24 April 2025

AFENTRA P L C

UNAUDITED ANNUAL RESULTS FOR THE YEAR ENDED 31 DECEMBER 2024

Afentra plc ("Afentra" or the "Company") (AIM: AET), the upstream oil and gas company focused on acquiring production and development assets in Africa, announces its unaudited annual results for the year ended 31 December 2024.

2024 SUMMARY

Key Highlights

•       Azule acquisition: completed in May 2024, increasing interest in Blocks 3/05 (30%) and 3/05A (21.33%).

•       Onshore Kwanza basin: secured Blocks KON15 (45%) and KON19 (45%).

•       2024 Net Average Production: 6,229 bopd

•       Reserve replacement: 140% replacement with year-end 2P reserves of 34.2 mmbo

•       Oil Sales: four crude liftings generating revenue of $180.9 million.

•       Year-End Net Cash Position: $12.6 million with cash balance of $54.8 million.

Financial and Risk Management Highlights

•       Revenue of $180.9 million

•       Year-end cash of $54.8 million; net cash position of $12.6 million.

•       Borrowings of $41.4 million; total debt / adjusted EBITDAX 0.5x.

•       Adjusted EBITDAX of $90.9 million and profit after tax of $49.8 million.

•       Four liftings totaling 2.3 mmbbls, average price of $82.2/bbl

•       Placed 2025 hedge programme with ~68% of sales volumes hedged: combination of $60-65/bbl floors and calls with $80-89/bbl caps.

Operational Highlights

•       Block 3/05 and 3/05A gross average production 21,111 bopd (2023: 20,180 bopd).

•       40 light well interventions (LWIs) delivered 2,000 bopd. Increased programme planned for 2025.

•       Reserve replacement since last CPR of 140% for Block 3/05, as a result of the LWI programme, increased water injection and infrastructure optimisation.

•       Three year re-development plan launched in 2024, $150 million gross (Net: $39 million) [1] invested in production optimisation, life extension and emissions reduction. 2025 spend of $180 million (Net: $54 million).

•       Successful completion of a 21-day maintenance shutdown in October enabled key upgrades to power systems, subsea infrastructure and installation of gas and water metering.

•       Water injection capacity significantly enhanced post shutdown, reaching rates of over 80,000 bwpd. A third pump is scheduled for installation in 2025, targeting water injection rates of 150,000 bwpd.

•       Installation of gas metering to support accurate measurement, flare reduction and export planning.

•       Planning progressed to prepare for first rig related activities in 2026 and 2027.

•       Onshore Kwanza Basin Blocks KON15 and KON19 secured with 45% non-operated interests. Basin-wide eFTG survey commenced in 2024 and is due to complete in 2025.

•       Initiated support for The HALO Trust's landmine clearance work in Angola.

Post year-end Summary

•       Gross Block 3/05 and Block 3/05A production for Q1 2025 averaged 22,120 bopd (Net: ~6566, bopd).

•       Crude lifting of ~466,000 bbls sold at $74.7/bbl, generating pre-tax sales revenue of $34.8 million.

•       Net cash at end of Q1 2025 of around $9.8m with crude oil stock of around 68,000 bbls.

•       Formal signing of onshore Kwanza block KON 15 on 7th April 2025.

•       Acquired 381,719 shares in the market through Employee Benefit Trust to fulfil recent Executive share awards, thereby avoiding issuance of new shares.

Strategic Focus for 2025

•       Continued focus on value driven M&A in Angola and wider West Africa region.

•       Investments in Block 3/05 and Block 3/05A and active JV partner collaboration to drive:

o  progress infrastructure upgrades, increase water injection rates and deliver well interventions to continue to increase production and improve asset performance.

o  plan for 2026 rig activities to deliver step change in production performance and continue to deliver reserves replacement.

o  continue sustainability initiatives to reduce emissions and deliver gas export.

•       Consolidate position in Onshore Kwanza Basin and complete evaluation of basin potential.

•       Optimise crude offtake, hedging programme, focus on costs and strengthen corporate balance sheet.

•       Continue to purchase shares in the market through Employee Benefit Trust to meet the requirements of the FSP awards due March 2026, of around 6.5 million shares.

