Interim report
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15 September 2026 AFENTRA PLC 2026 HALF YEAR RESULTS Afentra plc ('Afentra' or the 'Company') (AIM: AET), the upstream oil and gas company focused on production and development assets in Africa, is pleased to announce its half year results for the six months ended 30 June 2026 (the ‘Period’ or ‘H1 2026’). H1 2026 Summary Key Highlights - Block 3/05 Drilling: o Pacassa SW successful oil discovery; revised completion plan being finalised; o Impala-2 expected to be second well in drilling programme - Strategic Review: Afentra to pursue next phase of growth as an independent E&P company - Refinancing: cost of capital reduced with completion of $125m Gunvor prepayment facility - Equity Raise: completed heavily oversubscribed $40m placing and £2m retail offer at 67p/share - Etu Acquisition: expected to complete in Q3 2026, increasing equity interests in Blocks 3/05 & 3/05A - Kwanza Onshore: eFTG survey completed; KON4 licence awarded - Net Average Production: 5,777 bopd in H1 2026; averaging 6,236 bopd during July/August 20261 - Crude Oil Sales & Revenue: o two liftings totalling ~1.0 mmbbls at an average $91.3/bbl, generating $91.0 million o post-period lifting of 452,024 bbls in July at $84.1/bbl, generating $38.0 million - Financial Position: Cash of $97.4 million, Net cash of $28.4 million at 30 June 2026 Financial Highlights (As at and for six months ended 30 June 2026) - Revenue of $91.0 million2 - Cash resources of $97.4 million - Total debt of $70 million - Net cash of $28.4 million3 - Adjusted EBITDAX of $41.9 million - Company financial position strengthened significantly with new $125m debt facility and $40m equity raise o Gunvor prepayment facility put in place at significantly reduced cost of debt and trading costs; $70 million drawn with additional availability of $30 million in 2026 and $25 million in 2027 o Heavily oversubscribed equity fundraising of $40 million completed at 67 pence per share, together with additional £2.0 million WRAP Retail Offer - Crude Oil Sales o Two liftings of 997,252 bbls at average price of $91.3/bbl sold, generating revenue of $91.0 million o Post-period lifting of 452,024 bbls completed in July at an average $84.1/bbl, generating revenue of $38.0 million o Two additional liftings of ~450,000 bbls each anticipated in the remainder of 2026 - Hedging activity continued during the period and post period-end, resulting in approximately 49% of 2026 remaining forecast sales being hedged through a combination of puts and collars, with floor prices ranging from $60–85/bbl and collar caps ranging from $77.5–117.6/bbl; for 2027, approximately 24% of forecast sales are currently hedged, with floor prices of $70/bbl and collar caps ranging from $82–103/bbl4 - Post period-end, a cash call of ~$28 million was issued and paid in July, bringing JV funding broadly in line with the expected H1 budget Operational and Corporate Highlights Strategic Review - Following the comprehensive strategic review announced in March 2026, the Board determined, after considering a number of strategic options, including offers for the company, that pursuing Afentra’s next phase of growth as an independent E&P company offers the greatest opportunity to maximise shareholder value. Reserves & Resources - Independent year-end 2025 assessment confirmed net 2P WI reserves of 31.9 mmbo and in January Afentra announced a fourfold increase in 2C working interest contingent resources to 87.3 mmboe across Blocks 3/05, 3/05A and 3/24, based on both independent and management assessments. Block 3/05 and Block 3/05A - Pacassa SW: well was spudded in April as the first well in the two-well drilling programme, drilling progressed through the period. Post period end, the well reached total Measured Depth of 5,381 metres, encountering a 217m gross oil-bearing reservoir section with 136 metres of net oil pay; the well encountered significant losses in the reservoir section indicating high permeability from fractures as well as a level of depletion; the interpreted oil-water contact is consistent with that encountered in the main Pacassa field. Completion operations encountered challenges resulting in a failed packer restricting access to the wellbore. The joint venture is progressing plans to sidetrack the well to bypass the obstruction and enable the completion equipment to be run. Consideration is currently being given to either continuing to complete Pacassa SW or moving the rig to Impala-2 while the necessary planning and equipment mobilisation are completed. The commercial arrangements previously agreed with Sonangol mean that the Company has no exposure to the incremental costs arising from these additional Pacassa SW operations.
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- Impala-1: post period-end, the well was successfully returned to production following a well intervention, testing at up to approximately 4,700 bopd and subsequently producing at approximately 3,000 bopd before being shut in to accommodate preparations for Impala-2. - Impala-2: is expected to be the second well in the two-well drilling programme, with preparations advanced and timing subject to finalisation of the Pacassa SW completion plan. The well is targeting initial production of approximately 4,000 bopd. A further update will be provided once the drilling sequence is confirmed. - Gross average production: for the period of 19,379 bopd (net: Block 3/05 5,688 bopd; Block 3/05A 90 bopd). Production reflected downtime associated with the positioning of the Borr Grid drilling unit over the Pacassa platform and a planned shutdown of the gas compression system to improve gas distribution. Post period-end, gross production averaged 20,897 bopd during July and August 2026 (net: Block 3/05 6,156 bopd; Block 3/05A 80 bopd). - The multi-year redevelopment plan: remains on track, underpinning increased reserves recovery and production growth. o Water injection averaged ~45,000 bwpd in the period, with rates of up to 70,000 bwpd achieved and a target of ~100,000 bwpd in H2 2026. Post period-end, water injection averaged approximately 56,000 bwpd during July and August 2026. o Infrastructure upgrades progressed across key platforms, with work completed at Pambi and ongoing at Cobo and Palanca. Palanca FSO works were completed and formal recertification received for a further five-year period. o Well intervention activities, including slickline, electric line and acid stimulation activities, have continued successfully across the asset. - Hydraulic workovers: Preparations for the hydraulic workover programme continued, with execution planned for early 2027. Block 3/24 - Activities in support of the GPQ development progressed. Post period end, Afentra safely completed its first operated offshore campaign, inspecting four GPQ subsea wellheads using a low-cost ROV operation. Onshore Kwanza basin - Acquisition of eFTG geophysical survey data was completed across all licensed areas, with initial results being interpreted and integrated with existing datasets to support prospect maturation and future work programme planning. - Post period-end, initial eFTG interpretation continued across KON4, KON15 and KON19; identifying a number of post-salt leads. A contract has been awarded for a 300 km 2D seismic acquisition on KON15, this is expected to commence in September 2026. In KON4, the leads identified are adjacent to the previously produced Quenguela Norte field and consideration is being given to the acquisition of a focused 2D seismic programme around Quenguela Norte in H1 2027. Portfolio expansion - The KON4 licence was formally awarded and signed. - Under the Etu transaction Afentra will acquire an additional 3.33% in Block 3/05 and 3.66% in Block 3/05A, following the decision by Sonangol to participate alongside Afentra and M&P, with completion expected in Q3 2026. Near-Term Catalysts - Completion of the Pacassa SW well - Commencement of Impala-2 drilling - Completion of the Etu transaction expected Q3 2026 - Operational update on the redevelopment of the KON4 Quenguela Norte field - Update on the assessment of the exploration potential across the Kwanza Onshore portfolio - Commencement of the Block 3/05 hydraulic workover programme planned for early 2027 Paul McDade, Chief Executive Officer, Afentra plc commented: "The first half of 2026 has been a period of significant strategic and financial delivery, marking our transition into the execution phase of our organic growth strategy with the first drilling in Block 3/05 in over a decade. The successful refinancing through our new $125 million Gunvor facility has reduced our cost of debt and trading costs, while providing the financial flexibility to support our ongoing investment programme. Combined with our strong underlying cash generation and the oversubscribed equity fundraising of over $40 