 million, and net debt fell by $97 million in Q2 2026, all while we are in the peak year of investment for Katlan. Group production reached levels over 180 Kboe/d in August[1] following the restart of production in Israel, and we remain on track to deliver full year guidance of 130-140 Kboe/d[2]. "Operationally, our teams in the year so far have delivered three major milestones in parallel: commissioning the second oil train on the Energean Power FPSO, which lifted liquids processing capacity by 72%; completing the first Katlan heavy-lift campaign; and drilling and completing two Katlan deepwater development wells, marking progress on the critical path towards first gas from the Katlan project in H1 2027. "In Egypt, the payment environment has improved markedly, with our net receivables now at their lowest level since 2020. We have agreed the principal terms with EGPC to consolidate our Abu Qir, North El Amriya and North Idku concessions into a single concession with improved fiscal terms. It is under these new terms that we will invest an initial $150 million over the next four years with a target to double production and reserves. It also unlocks new exploration acreage, estimated to contain >4 Tcf[3] of exploration potential. "We are also laying the foundations for future growth through a new ~$1.4 billion gas sales and purchase agreement ("GSPA") with Sorek, continued progress on key milestones at Irena in Croatia and the Nitzana export pipeline, which remain on track respectively for first gas in H1 2027 and completion in late 2028, and preparations for exploration drilling at Block 2 in Greece with ExxonMobil, which is due to begin in Q2 2027. We also remain disciplined and focused on delivering transformational growth across EMEA, concentrated on those that strengthen and diversify our production base, enhance cash flow generation and support deleveraging." Financial results summary H1 2026EnergeanGroup H1 2025EnergeanGroup Increase/(Decrease)% Average daily working interest production (kboed)[4] 124 138 (10%) Total revenue from production activities ($m) 743 804 (8%) Realised weighted average liquid price ($/boe) 79.6 61.6 29% Realised weighted average gas ($/mcf) 4.8 5.2 (8%) Cash cost of production[5] ($m) 259 272 (5%) Cash cost of production per barrel ($/boe) 10.9 10.2 7% Cash G&A[6] 21 21 - Adjusted EBITDAX[7] ($m) 478 505 (5%) Profit after tax ($m) 160 110 45% Earnings per share ($ per share) $0.90 $0.60 50% Cash flow from operating activities ($m) 476 555 (14%) Capital expenditure ($m) 353 297 19% Dividend per share ($ per share) $0.40 $0.60 (33%) H1 2026Energean Group FY 2025Energean Group Total borrowings ($m) 3,548 3,585
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Cash and cash equivalents and restricted cash ($m) 321 330 Net debt ($m) (including restricted cash) 3,227 3,255 Leverage Ratio (Net Debt/ Adjusted EBITDAX)[8] 3.0 2.9 H1 2026 review:Strong recovery since the re-start of production in Israel and increase in liquids revenues · Consistent with previous 2026 updates, performance during the period was impacted by the 41-day government-mandated suspension of production in Israel caused by the regional conflict and lower production from Cassiopea in Italy, resulting in Group average working interest production of 124 Kboe/d[9] (H1 2025: 138 Kboe/d) and sales volumes[10] of 20.17 mmboe (H1 2025: 22.81 mmboe). o Production has subsequently recovered strongly, with 8-months 2026 production averaging 135 Kboe/d, in line with full-year guidance of 130-140 Kboe/d[11], supported by robust August standalone production, which reached levels over 180 Kboe/d during the month[12]. · Total revenue from production activities was $743 million (H1 2025: $804 million) and adjusted EBITDAX was $478million (H1 2025: $505 million). The reduction in sales volumes was partly offset by a 29% increase in realised liquids prices, which drove a 14% year-on-year increase in liquids revenues to $267 million[13] (H1 2025: $234 million).· Profit after tax was $160 million, up 45% year-on-year (H1 2025: $110 million), reflecting a lower effective tax rateprimarily driven by the recognition of previously unrecognised deferred tax assets in Italy. Egypt concession merger terms agreed, enhancing cash flow and unlocking new growth opportunities· Post-period end, Energean reached agreement with EGPC on the principal concession terms to consolidate its Abu Qir, North El Amriya and North Idku concessions into a single concession, subject to parliament ratification.· The new concession terms include enhanced fiscal terms and improved gas pricing, which are expected tostrengthen project economics and increase long-term cash flow generation. · Energean will commit an initial $150 million of near-field development and exploration investment over a four-yearperiod, which, subject to exploration success, could add up to 50 mmboe in aggregate and double production over the following decade. It also unlocks new exploration acreage, estimated to contain >4 Tcf[14], which includes approximately 3 Tcf of gas in the deep horizon.· The agreement reflects Egypt's increasingly supportive operating environment, including record-low receivableslevels and continued government backing for upstream investment, and reinforces Egypt as a core country within Energean's Mediterranean portfolio. Executing the next phase of organic growth · Demonstrating continued strong domestic gas demand in Israel, Energean signed a ~$1.4 billion GSPA with Sorekpost-period for the supply of gas to its new H-class power station. The agreement is for the supply of up to 0.5bcm/yr from late 2029, increasing to up to 0.6 bcm/yr from September 2035 and includes interruptible volumes during the summer months between late 2029-2035. The contract contains floor pricing, take-or-pay and priceindexation provisions.· Production and development capital expenditure was $350 million (H1 2025: $299 million) and up 17% year-on- year, reflecting the peak year of expenditure on the Katlan project.o Significant progress was made on the Katlan development across drilling, subsea and FPSO upgrade workstreams during the period, with first gas on track for H1 2027. Expenditure on Katlan totalled $267 million[15] during the period, bringing cumulative spend to just over 60% of the $1.2 billion FinalInvestment Decision ("FID") amount.o Commissioning of the second oil train project was safely completed post-period end, increasing liquids handling capacity from 18 kbbl/d to 31 kbbl/d.o The Nitzana export pipeline and Irena development continue to advance on schedule and on budget towards their targeted completion and start-up milestones in late 2028 and H1 2027, respectively. · Exploration activities continued to advance, with drilling underway on the East Bir El-Nus ("EBEN") exploration wellin Egypt and preparations ongoing for the Block 2 exploration well with ExxonMobil in Greece, the latter which is expected to spud in Q2 2027 and is targeting ~9.5 Tcf of gross Pmean GIIP[16]. Inorganic growth opportunities under active review· The Group is actively assessing growth opportunities across the EMEA region, including in its existing countries of operations. · Energean's M&A strategy remains focused on long-term growth and diversification, underpinned by strict capitaldiscipline, an intention to reduce leverage over time and a focus on enhancing cash flow generation and shareholder returns. · During the period, the Group announced the proposed acquisition of interests in certain offshore Angola assets. In August 2026, the Group was notified that Etu Energias had executed a sale and purchase agreement pursuant to itscontractual pre-emption rights with respect to the Group's proposed acquisition of Chevron's interests in Blocks 14and 14K, offshore Angola. As of the time of writing, the sale and purchase agreement between Energean and Chevron remains in effect until the sale and purchase agreement between Chevron and Etu Energias has beencompleted. Reduction in net debt and Cost of Production and increase in free cash flow · Cash cost of production[17] was $259 million (H1 2025: $272 million), down 5% year-on-year, primarily reflectinglower production-related operating expenditure in Israel. Excluding royalties, operating costs were $162 million (H1 2025: $175 million).
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· Cash flow from operating activities was $476 million (H1 2025: $555 million), down 14% reflecting the operationalimpacts described above, somewhat offset by strong collection of trade receivables in Egypt, whereby net receivables (after provision for expected credit loss) reduced to $75 million as at 30 June 2026; the lowest balancerecorded since Energean acquired the Edison E&P portfolio in 2020. · Free cash flow[18] of $250 million (H1 2025: $185 million), up 35%, as lower cash capital expenditure of $250 million (H1 2025: $385 million) offset the reduction in cash flow from operating activities.· Total liquidity of $404 million at 30 June 2026, comprising cash and cash equivalents and restricted cash of $321million and $83 million of available liquidity facilities. Total liquidity increased by $114 million since 31 March 2026 ($290 million), reflecting higher cash balances.· Net debt of $3,227 million, down $28 million since 31 December 2025 ($3,255 million) and $97 million since 31March 2026 ($3,325 million), reflecting lower total borrowings. Leverage was 3.0x at 30 June 2026 (31 December 2025: 2.9x; 31 March 2026: 3.2x), with the increase versus year-end reflecting lower adjusted EBITDAX for thereasons outlined above. Outlook:· All full year 2026 guidance re-iterated (refer to '2026 guidance' table below), except for exploration anddecommissioning expenditure, both of which have been reduced. o Strong post-period production performance, supported by the contribution of the second oil train, reinforces management confidence in delivering full year 2026 guidance. · Q2 2026 dividend of 10 US cents/share declared today and expected to be paid on 30 September 2026. · Energean expects to refinance its 2028 Energean Israel Limited bond and is evaluating a range of options.· Parliamentary ratification of the Egypt concession merger expected by mid-2027, with the new concession termstargeted to become effective on 1 January 2027. · First gas from Katlan in H1 2027. · Commencement of Block 2 drilling in Greece in Q2 2027, targeting ~9.5 Tcf of gross Pmean GIIP[19].· Active pipeline of transformational M&A opportunities under evaluation in the EMEA region, including within its existing countries of operations, to support long-term growth, underpinned by strict capital discipline. Online Results Presentation Management will host a live online presentation today at 08:30 BST / 10:30 IDT. Registration details can be accessed via thefollowing link: https://energean-hy-2026-results.open-exchange.net/. The presentation slides will be published on Energean's website at www.energean.com ahead of the live event. A replay ofthe webcast will be available after the event. Enquiries For capital markets: Kyrah McKenzie, Investor Relations Manager Tel: +44 (0) 7921 210 862 ir@energean.com For media: Adonis Seferlis, CEO Office Communications Manager Tel: +30 (0) 6972 414 262 aseferlis@energean.com Ben Brewerton, FTI Consulting Tel: +44 (0) 2037 271 065 energean@fticonsulting.com Operational ReviewHealth, Safety and the Environment Effective from January 2026, the Group expanded the scope of its Health and Safety KPI reporting. In addition to employeesand contractors at Energean-operated sites and premises in Israel, Italy and Greece, the reporting boundary now includes:the AQP Joint Venture ("JV") in Egypt, the Edina JV in Croatia, the Alba Marina and Leonis Floating, Storage and Offloading ("FSO") vessels in Italy, and the Energean Star Floating Storage Vessel ("FSV") in Israel. Comparative H1 2025 metrics havebeen restated accordingly. In H1 2026, the Lost Time Injury Frequency ("LTIF") Rate was 0.00 (H1 2025: 0.408) and the Total Recordable Incident Rate("TRIR") was 0.242 (H1 2025: 0.408), an improvement versus the prior year and well below the Group's full year targets of<0.55 and <1.10. Scope 1 and 2 emissions intensity on an equity share basis was 8.1 kgCO2e/boe, down 2% year-on-year (H1 2025: 8.3 kgCO2e/boe)due primarily to lower levels of non-routine flaring. Production and Operational UpdateSummary Group average working interest production[20] was 124 Kboe/d (83% gas) in H1 2026, down 10% year-on-year. This was largely driven by two factors: (1) the temporary suspension of production in Israel for 41 days between 28 February and 9 April 2026, following adirective from the Ministry of Energy and Infrastructure due to geopolitical escalations and (2) Cassiopea performance (refer to the'Europe' section below). Output from Israel was subsequently restored and Group production averaged 135 Kboe/d in the eight months to 31 August 2026, in line with the Group's full year 2026 production guidance of 130-140 Kboe/d[21], exceeding levels of 180 Kboe/d in August 2026[22].