Paul McDade, Chief Executive Officer, commented:

"2024 marked a year of transformative growth and strategic progress for Afentra, as we truly established ourselves as an active partner in Angola's oil and gas industry. With ownership of our offshore assets in place, we were able to embed ourselves operationally, build strong relationships with our joint venture partners, and demonstrate the value we can bring as a technically engaged and commercially disciplined non-operator. Afentra is fully supporting the operator, taking a long-term approach to maximising value from the assets through upgrades to asset integrity, production optimisation, and emissions reduction. We are already seeing tangible results from these redevelopment activities in enhanced production and reserves.

Opening our Luanda office and appointing an Angola-based Country Manager reflect our long-term commitment to the country and its energy sector. Further expanding our footprint, we secured new onshore opportunities through the award of KON15 and KON19 in an under-exploited yet proven hydrocarbon basin.

Importantly, we've also transformed our balance sheet-generating strong cash flow and ending the year with a net cash position-laying the foundation for disciplined growth ahead."

YE 2024 Results Presentation: https://afentraplc.com/wp-content/uploads/2025/04/2025.04-Afentra-YE-2024-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

Ben Romney

Barry Archer

George Pope

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

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, Afentra has a 30% non-operated interest in the producing Block 3/05 and a 21.33% non-operated interest in the adjacent development Block 3/05A in the lower Congo basin and a 40% non-operating interest in the exploration Block 23 in the Kwanza basin. Onshore Angola, Afentra has a 45% non-operated interest in the prospective Blocks KON15 and KON19 located in the western part of the onshore Kwanza basin. Afentra also has a 34% carried interest in the Odewayne Block onshore southwestern Somaliland. 

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.

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.

ChIEF EXECUTIVE OFFICER's Statement

Delivering Value Driven Growth

Introduction

2024 has been a period of transition in which we completed the third of our production acquisitions in Angola and have started to make material progress in enhancing the production and reserves from the assets acquired. In addition, we have expanded our portfolio with new opportunities onshore Angola which we identified as we further embedded ourselves as a leading Independent in the evolving landscape of Angola's upstream industry.

The completion of the Azule transaction in May was a watershed moment for Afentra and provided us with the opportunity to articulate the true value-accretive nature of these inaugural deals.  The fact that we were able to construct our current portfolio, underpinned by robust cash flow, proven reserves and material upside, for less than $10m net outflow reflects our mantra of Value Driven Growth, whereby we seek to grow the business responsibly alongside an unwavering focus on delivering shareholder value. 

Realising the upside

Our focus on value creation is not exclusive to our shareholders but extends to our broader stakeholders. The completion of the Azule transaction in May increased Afentra's equity interest by 12%, resulting in a material position in the high-quality Blocks 3/05 and Block 3/05A.  As per our stated business model, the assumption of a meaningful non-operated interest in any asset brings a duty to support the Operator and partners in enhancing the value of our shared assets.  A core point of difference at Afentra is the breadth and depth of our technical expertise. We are working closely with the Operator, Sonangol, to support them on the optimisation activities on Block 3/05 - as well as tabling technical solutions to deliver meaningful long-term impact to the sustainability performance of the assets.

The improved performance of the asset has been a key highlight for 2024 and has validated our technical view that these assets will provide material scope for production optimisation for decades to come. The 15-year runway provided to the Joint Venture partners by the licence extension out to 2040 ensures we have visibility and confidence in our ability to extract additional value from the nine producing fields and three  discoveries that these diverse and large-scale blocks contain.  The redevelopment works at Block 3/05, along with well interventions, have resulted in improved production and water injection performance, and we believe the continuation of the asset improvement work programme in the coming year will continue this trajectory.  

Block 3/05 and Block 3/05A gross average production has increased from 20,180 bopd (2023) to 21,111 bopd for 2024, an increase of 5%. A successful maintenance shutdown was delivered that focused on the long-term asset reliability and integrity which will serve the partnership as we deliver the next stage of Block 3/05 and Block 3/05A redevelopment.  The work performed in the shutdown has already had a positive impact on water injection resulting in rates exceeding up to 80,000 bwpd, on one of our key asset targets, versus an average in 2024 of 23,100 bwpd. The near-term investment in future-proofing the asset will better enable the partnership to realise full value from the asset which we believe has significant upside potential. As we presented at our webinar in June 2024 we consider these assets to be capable of delivering sustained production at levels above 30,000 bopd and materially higher levels of reserves. To date we have already added 18mmbo of gross reserves since acquisition. We remain fully focused on realising this potential upside value through focused execution.