million, this has materially strengthened our balance sheet and capital structure. The successful Pacassa SW oil discovery provides clear proof of concept for our offshore Angolan portfolio, supporting our view that the wider Pacassa SW area has the potential to contain up to 70 mmbo of gross recoverable resources. While completion operations encountered an obstruction that will require a sidetrack to bring the well onstream, our existing commercial agreement ensures we have no financial exposure to these additional costs. Preparations for the Impala-2 development well continue, with the timing and drilling sequence currently being finalised. Onshore, our high-resolution eFTG programme is already yielding results, which, alongside the upcoming seismic work, will allow us to progress the redevelopment of the Quenguela Norte field and define a broad portfolio of exploration prospectivity over the next six to 12 months. Looking forward, the completion of Pacassa SW, the drilling of Impala-2, the anticipated completion of the Etu acquisition and the commencement of onshore 2D seismic acquisition provide an active period with multiple near-term catalysts. We now have multiple pathways across our offshore and onshore portfolio to deliver the material production and reserves growth we have been building towards, and we look forward to updating shareholders on our progress." Supporting Presentation A presentation has been uploaded to Afentra’s website – please view here: https://wp-afentra-2025.s3.eu-west- 2.amazonaws.com/media/2026/09/2026.08-HY26-Results-presentation.pdf For further information contact: Afentra plc +44 (0)20 7405 4133 Paul McDade, CEO Anastasia Deulina, CFO Christine Wootliff, Investor Relations Burson Buchanan (Financial PR) +44 (0)20 7466 5000 Barry Archer Louise Mason-Rutherford
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Stifel Nicolaus Europe Limited (Nominated Adviser and Joint Broker) +44 (0)20 7710 7600 Callum Stewart Simon Mensley Ashton Clanfield Tennyson Securities (Joint Broker) +44 (0)20 7186 9033 Peter Krens --------------------------------------- 1. Production figures are reported on a net (working interest) basis; net entitlement volumes are reflected in revenue and cash flow reporting. 2. Revenue is net of the state’s fiscal take (cost oil and profit oil allocation), but prior to deduction of petroleum income tax (PIT). 3. Net cash comprises cash less debt principal drawn adjusted for accrued interest, capitalised costs and lease liabilities. 4. Refer to the accompanying H1 2026 presentation for further details of the Company's hedge portfolio, including collar structures, floor prices andceiling prices. About Afentra Afentra plc (AIM: AET) is an upstream oil and gas company focused on opportunities in Africa. The Company's purpose is to support a responsible energy transition in Africa by establishing itself as a credible partner for divesting IOCs and host governments. Offshore Angola, in the Lower Congo Basin, Afentra holds a 30% non-operated interest in the producing Block 3/05, a 21.33% non- operated interest in Block 3/05A, and a 40% operated interest in Block 3/24, both Blocks 3/05A and 3/24 are located adjacent to Block 3/05. Onshore Angola, in the western part of the onshore Kwanza basin, Afentra holds a 35% operated interest in Block KON4 and 45% non-operated interests in the prospective Blocks KON15 and KON19. Afentra also holds a 40% non-operated interest in the offshore exploration Block 23 in the Kwanza Basin. More information is available at www.afentraplc.com or by visiting Afentra’s Curation Showcase. Inside Information This announcement contains inside information for the purposes of article 7 of Regulation 2014/596/EU (which forms part of domestic UK law pursuant to the European Union (Withdrawal) Act 2018) and as subsequently amended by the Financial Services Act 2021 ('UK MAR'). Upon publication of this announcement, this inside information (as defined in UK MAR) is now considered to be in the public domain. For the purposes of UK MAR, the person responsible for arranging for the release of this announcement on behalf of Afentra is Paul McDade, Chief Executive Officer. Standard Estimates of reserves and resources have been prepared in accordance with the June 2018 Petroleum Resources Management System ("PRMS") as the standard for classification and reporting. Technical Information The technical information contained in this announcement has been reviewed and approved by Robin Rindfuss, Head of Sub- Surface at Afentra plc. Robin Rindfuss has over 30 years of experience in oil and gas exploration, production and development. He is a member of the Society of Petroleum Engineers (SPE) and holds a Bachelor of Science (BSc) and a Bachelor of Science Honours (BSc Hons) in Physics and Mathematics from the University of Cape Town. CEO Statement I am pleased to present our half year results for the period ended 30 June 2026, a period of very significant progress in Afentra’sjourney. The first six months of 2026 marked an important step into the next phase of operational delivery, supported by astrengthened capital structure and continued progress across our Angolan portfolio. The scale of the organic growth opportunityacross the portfolio was further demonstrated by our January resource update, which increased Afentra’s total 2P and 2C working-interest reserves and resources across Blocks 3/05, 3/05A and 3/24 to 120 mmboe. A major milestone during the period was the conclusion of our comprehensive Strategic Review. Initiated in January and announcedin March 2026, the Board carefully evaluated a range of strategic options to maximise value from our high-quality Angolan portfolio,including potential offers for the Company. Following this thorough process, the Board determined that pursuing our next phase ofgrowth as an independent E&P company offers the most compelling path to maximise long-term shareholder value. To support this independent growth strategy and optimise our capital structure, we successfully completed a debt refinancing andequity fundraising in May and June 2026 respectively. We secured a new $125 million Pre-Payment Facility with Gunvor Group,replacing our previous Reserve-Based Lending and Working Capital facilities. This facility significantly reduces our cost of capitaland cost of trading, enhances our funding flexibility, providing the financial structure we require to support our ongoing investmentprogramme. Alongside this, we completed an oversubscribed $40 million equity placing at 67p per share. The placing was stronglysupported by both new and existing institutional investors. To ensure we also provided an opportunity for our retail shareholders, wecomplemented the institutional equity placing with a £2.0 million WRAP Retail Offer, which was also heavily oversubscribed.Together with our strong underlying cash generation, these transactions materially strengthened our capital structure and liquidity. At30 June 2026, cash resources were $97.4 million and net cash was $28.4 million. During the first half of the year, we completed the first two of five planned 2026 liftings totalling approximately 1.0 million barrels at anaverage realised price of $91.3/bbl and generating $91.0 million in revenue. Our financial resilience is further underpinned by ourdisciplined hedging strategy, which continues to protect our cash flows against commodity price volatility. We have actively managedour exposure, with approximately 49% of 2026 remaining forecast sales currently hedged using collar structures that secure a firmfloor price while preserving meaningful exposure to oil price upside. Post period, we completed a further lifting of approximately450,000 barrels in July at an average realised price of approximately $84/bbl. Operationally, the first half of 2026 saw the commencement of the first drilling campaign on Block 3/05 in over a decade. Post periodend, the Pacassa SW well delivered a successful oil discovery, with 136 metres of net oil pay supporting our view that the wider area