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H1 2026Kboe/d H1 2025Kboe/d % change 8-months to31 August 2026Kboe/d Israel 87 (inc. 2.13 bcm ofgas) 94 (inc. 2.29 bcm ofgas) (7%) 98(inc. 3.19 bcm ofgas) Rest of portfolio1 37 (inc. 27 in Egypt) 44 (inc. 29 in Egypt) (16%) 37 (inc. 27 in Egypt) Total production1 124 138 (10%) 135 This table may not cast due to rounding. Israel ProductionIn H1 2026, production from Israel averaged 87 Kboe/d (88% gas), 7% down year-on-year (H1 2025: 94 Kboe/d). Productionwas impacted by the temporary suspension of operations for 41 days between 28 February and 9 April 2026, following a directive from the Ministry of Energy and Infrastructure in response to regional geopolitical developments. Excluding thisperiod of mandated shutdown, production averaged 112 Kboe/d, in line with the Group's original full year 2026 productionguidance range for Israel of 108-114 Kboe/d. FPSO uptime (excluding planned shutdowns and Ministry ordered suspensions) averaged 99% for the 6-months to 30 June2026 (H1 2025: 97%). Gas salesDuring H1 2026, Energean sold 2.13 bcm of gas into the domestic Israeli market, compared with 2.29 bcm in H1 2025. Of this, 1.97 bcm was sold under its long-term gas sales agreements (H1 2025: 2.21 bcm) and 0.16 bcm was marketed throughspot sales (H1 2025: 0.08 bcm). Post-period end, in September 2026, Energean Israel Limited ("Energean Israel") signed a new GSPA with Sorek EnergyPower Plant Ltd ("Sorek"). The contract is for the supply of gas to Sorek's new H-class power station, which is estimated to beoperational in late 2029. Sorek is a nationally significant energy infrastructure project, aligned with a government resolution to expand natural gas-based generation capacity in response to Israel's expected growth in electricity demand. The GSPA is for a term of ~15 years for a total contracted quantity of up to ~7.7 bcm, representing ~$1.4 billion in revenues over the life of the contract. The GSPA is for the supply of up to 0.5 bcm/yr once the new power station is operational,expected from late 2029, rising to up to 0.6 bcm/yr from September 2035 onwards, and includes interruptible volumesduring the summer months between late 2029-2035. The contract contains provisions regarding floor pricing, take-or-pay and price indexation and has been signed at terms in line with Energean's other large, long-term gas contracts. The agreement completes Energean's contracting of the three major new power generation projects expected to come online in Israel around the end of the decade. Alongside Kesem and Dalia II, the contracts add more than ~$5 billion of futurecontracted revenues, further strengthening the Company's contracted cash flow profile. Energean continues to evaluateadditional long-term domestic gas contracts in Israel, supporting the commercialisation of future gas volumes within an increasing local demand environment. Liquids sales During H1 2026, Energean sold 1.88 mmbbl of hydrocarbon liquids through four cargoes, compared with 2.06 mmbblthrough four cargoes in H1 2025. Liquids revenues increased to $156 million (H1 2025: $137 million), reflecting a 24%increase in realised liquids pricing to $82.9/bbl (H1 2025: $66.6/bbl), which offset lower year-on-year sales volumes. Post-period end, on 13 July 2026, Energean safely completed commissioning of the second oil train on its Energean PowerFPSO. This has expanded the total liquids processing capacity from 18 kbbl/d to 31 kbbl/d and further increased the proportion of the Company's revenues linked to Brent pricing. Liquids production has been tested at rates of up to 25 kbbl/d, representing a 160% increase compared with the H1 2026 average of 10 kbbl/d[23]. DevelopmentKatlan phase 1AEnergean's deepwater Katlan project (working interest ("W.I.") 100%; operator) remains on budget and on schedule to deliver first gas in H1 2027. The project has made significant progress during 2026, with key milestones achieved to dateincluding:· Subsea infrastructure: The first two of four offshore installation campaigns have been successfully completed, including installation of the ~30 km production pipeline system, ~25 km Monoethylene Glycol ("MEG") flowline, andproduction riser. All major in-line subsea infrastructure has also been installed. The remaining subsea infrastructureis scheduled to be fully installed by around the end of 2026. · Production wells: Drilling and completion activities for the Athena and Zeus production wells commenced duringthe period and completed in September 2026.· FPSO upgrades: Post-period end, the Inlet Heaters Module (M01) and associated E-House (M09) were safely lifted onto the Energean Power FPSO. These modules are key components of the FPSO modifications required for theKatlan development and to support first gas in H1 2027. Integration and commissioning activities for these modulesare ongoing. Remaining FPSO upgrade activities comprise installation of the MEG Reclamation Unit (M04) and FiredHeaters Module (M06), currently planned for 2027 and are not required to achieve first gas. 2027 growth drilling programme and Katlan Phase 1BDuring the period, Energean advanced planning for Katlan Phase 1B, which will develop the Hera and Apollo fields on the Katlan lease. A rig contract was signed with Stena Drilling Limited for Energean's 2027 growth drilling programme, whichincludes the Hera and Apollo development wells for Katlan Phase 1B, as well as the Karish North-02 development well on theKarish and Karish North lease. In addition, Energean progressed planning and procurement activities for Phase 1B; post- period end, Energean signed a Letter of Award with TechnipFMC UK for the Phase 1B subsea installation scope. Nitzana export pipeline
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The Nitzana export pipeline is a new onshore pipeline that will connect Ramat Hovav to the border with Egypt in the Nitzanaarea. Energean has signed a transmission agreement securing capacity for the supply of up to 1 bcm/yr over a 15-year period. Nitzana is expected to be operational in late 2028. During H1 2026, $10 million was incurred, bringing cumulative investments since the signing of the transmission agreement in Q4 2025 to around 60% of the total expected investment. The remaining investment will be made in accordance with themilestones set out in the agreement with INGL. Energean has signed a non-binding term sheet with an East Mediterraneanclient for the offtake of its exported gas. EgyptEgypt is a core country within Energean's portfolio and a priority growth market, supported by its significant resource potential and the country's strategic focus on increasing domestic energy production to strengthen energy security. Production Working interest production from Egypt averaged 27 Kboe/d (85% gas) during the period (H1 2025: 29 Kboe/d), reflectingsuccessful mitigation of typical natural decline through production optimisation activities. No new production drillingactivities were undertaken during the period while concession merger negotiations were ongoing. ReceivablesThe Group's net receivables position (after provision for expected credit loss) at 30 June 2026 was $75 million, of which $25 million was classified as overdue. This represents a 64% reduction compared to 31 December 2025 ($209 million, of which$167 million was classified as overdue), reflecting collections of $226 million during the period. As a result, receivables havefallen to their lowest level since Energean acquired the Edison E&P portfolio in 2020. Growth opportunitiesConcession merger Post-period end, Energean reached an agreement with EGPC on the main concession terms to consolidate its Abu Qir, NorthEl Amriya and North Idku concessions into a single concession, subject to concession agreement finalisation andparliamentary ratification. The new concession framework provides improved fiscal and commercial terms, including enhanced gas pricing, extendingthe economic life of existing assets and improving long-term cash flow generation. As a result, Energean has committed to invest up to an initial $150 million across production optimisation, development and exploration activities over a four-yearperiod, which, subject to exploration success, could add up to 50 mmboe and double production over the following decade. It also unlocks exploration acreage, estimated to contain >4 Tcf[24], which includes approximately 3 Tcf[25] of gas in the deephorizon. The commitment follows a period of tangible improvement in the Egyptian operating environment, including materiallyimproved receivables collection as outlined above and continued support from the Egyptian authorities for upstream investment. Egypt remains a structurally attractive gas market, with growing demand and an increasing focus on maximisingindigenous production to enhance energy security. Through the merger, Energean believes it can generate greater value from its existing asset base, accelerate the developmentof additional resources and deliver attractive cash flow growth while supporting Egypt's long-term energy objectives. ExplorationExploration drilling on the onshore East Bir El-Nus block ("EBEN") (Energean: 50% W.I. operator, INA: 50% W.I.), targeting 5- 10 mmbbl[26] of oil in the Gamma prospect, commenced in July 2026 and is progressing as planned. Operations to date have been executed safely with no incidents or environmental events recorded. Well results are expected towards the end ofSeptember 2026. EuropeProductionEnergean is focused on maximising value from its European portfolio (Italy, Greece, the UK and Croatia), which has access to European gas and Brent pricing. During H1 2026, working interest production averaged 10 kboed[27] (38% gas; H1 2025: 14kboed) down 29% due primarily to Cassiopea, reflecting non-operated asset underperformance. ItalyEnergean has 36 production and development concessions in Italy, 13 of which it operates. During H1 2026, working interestproduction averaged 9 kboed (including Cassiopea; 43% gas). 53% of Italian output was generated from the Rospo Mare, Vega and Sarago Mare oil fields, all of which are operated by Energean with a 100% working interest. Higher realised liquidsprices, up 38% year-on-year, supported a 28% year-on-year increase in oil revenues during the period. In 2025, formal arbitration proceedings commenced between Energean Italy S.p.A. ("Energean Italy") and the Operator ofthe Cassiopea field. As a consequence of the operator's conduct - which is contested by Energean Italy - Energean Italy hasnot received production from the field during H1 2026 (refer to Note 25 to the interim consolidated financial statements). No other material developments occurred during the period and the arbitration remains ongoing. Croatia The Irena development (Energean, 70% W.I.) remains on schedule and on budget, with first gas expected in H1 2027.Fabrication of the new ~10-kilometre sales pipeline has been completed, with offshore installation scheduled for lateSeptember 2026. Jacket erection and topside assembly for the new offshore platform are progressing in Italy, with offshore installation expected in October 2026. Preparations for the offshore drilling campaign have also advanced, with the Labinjack-up rig secured to drill the Irena-3 development well from the new platform following installation, with drilling expectedto commence towards the end of 2026. The rig is then expected to continue directly to the Izabela-9 exploration well, targeting approximately 25 Bcf of near-field gross gas prospective resources[28].
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UK Subsequent to period-end, the Garrow and Kilmar platform topsides and jackets were successfully removed and lifted ontoPetrodec's OBNA jack-up vessel as part of Energean's operated UK decommissioning programme. The removal campaign,covering 3,373 tonnes of topside and jacket infrastructure, was completed safely and in accordance with the approved schedule and budget. Removal of the Wenlock platform is scheduled for October 2026. Greece In March 2026, Energean completed the farm-out of part of its interest in the Block 2 exploration licence to ExxonMobil,recognising $11 million of other operating income. The Group subsequently signed a rig contract with Stena Drilling for its2027 growth drilling programme, which includes the Block 2 exploration well which is targeting ~9.5 Tcf of gross Pmean GIIP[29]. Energean will remain operator during the exploration phase, with exploration drilling anticipated to begin in Q22027. 2026 Guidance[30],[31] FY 2026 Production Israel (kboed) 98 - 104[32] Rest of portfolio (kboed) 32 - 36 Total production (kboed) 130 - 140 Cash Cost of Production (operating costs plus royalties) Israel ($ million) 310 - 330 (includes 190 - 205 royalties) Rest of portfolio ($ million)[33] 200 - 220 (includes 10-15 royalties and 30-35 of flux in Italy) Total Cash Cost of Production ($ million) 510 - 550 (includes 200 - 220 royalties) Cash G&A ($ million) 35 - 40 Development and production capital expenditure Israel ($ million) 700 - 750 Rest of portfolio ($ million)[34] 100 - 110 Total development & production capital expenditure ($ million) 800 - 860 Exploration expenditure ($ million) 5 - 10 (previously 10 - 15) Decommissioning expenditure ($ million) 40 - 50 (previously 50 - 60) Consolidated net debt ($ million) 3,250 - 3,350 Financial Review Revenue, production and commodity prices Group working interest production averaged 124 Kboe/d[35] in H1 2026, 10% lower than H1 2025 (138 Kboe/d), with Israelcontinuing to represent more than 70% of total output. The reduction primarily reflects a temporary, government-mandatedsuspension of production in Israel between 28 February and 9 April 2026, following geopolitical escalations in the region.Production resumed promptly following the restart, with June output running ahead of budget as the field ramped back up. Excluding the impact of the government-mandated shutdown days in both periods, average working interest production was3% higher in H1 2026 than H1 2025 (149 Kboe/d vs 144 Kboe/d). Refer to the "Production and Operational Update" sectionabove for further details. The production mix remained broadly consistent at 83% gas and 17% liquids (H1 2025: 84% gas, 16% liquids). Overall, Group gas production was 10% lower and liquids production 6% lower than in the first half of 2025. Group revenue and other income from production activities totalled $743 million, 8% below H1 2025 ($804 million), as lower volumes in Israel as a result of the temporary suspension of production were partially offset by the stronger pricingenvironment across the portfolio. Israel represented approximately 65% of Group revenue (H1 2025: 60%), while Italy'scontribution reduced to approximately 19% (H1 2025: 25%), mainly reflecting a reduction in underlying Cassiopea production volumes year-on-year. Liquids sales performed strongly, totalling $267 million (H1 2025: $234 million), driven by a materially higher weighted average realised liquids price of $79.6/bbl (H1 2025: $61.6/bbl), reflecting elevated Brent pricing during the period. Thismore than offset the lower liquids volumes in Israel arising from the temporary suspension. Reflecting the Group's activemanagement of Brent price exposure, a gain of $2 million was recognised on Brent hedge positions closed during the period. By contrast, the weighted average realised gas price was $4.8/mcf, 8% lower than in H1 2025 ($5.2/mcf). This reflected a shiftin the sales mix towards Israel, where realised gas prices are lower, and away from Italy, where PSV prices were broadly stable at €44.1/MWh (H1 2025: €43.6/MWh). Group gas revenue declined 21% to $429 million, primarily reflecting lowervolumes in Israel. In Italy, reported gas revenue also declined, though this partly reflects a presentational change: Cassiopeagas entitlement, previously recognised within gas revenue, is now recognised as other income from production activities under the non-cash settlement mechanism used while the dispute with the field operator remains ongoing. On a combinedbasis (gas revenue plus other income), total Italy production-related income decreased by $63 million year-on-year, reflectinglower underlying Cassiopea production volumes. Cash production costs
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Total cash production costs (including royalties) for the period decreased to $259 million (H1 2025: $272 million), with Israelaccounting for 54% of the total costs. Excluding Israel, costs reduced to $118 million (H1 2025: $123 million), reflecting lower transportation, treatment, and royalty costs in Italy associated with reduced Cassiopea production volumes. Group unit costsincreased to $10.9/boe (H1 2025: $10.2/boe), as lower production volumes in both Israel and Italy resulted in the Group'scost base being spread over a smaller production base. As outlined in note 5, royalties in Italy and Israel remain a significant component of production costs. Excluding royalties, production costs were $162 million (H1 2025: $175 million), equating to$6.6/boe (H1 2025: $6.4/boe). Despite the reduction in production volumes, the Group maintained strong cost disciplinedemonstrating the Group's ability to flex its cost base in response to lower throughput. Adjusted EBITDAX Adjusted EBITDAX of $478 million was 5% below H1 2025 (H1 2025: $505 million). Higher realised oil prices supportedgrowth in Israel and Egypt. This was more than offset by a $37 million decline in Italy, reflecting the Cassiopea performance discussed above. The rest of the Group was broadly stable in aggregate. Depreciation Depreciation on production and development assets remained broadly consistent compared to the prior year at $189 million in H1 2026 (H1 2025: $194 million). Exploration and evaluation expenditure and new ventures During the period, the Group expensed $7 million (H1 2025: $4 million) for exploration and new venture evaluation activities reflecting the Group's ongoing assessment of growth opportunities. As with prior periods, this spend relates toearly-stage technical, commercial, and due diligence work on a number of prospects, none of which are committed at thisstage. Other income The Group recognised $11 million of other operating income from the Block-2 (Greece) farm-out to ExxonMobil, whichcompleted in March 2026. An exploration well is planned on the block in Q2 2027, subject to permitting. Separately, the Group recorded $2 million of net reversals, including a $1 million reversal of a provision relating to tax litigation in Italy,with the remainder comprising minor releases of prior period accruals no longer required across other jurisdictions. Other operating expenses Other expenses were $1 million (H1 2025: $1 million), with the increase not material in relation to the Group's overall costbase. Expected credit loss A net expected credit loss reversal of $4 million (H1 2025: charge of $2 million) was recognised, reflecting an improvement inthe cash collection environment in Egypt, where the Group's principal counterparty is the state owned Egyptian GeneralPetroleum Corporation ("EGPC"). During H1 2026, EGPC made payments recovering approximately 75% of the aggregate opening receivable balance as at 31 December 2025 and sales recognised during the period, resulting in a significantreduction in the receivable balance subject to expected credit loss and a corresponding reduction in the allowance. Net finance costs Total finance costs in H1 2026 remained stable at $121 million (H1 2025: $128 million) reflecting the higher level of interestcapitalised in Israel for Katlan and Nitzana projects. Total financing costs before capitalisation were $154 million (H1 2025: $144 million), mainly comprising $83 million in interest expense on Senior Secured notes, $46 million on debt facilities, and$21 million from the unwinding of discounts on long-term payables and decommissioning provisions. Net finance costs alsoreflect net foreign exchange gain of $6 million comprising a foreign exchange loss in Israel, mainly on the ILS-denominated portion of the Bank Leumi loan, offset by a gain at plc level on the EUR-denominated bond against the US dollar. Separately,the Group recorded finance income of $3 million, which includes interest income from time deposits. Net gain on derivatives The net gain on derivatives recognised in profit or loss was not material for H1 2026 (H1 2025: $3 million loss) as the Group's other hedging activity during the period was recognised within other financial statements line items, consistent with thenature of the underlying hedged item. Taxation The Group had a tax expense of $19 million in H1 2026 (H1 2025: $64 million), on a profit before tax of $178 million (H12025: $174 million), giving an effective tax rate of 11% (H1 2025: 37%). The reduction in the effective tax rate compared to H1 2025 was driven primarily by the recognition of $26 million of previously unrecognised deferred tax assets in Italy, relatingto decommissioning provisions reflecting the current expectations of the forecast taxable profits. Following a reassessmentof recoverability at H1 2026, the Group concluded that sufficient forecast taxable profits are now expected to be available against which these temporary differences can be utilised. The current tax expense includes $26 million of tax expense in Israel (H1 2025: $29 million), a slight decrease reflecting reduced profitability of the Karish and Karish North operations following the temporary suspension of production at theEnergean Power FPSO during the period. Egypt non-cash taxes of $17 million (H1 2025: $13 million) continued to be asignificant component of the current tax charge. The Group remains within the scope of the Pillar Two Model Rules from 1 January 2025 and has applied the mandatorytemporary exception under IAS 12 from recognising and disclosing deferred taxes related to Pillar Two income taxes. There has been no change to the Group's assessment since 31 December 2025, and, including consideration of transitional safeharbour provisions, the Group does not expect a material exposure to Pillar Two top-up taxes. Accordingly, no current taxexpense in respect of Pillar Two top-up taxes has been recognised in the period.