Expanding the portfolio

Another key development this year has been our further expansion in Angola through our focus on the onshore Kwanza basin, an under-exploited and overlooked proven hydrocarbon basin with both low-cost exploration opportunities and numerous previously producing oil fields that we consider to have been abandoned prematurely. In July 2024 we were awarded a 45% non-operated interest in KON19 alongside two local companies and post-period end in February 2025 we were awarded a 45% non-operated interest in Block KON15 alongside Sonangol.  We believe these onshore licences strategically complement our offshore activities and provide long-term opportunities in the form of low-cost exploration in a proven basin - an area of expertise in which our team has significant experience.  It is particularly pleasing to demonstrate our commitment to further develop the Angolan industry by partnering with local companies.  This approach, coupled with our proven status and in-country network, may present further opportunities for low-cost exploration and development in this opportunity-rich area.

Alongside the organic growth opportunities we see within our existing portfolio and established foothold in Angola, we continue to screen strategically complementary M&A opportunities and retain strong liquidity on the balance sheet that will be put to work when we identify an opportunity that fits our investment criteria.  Having completed transactions with both IOC's and Sonangol in Angola, we have proven our ability to be a credible counterparty and it is clear that after only three years of operating the Afentra brand is well regarded within our industry. 

We have also demonstrated our Value Driven approach in action through the funding of all transactions without the requirement to issue new equity and the efficient use of the debt markets. The strength of cash flow from Block 3/05, which has been optimised through our active management of crude liftings and a structured hedging policy, means we end the period in a net cash position.  Whilst the recent softening of crude pricing may reduce near-term asset cashflow, when combined with our strong balance sheet, it may present further opportunities through the likely acceleration of divestments at reasonable price points.  Afentra remains agile in its approach and is well positioned to deliver further value accretive transactions in 2025.

Focus on value creation

In summary, 2024 was yet another year of strategic progress that resulted in value creation for our shareholders and enhanced the value of our overall proposition by demonstrating the upside potential of our expanding asset base.  Our strategic focus for the current year is to support Sonangol on the continued delivery of the work programme for Block 3/05 which aims to enhance production, improve asset integrity and prepare for the next phase of workover and development drilling.  We continue to assess the scope to reduce the emissions profile of the asset and will begin to see positive trends in this regard as we ramp up production and commence various initiatives including gas utilisation.

The market dynamics in our industry continue to evolve and support our purpose in terms of facilitating a responsible industry transition.  We have established a strong foothold in a country that provides a positive fiscal environment and a portfolio of compelling opportunities in both the offshore and onshore areas.  We continue to strengthen our working relationship with key stakeholders in Angola and demonstrate our commitment to the long-term development of the upstream industry through our establishment of an office in Luanda and our partnering with local players.

I would like to thank all of our stakeholders, including Sonangol, ANPG, our partners, and of course our shareholders for their continued support.  Afentra remains committed to enhancing value for all of these stakeholders as we execute our well-defined growth strategy, and the Company is uniquely placed to leverage its stable growth platform to deliver the next stage of value creation .

Operations Review

Asset Summary

Afentra's enlarged asset footprint in Angola, both offshore and onshore provides a solid platform for material long-term organic and inorganic growth 

Increased exposure to world-class midlife assets, low-cost development and near-field and short-cycle exploration opportunities with significant upside potential

In 2024, Afentra completed its third transformative deal offshore Angola. The acquisition of additional non-operating interests from Azule Energy in Block 3/05 and Block 3/05A increased our interests to 30% and 21.33% respectively (an increase of 12% in Block 3/05 and 16% in Block 3/05A). . Providing Afentra with material exposure to these world-class mid-life producing assets that generate robust cashflows and provide near-term upside potential for organic growth as well as the opportunity to make an impactful reduction in emissions.

Onshore Angola, in July 2024 Afentra was awarded a 45% non-operated interest in the KON19 licence alongside Angolan companies ACREP (the Operator) and Enagol. Post-period end, in February 2025, the Company was also awarded a 45% non-operated interest in KON15 alongside Sonangol as Operator, further expanding our footprint onshore. This was signed on April 7^th 2025. Both licences are located in the proven, yet under-explored, onshore Kwanza basin. Entry into this basin, where 11 oilfields have been discovered, offers an opportunity for low-cost exploration and near-term development by applying fresh ideas and modern concepts to an area where no new technology has been applied for 40 years.