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has the potential to contain up to 70 mmbo of gross recoverable resources. Completion operations encountered a wellboreobstruction and the joint venture is progressing plans to sidetrack the well to allow it to be completed and brought onstream. Thefinal completion plan and drilling sequence are currently being finalised. Pacassa SW is being financed by Sonangol under a carryarrangement, with a capped level of cost recovered from future incremental production revenues. Also post period-end, a successful intervention returned Impala-1, which had been shut in since 2017, to production. The well testedat approximately 4,700 bopd and subsequently produced at approximately 3,000 bopd to manage water production and longer-termreserves recovery, before being temporarily shut in to accommodate preparations for Impala-2. Impala-2 is expected to be thesecond well in the two-well drilling programme, with timing subject to finalisation of the Pacassa SW completion plan. Together,Pacassa SW and Impala-2 target a potential gross production uplift of approximately 9,000 bopd and gross recoverable resources ofover 100 mmbo. Our cornerstone Block 3/05 and 3/05A assets delivered a net average production of 5,777 bopd during the first half of 2026.Production was temporarily impacted by planned downtime for gas compression upgrades and the positioning of the Borr Griddrilling unit over the Pacassa wellhead platform. Operations have since been restored. Net production during July and Augustaveraged approximately 6,236 bopd, reflecting restored operations. Working with Sonangol as operator and our joint venturepartners, we continued to advance the multi-year redevelopment programme. Water injection averaged approximately 45,000 bwpdand reached rates of up to 70,000 bwpd, sustained injection rates of approximately 100,000 bwpd are targeted during H2 2026. Anumber of well interventions were completed and further infrastructure upgrades and asset integrity programmes were progressed.The joint venture also completed the Palanca FSO recertification, securing its operational licence for an additional five-year periodwithout the need for drydocking. In parallel, we have made significant progress on Block 3/24, our first offshore operatorship in Angola. With a management-estimated gross 2C resource of 92.4 mmboe across the block, we are progressing development studies to assess options to maturethese discoveries, providing a potential infrastructure-led route to future operated growth. The initial GPQ (Golungo, Palancanortheast, Quissama) development provides a low-cost, short-cycle opportunity, with the discoveries located approximately 5 kmfrom the existing Block 3/05 producing infrastructure. During the period, we advanced operational activities in support ofdevelopment planning. Post period end, a survey vessel programme was successfully completed in July, including wellheadinspections. Our strategic portfolio expansion remains on track, with the Etu transaction expected to complete in Q3 2026, which will increase ourworking interests in Blocks 3/05 and 3/05A to 33.33% and 24.99% respectively. Also onshore in the Kwanza Basin, we achieved amajor strategic milestone with the formal award and signing of the KON4 Risk Service Contract, where Afentra is operator with a35% interest. KON4 contains the large, prematurely abandoned Quenguela Norte oil field and offers immediate redevelopmentpotential alongside material exploration upside. Onshore we have already completed the acquisition of the high-resolution eFTG geophysical survey data across our onshorelicensed areas, (KON4, 15 & 19) and technical studies are progressing to assemble a full prospect inventory. Initial interpretation hasidentified a number of post-salt leads, supporting the next phase of targeted seismic activity. A 300km 2D seismic programme onKON15 is expected to commence in September 2026, while a focused programme is being considered for KON4 in H1 2027, as weseek to mature these leads and build the pipeline of future drilling opportunities. Looking forward, Afentra is in a strong position to deliver on the next phase of value creation. With our strengthened capital structureand liquidity, the financial flexibility of the new Gunvor facility, and continued operational delivery across our offshore and onshoreportfolio, we have the capacity to advance our growth strategy. The results from Pacassa SW and Impala-1, together with theplanned Impala-2 development well, reinforce the scale of the organic growth opportunity within Block 3/05. Together with theexpected completion of the Etu acquisition in Q3 2026, these developments provide multiple pathways to deliver the production andreserves growth and value delivery we have been building towards. We remain focused on maintaining strict capital discipline as weadvance our investment programme and pursue further growth opportunities. We look forward to updating shareholders on ourprogress. Paul McDade Chief Executive Officer Afentra plc Operations Summary Offshore Blocks Block 3/05 (30% current non-operated)Operational activity on Block 3/05 accelerated significantly during the first half of 2026, marked by the commencement of the firstdrilling campaign on the asset in over a decade. The programme targets a potential gross production uplift of ~9,000 bopd and grossrecoverable resources of over 100 mmbo.Gross average production for the six months ended 30 June 2026 was 18,959 bopd (Net: 5,688 bopd). Production during the periodwas impacted by downtime associated with the positioning of the Borr Grid jack-up drilling unit over the Pacassa platform, as well asa planned shutdown of the gas compression system to improve field-wide gas distribution. Production, water injection, and gascompression have since been fully restored. Asset uptime remained stable throughout the period, supported by continued progressacross the asset revamping and integrity workstreams. Pacassa SW: The Pacassa SW well was spudded in April 2026, following period-end, it reached a total Measured Depth of 5,381metres and encountered a significant oil-bearing reservoir section in the fractured Albian Pinda carbonate formation in line with pre-drill expectations. Evaluation of wire logging data and oil shows has identified gross hydrocarbon-bearing interval of 217 metres,containing an estimated 136 metres of net oil pay, characterised by good quality and fractured reservoir intervals, with the interpretedoil-water contact consistent with that observed in the main Pacassa field. Initial pressure indications suggest limited pressuredepletion, confirming communication with the main Pacassa field. During completion operations, a packer failed, restricting access tothe wellbore. The joint venture is progressing plans to sidetrack the well to bypass the obstruction and enable the completionequipment to be run. If the sidetrack cannot proceed immediately, consideration is being given to moving the rig to Impala-2 whilethe necessary planning and equipment mobilisation are completed, before returning to complete Pacassa SW. The final completionplan and drilling sequence are expected to be confirmed shortly. Once completed, the well will be connected to the existing Pacassaproduction infrastructure, with sustainable production rates to be established following well clean-up and flow-back operations. Impala-1: Post period-end, the Impala-1 well, which had been shut in since 2017, was successfully returned to production as part ofthe 2026 light well intervention (LWI) programme. Following a slickline intervention to clear a wellbore obstruction, the well achievedgross flow rates of up to ~4,700 bopd during testing and was then produced at a constrained rate of ~3,000 bopd to optimise
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reservoir performance. The well has subsequently been shut in to accommodate preparation activities for the rig arrival to drillImpala-2. The intervention has provided valuable reservoir pressure and productivity data which was incorporated into the final wellplanning for Impala-2. Impala-2: Impala-2 is expected to be the second well in the two-well drilling programme, with preparations advanced and timingsubject to finalisation of the Pacassa SW completion plan. The development well will target the Impala field approximately 1,000metres from the existing Impala-1 well and, once commenced, is expected to take approximately 80 days to drill and complete. Thewell targets an initial production rate of approximately 4,000 bopd and, if successful, would represent the beginning of the next phasein the redevelopment of the Impala field. Well Funding: During the period, the Block 3/05 partners entered into a commercial agreement with Sonangol under whichSonangol would finance the planned two-well drilling programme, with costs, up to an agreed cost cap, recovered from futureincremental production revenues from the wells. Production Optimisation and Asset IntegrityWell intervention activities have also continued across the asset during the first half of the year comprising slickline, electric line, andacid stimulation programmes focused on optimising production and improving well performance. Preparations for the hydraulicworkover programme are ongoing, with execution expected to commence in early 2027. The multi-year infrastructure revamping and integrity programme remains on track to support long-term reserves recovery. Assetuptime remained stable throughout the period, supported by the continued progress of our integrity workstreams, while operatingcosts (Opex) continued to track in line with our established baseline of approximately $23/bbl. Water injection averaged ~45,000 bwpd during the