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Profit after tax and earnings per share Profit before tax of $178 million was broadly consistent compared to the prior year (H1 2025: $174 million), as a netforeign exchange gain and lower finance costs largely offset the impact of lower revenue. Profit after tax was $160 million(H1 2025: $110 million), reflecting the lower effective tax rate discussed above, primarily driven by the recognition of previously unrecognised deferred tax assets in Italy. In H1 2026, basic earnings per share was $0.90 (H1 2025: $0.60). The increase is broadly in line with the growth in profit after tax, with the weighted average number of shares outstanding remaining largely unchanged period on period. Operating cash flow In H1 2026, the Group generated net operating cash inflows of $476 million compared with $555 million in H1 2025.Cash flow from operations before working capital movements was $452 million (H1 2025: $518 million). Working capitalmovements contributed a net inflow of $49 million (H1 2025: $148 million), including a reduction in trade and other payables, principally in Italy and Egypt, largely offset by strong collection of trade receivables, including recovery of historicalamounts due from EGPC in Egypt in addition to receipts in respect of ongoing sales. Income tax paid in the period was $25million (H1 2025: $111 million), with the prior period reflecting settlement of a significant element of Israel's 2024 tax liability in addition to payments relating to H1 2025 operations. Capital Expenditures Development capital expenditures totalled $350 million in the period (H1 2025: $299 million), primarily directed towards development projects in Israel ($301 million mainly related to the Katlan development and the Nitzana project, furtherdetails are available in the "Israel" section above) and Croatia ($14 million related to Irena development). Exploration andappraisal spend in H1 2026 was minimal ($3 million), reflecting some minor exploration activities in Israel and Egypt. The Group continued to hedge foreign currency exposure on payments due under the Katlan Engineering, Procurement,Construction and Installation ("EPCI") contract. Positions that matured during the period delivered a $7 million gain, which reduced the reported cost of the related capital expenditure, reflecting the benefit of the Group's hedging programme inlocking in favourable exchange rates. Decommissioning provision During the period, the decommissioning provision decreased by $16 million due to the updates to decommissioning costestimates and revision of other relevant assumptions such as discount and inflation rates. A $2 million increase in thedecommissioning provision (H1 2025: $4 million) was expensed during the period, primarily relating to Italy, due to a modest increase in the discount rate since year-end across all decommissioning-related assets. A further $11 million decrease indecommissioning provision, principally relating to Israel and Italy, was recognised as a reduction to the carrying value of therelated property, plant and equipment. In H1 2026, the Group invested $4 million in decommissioning works, comprising $1 million for the Wenlock and Torsprojects in the UK, and $3 million in Italy, primarily for the Candela and Squalo Fratello Nord projects. Net debt As at 30 June 2026, net debt was $3,227 million (FY25: $3,255 million), consisting of total borrowings of $3,548 millionincluding deferred amortised fees, offset by total cash of $321 million, including $6 million of restricted cash. Total borrowings include the following drawn amounts:· $2,000 million in Israeli senior secured notes; · €400 million in corporate senior secured notes;· €90.5 million from the Greek Black Sea Trade and Development Bank (BSTDB) loan and €9.5 million in Greek stateloan notes (both equivalent to $115 million); · $475 million and ILS 942 million (both equivalent to $750 million) drawn from Bank Leumi under the term loanagreement; and· $246 million in other borrowings including under the corporate RCF. Energean's floating interest rate exposure is limited to certain arrangements, namely the Greek BSTDB loan, the $750 millionBank Leumi term loan, the corporate RCF and other short-term bilateral agreements. All Senior Secured Notes, including both at Energean Plc and Energean Israel, carry fixed interest rates. Shareholder Distributions Energean returned $0.40 per share to shareholders in H1 2026, totalling $74 million, representing two-quarters of dividend payments. In H1 2025, Energean returned $0.60 per share. Non-IFRS measures The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include adjusted EBITDAX, underlying cash cost of production and G&A,capital expenditure, net debt and leveraging. Adjusted EBITDAX Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, share-based paymentcharge, impairment of property, plant and equipment, other income and expenses, net finance costs and exploration costs.The Group presents adjusted EBITDAX as it is used in assessing the Group's growth and operational efficiencies because it illustrates the underlying performance of the Group's business by excluding items not considered by management to reflectthe underlying operations of the Group.
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H1 2026Energean Group H1 2025Energean Group $m $m Adjusted EBITDAX 478 505 Reconciliation to profit for the period: Depreciation and amortisation (189) (194) Share-based payment charge (4) (4) Exploration and evaluation expenditure and new ventures (7) (4) Increase in decommissioning provision (2) (4) Reversal of / Expected credit (loss) 4 (2) Other income, net 11 32 Finance income 3 3 Finance cost (121) (128) Net gain / (loss) on derivatives - (3) Net foreign exchange loss 6 (27) Taxation (expense) (19) (64) Profit for the period 160 110 Cash cost of production Cash cost of production is a non-IFRS measure that is used by the Group as a useful indicator of the Group's underlying cashcosts to produce hydrocarbons. The Group uses the measure to compare operational performance period-to-period, tomonitor cost and assess operational efficiency. Cash cost of production is calculated as cost of sales, adjusted for depreciation and hydrocarbon inventory movements. H1 2026Energean Group H1 2025Energean Group $m $m Cost of sales 429 469 Adjusted for: Depreciation (184) (191) Change in inventory 14 (6) Cash cost of production 259 272 Total production for the period (kboe) 22,474 24,913 Adjustment for flux cost (14) (17) Cash cost of production per boe ($/boe) 10.9 10.2 Cash General & Administrative Expense (G&A) Cash G&A excludes certain non-cash accounting items from the Group's reported G&A. Cash G&A is calculated as follows: administrative and distribution expenses, excluding depletion and amortisation of assets and share-based payment chargethat are included in G&A. H1 2026Energean Group H1 2025Energean Group $m $m Administrative expenses 30 28 Less: Depreciation (5) (3) Share-based payment charge included in G&A (4) (4) Cash G&A 21 21 Capital Expenditure Capital expenditure is a useful indicator of the Group's organic expenditure on oil and gas assets and exploration andappraisal assets incurred during a period. Capital expenditure is defined as additions to property, plant and equipment andintangible exploration and evaluation assets less decommissioning asset additions, right-of-use asset additions, capitalised share-based payment charge and capitalised borrowing costs: H1 2026Energean Group H1 2025Energean Group $m $m Additions to property, plant and equipment 350 284 Additions to exploration and evaluation and other intangible assets 15 (2) Less: Capitalised borrowing costs 32 15 Leased assets additions and modifications 4 (37) Lease payments related to capital activities (12) (9) Change in decommissioning provision (11) 17 Total capital expenditures 353 297 Movement in working capital (103) 88 Cash capital expenditures per the cash flow statement 250 385 Net Debt Net debt is defined as the Group's total borrowings less cash and cash equivalents. Management believes that net debtserves as a valuable indicator of the Group's indebtedness, financial flexibility, and capital structure because it reflects the level of borrowings after accounting for any cash and cash equivalents that could be utilised to reduce borrowings. H1 2026Energean Group FY 2025Energean Group $m $m Current borrowings 18 229 Non-current borrowings 3,530 3,356
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H1 2026Energean Group FY 2025Energean Group Total borrowings 3,548 3,585 Less: Cash and cash equivalents (315) (227) Less: Restricted cash held for loan repayment (6) (103) Net Debt 3,227 3,255 Going Concern The Directors assessed the Group's ability to continue as a going concern over a going concern assessment period to 31December 2027. As a result of this assessment, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future and for this reason they continue to adopt the going concern basis inpreparing the condensed consolidated interim financial statements. Detail of the Group's going concern assessment for theperiod can be found within note 2.2 of the condensed consolidated interim financial statements. Principal risks at half-year 2026 and key developments since the 2025 Annual Report Effective risk management is fundamental to achieving Energean's strategic objectives and protecting its personnel, assets,shareholder value and reputation. Energean's risk management framework and process are described in detail between pages 65-79 in its 2025 Annual Report and Accounts. The principal risks and uncertainties facing the business are monitoredon an ongoing basis in line with the UK Corporate Governance Code 2024. The Board has overall responsibility fordetermining the nature and extent of the risks it is willing to take in achieving the strategic objectives of the Group and ensuring that such risks are managed effectively. Principal risks and uncertainties The Board has reviewed the principal risks and uncertainties facing the Group for the remainder of the financial year. While the majority of the principal risks disclosed in the 2025 Annual Report remain relevant and materially unchanged, the Boardhas identified certain developments that have resulted in changes to the Group's principal risk profile, as described below. Key developments in relation to Energean's risks New principal risk: M&A strategy execution and value deliveryAs the Group increasingly pursues inorganic growth opportunities across the Europe, Middle East and Africa region, theBoard has identified "M&A strategy execution and value delivery risk" as a new principal risk. This reflects the growing importance of acquisitions, strategic transactions and portfolio optimisation activities to the Group'slong-term growth strategy. The risk encompasses transaction execution, regulatory approvals, integration planning and delivery, cost and schedule performance, value realisation, stakeholder management and post-transaction operationalperformance. During the period, the Group announced the proposed acquisition of interests in certain offshore Angola assets. In August2026, the Group was notified that Etu Energias had executed a sale and purchase agreement pursuant to its contractual pre-emption rights with respect to the Group's proposed acquisition of Chevron's interests in Blocks 14 and 14K, offshore Angola. As of the time of writing, the sale and purchase agreement between Energean and Chevron remains in effect until the saleand purchase agreement between Chevron and Etu Energias has been completed. Geopolitical and security risksOperations in Israel remain subject to elevated geopolitical and security risks. Production in Israel was temporarilysuspended for 41 days between 28 February and 9 April 2026, following a directive from the Ministry of Energy andInfrastructure due to geopolitical escalations. Operations subsequently resumed safely and without incident. Energean continues to monitor the situation closely and maintains contingency plans, including security protocols for its workforce andpersonnel that prioritises the safety of its staff and contract personnel, and diversified logistic routes. It also maintainsfinancial and structural resilience measures, including engagement with lenders and stakeholders to preserve covenant stability during potential disruption events, eligibility for applicable government compensation mechanisms in respect ofqualifying war-related damage, and the active review and procurement of war-risk insurance solutions. Changes to risk categorisation and nomenclatureThe Board has also approved certain refinements to the naming and categorisation of principal risks to better reflect theGroup's risk governance framework and underlying risk exposures. These changes are intended to improve clarity, accountability and reporting and do not, in themselves, indicate a change in the Group's overall risk profile.The principal risks are now summarised as:· Geopolitical and security risks · Production downtime and operating efficiency risk· Project delivery risk· Subsurface risk · M&A strategy execution and value delivery risk (new)· Liquidity and market risks· Non-operated assets and JV management risk · Significant IT and OT cyber risk· Legal, compliance, regulatory and financial crime risk· Asset integrity, health, safety and environmental risk · Climate change and energy transition risk Emerging risks Within the Company's enterprise risk management framework, emerging risks are considered as part of the identification phase. These are risks that cannot yet be fully assessed, risks that are known but are not likely to have an impact for severalyears, or risks which are unknown but could have implications for the business moving forward. During the second half of2026, management will continue to monitor any relevant trends, enhancing proactive monitoring and scenario planning while exploring new opportunities.
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Statement of Directors' responsibilities The Directors confirm that, to the best of their knowledge: · The condensed consolidated interim financial statements have been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted pursuant to UK-adopted international accounting standards. · The interim management report includes a fair review of the information required by the Disclosure Guidance and Transparency Rules (DTR) 4.2.7R, namely an indication of important events during the six months ended 30 June 2026 and a description of the principal risks and uncertainties for the remaining six months of the financial year. · The interim management report includes a fair view of the information required by the DTR 4.2.8R, including disclosure of related party transactions and any changes therein during the reporting period. Matthaios Rigas Chief Executive Officer Panagiotis Benos Chief Financial Officer 8 September 2026 8 September 2026 Forward looking statements This announcement contains statements that are, or are deemed to be, forward-looking statements. In some instances,forward-looking statements can be identified by the use of terms such as "projects", "forecasts", "on track", "anticipates","expects", "believes", "intends", "may", "will", or "should" or, in each case, their negative or other variations or comparable terminology. Forward-looking statements are subject to a number of known and unknown risks and uncertainties that maycause actual results and events to differ materially from those expressed in or implied by such forward-looking statements,including, but not limited to: general economic and business conditions; demand for the Company's products and services; competitive factors in the industries in which the Company operates; exchange rate fluctuations; legislative, fiscal andregulatory developments; political risks; terrorism, acts of war and pandemics; changes in law and legal interpretations; andthe impact of technological change. Forward-looking statements speak only as of the date of such statements and, except as required by applicable law, the Company undertakes no obligation to update or revise publicly any forward-lookingstatements, whether as a result of new information, future events or otherwise. The information contained in thisannouncement is subject to change without notice. Casting in tablesNumbers outside of the unaudited consolidated interim financial statements, where applicable, are rounded to the nearest million US$ and therefore totals may differ in the order of a million US$. INDEPENDENT REVIEW REPORT TO ENERGEAN PLC ConclusionWe have been engaged by the Company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2026 which comprises the interim consolidated income statement, the interimconsolidated statement of comprehensive income, the interim consolidated statement of financial position, interimconsolidated statement of changes in equity, the interim consolidated statement of cash flows and the related explanatory notes 1 to 28. We have read the other information contained in the half yearly financial report and considered whether itcontains any apparent misstatements or material inconsistencies with the information in the condensed set of financialstatements. Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financialstatements in the half-yearly financial report for the six months ended 30 June 2026 is not prepared, in all materialrespects, in accordance with UK-adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority. Basis for Conclusion
