2026 HALF YEAR RESULTS

Afentra PLC

15 September 2026

 

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.

-            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 [phone]

Paul McDade, CEO

Anastasia Deulina, CFO

Christine Wootliff, Investor Relations

Burson Buchanan (Financial PR) [phone]

Barry Archer

Louise Mason-Rutherford

Stifel Nicolaus Europe Limited (Nominated Adviser and Joint Broker) [phone]

Callum Stewart

Simon Mensley

Ashton Clanfield

Tennyson Securities (Joint Broker) [phone]

Peter Krens

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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 and ceiling 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’s journey. The first six months of 2026 marked an important step into the next phase of operational delivery, supported by a strengthened capital structure and continued progress across our Angolan portfolio. The scale of the organic growth opportunity across 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 announced in 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 of growth 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 and equity 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 capital and cost of trading, enhances our funding flexibility, providing the financial structure we require to support our ongoing investment programme. Alongside this, we completed an oversubscribed $40 million equity placing at 67p per share. The placing was strongly supported by both new and existing institutional investors. To ensure we also provided an opportunity for our retail shareholders, we complemented 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. At 30 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 an average realised price of $91.3/bbl and generating $91.0 million in revenue. Our financial resilience is further underpinned by our disciplined hedging strategy, which continues to protect our cash flows against commodity price volatility. We have actively managed our exposure, with approximately 49% of 2026 remaining forecast sales currently hedged using collar structures that secure a firm floor price while preserving meaningful exposure to oil price upside. Post period, we completed a further lifting of approximately 450,000 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 period end, the Pacassa SW well delivered a successful oil discovery, with 136 metres of net oil pay supporting our view that the wider area has the potential to contain up to 70 mmbo of gross recoverable resources. Completion operations encountered a wellbore obstruction and the joint venture is progressing plans to sidetrack the well to allow it to be completed and brought onstream. The final completion plan and drilling sequence are currently being finalised. Pacassa SW is being financed by Sonangol under a carry arrangement, 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 tested at approximately 4,700 bopd and subsequently produced at approximately 3,000 bopd to manage water production and longer-term reserves recovery, before being temporarily shut in to accommodate preparations for Impala-2. Impala-2 is expected to be the second 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 of over 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 Grid drilling unit over the Pacassa wellhead platform. Operations have since been restored. Net production during July and August averaged approximately 6,236 bopd, reflecting restored operations. Working with Sonangol as operator and our joint venture partners, we continued to advance the multi-year redevelopment programme. Water injection averaged approximately 45,000 bwpd and reached rates of up to 70,000 bwpd, sustained injection rates of approximately 100,000 bwpd are targeted during H2 2026. A number 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 period without 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 mature these discoveries, providing a potential infrastructure-led route to future operated growth. The initial GPQ (Golungo, Palanca northeast, Quissama) development provides a low-cost, short-cycle opportunity, with the discoveries located approximately 5 km from the existing Block 3/05 producing infrastructure. During the period, we advanced operational activities in support of development planning. Post period end, a survey vessel programme was successfully completed in July, including wellhead inspections.

Our strategic portfolio expansion remains on track, with the Etu transaction expected to complete in Q3 2026, which will increase our working interests in Blocks 3/05 and 3/05A to 33.33% and 24.99% respectively. Also onshore in the Kwanza Basin, we achieved a major strategic milestone with the formal award and signing of the KON4 Risk Service Contract, where Afentra is operator with a 35% interest. KON4 contains the large, prematurely abandoned Quenguela Norte oil field and offers immediate redevelopment potential alongside material exploration upside.

Onshore we have already completed the acquisition of the high-resolution eFTG geophysical survey data across our onshore licensed areas, (KON4, 15 & 19) and technical studies are progressing to assemble a full prospect inventory. Initial interpretation has identified a number of post-salt leads, supporting the next phase of targeted seismic activity. A 300km 2D seismic programme on KON15 is expected to commence in September 2026, while a focused programme is being considered for KON4 in H1 2027, as we seek 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 structure and liquidity, the financial flexibility of the new Gunvor facility, and continued operational delivery across our offshore and onshore portfolio, we have the capacity to advance our growth strategy. The results from Pacassa SW and Impala-1, together with the planned Impala-2 development well, reinforce the scale of the organic growth opportunity within Block 3/05. Together with the expected completion of the Etu acquisition in Q3 2026, these developments provide multiple pathways to deliver the production and reserves growth and value delivery we have been building towards. We remain focused on maintaining strict capital discipline as we advance our investment programme and pursue further growth opportunities. We look forward to updating shareholders on our progress.