period, with rates of up to 70,000 bwpd achieved. Post period-end, water injectionaveraged ~56,000 bwpd during July and August. Upgrades continue to target sustained water injection rates of ~100,000 bwpd in H22026. Infrastructure upgrades to improve platform reliability were completed at the Pambi platform and remain ongoing at the Coboand Palanca platforms. Additionally, the Palanca FSO maintenance works were successfully completed, and formal recertificationwas received for a further five-year period, securing the vessel's operational life and avoiding drydocking until beyond 2030. We remain on track to deliver the planned 2026 production optimisation and asset integrity capital investment programme for Blocks3/05 and 3/05A of approximately $163 million gross (Net: $50 million), covering continued asset integrity, revamping and wellintervention activities. Block 3/05A (21.33% current non-operated / 24.99% post-Etu completion)Production from the Gazela field averaged 420 bopd gross (Net: 90 bopd) during the first half of 2026. Technical evaluations andsubsurface mapping of the Caco and Gazela fault compartments are ongoing to refine the optimal development strategy and de-riskthe long-term resource potential of the block's undeveloped discoveries, which hold an estimated 98 mmbo gross 2C recoverableresources. H1 2026 Production from Blocks 3/05 and 3/05A Production Gross Net Block 3/05 18,959 5,688 Block 3/05A 420 90 Total 19,379 5,777 Net production figures are reported on a working interest basis (30% for Block 3/05 and 21.33% for Block 3/05A) prior to the completion of the Etu transaction. Block 3/24 (40% operated)Operational activities in support of the GPQ (Golungo-Palanca NE-Quissama) development progressed during the period. Postperiod end, Afentra completed its first operated offshore campaign on Block 3/24 inspecting the Palanca NE, Quissama-1,Quissama-2 and Golungo-1 subsea wellheads and acquiring video, measurement and well integrity data. No hydrocarbon leakage orseepage was observed, and the campaign was completed with zero safety or environmental incidents. The data acquired will support the maturation of the GPQ development towards FID, targeted for H1 2027. The campaign, managedby Afentra, utilised a compact ROV from a local vessel at a total cost of ~$60k, delivering a significant saving against standardcontractor quotes of $500k to $1.0 million. Subsurface work continues to assess the various hydrocarbon discoveries and thebroader exploration potential within the block. Block 23 (40% non-operated)Block 23, a 5,000 km² deepwater exploration and appraisal block in the offshore Kwanza Basin, remains under-explored with nooutstanding work commitments. Afentra continues to monitor regional activity, including progress on the adjacent Kaminhodeepwater development to the north, to assess commercialisation pathways. Onshore Kwanza Basin Blocks KON4 (35% operated), KON15 (45% non-operated) & KON19 (45% non-operated)Afentra consolidated its material position in the proven, under-explored onshore Kwanza Basin during the first half of 2026. The RiskService Contract (RSC) for Block KON4 was formally approved and signed, confirming Afentra as Operator with a 35% interest.KON4 contains the Quenguela Norte field, the largest onshore discovery in the basin, estimated to hold over 200 mmbbls ofdiscovered oil-in-place. The acquisition of the high-resolution enhanced Full Tensor Gravity Gradiometry (eFTG) geophysical survey data was successfullycompleted across all licensed onshore areas. Initial results are currently being interpreted and integrated with legacy seismic andwell datasets to update the subsurface models and play analysis. KON4: Subsurface studies are underway to assess the reactivation of the Quenguela Norte field. Following the eFTG completioncovering the Block, planning is progressing for a potential phased redevelopment, beginning with an initial pilot phase involving re-entry of a number of wells to validate reservoir performance and inform the scope of a wider redevelopment. Subject to regulatoryapprovals and permitting, the pilot is targeted for H2 2027. Initial eFTG interpretation has also highlighted prospective fault blocksadjacent to the field, and a focused 2D seismic programme is being considered for H1 2027 to better understand this prospectivity. KON15 & KON19: Technical studies are progressing toward assembling a full prospect inventory, with interpretation of the highresolution eFTG survey and legacy 2D seismic used to identify a number of post-salt leads within KON15. Environmental andregulatory preparations are ongoing to support 2D seismic acquisition. A contract has been awarded for 300km of 2D seismic
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acquisition on KON15, with acquisition expected to commence in September 2026. The programme will focus on infill of the legacy2D seismic and support the maturation of potential future drilling prospects. Financial Review During the first half of 2026, following the conclusion of the Strategic Review, the Group entered its next phase of growth as an independent E&P company in a strong financial position having refinanced our debt facility at a lower cost of capital and completing an oversubscribed equity fundraising. The Block 3/05 JV partnership also commenced the first drilling campaign on the block in over a decade. In March 2026, the Block 3/05 partners entered into a commercial agreement with Sonangol under which Sonangol would finance the planned two-well programme, with costs, up to an agreed cost cap, recovered from future incremental production revenues from the wells being drilled. In May 2026, we entered into a prepayment financing arrangement with Gunvor, structured in two tranches and with a four-yeartenor. The new facility comprises $125 million of committed capacity ($100 million initial advance plus $25 million subsequentadvance available in 2027 subject to certain conditions), with an uncommitted accordion to scale the facility size based on futureproduction growth. During the period we drew down $70 million of this facility with a further $30 million expected to be drawn later in2026. The additional $25m is expected to be drawn in 2027. The facility has replaced our previous debt facilities and is securedagainst future crude oil deliveries from our Angolan assets, with repayment primarily effected through cargo liftings. In June 2026, we successfully completed an equity placement in two tranches, as well as a retail offer, at 67p/share, raising an additional $40.3 million, net of associated transaction costs. Strong demand resulted in a heavily oversubscribed book, with 52% of the institutional placing allocated to 21 new institutional investors alongside continued support from existing institutional and retail shareholders. The transaction materially broadened and diversified our shareholder register and increased our long-only institutional ownership. Our balance sheet at the end of June 2026 included $97.4 million in cash ($10.2 million at 31 December 2025, inclusive of restricted cash balances), and an end of period net cash position of $28.4 million (net debt of $21.8 million at 31 December 2025). A Block 3/05 cash call of approximately $28 million was issued and paid in July, bringing JV funding broadly back in line with the expected H1 budget run-rate. A full reconciliation of net cash and net debt is provided in note 8 to the Financial Statements. Our Debt to Annualised EBITDAX ratio increased slightly from 0.7x at 30 June 2025 to 0.8x at 30 June 2026. Together, the refinancing and equity raise have transformed the Group’s balance sheet and materially strengthened our funding position and liquidity, providing flexibility to fund the current investment programme and pursue further value-accretive growth. Our financial priorities remain maintaining sufficient liquidity, ensuring hedging provides appropriate oil price exposure, managing leverage and deploying capital in a disciplined manner across the portfolio. We completed two planned crude oil liftings during the period, at an average realised price of $91.3/bbl, resulting in revenue of $91.0 million. Post period, in July 2026, we sold our third cargo of crude oil of 452,024 barrels at a sales price of $84.1/bbl resulting in additional revenue of $38.0m. The purchase of an additional interest in Blocks 3/05 and 3/05A from Etu Energias is expected to complete during Q3 2026. At completion our participating interest in Block 3/05 will increase to 33.33% and our participating interest in Block 3/05A will increase to 24.99%. The effective date of the transaction is 31 December 2023, which is expected to result in a significantly reduced payment on completion. The completion of the acquisition is subject to the satisfaction of customary conditions precedent, including approval by the relevant governmental agencies and