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We conducted our review in accordance with International Standard on Review Engagements 2410 (UK) "Review of InterimFinancial Information Performed by the Independent Auditor of the Entity" (ISRE) issued by the Financial Reporting Council. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial andaccounting matters, and applying analytical and other review procedures. A review is substantially less in scope than anaudit 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 UK - adopted international accounting standards. The condensed set of financial statements included in this half-yearly financial reporthas been prepared in accordance with UK-adopted International Accounting Standard 34, "Interim Financial Reporting". Conclusions Relating to Going ConcernBased on our review procedures, which are less extensive than those performed in an audit as described in the Basis forConclusion section of this report, nothing has come to our attention to suggest that management have inappropriately adopted the going concern basis of accounting or that management have identified material uncertainties relating to goingconcern that are not appropriately disclosed.This conclusion is based on the review procedures performed in accordance with this ISRE, 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 half-yearly financial report in accordance with the Disclosure Guidance andTransparency Rules of the United Kingdom's Financial Conduct Authority.In preparing the half-yearly financial report, the directors are responsible for assessing the company's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accountingunless the directors either intend to liquidate the company or to cease operations, or have no realistic alternative but to doso. Auditor's Responsibilities for the review of the financial informationIn reviewing the half-yearly report, we are responsible for expressing to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report. Our conclusion, including our Conclusions Relating to GoingConcern, are based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusionparagraph of this report. Use of our reportThis report is made solely to the company in accordance with guidance contained in International Standard on ReviewEngagements 2410 (UK) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council. To the fullest extent permitted by law, we do not accept or assume responsibilityto anyone other than the company, for our work, for this report, or for the conclusions we have formed. Ernst & Young LLPLondon 8 September 2026
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Interim Consolidated Income Statement Six months ended 30 June 2026 (Unaudited) 30 June 2026 30 June 2025 $'000 $'000 Note Revenue 4 743,072 803,780Cost of sales 5 (428,580) (469,078) Gross profit 314,492 334,702 Other operating income 4 13,017 33,593General and administrative expenses 5 (29,960) (27,541)Change in decommissioning provision 20 (2,402) (3,927)Exploration and evaluation expenses and new ventures 5 (7,084) (4,271)Expected credit loss reversal/ (expense) 5 4,134 (2,205)Other operating expenses 5 (983) (1,292) Operating profit 291,214 329,059 Finance income 6 2,983 3,202Finance costs 6 (121,421) (128,276)Net income/(loss) on derivatives 7 117 (2,983)Net foreign exchange gain/ (loss) 6 5,519 (26,853) Profit before tax 178,412 174,149 Taxation expense 8 (18,775) (63,665) Profit for the period after taxation 159,637 110,484 Attributable to:Owners of the parent 159,637 110,484 159,637 110,484 Basic and diluted earnings per share ($ per share) Basic $0.87 $0.60Diluted $0.85 $0.59 Interim Consolidated Statement of Comprehensive Income Six months ended 30 June 2026 (Unaudited) 30 June 2026 30 June 2025 $'000 $'000 Profit for the period after taxation 159,637 110,484 Other comprehensive income: Items that may be reclassified subsequently to profit or (loss)Net investment hedge - -Cashflow hedges - (loss)/ gain recognised in OCI, net of tax (529) 28,789Exchange difference on the translation of foreign operations, net of tax 2,457 36,407 Items that will not be reclassified subsequently to profit or (loss)Remeasurement of defined benefit plan (1) - Other comprehensive profit after tax 1,927 65,196 Total comprehensive profit for the period 161,564 175,680 Total comprehensive profit attributable to: Owners of the parent 161,564 175,680 161,564 175,680 Interim Consolidated Statement of Financial Position As at 30 June 2026 (Unaudited) 30 June 2026 31 December 2025 Note $'000 $'000 ASSETSNon-current assets Property, plant and equipment 10 4,395,966 4,250,419Intangible assets 11 256,969 249,220Equity-accounted investments 4 4
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Other receivables 28,726 30,861Derivative financial instruments 7 239 3,931Deferred tax assets 12 176,820 156,493Restricted cash 14 3,248 3,345 4,861,972 4,694,273 Current assetsInventories 15 111,187 94,193Trade and other receivables 16 294,619 451,822Derivative financial instruments 7 18,237 22,390Restricted cash 14 2,460 99,399Cash and cash equivalents 13 315,190 227,213 741,693 895,017 Total Assets 5,603,665 5,589,290 EQUITY AND LIABILITIES Equity attributable to owners of the parentShare capital 17 2,465 2,459Share premium 17 465,331 465,331Merger reserve 139,903 139,903Other reserves 20,187 26,231Foreign currency translation reserve (6,316) (8,773)Share-based payment reserve 53,232 49,340Retained earnings (446,978) (532,869) Total Equity 227,824 141,622 Non-current liabilities Borrowings 19 3,529,965 3,355,741Deferred tax liabilities 12 149,476 145,110Retirement benefit liability 1,534 1,704Provisions 20 751,239 777,804Trade and other payables 22 25,680 36,709 4,457,894 4,317,068 Current liabilities Trade and other payables 21 774,828 780,062Current portion of borrowings 19 18,346 229,005Current tax Liability 3,302 8,449Provisions 20 121,471 113,084 917,947 1,130,600 Total Equity and Liabilities 5,603,665 5,589,290 Matthaios RigasChief Executive Officer Panagiotis BenosChief Financial Officer8 September 2026 8 September 2026 Interim Consolidated Statement of Changes in Equity Six months ended 30 June 2026 (Unaudited) Share capital Share premium Hedges and definedbenefit plans reserve Share basedpaymentreserve Translationreserve $'000 $'000 $'000 $'000 $'000 At 1 January 2026 2,459 465,331 26,231 49,340 (8,773) Profit for the period - - - - -Remeasurement of defined benefit liability, net oftax - - (1) - - Cash flow hedge, net of tax - - (529) - -Exchange difference on the translation of foreignoperations - - - - 2,457 Total comprehensive income - - (530) - 2,457 Transactions with owners of the companyCashflow hedges - basis adjustment transferred toPPE - - (7,161) - -Cashflow hedge - deferred tax related to basisadjustment - - 1,647 - -Share-based payment charges - - - 3,898 - Issuance of shares 6 - - (6) -Dividends - - - - - At 30 June 2026 2,465 465,331 20,187 53,232 (6,316) Interim Consolidated Statement of Changes in Equity Six months ended 30 June 2025 (Unaudited) Share capital Share premium Hedges and definedbenefit plans reserve Share basedpaymentreserve Translationreserve $'000 $'000 $'000 $'000 $'000
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At 1 January 2025 2,449 465,331 5,796 41,996 (23,547) Profit for the period - - - - - Cash flow hedge, net of tax - - 28,789 - -Exchange difference on the translation of foreignoperations - - - - 36,407 Total comprehensive income - - 28,789 - 36,407 Transactions with owners of the company Share-based payment charges - - - 3,678 - Issuance of shares 10 - - (10) - Dividends - - - - - At 30 June 2025 2,459 465,331 34,585 45,664 12,860 Interim Consolidated Statement of Cash Flows Six months ended 30 June 2026 (Unaudited) 30 June 202630 June 2025 Note $'000 $'000 Operating activities Profit before taxation 178,412 174,149 Adjustments to reconcile profit before taxation to net cashprovided by operating activities: Depreciation, depletion and amortisation 10, 11 189,138 194,431Impairment (reversal)/loss on exploration and evaluationassets 10, 11 - (656) Change in decommissioning provision estimates 5, 20 2,402 3,927Defined benefit (gain)/loss (162) 10Movement in other provisions (1,864) (829)Expected credit loss (reversal)/expense on trade receivables 5 (4,134) 2,205Other income and expenses, net (10,223) (1,270)Finance income 6 (2,983) (3,202)Finance costs 6 121,421 128,276Non-cash revenues from Egypt (16,526) (12,957)Share-based payment charge 23 3,898 3,678Net (income)/loss on derivative instruments 7 (1,721) 2,983Net foreign exchange (gain)/loss 6 (5,519) 26,853Working capital adjustments: (Increase)/decrease in inventories (18,242) 17,279Decrease/(increase) in trade and other receivables 174,377 (17,110)(Decrease)/increase in trade and other payables (107,196) 147,591 Cash flow from operations 501,078 665,358 Income tax paid (25,403) (110,460) Net cash inflow from operating activities 475,675 554,898 Investing activities Payment for purchase of property, plant and equipment (220,129) (331,109)Payment for exploration and evaluation, and other intangibleassets (29,944) (53,412)Proceeds from disposal of exploration and evaluation andother intangible assets 20,423 668Other investing activities (116) 9,500Interest received 3,827 4,160 Net cash outflow for investing activities (225,939) (370,193) Financing activities Drawdown of borrowings 19 115,000 238,000Repayment of borrowings 19 (158,000) (33,000)Movement in restricted cash* 14 96,939 (834)Dividend Paid 18 (73,746) (110,267)Repayment of obligations under leases 19 (12,494) (9,191)Finance costs paid 19 (129,354) (121,599) Net cash outflow for financing activities (161,655) (36,891) Net increase in cash and cash equivalents 88,081 147,814 Cash and cash equivalents at beginning of the period 227,213 235,270Effect of exchange rate fluctuations on cash held (104) 17,566 Cash and cash equivalents at end of the period 13 315,190 400,650 *The presentation of the movement in restricted cash has been changed in the current period, refer to Note 2 for further details. 1. Corporate Information Energean plc (the 'Company') was incorporated in England & Wales on 8 May 2017 as a public company limited by shares, under the Companies Act 2006. Its registered office is at One Great Cumberland Place, London, W1H 7AL, United Kingdom. The Company and all subsidiaries controlled by the Company, are together referred to as 'the Group'.
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The Group has been established with the objective of exploration, production and commercialisation of crude oil, hydrocarbon liquids and natural gas in gas in the Europe, Middle East and Africa ("EMEA") region. Energean has operations in six countries: Israel, Egypt, Italy, Greece, Croatia and the UK. The Group's subsidiaries and core assets, as of 30 June 2026, are presented in notes 27 and 28. 2. Basis of preparation 2.1 Basis of preparation The unaudited condensed consolidated interim financial statements for the six months ended 30 June 2026 included in this interim reporthave been prepared in accordance with UK-adopted International Accounting Standard 34 'Interim Financial Reporting' ('IAS 34'), and,unless otherwise disclosed, have been prepared on the basis of the same accounting policies and methods of computation as applied inthe Group's Annual Report for the year ended 31 December 2025. The unaudited condensed consolidated interim financial statements have been prepared on a historical cost basis and are presented in US Dollars, which is also the Company's functional currency, rounded to the nearest thousand dollars ($'000) except where otherwise indicated. The US dollar is the currency that mainly influences sales prices, revenue estimates, and has a significant effect on the Group's operations. The functional currencies of the Group's main subsidiaries are Euro for Energean Italy Spa, Energean Sicilia Srl, Energean Oil & Gas S.A. and EnEarth Limited, $ for Energean Group Services Limited, Energean Israel Limited, Energean Egypt Limited, Energean E&P Holdings Limited, Energean Investments Limited, and Energean Capital Limited, and GBP for Energean UK Limited and Energean Exploration Limited. The unaudited condensed consolidated interim financial statements do not constitute statutory accounts of the Group within the meaning of Section 435 of the Companies Act 2006 and do not include all the information and disclosures required in the annual financial statements. These financial statements should be read in conjunction with the Group's Annual Report for the year ended 31 December 2025, which were prepared in accordance with UK-adopted International Accounting Standards ('UK-adopted IAS'). These financial statements have been delivered to the Registrar of Companies. The auditor's report on those financial statements was unqualified, did not include a reference to any matters by way of emphasis and did not contain a statement under Section 498 (2) or Section 498 (3) of the UK Companies Act 2006. In the period, the Group has changed the presentation of movements in restricted cash relating solely to debt servicing, specifically cash restricted under the terms of the Senior Secured Notes ahead of scheduled coupon payments, from investing activities to financing activities in the Statement of Cash Flows. Previously, such movements were presented within investing activities as movements between cash and cash equivalents and restricted cash. The Group considers that this change provides more relevant and reliable information, as the restrictions relate solely to the financing activity, being the servicing of debt under the Senior Secured Notes, and the revised presentation better reflects the nature of the underlying cash flows. In accordance with IAS 8, the comparative period has been restated. There is no impact on the total net increase or decrease in cash and cash equivalents, profit for the period, or the Statement of Financial Position for any period presented. 2.2 Going concern The Group carefully manages the risk of a shortage of funds by closely monitoring its funding position and its liquidity risk. The Going Concern assessment covers the period up to 31 December 2027 'the forecast period'. As of 30 June 2026, the Group's available liquidity was approximately $399 million. In addition to $315 million of cash and cash equivalents held by the Group at 30 June 2026, this available liquidity figure includes: (i) $37 million available under unsecured loan facility obtained in relation to the Nitzana project and $47 million under Revolving Credit Facility. In addition, the Group holds $6 million of restricted cash, principally comprising debt service reserve accounts. The going concern assessment is founded on a cashflow forecast prepared by management and approved by the Board of Directors, which is based on a number of assumptions, most notably the Group's latest life of field production forecasts, budgeted expenditure forecasts, estimated of future commodity prices (based on recent published forward curves) and available headroom under the Group's debt facilities. The going concern assessment contains a "Base Case" and a "Reasonable Worst Case" ("RWC") scenario, as well as additional stress tests on production and pricing and a scenario assuming an Israel shutdown due to geopolitical risks. Base Case assumes Brent at $83/bbl in 2026 and $75/bbl in 2027, and PSV at €52/MWh and €40/MWh in 2026 and 2027 respectively, with prices for gas sold assumed at contractually agreed prices for Egypt and Israel. Under the Base Case, sufficient liquidity is maintained throughout the going concern period. The Group also routinely performs sensitivity tests of its liquidity position to evaluate adverse impacts that may result from changes to the macro-economic environment, such as a reduction in commodity prices and in production. These downsides are considered in the RWC scenario along with other assumptions. Following the drawdown of the $750 million senior-secured term loan with Bank Leumi as Facility Agent and Arranger in the second half of 2025, the Group has floating interest rate exposure, which continues to be reflected in the going concern assessment. The group also looks at the impact of changes or deferral of key projects and downside scenarios to budgeted production forecasts in the RWC. The two primary downside sensitivities considered in the RWC are: (i) reduced commodity prices; (ii) reduced production - these downsides are applied to assess the robustness of the Group's liquidity position over the Assessment Period. In a RWC downside case, there are appropriate and timely mitigation strategies, within the Group's control, to manage the risk of funding shortfalls and to ensure the Group's ability to continue as a going concern. Mitigation strategies, within management's control, modelled in the RWC include deferral of discretionary capital expenditure on operated assets and/or management of controllable operating expenses to improve liquidity.