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 first drilling campaign on the asset in over a decade. The programme targets a potential gross production uplift of ~9,000 bopd and gross recoverable 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 period was impacted by downtime associated with the positioning of the Borr Grid jack-up drilling unit over the Pacassa platform, as well as a planned shutdown of the gas compression system to improve field-wide gas distribution. Production, water injection, and gas compression have since been fully restored. Asset uptime remained stable throughout the period, supported by continued progress across 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 5,381 metres 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 interpreted oil-water contact consistent with that observed in the main Pacassa field. Initial pressure indications suggest limited pressure depletion, confirming communication with the main Pacassa field. During completion operations, a packer failed, 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. If the sidetrack cannot proceed immediately, consideration is being given to moving the rig to Impala-2 while the necessary planning and equipment mobilisation are completed, before returning to complete Pacassa SW. The final completion plan and drilling sequence are expected to be confirmed shortly. Once completed, the well will be connected to the existing Pacassa production 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 of the 2026 light well intervention (LWI) programme. Following a slickline intervention to clear a wellbore obstruction, the well achieved gross flow rates of up to ~4,700 bopd during testing and was then produced at a constrained rate of ~3,000 bopd to optimise reservoir performance. The well has subsequently been shut in to accommodate preparation activities for the rig arrival to drill Impala-2. The intervention has provided valuable reservoir pressure and productivity data which was incorporated into the final well planning for Impala-2.

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 development well will target the Impala field approximately 1,000 metres from the existing Impala-1 well and, once commenced, is expected to take approximately 80 days to drill and complete. The well targets an initial production rate of approximately 4,000 bopd and, if successful, would represent the beginning of the next phase in the redevelopment of the Impala field.

Well Funding: During the period, the Block 3/05 partners entered into a commercial agreement with Sonangol under which Sonangol would finance the planned two-well drilling programme, with costs, up to an agreed cost cap, recovered from future incremental production revenues from the wells.

Production Optimisation and Asset Integrity

Well intervention activities have also continued across the asset during the first half of the year comprising slickline, electric line, and acid stimulation programmes focused on optimising production and improving well performance. Preparations for the hydraulic workover 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. Asset uptime remained stable throughout the period, supported by the continued progress of our integrity workstreams, while operating costs (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 injection averaged ~56,000 bwpd during July and August. Upgrades continue to target sustained water injection rates of ~100,000 bwpd in H2 2026. Infrastructure upgrades to improve platform reliability were completed at the Pambi platform and remain ongoing at the Cobo and Palanca platforms. Additionally, the Palanca FSO maintenance works were successfully completed, and formal recertification was 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 Blocks 3/05 and 3/05A of approximately $163 million gross (Net: $50 million), covering continued asset integrity, revamping and well intervention 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 and subsurface mapping of the Caco and Gazela fault compartments are ongoing to refine the optimal development strategy and de-risk the long-term resource potential of the block's undeveloped discoveries, which hold an estimated 98 mmbo gross 2C recoverable resources.

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. Post period 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 or seepage 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, managed by Afentra, utilised a compact ROV from a local vessel at a total cost of ~$60k, delivering a significant saving against standard contractor quotes of $500k to $1.0 million. Subsurface work continues to assess the various hydrocarbon discoveries and the broader 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 no outstanding work commitments. Afentra continues to monitor regional activity, including progress on the adjacent Kaminho deepwater 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 Risk Service 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 of discovered oil-in-place.

The acquisition of the high-resolution enhanced Full Tensor Gravity Gradiometry (eFTG) geophysical survey data was successfully completed across all licensed onshore areas. Initial results are currently being interpreted and integrated with legacy seismic and well 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 completion covering 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 regulatory approvals and permitting, the pilot is targeted for H2 2027. Initial eFTG interpretation has also highlighted prospective fault blocks adjacent 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 high resolution eFTG survey and legacy 2D seismic used to identify a number of post-salt leads within KON15. Environmental and regulatory preparations are ongoing to support 2D seismic acquisition. A contract has been awarded for 300km of 2D seismic acquisition on KON15, with acquisition expected to commence in September 2026. The programme will focus on infill of the legacy 2D 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-year tenor. The new facility comprises $125 million of committed capacity ($100 million initial advance plus $25 million subsequent advance available in 2027 subject to certain conditions), with an uncommitted accordion to scale the facility size based on future production growth. During the period we drew down $70 million of this facility with a further $30 million expected to be drawn later in 2026. The additional $25m is expected to be drawn in 2027. The facility has replaced our previous debt facilities and is secured against 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
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.

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
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
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	shares	Retained
	capital	premium	reserve	reserve	reserve	earnings	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
		Share	translation	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)
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 noted below.

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 associated assumptions 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:
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 dilutive calculation 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

		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 a committed 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
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 be payable 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 million over 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 resulting in 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 consideration provision 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 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 scenarios would 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 of Proved plus Probable Reserves
AIM	AIM, an SME Growth market of the London Stock Exchange
AGM	Annual General Meeting
ANPG	Agência Nacional de Petróleo, Gás e Biocombustíveis (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
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-based payments, provisions, and pre-licence expenditure
Entitlement Reserves	Entitlement production/reserves refers to the share of 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 Quissama discoveries 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)
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 four criteria; they must be discovered, recoverable, commercial and remaining based on the development projects applied. Reserves are further categorised in accordance with the level of certainty 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
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

 

END