the operator. Strategically, the acquisition consolidates Afentra's position across its core offshore portfolio, enhances alignment within the joint venture, and delivers an immediate uplift in production and reserves. Onshore Angola, in May 2026, we were awarded a 35% operated interest in KON4 alongside our local Angolan partners Grupo Simples Oil, Sonangol E&P, Brite's Oil and Gas and Sodedurs. The award of KON4 further strengthens our position in the onshore Kwanza basin and expands our operated portfolio in Angola. We continue to manage our exposure to oil price risk through our hedging strategy. Hedging activity during the period and post period-end has resulted in approximately 49% of 2026 remaining forecast sales being hedged through a combination of puts and collars, with floor prices ranging from $60–85/bbl and collar caps ranging from $77.5–117.6/bbl. For 2027, approximately 24% of forecast sales are currently hedged, with floor prices of $70/bbl and collar caps ranging from $82–103/bbl. The hedging programme will continue to be under active review to evaluate further hedging opportunities. For the remainder of 2026, our financial focus remains on the disciplined funding and execution of the investment programme, completion of the Etu acquisition and continued assessment of value accretive growth opportunities in Angola as well as in selected West African jurisdictions. Selected financial data For the six months ended 30 June 2026 30 June 2025 Sales volume mmbo 1.0 0.7 Realised oil price $/bbl 91.3 72.2 Total revenue $ million 91.0 52.0 Adjusted EBITDAX $ million 41.9 27.9 (Loss)/profit after tax $ million (1.5) 5.7
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Basic (loss)/earnings per share Cents (0.7) 2.5 Diluted (loss)/earnings per share Cents (0.7) 2.2 As at 30 June 2026 31 December 2025 Cash and cash equivalents $ million 97.4 5.1 Restricted funds $ million - 5.0 Borrowings $ million (70.0) (31.1) Net cash/(debt) $ million 28.4 (21.8) Share price Pence 59.2 41.4 Non-IFRS measures The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. EBITDAX (Adjusted) represents earnings before interest, taxation, depreciation, total depletion and amortisation, impairment and expected credit loss allowances, share-based payments, provisions, and pre-licence expenditure. Additionally, in any given period, the Company may have significant, unusual or non-recurring items which may be excluded from EBITDAX (Adjusted) for that period. When applicable, these items are fully disclosed and incorporated into the reconciliation provided below. The Company believes this measure assists investors by excluding the potentially disparate effects between periods of the adjustments specified. Debt to EBITDAX is calculated as total debt divided by annualised EBITDAX and is presented to assist users of the financial statements in evaluating the Group’s financial leverage and its ability to service debt from operating earnings. EBITDAX (Adjusted) and Debt to EBITDAX are non-IFRS financial measures. EBITDAX (Adjusted) and Debt to EBITDAX should not be considered as alternatives to net income or any other indicator of Afentra plc’s performance calculated in accordance with IFRS. Because the definition of EBITDAX (Adjusted) and Debt to EBITDAX may vary among companies and industries, they may not be comparable to other similarly titled measures used by other companies. Income Statement Sales volumes increased in the first half of 2026 to 1.0 mmbbls compared to 0.7 mmbls during H1 2025. The increased sales volumes, combined with a higher average realised price of $91.3/bbl (H1 2025: $72.2/bbl), resulted in H1 2026 revenue, net of off- take fees, of $91.0 million (H1 2025: $52.0 million). Higher revenue was offset by an increase in cost of sales from $29.8 million during H1 2025 to $53.9 million in H1 2026, primarily due to higher volumes sold and losses on oil price derivatives. The profit from operations for H1 2026 was $17.5 million (H1 2025: $14.8 million). The increased gross profit described above was offset by early termination payments associated with the debt refinancing ($6.4 million) and losses on the revaluation of the contingent consideration provision ($5.5 million). Finance costs increased slightly during H1 2026 to $4.6 million (H1 2025: $4.1 million). The release of the unamortised capitalised arrangement fees following the debt refinancing was offset by lower interest on external borrowings as a result of scheduled repayments made on the RBL facility. Group adjusted EBITDAX totalled $41.9 million (2025: $27.9 million): Six months ended 30 June 2026 2025 $’ Million $’ Million (Loss)/profit after tax (1.5) 5.7 Net finance costs 4.6 4.1 Depletion and depreciation 11.1 11.0 Pre-licence costs 0.4 1.3 Loss on revaluation of contingent consideration provision 5.5 - Early termination fees 6.4 - Share-based payment charge 1.0 0.9 Taxation 14.4 4.9 Total EBITDAX (Adjusted) 41.9 27.9 No dividend was proposed to be paid for the six months ended 30 June 2026 (2025: nil). Statement of financial position As at 30 June 2026, non-current assets totalled $184.3 million (31 December 2025: $172.6 million). The increase is primarily due to capital expenditure on Blocks 3/05 and 3/05A of $21.3 million offset by depreciation, depletion and amortisation of $11.1 million.
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Current assets stood at $137.1 million (31 December 2025: $47.0 million) including cash and cash equivalents of $97.4 million (31 December 2025: $5.1 million), inventories of $24.0 million (31 December 2025: $25.0 million), and trade and other receivables of $14.5 million (31 December 2025: $11.6 million). Current liabilities were $94.8 million (31 December 2025: $83.4 million) including trade and other payables of $82.2 million (31 December 2025: $68.8 million), borrowings of $7.9 million (31 December 2025: $10.9 million), and contingent consideration provision of $3.5 million (31 December 2025: $3.5 million). Non-current liabilities were $93.4 million (31 December 2025: $42.4 million), comprised primarily of borrowings of $60.3 million (31 December 2025: 20.2 million), deferred tax of $20.2 million (31 December 2025: $11.5 million), and contingent consideration provision of $12.4 million (31 December 2025: $9.9 million). The increase is primarily due to the refinancing of our external borrowings, an increase in deferred tax, and the revaluation of the contingent consideration provision in a higher oil price environment. The Group’s net assets increased from $93.8 million at the end of 2025 to $133.2 million as at 30 June 2026, primarily as a result of the equity placement ($40.3 million) offset by the loss for the period ($1.5 million). Cash flow Net cash inflow from operating activities totalled $33.2 million for the first six months of 2026 (H1 2025: $3.2 million outflow). Positive cash flows were driven by the increased gross profit, primarily as a result of the increased oil price, plus working capital movements driven by the timing of liftings which resulted in a build in crude oil inventory in the first six months of 2025 which was not repeated in the first half of 2026 and an increase in trade payables as at 30 June 2026 due to the timing of Joint Venture cash calls. Net cash used in investing activities decreased to $13.8 million from $21.7 million as a result of the release of restricted funds associated with the RBL facility, lower payments for contingent consideration, and a one-off deposit paid to Etu Energias in June 2025 for the planned acquisition. Net cash generated from financing activities totalled $72.9 million compared to net cash used of $7.9 million in 2025 as a result of the debt refinancing and the equity placement. Going Concern The Group's business activities, together with the factors likely to affect its future development, performance and position is set out above and within the CEO Statement, Operations Summary and Financial Review. The financial position of the Group is described in the Financial Review. The Group has sufficient cash resources for its working capital needs and its committed capital expenditure programme at least for the next 12 months. Consequently, the Directors believe that the Group is well placed to manage its business risks successfully. The Group has adequate cash resources based on existing cash on balance sheet, proceeds from future oil sales, and the new prepayment debt facility, in place with Gunvor, to meet its liabilities as they fall due for a period of at least 12 months from the date of signing the financial statements, based on forecasts covering the period through to 30 September 2027. The Board has looked at a combination of downside scenarios, including a production shortfall alongside higher costs and lower than anticipated oil prices. The impact of the downside scenarios can be mitigated by a combination