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Under the RWC scenario, after considering mitigation strategies, liquidity is maintained throughout the going concern period. In assessing the Group's resilience, the Board also considered downside scenario incorporating a prolonged suspension of production in Israel, reflecting the ongoing geopolitical uncertainty in the Middle East and the temporary suspension of Israeli production taking place in the beginning of 2026. This scenario was modelled across the full going concern horizon (until 31 December 2027) and assumes an extended period without Israeli revenues - a scenario which the Board considers to be remote and unrealistic. Notwithstanding its remote likelihood, and after taking into account available mitigating actions, the Group maintains adequate liquidity and covenant headroom throughout the assessment period. Reverse stress testing was also performed to determine what production shortfall could need to occur for liquidity headroom to be eliminated. The conditions necessary for liquidity headroom to be eliminated are judged to have a remote possibility of occurring, given the diversified nature of the Group's portfolio and the "natural hedge" provided by virtue of the Group's fixed-price gas contracts in Israel. In the event a remote downside scenario occurred, prudent mitigating strategies, consistent with those described above, could also be executed in the necessary timeframe to preserve liquidity. There is no material impact of climate change within the Assessment Period and therefore, it does not form part of the reverse stress testing performed by management. In forming its assessment of the Group's ability to continue as a going concern, including its review of the forecasted cashflow of the Group over the Forecast Period, the Board has made judgements about: • Reasonable sensitivities appropriate for the current status of the business and the wider macro environment; and • the Group's ability to implement the mitigating actions within the Group's control, in the event these actions were required. After careful consideration, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future, for the Assessment Period from the date of approval of these unaudited condensed consolidated interim financial statements on 8 September 2026 to 31 December 2027. For this reason, they continue to adopt the going concern basis in preparing these condensed consolidated interim financial statements. 2.3 New and amended accounting standards and interpretations The following amendments became effective as at 1 January 2026 : · Amendments to IFRS 9 and IFRS 7: Classification and measurement of financial instruments; · Annual improvements to IFRS accounting standards: Volume 11; and · Amendments to IFRS 9 and IFRS 7: Contracts referencing nature-dependent electricity. The adoption of the above amendments to UK-adopted IAS did not result in any material changes to the Group's accounting policies anddid not have any material impact on the financial position or performance of the Group. 2.4 Standards issued but not yet effective IFRS 18 Presentation and Disclosure in Financial Statements was issued by the IASB in April 2024 and is effective for annual reportingperiods beginning on or after 1 January 2027, with full retrospective application required. The Group has not early adopted IFRS 18. IFRS 18 will replace IAS 1 and introduces a revised structure for the statement of profit or loss, requiring all income and expenses to beclassified into one of five categories (operating, investing, financing, income taxes and discontinued operations) and the presentation oftwo new mandatory subtotals: 'operating profit or loss' and 'profit or loss before financing and income tax'. The standard also introducesmandatory disclosure requirements for management-defined performance measures ('MPMs') and enhanced guidance on the aggregationand disaggregation of information in the financial statements. Consequential amendments are made to IAS 7, IAS 8, IAS 33 and IAS 34. The Group has commenced its assessment of the impact of IFRS 18. The most significant area identified to date is the classification ofAdjusted EBITDAX as a management-defined performance measure under IFRS 18. Adjusted EBITDAX is used by management in itsexternal communications to communicate the underlying performance of the business, and the Group therefore expects to be required topresent a reconciliation of Adjusted EBITDAX to the nearest IFRS 18-required subtotal, together with a description of the measure and therelated income tax effect, in a new note to the financial statements. Other significant areas of judgement identified to date include: the classification of net foreign exchange gains and losses into the newoperating, investing and financing categories, given the Group's material non-US dollar monetary exposures (principally EUR and ILS); theclassification of interest income on cash and short-term deposits, which is expected to move from finance income to the new investingcategory; the treatment of reclassification adjustments on settlement of the Group's cash flow hedging instruments; and the classificationof the petroleum profits levy in Israel under the Income and Natural Resources Taxation Law, 5771-2011, which management expects topresent within the income taxes category under IFRS 18, consistent with its treatment as a tax on the economic returns from hydrocarbonproduction. This conclusion will be confirmed as part of the Group's finalised IFRS 18 assessment by 31 December 2026. As 2026 is the comparative period for the Group's first IFRS 18 financial statements, the Group's assessment and resulting accountingpolicy choices are expected to be substantially complete by 31 December 2026. The Group will provide further detail and a quantificationof the expected impact of IFRS 18 on its primary financial statements in its annual financial statements for the year ending 31 December2026. The following amendments to IFRS Accounting Standards are also effective for annual periods beginning on or after 1 January 2027 andhave not been early adopted: · IFRS 19 Subsidiaries without Public Accountability: Disclosures and · Amendments to IAS 21 Translation to a Hyperinflationary Presentation Currency. No material impact on the Group's financial statements is anticipated from either amendment. 2.5 Approval of unaudited condensed consolidated interim financial statements by Directors These unaudited condensed consolidated interim financial statements were approved by the Board of Directors on 8 September 2026. 3. Segmental Reporting
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The information reported to the Group's Chief Executive Officer and Chief Financial Officer (together the Chief Operating Decision Makers)for the purposes of resource allocation and assessment of segment performance is focused on four operating segments: Europe (includingGreece, Italy, UK and Croatia), Israel, Egypt and New Ventures. The Group's reportable segments under IFRS 8 Operating Segments areEurope, Israel and Egypt. New Ventures segment does not exceed the quantitative thresholds for reporting information about operatingsegments and has therefore been included within "Other" alongside inter-segment transactions. Segment revenues, results and reconciliation to profit before tax The following is an analysis of the Group's revenue, results and reconciliation to profit/ (loss) before tax by reportable segment: Six months ended 30 June 2026(unaudited) Europe Israel Egypt Other &inter-segmenttransactions Total $'000 $'000 $'000 $'000 $'000 Revenue from gas sales 36,075 323,828 68,826 - 428,729 Revenue from hydrocarbon liquid sales 18,273 155,696 - - 173,969 Revenue from crude oil sales 75,995 - 23,847 - 99,842 Revenue from LPG sales 171 - 11,756 - 11,927 Tariff income 1,842 - - - 1,842 Hedging income (206) 1,810 - - 1,604 Other revenue 8,083 - - (7,838) 245 Other income from production activities 24,914 - - - 24,914 Total revenue from production activities165,147 481,334 104,429 (7,838) 743,072 Adjusted EBITDAX 61,523 328,524 86,984 537 477,568 Reconciliation to profit before tax: Other operating income 12,481 - 115 421 13,017 Depreciation and amortisation expenses (29,552) (115,580) (43,432) (574) (189,138) Share-based payment charge (1,328) (761) - (1,809) (3,898) Exploration and evaluation expenses andnew ventures (2,189) - (130) (4,765) (7,084) Change in decommissioning provision (2,402) - - - (2,402) Reversal of expected credit loss 20 - 4,114 - 4,134 Other operating expenses (117) (524) (251) (91) (983) Finance income 1,835 1,949 2,063 (2,864) 2,983 Finance costs (22,629) (76,199) (268) (22,325)(121,421) Net (loss)/gain on derivative instruments - 117 - - 117 Net foreign exchange gain/(loss) 5,477 (15,016) (5) 15,063 5,519 Profit/(loss) before income tax 23,119 122,510 49,190 (16,407) 178,412 Taxation income / (expense) 23,437 (25,581) (16,526) (105) (18,775) Profit/(loss) for the period 46,556 96,929 32,664 (16,512) 159,637 Six months ended 30 June 2025(unaudited) Europe Israel Egypt Other &inter-segmenttransactions Total $'000 $'000 $'000 $'000 $'000 Revenue from gas sales 124,634 345,718 70,578 - 540,930 Revenue from hydrocarbon liquids sales 249 136,909 - - 137,158 Revenue from crude oil sales 82,532 - 23,054 - 105,586 Revenue from LPG sales 168 - 7,577 - 7,745 Tariff income 469 - - - 469 Other revenue 285 - - - 285 Other operating income-lost productioninsurance proceeds 11,607 - - - 11,607 Total Revenue 219,944 482,627 101,209 - 803,780 Adjusted EBITDAX 97,903 328,226 82,735 (3,593) 505,271 Reconciliation to profit before tax: Depreciation and amortisation expenses (36,766) (115,907) (40,406) (1,353) (194,432) Share-based payment charge (2,370) (614) - (694) (3,678) Exploration and evaluation expenses andnew ventures (1,721) (1,994) 2,651 (3,207) (4,271) Change in decommissioning provision (3,927) - - - (3,927) Expected credit loss - - (2,205) - (2,205) Other expense (1,097) (9) (136) (50) (1,292) Other income 2,101 9,794 19,857 1,841 33,593 Finance income 185 2,355 142 520 3,202 Finance costs (22,080) (80,851) (235) (25,110)(128,276) Net loss on derivative instruments - 134 - (3,117) (2,983) Net foreign exchange gain/(loss) (34,230) (11,814) (1,237) 20,428 (26,853) Profit/(loss) before income tax (2,002) 129,320 61,166 (14,335) 174,149 Taxation expense (21,934) (28,937) (12,957) 163 (63,665) Profit/(loss) for the period (23,936) 100,383 48,209 (14,172) 110,484 Other & inter-segment transactions column refer to other segments transactions as well as transactions between the reported reportablesegments. They are eliminated upon consolidation.Finance costs, finance income, other income and expenses and share - based payment charge included in "Other & inter-segmenttransactions" are not allocated to individual segments as the underlying instruments are managed on a group basis. Segment financial position
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The following tables present assets and liabilities information for the Group's operating segments as at 30 June 2026 and 31 December2025, respectively: Six months ended 30 June 2026(unaudited) Europe Israel Egypt Other & inter-segmenttransactions Total $'000 $'000 $'000 $'000 $'000 Oil & Gas properties 480,499 3,547,169310,048 - 4,337,716 Other fixed assets 19,327 8,463 5,224 25,236 58,250 Intangible assets 14,504 235,382 6,975 108 256,969 Trade and other receivables 118,932 155,764 80,040 (31,391) 323,345 Derivative assets 3,614 14,602 - 260 18,476 Deferred tax assets 176,812 - - 8 176,820 Cash and cash equivalents 34,982 213,816 53,147 13,245 315,190 Restricted cash 3,248 1,993 467 - 5,708 Other assets 911,992 22,318 300,854 (1,123,973) 111,191 Total assets 1,763,910 4,199,507756,755 (1,116,507)5,603,665 Trade and other payables 352,781 452,004 23,100 (27,377) 800,508 Borrowings 351,139 2,766,042 - 431,130 3,548,311 Decommissioning provision 730,427 88,330 - - 818,757 Current tax payable 2,598 505 - 199 3,302 Deferred tax liabilities - 149,476 - - 149,476 Other provisions 4,445 - 1,042 50,000 55,487 Total liabilities 1,441,390 3,456,357 24,142 453,952 5,375,841 Other segment information Capital Expenditure: - Property, plant and equipment 38,868 292,564 3,849 4,168 339,449 - Intangible, exploration and evaluationassets 639 12,376 416 (286) 13,145 Year ended 31 December 2025 Europe Israel Egypt Other & inter-segmenttransactions Total $'000 $'000 $'000 $'000 $'000 Oil & Gas properties 510,733 3,367,761349,358 (23,280) 4,204,572 Other fixed assets 25,576 9,834 7,071 3,366 45,847 Intangible assets 16,835 223,276 6,662 2,447 249,220 Trade and other receivables 130,631 158,184 214,896 (21,028) 482,683 Derivative assets 685 25,636 - - 26,321 Deferred tax assets 156,442 - - 51 156,493 Cash and cash equivalents 17,007 118,819 73,485 17,902 227,213 Restricted cash 3,345 97,647 1,752 - 102,744 Other assets 964,205 20,991 88,865 (979,864) 94,197 Total assets 1,825,459 4,022,148742,089 (1,000,406)5,589,290 Trade and other payables 475,545 315,552 40,038 (14,364) 816,771 Borrowings 343,754 2,744,085 - 496,907 3,584,746 Decommissioning provision 744,967 89,999 - - 834,966 Current tax payable (50) 8,325 - 174 8,449 Deferred tax liabilities - 145,110 - - 145,110 Other provisions 6,572 - 1,054 50,000 57,626 Total liabilities 1,570,788 3,303,071 41,092 532,717 5,447,668 Other segment information Capital Expenditure: - Property, plant and equipment 119,755 397,832 7,647 9,082 534,316 - Intangible, exploration and evaluationassets 1,018 53,357 (1,562) (193) 52,620 Other & inter-segment transactions column refer to other segments and transactions between the reportable segments. The oil & gasproperties primarily reflect the fair value assessment by the Group following the acquisition of Israeli oil & gas assets in 2018.Borrowings balance retained in Other & intersegment transactions column mainly comprises the loan balances held by Energean plc.Eliminations of cash management transactions within the Group are included in Other liabilities line in Other & inter-segment transactionscolumn.Segment cash flowsThe following tables present cash flow information for the Group's operating segments for six months ended 30 June: Six months ended 30 June 2026(unaudited) Europe Israel Egypt Other & inter-segmenttransactions Total $'000 $'000 $'000 $'000 $'000 Net cash from / (used in) operatingactivities (16,788) 314,253 198,474 (20,264) 475,675 Net cash (used in) investing activities (47,235) (170,880) (7,684) (140) (225,939) Net cash from financing activities 83,050 (49,375)(211,259) 15,929 (161,655) Net increase/(decrease) in cash and cashequivalents 19,027 93,998 (20,469) (4,475) 88,081 Cash and cash equivalents at beginning ofthe period 17,007 118,819 73,484 17,903 227,213 Effect of exchange rate fluctuations oncash held (1,052) 999 132 (183) (104) Cash and cash equivalents at end of theperiod 34,982 213,816 53,147 13,245 315,190
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Six months ended 30 June 2025(unaudited) Europe Israel Egypt Other & inter-segmenttransactions Total $'000 $'000 $'000 $'000 $'000 Net cash from / (used in) operatingactivities 244,190 237,466 29,079 44,163 554,898 Net cash (used in) investing activities (127,889) (172,575) (36,328) (34,235) (371,027) Net cash from financing activities (94,114) (124,637) (904) 183,598 (36,057) Net increase/(decrease) in cash and cashequivalents 22,187 (59,746) (8,153) 193,526 147,814 Cash and cash equivalents at thebeginning of the period 35,576 157,728 27,710 14,256 235,270 Effect of exchange rate fluctuations oncash held 4,950 2,897 (29) 9,748 17,566 Cash and cash equivalents at end ofthe period 62,713 100,879 19,528 217,530 400,650 4. Revenue 30 June (Unaudited)2026 2025 $'000 $'000 Revenue from gas sales 428,729 540,930 Revenue from hydrocarbon liquids sales 173,969 137,158 Revenue from crude oil sales 99,842 105,586 Revenue from LPG sales 11,927 7,745 Tariff income 1,842 469 Hedging income 1,604 - Other revenue 245 285 Revenue from contracts with customers 718,158 792,173 Other operating income-lost production insurance proceeds - 11,607 Other revenue from production activities 24,914 - Total Revenue from production activities 743,072 803,780 Insurance proceeds - 9,500 Other income from reversal of prior period accruals 1,935 24,093 Other income from the investment disposal 11,082 - Total revenue and other income 756,089 837,373 Other revenue from production activities of $24.9 million (H1 2025: $nil) represents the non-cash settlement of outstanding jointoperating liabilities in respect of the Cassiopea gas concession in Italy, recognised in accordance with the contractual valuation mechanismunder the Joint Operating Agreement, consistent with the treatment described in the Note 30 in the Group's Annual Report for the yearended 31 December 2025. Refer to Note 25 for further details of the ongoing dispute and arbitration proceedings between Energean Italyand the operator. In November 2025, ExxonMobil agreed to farm into Block 2, located in the northwest of the Ionian Sea. The transaction completed on 11March 2026, resulting in the recognition of $11.1 million of other income in H1 2026. Refer to Note 11 for further details. Other income from reversal of prior period accrual in 2025 mainly relates to $18.9 million reversed accrued expense no longer required inEgypt, following the lapse of the statute of limitations period under the Egyptian Commercial law. Sales volumes for the six months ending 30 June (unaudited): 2026 2025 kboe kboe Israel 15,749 16,964Gas 13,871 14,907Hydrocarbon liquids 1,878 2,057Italy 1,358 2,469Gas 425 1,499Crude Oil 933 970Egypt (net entitlement) 2,911 3,103Gas 2,473 2,599Hydrocarbon liquids 153 147Condensate 285 357UK 152 144Gas 10 12Crude Oil 142 132Croatia - 3Gas - 3Greece - 131Crude Oil - 131 Total sales volumes 20,170 22,814 5. Operating profit