of existing hedges and rephasing of certain projects included in the preliminary 2027 capital expenditure programme by the Joint Venture. The Board also notes the implementation of the hedging policy and will utilise commodity-based derivatives to manage oil price downside risk where appropriate. The financial covenants associated with the new debt facility are not forecast to be breached within the going concern period. Thus, the Board believes it is appropriate to continue to adopt the going concern basis of accounting in preparation of the financial statements. The Directors have, at the time of approving the financial statements, a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Accounting Standards The Group has reported its 2026 and 2025 interim accounts in accordance with UK adopted international accounting standards. Cautionary statement This financial report contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil and gas exploration and production business. Whilst the Directors believe the expectation reflected herein to be reasonable in light of the information available up to the time of their approval of this report, the actual outcome may be materially different owing to factors either beyond the Group’s control or otherwise within the Group’s control but, for example, owing to a change of plan or strategy. Accordingly, no reliance may be placed on the forward-looking statements. Financial Statements Condensed consolidated statement of profit or loss and other comprehensive income Six months ended 30 June Note 2026 2025 $000 $000 Revenue 91,044 52,026 Cost of sales (53,904) (29,845) Gross profit 37,140 22,181
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Other administrative expenses (7,291) (6,090) Pre-licence costs (440) (1,339) Total administrative expenses (7,731) (7,429) Early termination fees (6,400) - Loss on revaluation of contingent consideration provision (5,518) - Profit from operations 17,491 14,752 Finance income 3 10 2 Finance costs 3 (4,630) (4,131) Profit before tax 12,871 10,623 Income tax 4 (14,407) (4,948) Loss/ (profit) for the period attributable to the owners of the parent (1,536) 5,675 Items that may be reclassified subsequently profit or loss Foreign exchange differences on translation of foreign operations 10 (5) Total other comprehensive income/(loss) for the period 10 (5) Total comprehensive income for the period attributable to the owners of the parent (1,526) 5,670 Basic (loss)/earnings per share (US cents) 5 (0.7) 2.5 Diluted (loss)/earnings per share (US cents) 5 (0.7) 2.2 Condensed consolidated statement of financial position Note 30 June 2026 31 December 2025 $000 $000 Non-current assets Intangible exploration and evaluation assets 6 1,745 1,332 Property, plant and equipment 7 182,520 171,229 184,265 172,561 Current assets Inventories 24,006 25,012 Trade and other receivables 14,549 11,623 Derivative assets 1,100 225 Cash and cash equivalents 97,449 5,145 Restricted funds - 5,044 137,104 47,049 Total assets 321,369 219,610 Current liabilities Borrowings 8 7,909 10,874 Trade and other payables 82,206 68,811 Derivative liabilities 942 - Contingent consideration provision 9 3,500 3,500 Lease liability 249 240 94,806 83,425 Non-current liabilities Borrowings 8 60,336 20,227 Contingent consideration provision 9 12,397 9,932 Deferred tax liability 20,153 11,520 Lease liability 521 674 93,407 42,353 Total liabilities 188,213 125,778
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Equity attributable to equity holders of the Company Share capital 10 35,289 28,914 Share premium 10 33,939 - Currency translation reserve (419) (429) Share option reserve 2,726 2,117 Own shares reserve (2,862) (2,789) Retained earnings 64,483 66,019 133,156 93,832 Total liabilities and equity 321,369 219,610 Condensed consolidated statement of changes in equity for the six months ended 30 June 2026 Currency Share Own Share Share translation option sharesRetained capitalpremium reserve reserve reserveearnings Total $000 $000 $000 $000 $000 $000 At 1 January 2026 28,914 - (429) 2,117 (2,789) 66,019 93,832 Profit for the period - - - - - (1,536) (1,536) Currency translation adjustments - - 10 - - - 10 Total comprehensive income for the period attributable to the owners of the parent- - 10 - - (1,536) (1,526) Issue of share capital 6,375 33,939 - - - - 40,314 Share options exercised - - - (364) 199 - (165) Shares purchased - - - - (272) - (272) Share-based payment charge for the period - - - 973 - - 973 At 30 June 2026 35,289 33,939 (419) 2,726 (2,862) 64,483 133,156 Condensed consolidated statement of changes in equity for the six months ended 30 June 2025 Currency Share Sharetranslation option Retained capital reserve reserve earnings Total $000 $000 $000 $000 $000 At 1 January 2025 28,914 (333) 842 69,206 98,629 Profit for the period - - - 5,675 5,675 Currency translation adjustments - (5) - - (5) Total comprehensive income for the period attributable to the owners of the parent - (5) - 5,675 5,670 Share options exercised - - (387) - (387) Share-based payment charge for the period - - 854 - 854 At 30 June 2025 28,914 (338) 1,309 74,881 104,766 Condensed consolidated statement of cash flows Note Six months ended 30 June 2026 2025 Operating activities: $000 $000 Profit before tax 12,871 10,623 Depreciation, depletion and amortisation 10,015 11,047 Share-based payment expense 973 854 Tax payments related to share-based payments (165) (184) Unrealised losses/(gains) on derivatives 67 (1,321) Loss on revaluation of contingent consideration 9 5,518 - Finance income 3 (10) (2) Finance costs 3 4,630 4,131 Operating cash flow prior to working capital movements 33,899 25,148 Decrease/(increase) in inventories 1,006 (16,714) (Increase)/decrease in trade and other receivables (2,926) 515 Increase/(decrease) in trade and other payables 6,988 (7,264)
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Cash flow generated from operating activities 38,967 1,685 Income tax paid (5,774) (4,866) Net cash flow generated from/(used in) operating activities 33,193 (3,181) Investing activities Deposit paid for asset acquisitions - (1,750) Interest received 3 10 2 Purchase of property, plant and equipment (14,907) (14,203) Exploration and evaluation costs 6 (413) (179) Cash inflow from restricted funds 5,044 - Contingent consideration paid 9 (3,500) (5,544) Net cash used in investing activities (13,766) (21,674) Financing activities Drawdown on loan 8 70,000 - Principal repayments on loan facilities 8 (31,516) (5,253) Interest paid (3,203) (2,780) Gross proceeds from issue of share capital 10 42,713 - Costs incurred on issue of share capital 10 (2,399) - Costs incurred on refinancing 8 (2,278) - Cash inflow from restricted funds - 355 Shares acquired for settlement of share-based payments (272) (203) Principal and interest paid on lease liability (176) (60) Net cash generated from/(used in) financing activities 72,869 (7,941) Net increase/(decrease) in cash and cash equivalents 92,296 (32,796) Cash and cash equivalents at beginning of year 5,145 46,880 Effect of foreign exchange rate changes 8 (12) Cash and cash equivalents at end of the period 97,449 14,072 Notes to the consolidated results for the six months ended 30 June 2026 1. Basis of preparation The financial information contained in this announcement does not constitute statutory financial statements within the meaning of Section 435 of the Companies Act 2006. The financial information for the six months ended 30 June 2026 is unaudited. In the opinion of the Directors, the financial information for this period fairly represents the financial position of the Group. Results of operations and cash flows for the period are in compliance with UK adopted International Accountings Standards. The accounting policies, estimates and judgements applied are consistent with those disclosed in the annual financial statements for the year ended 31 December 2025, and are also consistent with additional policies, estimates and judgements as notedbelow. Critical Accounting Judgements and Estimates In the application of the Group’s accounting policies, the Directors are required to make judgements, estimates and assumptions about the carrying value of assets and liabilities that are not readily available from other sources. The estimates and associatedassumptions are based on historical experience and other factors that are relevant. Actual results may differ from these estimates. These financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2025. All financial information is presented in USD, unless otherwise disclosed. An unqualified audit opinion was expressed for the year ended 31 December 2025, as delivered to the Registrar. The Directors of the Company approved the financial information included in the results on 2 September 2026. 2. Results and dividends The Group has retained earnings at the end of the period of $64.5 million (31 December 2025: $66.0) to be carried forward. The Directors do not recommend the payment of a dividend (1H 2025: nil). 3. Finance income and costs Six months ended 30 June 2026 2025 $000 $000 Finance income: Interest on short-term deposits 10 2 10 2 Finance costs:
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Interest on borrowings 2,102 2,453 Joint venture finance fees 59 - Interest accretion on contingent consideration provision 447 1,197 Finance and arrangement fees 1,406 304 Bank charges 15 222 Interest expense for leasing arrangement 42 40 Exchange differences and other 559 (85) 4,630 4,131 4. Taxation Income tax is comprised of current tax and deferred tax as presented below: Six months ended 30 June 2026 2025 $000 $000 Current tax Foreign tax 5,774 3,064 5,774 3,064 Deferred tax Increase in deferred tax liability 8,633 1,884 8,633 1,884 Income tax 14,407 4,948 5. Earnings per share (basic and diluted) (Loss)/earnings per share (LPS/EPS) is calculated by dividing the earnings attributable to ordinary shareholders by the weighted average number of shares outstanding during the period. Diluted EPS is calculated using the weighted average number of shares adjusted to assume the conversion of all dilutive potential ordinary shares. Share options and awards are not included in the dilutivecalculation for loss making periods because they are anti-dilutive. The dilutive effect of share awards outstanding is the total possible award number and does not take into account vesting conditions potentially not met, or the Group’s expectation that these awards will be settled net of tax, that will reduce the impact of the dilutive effect of the awards. Six months ended 30 June 2026 2025 (Loss)/profit for the period ($000) (1,536) 5,675 Weighted average number of ordinary shares in issue during the year1 (number of shares) 229,081,612 226,155,990 Basic (LPS)/EPS (US cents) (0.7) 2.5 Total possible dilutive effect of share awards outstanding - 29,250,885 Fully diluted average number of ordinary shares during the year 229,081,612 255,406,875 Diluted (LPS)/EPS (US cents) (0.7) 2.2 1 Weighted average number of ordinary shares in issue excludes 0.4 million own shares purchased during the year. 6. Exploration and evaluation assets As at 30 June 2026 As at 31 December 2025 Exploration and evaluation assets 1,745 1,332 1,745 1,332 The following table summarises the movement for the six months ended 30 June 2026: Exploration and evaluation assets $000 Carrying amount at beginning of period 1,332 Additions 413 Carrying amount at end of period 1,745 Group intangible assets as at 30 June 2026 comprise: Block KON 19 PSA, Angola: Afentra (Angola) Ltd 45%, ACREP (Operator) 45%, and Enagol 10%. Block KON 15 PSA, Angola: Afentra (Angola) Ltd 45%, Sonangol (Operator) 55%. Block 3/24 RSC, Angola: Afentra (Angola) Ltd (Operator) 40%, M&P 40%, Sonangol 20% (carried during exploration phase). 7. Property, plant and equipment
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As at 30 June 2026 As at 31 December 2025 Oil and gas assets 181,659 170,229 Office lease 676 794 Computer and office equipment 185 206 182,520 171,229 The following table summarises the movement in oil and gas assets for the six months ended 30 June 2026: Oil and gas assets $000 Carrying amount at beginning of period 170,229 Additions 21,281 Depreciation (9,851) Carrying amount at end of period 181,659 The Group’s oil and gas assets as at 30 June 2026 comprise: Block 3/05 PSA, Angola: Afentra Angola Ltd 30%, Sonangol (Operator) 36%, M&P 20%, Etu Energias 10%, and NIS- Naftagas 4%. Block 3/05A PSA, Angola: Afentra Angola Ltd 21.33%, Sonangol (Operator) 33.33%, M&P 26.68%, Etu Energias 13.33%,and NIS-Naftagas 5.33%. 8. Borrowings In May 2026, Afentra entered into a prepayment financing arrangement with a subsidiary of Gunvor Group for up to US$125 million, structured in two tranches and with a four-year tenor. The first tranche of $100 million is immediately available and acommitted facility; the second tranche of $25 million is subject to further conditions precedent. The facility was used to replace the Company’s previous Reserve-based lending (RBL) facilities and is secured against future crude oil deliveries from its Angolan assets, with repayment primarily effected through cargo liftings. As of 30 June 2026, the Group has drawn down $70.0 million on the new facility. The key terms of our debt are shown below: Gunvor Prepayment Facility $70.0 million 4-year tenor to May 2030 6% margin over 3-month SOFR (Secured Overnight Financing Rate) Quarterly principal and interest repayments The following table summarises the movement of total borrowings for the six months ended 30 June 2026: Borrowings $000 At 1 January 2026 31,101 Loan drawdowns 70,000 Arrangement fee capitalised (2,278) Interest charge 2,102 Repayments of principal (31,516) Repayments of interest (2,570) Amortisation of capitalised arrangement fee 1,406 At 30 June 2026 68,245 A charge is placed on Afentra (Angola) Ltd shares to Gunvor Singapore Pte. Ltd. Net cash/(debt) The table below details our net cash/(debt) as at 30 June 2026 and 31 December 2025: As at 30 June 2026 As at 31 December 2025 $000 $000 Cash and cash equivalents 97,449 5,145 Restricted Funds - 5,044 Borrowings (68,245) (31,101) Lease liability (770) (914) Net cash/(debt) 28,434 (21,826) 9. Contingent consideration provision The provision for contingent consideration is presented on the Condensed consolidated statement of financial position as: As at 30 June 2026 As at 31 December 2025 Current 3,500 3,500 Non-current 12,397 9,932
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Total contingent consideration provision 15,897 13,432 The following table summarises the movement in the contingent consideration provision for the six months ended 30 June 2026: Contingent consideration $000 At 1 January 2026 13,432 Accretion of interest 447 Payments (3,500) Changes in fair value 5,518 At 30 June 2026 15,897 Contingent consideration is payable to SNL, INA, and Azule on Blocks 3/05 and 3/05A: INA acquisition (2023): Tranche 1: The contingent consideration for 3/05 relates to the 2023 and 2024 production thresholds and a realised Brent price hurdle, subject to an annual cap of $2.0 million. Tranche 1 has since expired and no further payments will become due. Tranche 2 – Caco-Gazela and Punja (Development Milestones): The contingent consideration for 3/05A is linked to the future development of the Caco-Gazela and Punja development areas. Caco-Gazela Development Area: The contingent consideration relating to the Caco-Gazela development area has now lapsed as the production threshold was not satisfied within the measurement period, with no payments due. Punja Development Area: The Punja contingent consideration is comprised of a one-off payment of $2.5 million, payable if: first oil occurs before 2028, cumulative production exceeds one million barrels within 24 months of first oil, and the average Brent price for the preceding 12 months exceeds $65/bbl. If these conditions are not satisfied, the entitlement lapses with no payment due. Based on the current stage of development, and expected timelines to first oil, the Group does not currently expect any contingent consideration to bepayable in 2027. SNL acquisition (2023): The contingent consideration for the SNL acquisition is payable annually over the next ten years from acquisition in each year where the 15,000 barrel of oil equivalent (BOE) average daily production hurdle is reached and the realised oil price exceeds $65/bbl. The maximum annual amount payable is $3.5 million, potentially resulting in a total maximum payment of $35 millionover the ten years to 2032. During the year, the Group paid contingent consideration of $3.5 million to Sonangol in relation to calendar year 2025. Azule acquisition (2024): Tranche 1: The contingent consideration for the Azule acquisition related to oil price and Block 3/05 production hurdles for the 2023, 2024, and 2025 production years, subject to an annual cap of $7.0 million and an aggregate cap of $21.0 million (now completed). Tranche 1 has since expired and no further payments will become due. Tranche 2: Block 3/05A Discoveries: Further contingent consideration of up to $15 million is linked to the future development of the Caco-Gazela and Punja discoveries. Caco-Gazela Discovery: On the Caco-Gazela Trigger Date (12 months following recommencement), a payment of $7.5 million will become payable if: the average Brent price for the preceding 12 months is at or above $75/bbl, and average daily production exceeds 5,000 BOE per day. Punja Discovery: On the Punja Trigger Date (12 months following first oil), a payment of $7.5 million will become payable if: the average Brent price for the preceding 12 months is at or above $75/bbl, and average daily production exceeds 5,000 BOE per day. If these