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30 June (Unaudited)2026 2025 $'000 $'000 Cost of sales Staff costs 34,507 31,714 Energy cost 15,732 13,513 Flux cost 14,131 16,609 Royalty payable 97,255 96,925 Maintenance, insurance, transportation and treatment costs 96,962 113,297 Depreciation and amortisation 184,449 191,409 Oil stock movement (13,623) 11,441 Stock (underlift)/overlift movement (833) (5,830) Total cost of sales 428,580 469,078 General & administrative expenses Staff costs 11,925 14,725 Other General & Administrative expenses 7,862 4,713 Share-based payment charge included in administrative expenses 3,898 3,678 Depreciation and amortisation 4,689 3,022 Auditor fees 1,586 1,403 Total General & administrative expenses 29,960 27,541 Change in decommissioning provision 2,402 3,927 Exploration and evaluation expenses and new ventures 7,084 4,927 Reversal of exploration costs written off - (656) Expected credit loss (reversal)/expense (4,134) 2,205 Other operating expenses 983 1,292 6. Net finance cost 30 June (Unaudited) 2026 2025 $'000 $'000 Interest on bank and other borrowings 46,499 9,549 Interest on Senior Secured Notes 82,659 102,595 Interest expense on long terms payables 742 1,498 Interest expense on short term liabilities - 676 Less amounts included in the cost of qualifying assets (32,635) (15,498) 97,265 98,820 Finance and arrangement fees 899 55 Commission charges for bank guarantees 1,713 2,507 Other finance costs and bank charges 1,412 822 Unwinding of discount on lease liability 1,312 1,087 Unwinding of discount on long-term trade payables 2,346 5,146 Unwinding of discount on provision for decommissioning 16,844 18,295 Unwinding of discount on deferred consideration - 2,085 Less amounts included in the cost of qualifying assets (370) (541) Total finance costs 121,421 128,276 Interest income from time deposits (2,958) (3,202) Other finance income (25) - Total finance income (2,983) (3,202) Net (gain)/loss on derivative instruments (117) 2,983 Net foreign exchange (gain)/ loss (5,519) 26,853 Net financing costs 112,802 154,910 7. Financial instrumentsThe Group's objectives and policies for managing financial instrument risks are consistent with those described in the Annual Report forthe year ended 31 December 2025. This note provides an update on significant developments in the Group's risk exposures and hedgingactivities during the six months ended 30 June 2026. 7.1 Fair values of financial assets and liabilitiesThe following financial instruments are measured at amortised cost and are considered to have fair values different to their book values: 30 June 2026 (Unaudited) 31 December 2025 $'000 Carrying value Fair value Carrying value Fair value Senior Secured notes 2,423,743 2,463,650 2,435,470 2,494,757
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The fair value of the bond is within level 1 of the fair value hierarchy. The fair values of other financial instruments not measured at fairvalue including cash and short-term deposits, trade receivables and trade and other payables equate approximately to their carryingamounts. The Group also holds short-term foreign exchange derivative instruments that are not designated in formal hedge relationships, used tomanage transactional currency exposures arising in the ordinary course of operations. These instruments are measured at fair valuethrough profit or loss. The aggregate fair value of undesignated derivative instruments as at 30 June 2026 was $99 thousand, recognised asa current derivative asset in the consolidated statement of financial position. Fair value movements of $99 thousand were recognised inforeign exchange gain during the period. 7.2 Hedging activities Hedge of net investment in foreign operationsFollowing the impairment charge recognised against the Argo-Cassiopea CGU in the year ended 31 December 2025, the net investmenthedge of the EUR 400 million senior secured notes in Energean Italy S.p.A. ceased with effect from 31 December 2025. From 1 January2026, foreign exchange movements on the retranslation of the EUR-denominated borrowing are recognised directly in the consolidatedstatement of profit or loss. Derivatives designated as hedging instruments: cashflow hedgesThe Group's cashflow hedge relationships during the six months ended 30 June 2026 comprised the following: · Commodity price riskThe Group actively manages its exposure to gas price volatility through a programme of collar instruments. The put and call optionsentered in April and May 2025 to hedge approximately 30% of anticipated Italian gas production against PSV price movements expiredduring the period. During H1 2026 the Group entered into new PSV collars and Brent crude oil collars to hedge a meaningful portion ofanticipated gas production for the period from April 2026 to March 2027 and a smaller portion of forecasted oil production from April to September 2026 in Italy, consistent with the Group's ongoing commodity price risk management strategy. The Group also entered into andexercised a Brent swap and a collar in relation to a single cargo of Israeli liquids production during the period. · Foreign exchange risk - capital expenditureThe multi-currency forward contracts entered in January 2025 to hedge EUR, NOK and GBP payments under the Katlan EPCI contractremain active and continue to be designated as cashflow hedges of highly probable forecast purchases. These instruments are effectiveuntil August 2027. · Foreign exchange risk - financingThe Group entered into a cross-currency swap to partially hedge the foreign exchange risk arising from EUR-denominated couponpayments on the senior secured notes issued by Energean plc. The swap covers approximately 65% of the semi-annual coupon obligationand converts the hedged portion of EUR coupon payments into USD. The instrument is designated as a cashflow hedge of highly probableforecast financing outflows and matures in line with the coupon payment schedule of the underlying bond. The Group is holding the following foreign exchange, commodity forward contracts and swap agreements on 30 June 2026: Lessthan 1month 1 to 3months 3 to 6months 6 to 9months 9 to 12months 13 to 24months 3 to 5years Total Foreign exchange forward contracts highly probable forecast purchases - Notional amount (in $'000) 38,246 47,410 79,989 43,835 - 3,633 - 213,113 - Average forward rate(EUR/USD) 1.07 1.08 1.08 1.09 - - - - Average forward rate(GBP/USD) 1.24 1.24 1.24 1.24 - 1.24 - - Average forward rate(USD/NOK) 11.20 11.19 11.18 11.16 - - - Cross-currency swaps(financing) - Notional amount (in $'000) - - 7,976 - - - - 7,976 - Swap rate (EUR/USD) - - 1.16 - - - - Commodity forward contracts(PSV) - Notional amount (in MWh)Put - - - 225,000450,000 - - - Notional amount (in MWh)Call - - - 225,000450,000 - - - Notional amount (in $'000)Put - - - 11,536 21,278 - - 32,814 - Notional amount (in $'000)Call - - - 25,637 54,606 - - 80,243 - Average put strike (floor) (in $per MWh) - - - 51 47 - - - Average call strike (ceiling) (in$ per MWh) - - - 114 121 - - Commodity forward contracts(Brent) - Notional amount (in bbl) Put25,000 50,000 - - - - -
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- Notional amount (in bbl) Call25,000 50,000 - - - - - - Notional amount (in $'000)Put 2,000 4,000 - - - - - 6,000 - Notional amount (in $'000)Call 2,750 5,500 - - - - - 8,250 - Average put strike (floor) (in $per bbl) 80 80 - - - - - - Average call strike (ceiling) (in$ per bbl) 110 110 - - - - - The impact of hedging instruments on the statement of financial position is, as follows: Notionalamount Carryingamount on 30June 2026 Line item inthe statementof financialposition Change in fairvalue used formeasuringineffectivenessfor the period $'000 $'000 $'000 Foreign exchange forward contracts 3,633 239 Derivativeasset, non-current - Foreign exchange forward contracts 209,480 14,363 Derivativeasset, current - Interest rate swaps/options 7,976 257 Derivativeasset, current - Commodity forward contracts (Put) 38,814 4,182 Derivativeasset, current - Commodity forward contracts (Call) 88,493 (565) Derivativeasset, current - 348,396 18,476 - The effect of the cash flow hedge in the statement of profit or loss and other comprehensive income is, as follows: Hedged Item Totalhedginggain/(loss)recognisedin OCI Amountreclassifiedfrom OCI toprofit or(loss)/ statementof financialposition Line item in the statement ofprofit or (loss) / statement offinancial position $'000 $'000 Highly probable forecast purchases(property, plant and equipment related) (3,730) 7,161 Basis adjustment to PPE (credit) Highly probable forecast purchases (26) 117 Finance incomeHighly probable forecast gas sales 2,174 (199) Other revenueHighly probable forecast liquids sales 2,450 1,802 Other revenueHighly probable forecast financing outflows 158 - - No hedge ineffectiveness was recognised in profit or loss during H1 2026 in respect of the Group's cash flow hedges. The movement in hedging reserves and foreign currency translation reserve during the six months ended 30 June 2026 is as follows: Cashflow hedgereserve Foreign currencytranslation reserve As at 1 January 2026 20,241 (8,773) Effective portion of changes in fair valuearising from: Commodity forward contracts - forecastgas sales 2,174 - Foreign exchange forward contracts -forecast purchases (3,756) - Cross-currency swap - forecast financingoutflows 158 Commodity forward contracts and swaps- Brent 2,450 - Amount reclassified to profit or loss (1,721) - Amount capitalised under PPE (7,161) - Foreign currency revaluation of foreignoperations - 2,457 Tax effect 1,813 -
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Cashflow hedgereserve Foreign currencytranslation reserve As at 30 June 2026 14,198 (6,316) 8. Taxation 30 June (Unaudited) 2026 2025 $'000 $'000 Current income tax charge (40,587) (38,903)Adjustments in respect of current income tax of previous year(s) 2,596 - Total current tax charge (37,991) (38,903) Deferred tax relating to origination and reversal of temporary differences 19,216 (24,762) Income tax expense reported in the Income statement (18,775) (63,665) Reconciliation of the total tax charge: The tax rate applied to the Group's profits in preparing the reconciliation below is the main corporation tax rate of 25.0% applicable in theUnited Kingdom. The effective tax rate for the period is 11% (June 2025: 37%). The tax (charge)/ credit of the period can be reconciled to the profit per the unaudited interim consolidated income statement as follows: 30 June (Unaudited) 2026 2025$'000 $'000 Profit before tax 178,412 174,149 Tax calculated at 25% UK standard tax rate (H1 2025: 25%) (44,603) (43,537)Impact of different tax rates (3,441) (4,557)Non recognition of deferred tax on current year tax losses and othertemporary differences (note A) (7,002) (20,450) Recognition and utilisation of previously unrecognised deferredtax/Derecognition of previously recognised deferred tax (note B) 33,055 372 Permanent differences 492 (2,057)Tax effect of non-taxable income and allowances 281 6,514Other adjustments (153) 50Prior year tax 2,596 - Total taxation expense (18,775) (63,665) Note A: The Group has not recognised deferred tax assets relating to current-year tax losses and other temporary differences arising in the UK ($5.8 million), Cyprus ($0.8 million) and Greece ($0.4 million), in line with the latest forecasts and assumptions regarding future taxable profits. Note B: During H1 2026, the Group recognised $26 million of previously unrecognised deferred tax assets in Italy, principally relating to decommissioning-related temporary differences. The recognition reflects updated evidence supporting the recoverability of these deferred tax assets, including production performance across the Group's Italian portfolio and the resulting enhancement of forecasts of future taxable profits. Based on this reassessment, management concluded that it is probable that sufficient taxable profits will be available to utilise the associated deductible temporary differences. In addition, during the period, Italy utilised previously unrecognised temporary differences of $5.5 million, mainly relating to property, plant and equipment. There are no income tax consequences attached to the payment of dividends in either 2026 or 2025 by the Group to its shareholders. The Group is within the scope of the Pillar Two Model Rules starting from 1 January 2025. Legislation implementing these rules has beenenacted or substantively enacted in a number of jurisdictions in which the Group operates. The Group has applied the mandatorytemporary exception under IAS 12 from recognising and disclosing deferred taxes related to Pillar Two income taxes. The Group has performed an assessment of its potential exposure to Pillar Two top-up taxes. Based on the analysis performed usinginformation currently available, including consideration of transitional safe harbour provisions where applicable, the Group does notexpect a material exposure to arise. In jurisdictions where the safe harbour provisions are not met, the Group does not expect anymaterial top-up tax exposure. Accordingly, no amount has been recognised in the consolidated financial statements for the period. The Group will continue to monitor developments in legislation, guidance and the geographic mix of earnings, which may impact futureperiods. 9. Earnings per share Basic earnings per ordinary share amounts are calculated by dividing net income for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year. Diluted income per ordinary share amounts is calculated by dividing net income for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued if dilutive employee share options were converted into ordinary shares. 30 June (Unaudited) 2026 2025 Total profit / (loss) attributable to equity shareholders ($'000) 159,637 110,484Effect of dilutive potential ordinary shares ($'000) - -
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159,637 110,484 Number of shares Basic weighted average number of shares including those heldby Employee Benefit Trust 184,498,459 183,947,626Dilutive potential ordinary shares 3,093,992 2,648,155 Diluted weighted average number of shares 187,592,451 186,595,781 Basic earnings per share $0.87/share $0.60/share Diluted earnings per share $0.85/share $0.59/share 10. Property, plant and equipment Oil and gasassets Leased assets Other property,plant andequipment Total $'000 $'000 $'000 $'000 Property, Plant & Equipment at cost: At 1 January 2025 5,705,751 115,647 68,446 5,889,844 Additions 500,033 16,754 10,883 527,670Lease modifications - (17,652) - (17,652)Disposal of assets (5,844) (11,237) (1) (17,082)Capitalised borrowing cost 40,144 - - 40,144Change in decommissioning provision (27,624) - - (27,624)Transfer from Intangible assets (30) - - (30)Government grants deducted from assetcost - - (16,021) (16,021) Foreign exchange impact 407,710 9,931 8,135 425,776 31 December 2025 6,620,140 113,443 71,442 6,805,025 Additions 319,893 2,787 7,062 329,742Lease modifications - 615 - 615Disposal of assets (2,784) - - (2,784)Transfer between classes of assets (16,985) - 16,985 -Capitalised borrowing cost 30,416 - - 30,416Change in decommissioning provision (11,152) - - (11,152)Foreign exchange impact (108,014) (6,890) 1,014 (113,890) At 30 June 2026 6,831,514 109,955 96,503 7,037,972 Accumulated Depreciation and Impairment: At 1 January 2025 1,258,332 59,170 56,983 1,374,485 Charge for the period 556,057 19,856 2,276 578,189Impairments 285,726 - - 285,726Lease modifications - (6,308) - (6,308)Disposal of assets (4,732) (7,190) - (11,922)Foreign exchange impact 320,185 7,466 6,785 334,436 31 December 2025 2,415,568 72,994 66,044 2,554,606 Charge for the period 174,568 11,962 1,377 187,907Disposal of assets (2,028) - - (2,028)Foreign exchange impact (94,310) (2,349) (1,820) (98,479) At 30 June 2026 2,493,798 82,607 65,601 2,642,006 Net Carrying Amount: At 31 December 2025 4,204,572 40,449 5,398 4,250,419 At 30 June 2026 4,337,716 27,348 30,902 4,395,966 Included in the carrying amount of leased assets at 30 June 2026 are right of use assets related to Oil and gas properties and Other property, plant and equipment of $15.4 million and $11.9 million respectively (31 December 2025: $37.0 million and $3.5 million respectively). The depreciation charged on these classes for the six-month ending 30 June 2026 were $8.9 million and $3.0 millionrespectively (six months ended 30 June 2025: $6.5 million and $2.8 million). The additions to Oil & gas properties for the period of six months ended 30 June 2026 are mainly due to development costs of Katlan($267 million) in Israel, and the Irena development in Croatia ($14 million). Borrowing costs capitalised for qualifying assets, included in oil & gas properties, for the six months ended 30 June 2026 amounted to $30.4 million (30 June 2025: $15.5 million). The weighted average interest rates used was 7.46% for the six months ended 30 June 2026 (30 June 2025: 5.34%). No indicators of property, plant and equipment impairment were noted on 30 June 2026. 11. Intangible assets Exploration andevaluationassets Goodwill Otherintangibleassets Total$'000 $'000 $'000 $'000 Intangible assets at cost: At 1 January 2025 425,398 101,146 12,769 539,313 Additions 243 - 52,377 52,620Capitalised borrowing cost - - 580 580Transfer to property, plant and equipment 30 - - 30Foreign exchange impact 24,582 - 1,601 26,183 31 December 2025 450,253 101,146 67,327 618,726 Additions 2,155 - 10,990 13,145Borrowing Cost 2,219 - - 2,219