conditions are not satisfied, the relevant contingent consideration lapses with no payment due. Based on the current stage of development of the relevant Block 3/05A discoveries, and expected timelines to first oil and recommencement, the Group does not currently expect any contingent consideration to be payable in respect of Tranche 2 in 2027. These contingent payments are measured at fair value and changes in fair value are recognised in profit or loss. Management have reviewed the contingent payments related to the above acquisitions, which are dependent upon production levels, future oil price hurdles, and future 3/05A developments. Judgement has been applied to the probability of the circumstances occurring that would give rise to some or all of the future payments. For each tranche of contingent consideration Management have applied a multiple scenario approach to each tranche along with the related weightings of probability resultingin an expected amount payable. The base case scenario, which has the greatest weighting is based on the Brent forward curve at period end, with an average oil price of $77/bbl in 2026, $74/bbl in 2027, and $71/bbl in 2028. Management has applied a discount rate that approximates to the incremental borrowing rate in arriving at a present value at the balance sheet date of the probable future liabilities. The discount rate is based on a market rate of 10.4% (2025: 9.1%). Applying Management’s judgements discussed above, has resulted in an estimated fair value of the contingent considerationprovision of $15.9 million at period end (2025: $13.4 million). A 2% increase in the discount rate would result in a reduction in the
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contingent consideration liability of $0.7 million. A 2% decrease in the discount rate would result in an increase in contingent consideration provision of $0.7 million. The impact of removing the scenarios that have an expectation the realised Brent price hurdles will not be met in the long term (5% original weighting) and including a relative increase in the base case scenarioswould increase the contingent consideration provision by $0.8 million. In the event of a sustained low oil price scenario, where the average Brent oil price remains below $65/bbl, the non-current contingent consideration provision would be reversed. 10. Share capital and share premium Ordinary shares (10p) Share capital Share premium No. shares $000 $000 Authorised, called up, allotted and fully paid At 1 January 2026 226,155,990 28,914 - Equity placement 47,300,314 6,375 33,939 At 30 June 2026 273,456,304 35,289 33,939 During the period the Company completed an equity placement of 47.3 million shares at a price of £0.67 per share. Share premium is stated net of transaction fees of $2.4 million. As of 30 June 2026, 4.5 million of the above shares are held in the EBT (31 December 2025: 4.3 million). 11. Subsequent Events Founder share plan (FSP) During July, the Executive Directors exercised their remaining unexercised FSP options in full and have received the net shares after applicable deductions for income tax and national insurance. Of the aggregate 6,179,956 net shares received, 4,501,338 shares have been satisfied using shares purchased by the Employee Benefit Trust and 1,678,618 shares have been satisfied through the allotment and issue of new shares allotted by the Company. July lifting On 27 July 2026 the Group completed a third crude oil lifting on of 0.5 mmbbls at $84.1/bbl, generating revenue of $38.0 million. Glossary and Definitions Term Definition $ US dollars 2D Two dimensional 2C Denotes best estimate of Contingent Resources 2P Denotes the best estimate of Reserves. The sum ofProved plus Probable Reserves AIM AIM, an SME Growth market of the London Stock Exchange AGM Annual General Meeting ANPG Agência Nacional de Petróleo, Gás eBiocombustíveis (holder of the mining rights of Exploration, Development and Production of liquid and gaseous hydrocarbons in Angola) Block 3/05 The contract area described in and covered by the Block 3/05 PSA Block 3/05A The contract area described in the Block 3/05A PSA Block 23 The contract area described in and covered by the Block 23 PSA Board The Board of Directors of the Company bbls Barrels of oil (‘k-’ / ‘mm-’ / ‘bn-’ for thousand / million / billion) bcpd Barrels of condensate per day
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bopd Barrels of oil per day (‘k-’ / ‘mm-’ for thousand / million) bwpd Barrels water injected per day Companies Act or Companies Act The Companies Act 2006, as amended 2006 Company Afentra plc CPR Competent Persons Report CSR Corporate Social Responsibility Directors The Directors of the Company ECL Expected credit loss E&E Exploration and evaluation assets EDLTIP Executive Director Long-term Incentive Plan eFTG Enhanced Full Tensor Gravity Gradiometry E&P Exploration and production EPS/LPS Earnings/loss per share EBITDAX (Adjusted) Earnings before interest, taxation, depreciation, total depletion and amortisation, impairment and expected credit loss allowances, share-basedpayments, provisions, and pre-licence expenditure Entitlement Reserves Entitlement production/reserves refers to the shareof oil/gas that a company is entitled to receive based on fiscal and contractual agreements governing the specific asset. EOR Enhanced Oil Recovery ESP Electrical Submersible Pumps FID Final investment decision FSO Floating storage and offloading FSP Founders’ Share Plan G&A General and administrative GBP Pounds sterling G&G Geological and geophysical GHG Greenhouse gases GIIP Gas initially in place GOR Gas Oil Ratio GPQ The Golungo, Palanca North East and Quissamadiscoveries on Block 3/24 Group The Company and its subsidiary undertakings hydrocarbons Organic compounds of carbon and hydrogen IAS International Accounting Standards IFRS International Financial Reporting Standards INA INA-Industrija Nafte d.d IOC International oil company IPCC Intergovernmental Panel on Climate Change JV Joint venture JOA Joint operating agreement k Thousands km Kilometre(s) km2 Square kilometre(s)
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KPIs Key performance indicators lead Indication of a potential exploration prospect LiDAR Light Detection and Ranging Lifex Life extension capex LNG Liquefied Natural Gas LSE London Stock Exchange LTIP Long-term incentive plan LWI Light Well Intervention M&A Mergers and acquisitions m Million mmbbls Million barrels of oil mmbo Million barrels of oil mmboe Million barrels of oil equivalent mmcfd Million cubic feet per day M&P Maurel & Prom MVO Market Value Options NED Non-Executive Director NEDP Non-Executive Director Option plan O&G Oil and gas OIW Oil in water Op. Operator Opex Operating expenditure Opex/bbl Gross operating cost / Gross production Ordinary Shares ordinary shares of 10 pence each Petroleum Oil, gas, condensate and natural gas liquids Plc Public limited company PIT Petroleum income tax Prospect An area of exploration in which hydrocarbons have been predicted to exist in economic quantity. A group of prospects of a similar nature constitutes a play. PSA Production sharing agreement PSC Production sharing contract PWTS Produced Water Treatment System QCA Code QCA (Quoted Companies Alliance) Corporate Governance Code 2023 RBL Reserve-Based Lending Reserves Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must satisfy fourcriteria; they must be discovered, recoverable, commercial and remaining based on the development projects applied. Reserves are further categorised in accordance with the level ofcertainty associated with the estimates and may be sub-classified based on project maturity and/or characterised by development and production status RSC Risk service contract
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ROV Remotely Operated Vehicle RTO Reverse takeover (pursuant to Rule 14 of the AIM Rules) SPA Sale and Purchase Agreements Seismic Data, obtained using a sound source and receiver, that is processed to provide a representation of a vertical cross-section through the subsurface layers SOFR Secured Overnight Financing Rate Shares 10p ordinary shares Shareholders Ordinary shareholders of 10p each in the Company STOIIP Stock tank oil initially in place Subsidiary A subsidiary undertaking as defined in the 2006 Act Sonangol Sonangol Pesquisa e Producao S.A. Sonangol EP Sociedade Nacional de Combustíveis de Angola, Empresa Pública TCFD Task force on Climate-related Financial Disclosure TRIF Total Recordable Incident Frequency TSR Total Shareholder Return United Kingdom or UK The United Kingdom of Great Britain and Northern Ireland Working Interest or WI A Company’s equity interest in a project before reduction for royalties or production share owed to others under the applicable fiscal terms ZRF Zero Routine Flaring
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