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Exploration andevaluationassets Goodwill Otherintangibleassets Total$'000 $'000 $'000 $'000 Disposal of asset (6,016) - - (6,016)Foreign exchange impact (5,918) - (831) (6,749) At 30 June 2026 442,693 101,146 77,486 621,325 Accumulated amortisation and impairments: At 1 January 2025 295,459 20,485 6,991 322,935 Charge for the period 578 - 1,794 2,372Write off of exploration and evaluationcosts 21,760 - - 21,760 Foreign exchange impact 21,123 - 1,316 22,439 31 December 2025 338,920 20,485 10,101 369,506 Charge for the period 101 - 1,130 1,231Foreign exchange impact (5,999) - (382) (6,381) At 30 June 2026 333,022 20,485 10,849 364,356 Net Carrying Amount: 31 December 2025 111,333 80,661 57,226 249,220 At 30 June 2026 109,671 80,661 66,637 256,969 In November 2025, ExxonMobil agreed to farm into Block 2, located in the northwest of the Ionian Sea. Following receipt of governmentapproval and an extension of the licence (as requested by Energean and HELLENiQ ENERGY Upstream), the transaction completed on 11March 2026, during the current reporting period. Following completion, the participating interests in the licence are: Energean 30%(Operator), ExxonMobil 60%, and HELLENiQ ENERGY Upstream 10%. Energean remains Operator of the concession through the explorationphase, during which an exploratory well is expected to be drilled in early 2027, subject to permitting. At completion, Energean receivedconsideration in respect of costs incurred prior to completion of the farm-out on 11 March 2026 resulting in the recognition of $11.1million of other income in H1 2026. No indicators of intangible assets impairment were noted on 30 June 2026. 12. Net deferred tax (liability)/ asset Deferred tax (liabilities)/assets ($'000) Property, plant and equipment Right of use asset IFRS 16 Decommissioning Prepaid expenses and other receivables Inventory Tax losses Deferred expenses for tax Retirement benefit liability Accrued expenses and other short- term liabilities Total At 1 January 2025 (166,541) (3,059) 114,541 (2,780) 402 157,013 4,945 403 7,738 112,662 Increase/(decrease) for the period through: Profit or loss (13,185) 3,039 (107,890) 18 (213) (3,097) (633) 3 (148) (122,106) Other comprehensive income - - - - - - - 24 (8,627) (8,603) Equity 2,492 - - - - - - - - 2,492 Exchange difference (2,078) (76) 9,936 (76) 44 18,487 - 17 684 26,938 31 December 2025 (179,312) (96) 16,587 (2,838) 233 172,403 4,312 447 (353) 11,383 Increase/(decrease) for the period through: Profit or loss (7,475) 2,326 22,701 (263) (12) 3,878 (314) 85 (1,711) 19,215 Other comprehensive income - - - - - - - - 166 166 Equity 1,647 - - - - - - - - 1,647 Exchange difference 790 8 (955) 21 (7) (4,720) - (5) (199) (5,067) 30 June 2026 (Unaudited) (184,350) 2,238 38,333 (3,080) 214 171,561 3,998 527 (2,097) 27,344 30 June 2026 (Unaudited) 31 December 2025 $'000 $'000 Deferred tax liabilities (149,476) (145,110) Deferred tax assets 176,820 156,493 Net deferred tax (liabilities)/ assets 27,344 11,383 As of June 2026 the Group had gross total unused tax losses of $1,066.5 million (as of 31 December 2025: $1,169.2 million) available to offset against future profits and other temporary differences. The Group has not recognised deferred tax on tax losses and other differences of $1,062.4 million. In Greece and the UK, the net DTA for carried forward losses recognised in excess of the other net taxable temporary differences was $119.6 million and $21.1 million (2025: $121.4 million and $22.1 million) respectively. Greek tax losses (Prinos area) can be carried forward without limitation up until the relevant concession agreement expires (by 2049), whereas, the tax losses in Israel, Italy and the United Kingdom can be carried forward indefinitely. Based on the Prinos area forecasts including the Epsilon development with first oil expected 2029, the deferred tax asset is fully utilised by 2038. Finally, in the UK, decommissioning losses are expected to be tax relieved up until 2030 in accordance with the latest taxable profits forecasts. At June 2026, the gross amount and expiry dates of losses available for carry forward are as follows:
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($'000) Expiringwithin 5years Expiringbeyond 6years Unlimited Total (Note A) (Note B) (Note C) Losses for which a deferred tax asset is recognised 477,881 80,901 558,782 Losses for which no deferred tax asset is recognised 75,393 - 432,367 507,760 Total 75,393 477,881 513,268 1,066,542 Note A: Mainly comprises tax losses generated in the Republic of Cyprus ($34 million), the UK ($25 million), and Greece ($15 million)relating to trading losses that cannot currently be utilised against profits from the Prinos asset. Note B: Tax losses ring-fenced to the Prinos asset in Greece, which can be carried forward until the expiry of the relevant licences, i.e. by2049. Note C: Comprises Italian tax losses of $11 million, for which a deferred tax asset has been recognised, and UK tax losses of $70 million, forwhich no deferred tax asset has been recognised; both can be carried forward indefinitely. There are no income tax consequences attached to the payment of dividends by the Group to its shareholders. As a result of exemptionson dividend from subsidiaries and capital gains on disposal there are no significant taxable temporary differences associated withinvestments in subsidiaries, branches, associates and interests in joint arrangements. 13. Cash and cash equivalents 30 June 31 December2026 2025 $'000 $'000 Cash and bank deposits 315,190 227,213 315,190 227,213 Bank deposits comprise deposits and other short-term money market deposit accounts that are readily convertible into known amounts of cash. The effective interest rate on short ‐ term bank deposits was 4.29% for the six months period ended 30 June 2026 (H1 2025: 4.22%). 14. Restricted Cash In addition to cash restricted in relation to letters of credit issued in Egypt, restricted cash comprises cash retained under the Israel SeniorSecured Notes and the Greek State Loan requirement as follows: Current: The current portion of restricted cash at 30 June 2026 was $2.5 million (31 December 2025: $99.4 million). It mainly relates to theSeptember 2026 coupon payment on Senior Secured Notes. Non-Current: The cash restricted for more than 12 months after the reporting date was $3.2 million (31 December 2025: $3.3 million) mainly comprising$2.3 million (31 December 2025: $2.3 million) held on the Interest Service Reserve Account ('ISRA') in relation to the Greek Loan Notes and$0.7 million (31 December 2025: $0.8 million) for Prinos Guarantee. 15. Inventories 30 June 31 December 2026 (Unaudited) 2025 $'000 $'000 Crude oil 34,235 19,616 Hydrocarbon liquids 802 1,031 Gas 492 506 Raw materials and supplies 75,658 73,040 Total inventories 111,187 94,193 16. Trade and other receivables 30 June 2026 31 December (Unaudited) 2025 $'000 $'000 Financial items: Trade receivables 204,659 363,963Receivables from partners under JOA 586 2,967Other receivables 18,586 22,470 Refundable VAT 27,366 32,120Accrued interest income 15 968 251,212 422,488 Non-financial items:Deposits and prepayments 17,447 19,375 Refundable VAT 25,273 7,954Other deferred expenses 687 2,005 43,407 29,334 294,619 451,822 The decrease in trade receivables during the period was primarily driven by improved collections in Egypt, including a $125 million one-offrecovery received in April 2026 in respect of amounts previously outstanding from the Egyptian General Petroleum Corporation ("EGPC"),
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together with continued monthly cash collections in respect of ongoing sales. As a result, overdue receivables in Egypt reduced to $25.0million at 30 June 2026 (31 December 2025: $166.8 million). 17. Share capital The below table outlines the share capital of the Company: Equity share capitalallotted and fullypaid Share capital Share premium Issued and authorised $'000 $'000 At 1 January 2025 183,480,959 2,449 465,331Issued during the year- New shares - - -- Share based payment 800,000 10 - At 31 December 2025 184,280,959 2,459 465,331 Issued during the period- New shares - - -- Share based payment 435,000 6 - At 30 June 2026 (Unaudited) 184,715,959 2,465 465,331 18. Dividends In line with the Group's dividend policy, Energean returned $0.40/share to shareholders during the reporting period, representing two- quarters of dividend payments (6 months ended 30 June 2025: $0.60/ share). $ cents per share 30 June, $'000 Dividends announced and paid in cash 2026 2025 2026 2025 March 30 30 55,277 54,990 June 10 30 18,469 55,277 40 60 73,746 110,267 19. Borrowings 30 June 31 December 2026 (Unaudited) 2025 $'000 $'000 Non-current Bank borrowings - after two years but within five years5.375% Senior Secured notes due 2028 ($625 million) 621,946 621,144Bank borrowings - more than five years 5,625% Senior Secured notes due 2031 (€400 million) 446,264 459,6635.875% Senior Secured notes due 2031 ($625 million) 619,188 618,6738.50% Senior Secured notes due 2033 ($750 million) 736,345 735,990Nitzana facility 32,075 31,848Bank Leumi Loan 766,494 746,033Revolving Credit Facility 88,000 130,567BSTDB Loan 83,635 -Greek State Loan Notes 11,942 11,823Other borrowings 124,076 - Carrying value of non-current borrowings 3,529,965 3,355,741 Current Other borrowings - 124,543BSTDB Loan 18,346 104,462 Carrying value of current borrowings 18,346 229,005 Carrying value of total borrowings 3,548,311 3,584,746 The Group's borrowing facilities and associated security arrangements are described in the Annual Report for the year ended 31 December2025. The following provides an update on significant developments during the six months ended 30 June 2026. At 30 June 2026, the Group holds $2.0 billion in aggregate principal amount of senior secured notes, issued in three series as follows: · $625 million, issued on 24 March 2021, maturing on 30 March 2028, with a fixed annual interest rate of 5.375%. · $625 million, issued on 24 March 2021, maturing on 30 March 2031, with a fixed annual interest rate of 5.875%. · $750 million, issued on 11 July 2023, maturing on 30 September 2033, with a fixed annual interest rate of 8.5%. The interest on each series is paid semi-annually on 30 March and 30 September. The notes are listed for trading on the TACT Institutionalof the Tel Aviv Stock Exchange Ltd (TASE), and the TASE-UP for the 2023 issuance. The EUR 400 million senior secured notes issued on 10 November 2025, maturing in 2031 at a fixed annual interest rate of 5.625%, and the$750 million senior-secured term loan with Bank Leumi, remain in place and continue in accordance with their terms. The $125 million unsecured facility, originally signed in April 2025, was amended in March 2026 to extend its maturity to 15 March 2027,with an option at the Company's discretion to extend to 15 September 2027. As a result of this amendment, the facility has beenreclassified from current to non-current borrowings in the period. The Bank Hapoalim $70 million unsecured nine-year term loan, entered into in October 2025 to fund the Group's share of constructioncosts in the Nitzana project, continues to be drawn as project payments progress. As at 30 June 2026, $33.0 million has been drawn underthis facility.
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The BSTDB facility of €90.5 million entered into by Energean Oil and Gas S.A. continues in line with its contractual maturity to 2030.Following the resumption of production at Prinos in February 2026, the facility has been reclassified from current to non-current borrowings in the period. Separately, prior to 30 June 2026, Energean Oil and Gas S.A. completed the sale of a fixed asset (a jacketstructure) to a fellow Group company, EnEarth, in connection with a carbon storage project; as an intragroup transaction, this has noimpact on the Group's consolidated results. Under the terms of the facility agreement, proceeds from this type of disposal are required tobe used to partially repay the loan. Accordingly, $18.3 million of the facility has been reclassified to current borrowings at 30 June 2026,reflecting this mandatory repayment obligation. The $300 million Revolving Credit Facility, extended to September 2028 in August 2025, remains available. As at 30 June 2026, $88.0million was drawn under the facility (2025: $130.6 million). There have been no other material changes to the Group's borrowing facilities or security arrangements during the six months ended 30June 2026. Capital management The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholdersand benefits to stakeholders and to safeguard the Group's ability to continue as a going concern. Energean is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, the Group may put inplace new debt facilities, issue new shares for cash, repay debt, engage in active portfolio management, adjust the dividend payment toshareholders, or undertake other such restructuring activities as appropriate. 30 June 2026(Unaudited) 31 December 2025$'000 $'000 Net DebtCurrent borrowings 18,346 229,005Non-current borrowings 3,529,965 3,355,741Total borrowings 3,548,311 3,584,746 Less: Cash and cash equivalents 315,190 227,213 Restricted cash 5,708 102,744 Net Debt 3,227,413 3,254,789 Total equity 227,824 141,622 Reconciliation of liabilities arising from financing activities 1 January2026 Cashinflows Cashoutflows Reclassification Additions Leasemodification Borrowingcostsincludingamortisationofarrangementfees Foreignexchangeimpact 30 June2026(Unaudited) $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 2026 3,625,707115,000(297,564) 1,020 2,787 615 131,253 1,385 3,580,203 SecuredSeniorNotes 2,435,470 - (81,194) 963 - - 82,743 (14,239) 2,423,743 Otherlong-termborrowings 789,704 - (34,836) 209,515 - - 36,436 17,403 1,018,222 Revolvingcreditfacility 130,567115,000(163,043) 291 - - 5,185 - 88,000 Othercurrentborrowings 229,005 - (5,997) (209,054) - - 5,577 (1,185) 18,346 Leaseliabilities 40,961 - (12,494) (695) 2,787 615 1,312 (594) 31,892 20. Provisions Decommissioning provision Litigation and otherclaims Total $'000 $'000 $'000 At 1 January 2026 834,966 55,922 890,888 Change in estimates (8,750) (1,864) (10,614) Recognised in property, plant andequipment (11,152) - (11,152) Recognised in profit or loss 2,402 (1,864) 538 Spend (3,617) - (3,617) Unwinding of discount 16,844 - 16,844 Currency translation adjustment (20,686) (105) (20,791) At 30 June 2026 818,757 53,953 872,710 Current provisions 70,429 51,042 121,471 Non-current provisions 748,328 2,911 751,239
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Decommissioning provision: The decommissioning provision represents the present value of decommissioning costs relating to oil and gas properties, which are expected to be incurred up to 2052, when the producing oil and gas properties are expected to cease operations. The decrease in the estimate is primarily due to changes in the discount rate and inflation assumptions as of 30 June 2026. The principal assumptions used in determining decommissioning obligations for the Group are shown below: InflationAssumption30 June 2026 Discount rateassumption30 June 2026 Cessation ofproductionassumption Spend in2026$'000 30 June2026(Unaudited)$'000 31December2025$'000Greece 2,04% - 2.00% 3.70% 2045 - 16,581 16,021Italy 1,66% - 2,00% 4.02% 2052 2,873 528,391 540,394UK 2.32% 4.73% 2030 744 163,731 166,332Israel 2.18% - 2.75% 4.90% 2044 - 88,330 89,999Croatia 1,66% - 2,00% 4.02% 2039 - 21,724 22,220 3,617 818,757 834,966 21. Trade and other payables 30 June 2026(Unaudited) 31 December 2025$'000 $'000 Financial items:Trade accounts payable 302,132 244,846Payables to Partners under JOA 180,958 182,847Other payables 65,203 66,044Short term lease liability 16,952 19,314Deferred income 14,292 96,430VAT payable 3,891 9,778 583,428 619,259 Non-financial items: Accrued Expenses 130,223 97,563Other finance costs accrued 55,458 57,790Social insurance and other taxes 5,719 5,450 191,400 160,803 774,828 780,062 Payables to partners under the JOA include both payables and working capital estimates provided by the operators. Deferred income mainly comprises 'take-or-pay' payments received in Israel ($5.9 million) and government grants received for the CCSProject in Greece ($8.3 million). Other payables primarily consist of royalties accrued in Israel (H1 2026:$ 35.6 million, 31 December 2025: $36.8 million) and in Italy (H12026: $27.4 million, 31 December 2025: $27.9 million).22. Other non-current liabilities30 June 2026(Unaudited) 31 December 2025$'000 $'000 Financial items:Trade and other payables 10,569 14,987Long term lease liability 14,940 21,647 25,509 36,634 Non-financial items:Social insurance 171 75 171 75 25,680 36,709 23. Share based payments Analysis of share-based payment charge: 30 June (Unaudited) 2026 2025 $'000 $'000 Energean Deferred Bonus Plan (DSBP) 1,169 822 Energean Long Term Incentive Plans (LTIP) 2,729 2,856 Total share-based payment charge 3,898 3,678 Expensed as administration expenses 3,898 3,678 Total share-based payment charge 3,898 3,678 Energean Long Term Incentive Plan (LTIP) Under the Energean plc's 2018 LTIP rules, senior executives may be granted conditional awards of shares or nil cost options. Nil costoptions are normally exercisable from three to ten years following grant provided an individual remains in employment. Awards aresubject to performance conditions (including Total Shareholder Return (TSR) normally measured over a period of three years. Vesting ofawards or exercise of nil cost options is generally subject to an individual remaining in employment except in certain circumstances such asgood leaver and change of control. Awards may be subject to a holding period following vesting. No dividends are paid over the vestingperiod; however, Energean's Board may decide at any time prior to the issue or transfer of the shares in respect of which an award is
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released that the participant will receive an amount (in cash and/or additional shares) equal in value to any dividends that would havebeen paid on those shares on such terms and over such period (ending no later than the Release Date) as the Board may determine. Thisamount may assume the reinvestment of dividends (on such basis as the Board may determine) and may exclude or include specialdividends. The weighted average remaining contractual life for LTIP awards outstanding at 30 June 2026 was 1.5 years, number of shares outstanding2,652,673 and weighted average price of $11.8. Deferred Share Bonus Plan (DSBP) Under the DSBP, a portion of any annual bonus of a Senior Executive nominated by the Remuneration & Talent Committee, may bedeferred into shares. Deferred awards are usually granted in the form of conditional share awards or nil-cost options (or, exceptionally, ascash-settled equivalents). Deferred awards usually vest two years after award although may vest early on leaving employment or on achange of control. The weighted average remaining contractual life for DSBP awards outstanding at 30 June 2026 was 1.2 years, number of sharesoutstanding 366,051 and weighted average price of $10.89. 24. Related parties Balances and transactions between the Company and its subsidiaries, which are related parties, have been eliminated upon consolidationand are not disclosed in this note. There have been no significant changes to related party transactions since 31 December 2025, refer to note 29 in the 2025 Annual Reportand Accounts for more information. The Directors of Energean Plc are considered to be the only key management personnel as defined byIAS 24. 25. Commitments and contingencies In acquiring its oil and gas interests, the Group has pledged that various work programmes will be undertaken on each permit/interest. Theexploration and development capital commitments in the following table are an estimate of the net cost to the Group of performing thesework programmes: 30 June 2026(Unaudited) 31 December 2025 $'000 $'000 Capital Commitments: Due within one year 13,181 15,217 Due later than one year but within two years - - Due later than two years but within five years - - 13,181 15,217 As of 30 June 2026, $1.0 million of capital commitments is towards Governments (31 December 2025: $1.4 million). An amount of $12.2million (31 December 2025: $13.8 million) pertains to capital commitments with partners based on future work programs for thedevelopment of the Scott field in the United Kingdom and the second phase of drilling at Block 2 in Greece. 30 June 2026(Unaudited)$'000 31 December 2025$'000 Performance guarantees: Greece 5,025 1,141Israel 90,615 87,276UK 120,835 152,528Cyprus 26,000 -Egypt 6,000 6,000Italy 11,871 12,241 260,346 259,186 Open guarantees at 30 June 2026 comprise the following: · Karish and Tanin Leases ($25 million) - As required by the Karish and Tanin Lease deeds, the Group provided the Ministry ofNational Infrastructures, Energy, and Water with bank guarantees for each lease. These guarantees are valid until June 2027. · Blocks 23 and 31 ($13 million) - To meet the conditions for obtaining exploration and appraisal licenses, the Group provided theMinistry of National Infrastructures, Energy, and Water with bank guarantees covering all mentioned blocks. They are valid untilJune 2027. · Katlan lease ($10 million) - As required by the Katlan Lease deeds, the Group provided the Ministry of National Infrastructures,Energy, and Water with bank guarantee. This guarantee is valid until January 2029. · Nitzana project ($39 million) - The Group has provided guarantees to INGL in relation to Nitzana project. These guarantees were issued in November 2025 and are valid until November 2026. · Israel Other ($3 million) - The Group has provided various bank guarantees to third parties in Israel as part of ongoingoperations. · United Kingdom ($121 million) - The Group has issued letters of credit for United Kingdom decommissioning obligations andother obligations under the United Kingdom licenses. · Greece ($5 million) - The Group issued letters of credit ($1 million) to cover exploration obligations under the Prinos license andin regard to its gas and electricity contracts in Greece. In March 2026 the Group also provided a bank guarantee to the Greekstate in regards to the second phase of Block 2 ($4 million). · Cyprus ($26 million) - As disclosed in the Group's 2025 Annual Report, on 12 March 2026 the Group announced that it hadsigned an agreement to acquire Chevron's 31% operated interest in Block 14 and 15.5% non-operated interest in Block 14K,offshore Angola. Completion remains subject to government and regulatory approvals and the waiver of applicable pre-emption
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rights. In connection with the arrangements under the sale and purchase agreement, in March 2026 the Group issued a letter ofcredit of $26 million. The letter of credit is contingent on completion of the Angola transaction. As set out in note 26, thetransaction was pre-empted by an existing partner in August 2026 and the letter of credit was released in the same month. · Egypt ($6 million) - The total capital commitments in Egypt amounted to $6.0 million, with $4.8 million already spent as of 30June 2026. The Group is awaiting clearance from EGPC, which is expected upon the completion of all commitments. · Italy ($12 million) - The Group has issued guarantees primarily in favour of port authorities and counterparties in Italy to secureconcession rights, field-related obligations, lease commitments and certain service contracts. Legal cases and contingent liabilities: The Group's legal cases and contingent liabilities are described in the Annual Report for the year ended 31 December 2025, refer to note30. The most significant matter relates to the ongoing arbitration proceedings between Energean Italy S.p.A. and the operator of theCassiopea gas concession in Italy. There have been no material developments in the arbitration during the six months ended 30 June 2026.The tribunal is in the process of appointing a technical expert, and the Group continues to await the outcome of that process. The Grouphas continued to apply the same accounting treatment as at 31 December 2025, recognising the retention of production by the operatoras a non-cash settlement of outstanding joint operating liabilities, with a corresponding reduction to trade payables and recognition ofother income from production activities. 26. Subsequent events In August 2026, the Group was notified that Etu Energias had executed a sale and purchase agreement pursuant to its contractual pre-emption rights with respect to the Group's proposed acquisition of Chevron's interests in Blocks 14 and 14K, offshore Angola. Etu Energiasis an existing partner in both licenses. Following this outcome, the $26 million letter of credit recorded by the Group in support of its bidwas released in the same month. In September 2026, the Group incorporated Energean Holdings Limited and Energean Holdings II Limited, both ultimately wholly-owned byEnergean plc, in England & Wales, as part of the Group's ongoing corporate structuring activities. 27. Subsidiary undertakings At 30 June 2026, the Group had investments in the following subsidiaries: Name of subsidiary Country of incorporation / registered office Principal activities Shareholding At 30 June 2026 (%) Shareholding At 31 December 2025 (%) Energean E&P Holdings Ltd. 22 Lefkonos Street, 2064 Nicosia, Cyprus Holding Company 100 100 Energean Capital Ltd. 22 Lefkonos Street, 2064 Nicosia, Cyprus Holding Company 100 100 Energean Group Services Ltd. One Great Cumberland Place, London,W1H 7AL, United Kingdom Oil and gas exploration, development and production 100 100 Energean Oil & Gas S.A. 32 Kifissias Avenue, Marousi Athens, 151 25, Greece Oil and gas exploration, development and production 100 100 Energean International Ltd. 22 Lefkonos Street, 2064 Nicosia, Cyprus Oil and gas exploration, development and production 100 100 Energean Israel Ltd. 22 Lefkonos Street, 2064 Nicosia, Cyprus Oil and gas exploration, development and production 100 100 Energean Montenegro Ltd. 22 Lefkonos Street, 2064 Nicosia, Cyprus Oil and gas exploration, development and production 100 100 Energean Israel Transmission Ltd. Andre Sakharov 9, Haifa, Israel Gas transportation license holder 100 100 Energean Israel Finance Ltd. Andre Sakharov 9, Haifa, Israel Financing activities 100 100 Energean Egypt Ltd. 22 Lefkonos Street, 2064 Nicosia, Cyprus Oil and gas exploration, development and production 100 100 Energean Hellas Ltd. 22 Lefkonos Street, 2064 Nicosia, Cyprus Oil and gas exploration, development and production 100 100 Energean Italy S.p.a. 31 Foro Buonaparte, 20121 Milano, Italy Oil and gas exploration, development and production 100 100 Energean Sicilia S.r.l. Via Salvatore Quasimodo 2 - 97100 Ragusa (Ragusa) Oil and gas exploration, development and production 100 100 Energean Exploration Ltd. One Great Cumberland Place, London,W1H 7AL, United Kingdom Oil and gas exploration, development and production 100 100 Energean UK Ltd. One Great Cumberland Place, London,W1H 7AL, United Kingdom Oil and gas exploration, development and production 100 100 Energean Egypt Energy Services JSC Block #17, City Center, 5th Settlement, New Cairo, 11835, Egypt Oil and gas exploration, development and production 100 100 Energean Investments Ltd. One Great Cumberland Place, London,W1H 7AL, United Kingdom Oil and gas exploration, development and production 100 100 Energean West Africa Ltd. 22 Lefkonos Street, 2064 Nicosia, Cyprus Oil and gas exploration, development and production 100 100
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Name of subsidiary Country of incorporation / registered office Principal activities Shareholding At 30 June 2026 (%) Shareholding At 31 December 2025 (%) Enearth Limited 22 Lefkonos Street, 2064 Nicosia, Cyprus Holding Company 100 100 Enearth Greece S.A. 32 Kifissias Avenue, Marousi Athens, 151 25, Greece Carbon Capture Storage 100 100 28. Exploration, development and production interests Development and production: Country Licence/unit area Fields Fiscal regime Group's working interest Joint operation Operator Israel Karish Karish North, Karish Main Concession 100% No NA Tanin Tanin Concession 100% No NA Katlan Katlan Concession 100% No NA Egypt Abu Qir Abu Qir, Abu Qir North, Abu Qir West, Yazzi (32.75%) PSC 100% No NA NEA Yazzi (67.25%), Python PSC 100% No NA NI Field A (NI-1X), Field B (NI- 3X), NI-2X, Viper (NI-4X) PSC 100% No NA Greece Prinos Prinos, Prinos North, Epsilon Concession 100% No NA South Kavala Concession 100% No NA Katakolo Katakolo Concession 100% No NA Italy C.C6.EO Vega A (Vega B, undeveloped) Concession 100% Yes Energean B.C8.LF Rospo Mare Concession 100% Yes Energean Fiume tenna Verdicchio Concession 100% No Energean B.C7.LF Sarago, cozza, vongola Concession 95% Yes Energean Garaguso Accettura Concession 50% Yes Energean A.c14.AS Rosanna and Gaia Concession 50% Yes ENI A.C15.AX Valentina, Raffaella, Emanuela, Melania Concession 10% Yes ENI Masseria Monaco Appia and Salacaro (undeveloped) Concession 50% Yes Energean G.C1.AG Cassiopea , Gemini, Centauro Concession 40% Yes ENI B.C14.AS Calipso and Clara West Concession 49% Yes ENI B.C20.AS Carlo, Clotilde e Didone (undeveloped) Concession 49% Yes ENI Montignano Cassiano and Castellaro Concession 50% Yes Energean B.C13.AS Clara Est, Clara Nord, Clara NW, (Cecilia undeveloped) Concession 49% Yes ENI Comiso (EIS) Comiso Concession 100% No NA A.c13.AS Daria, (Manuela, Arabella, Ramona, undeveloped) Concession 49% Yes ENI B.C10.AS Emma West and Giovanna Concession 49% Yes ENI A.C36.AG Fauzia Concession 40% Yes ENI Torrente menocchia Grottammare (undeveloped) Concession 88% Yes Petrorep Montegranaro Leoni Concession 50% Yes Gas Plus Lucera Lucera Concession 5% Yes GPI Monte Urano San Lorenzo Concession 40% Yes Energean A.C21.AG Naide Concession 49% Yes ENI Colle di lauro Portocannone Concession 62% Yes Energean Porto civitanova Porto civitanova Concession 40% Yes GPI Quarto Quarto Concession 33% Yes Padana Energia A.C17.AG Regina Concession 25% Yes ENI S. Andrea Concession 50% Yes Canoel B.C2.LF San Giorgio Mare Concession 95% Yes Energean San Marco San Marco Concession 100% No Energean B.C1.LF Santo Stefano Concession 95% Yes Energean Mafalda Sinarca Concession 40% Yes Gas Plus B.C9.AS Squalo Centrale Concession 33% Yes ENI Massignano Talamonti Concession 50% Yes Energean Masseria Grottavecchia Traetta Concession 14% Yes Canoel S. Anna (EIS) Tresauro Concession 25% Yes Enimed Torrente Celone Vigna Nocelli (Masseria Conca undeveloped) Concession 50% Yes Rockhopper Italia UK Tors Garrow, Kilmar Concession 68% Yes Energean Markham Concession 3% Yes Spirit Energy
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Country Licence/unit area Fields Fiscal regime Group's working interest Joint operation Operator Scott Concession 10% Yes CNOOC Telford Concession 16% Yes CNOOC Wenlock Concession 80% Yes Energean Croatia Izabela, Irena PSC 70% No EdINA A joint relinquishment application in respect of Carlo, Clotilde e Didone (Italy) was submitted to MASE on 25 May 2026 and remains subject to Government approval as at the date of these financial statements. Exploration: Country Concession Fields Fiscal regime Group's working interest Joint operation Operator Israel Blocks 23 Concession 100% No NA Blocks 31 Concession 100% No NA Egypt East North Bir El Nus PSC 50% Yes Energean Greece Block-2 Concession 30% Yes Energean Prinos Prinos CO2 Storage Concession 100% No NA Italy G.R13.AG Lince prospect Concession 40% Yes ENI G.R.14.AG Panda, Vela prospect Concession 40% Yes ENI Relinquished and are in the decommissioning phase: Country Licence/unit area Fields Fiscal regime Group's working interest Joint operation Operator UK Tors Kilmar (P683) Concession 68% Yes Energean Garrow Garrow (P1034) Concession 68% Yes Energean Wenlock Concession 80% Yes Energean Italy Candela Candela Concession 40% Yes ENI Capparuccia Capparuccia Concession 5% Yes ENI Masseria Acquasalsa Palmori Concession 45.2% Yes GPI Monte Castellano Carassai Concession 50% and 67.63% Yes ENI S. Benedetto del Tronto S. Benedetto Concession 12.5% Yes ENI Tempa rossa Demma Locantore Concession 30% Yes ENI B .C21.AG Fabrizia /Jole Concession 49% Yes ENI A.C8.ME Anemone and Azelea Concession 19% and 15.675% Yes ENI [1] Average Group August 2026 production (including Cassiopea) was 165 Kboe/d and reflects the planned shutdown for the first Katlan heavy lift operation between 23 - 26 August 2026. [2] Guidance excludes Cassiopea. [3] Internal estimate includes prospectivity on existing licences and is based on Pmean Gas Initially In Place ("GIIP"). Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success. [4] Includes Cassiopea. [5] Cash cost of production is defined later in the financial review.
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[6] Cash G&A is defined later in the financial review. [7] Adjusted EBITDAX is defined later in the financial review. Energean uses adjusted EBITDAX as a core business KPI. [8] Leverage calculated using last 12-months average Adjusted EBITDAX. [9] Production includes Cassiopea (2 Kboe/d net to Energean's 40% working interest in H1 2026; H1 2025: 6 Kboe/d). [10] Sales volumes are reported on a net entitlement basis in Egypt and excludes Cassiopea volumes from 1 October 2025 (refer to Note 30 in the Group's Annual Report for the year ended 31 December 2025 and Notes 4 and 25 to the interim condensed consolidated financial statements). Accordingly, Cassiopea revenues in H1 2026 are presented within 'Other revenue from production activities', whereas in H1 2025 they were presented within 'Revenue from gas sales'. [11] Guidance excludes Cassiopea. [12] Average Group August 2026 production (including Cassiopea) was 165 Kboe/d and reflects the planned shutdown for the first Katlan heavy lift operation between 23 - 26 August 2026. [13] Excludes flux revenues in Italy. [14] Internal estimate includes prospectivity on existing licences and is based on Pmean GIIP. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success. [15] Actuals include capitalised borrowing costs and management services, not included in the FID amount. [16] Energean has a 30% working interest in the Block 2 licence. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success. [17] Includes flux costs in Italy. [18] Free cash flow is defined as cash flow from operating activities less cash flow for investing activities. [19] Energean has a 30% working interest in the Block 2 licence. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success. [20] Production includes Cassiopea (2 Kboe/d net to Energean's 40% working interest in H1 2026; H1 2025: 6 Kboe/d; 8-months to 31 August 2026: 2 Kboe/d). [21] Guidance excludes Cassiopea. [22] Average Group August 2026 production (including Cassiopea) was 165 Kboe/d and reflects the planned shutdown for the first Katlan heavy lift operation between 23 - 26 August 2026. [23] Includes temporary suspension between 28 February and 9 April 2026. Excluding this shutdown, Israel liquids production averaged 13 kbbl/d in H1 2026. [24] Internal estimate includes prospectivity on existing licences and is based on Pmean GIIP. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success. [25] Internal estimate based on Pmean GIIP. [26] Internal estimate based on Pmean prospective resources, shown net of Energean's 50% working interest and after application of recovery factors, but before chance of success. [27] Production includes Cassiopea (2 Kboe/d net to Energean's 40% working interest in H1 2026; H1 2025: 6 Kboe/d). [28] Internal estimate based on Pmean prospective resources, with gross volumes shown (i.e. before Energean's 70% working interest) and after application of recovery factors, but before chance of success. [29] Energean has a 30% working interest in the Block 2 licence. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success. [30] Guidance excludes Cassiopea. [31] Development and production capital expenditure, exploration expenditure and decommissioning expenditure guidance are presented on an accrual basis and not on a cash basis. [32] Includes 4.7-4.9 bcm of gas. SCM to BOE conversion factor for Israel used is 153.78. [33] Note that flux in Italy is not reflected in the production guidance but is included in sales revenue actuals. [34] Guidance excludes $70-75 million of contingent Prinos Carbon Storage expenditure which is expected to be funded by grants. [35] Energean Group including gas production from Cassiopea in Italy. This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authorityto act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this informationmay apply. For further information, please contact rns@lseg.com or visit www.rns.com. RNS may use your IP address to confirm compliance with the terms and conditions, to analyse how you engage with the informationcontained in this communication, and to share such analysis on an anonymised basis with others as part of our commercial services. Forfurther information about how RNS and the London Stock Exchange use the personal data you provide us, please see our Privacy Policy. END