Fostering a close working relationship across the Joint Ventures

Since 2022 the Afentra team has developed a strong collaborative working relationship with Sonangol and the JV partners on Block 3/05 and Block 3/05A. The JV partners are aligned on making informed data driven decisions on field optimisation through the deployment of proven industry techniques and the latest technology, taking a phased approach to manage capital expenditure, with the aim being to cost effectively optimise and increase production while simultaneously reducing emissions.

Onshore, Afentra is also working closely with its JV partners on KON19 and post-period end on KON15 utilising technologies and techniques that the team have deployed successfully in other regions of Africa. For example, using basin-wide enhanced Full Tensor Gravity Gradiometry (eFTG) surveying to undertake a more comprehensive subsurface analysis of the largely unexplored onshore Kwanza basin.

Block 3/05 production increase and reserve replacement through phased long-term sustainable field extension activities

During 2024, Block 3/05 and Block 3/05A gross production averaged 21,111 bopd, a 5% increase from the prior year (2023: 20,180 bopd), with peaks exceeding 25,000 bopd. Over 40 light well interventions (LWIs during 2024 added 2,000 bopd, with a similar program planned for 2025. These LWIs and facility improvements drove a 140% reserve replacement since the last CPR, carried out in June 2023. Increased water injection will support the reservoir pressure which is expected to further enhance recovery factors and reduce emissions as a lower Gas Oil Ratio (GOR) reduces the need for gas flaring.

The Block 3/05 licence extension to 2040 and revised fiscal terms received in 2023 has allowed the JV partnership to strategically invest in infrastructure upgrades. At the end of 2024 the JV commenced a 3-year asset redevelopment plan that is designed to extend the field life, optimise and increase production, enable future development activities and reduce GHG emissions.

As part of the redevelopment plan, a planned 21-day maintenance shutdown was successfully conducted in October 2024. The shut-down specifically targeted making upgrades to the power equipment, and the metering systems for water and gas, improving reliability and enabling reliable emissions monitoring. The upgrades to the water injection system have resulted in year-end injection rates increasing to over 80,000 bwpd. Post-year end, Q1 2025 water injection rates have exceeded 100,000 bwpd. Further upgrades later in 2025 will increase available capacity up to 150,000 bwpd . The newly installed gas meters will pave the way for the JV to progress a field-wide gas export plan.

A further shutdown is planned for 2025 in accordance with the asset redevelopment plans to extend the field life and to ready the infrastructure for future increases in production. Future development activities include infill drilling, tie-backs of nearby satellite discoveries, and near-field exploration within Blocks 3/05 and 3/05A. The JV partnership is actively evaluating several opportunities, aiming to develop value-generating appraisal and development well proposals with the potential to add reserves within the 2026-2027 timeframe.

Near-term investment for long-term growth

Given the age and scale of the Block 3/05 infrastructure, the 2024 base operating expense associated with these assets is attractive at $23/bbl (and is expected to be similar in 2025). Going forward, production increases through further optimisation and near-field developments will act to further reduce the opex/bbl as near-term investment delivers long-term growth and value. Investment of $150 million gross (net: $39 million^{) [2] ,} including $40 million gross of life extension costs, was invested in 2024 in the first year of the 3-year asset redevelopment plan. Gross investment in 2025 will increase to around $180 million (net: $54 million^{) [3]} with a focus on asset integrity to continue to support our long-term increased production outlook. The three-year asset redevelopment plan is expected to be completed during 2027.

Angola: A prime location for portfolio expansion and a platform for wider growth

Angola has a compelling investment environment, supported by the Angolan government's stable fiscal regime and its commitment to enacting fiscal and regulatory reforms designed to encourage investment into its domestic oil and gas sector.

We view Angola as a core market and a key part of our growth strategy. An important part of our strategy is to actively collaborate with local partners like Sonangol, the NOC, and local Angolan companies such as ACREP, Etu Energias and Enagol to work together to maximise in-country value creation. The Angolan government, supported by the regulator ANPG's proactive and collaborative approach is fostering an environment where Afentra can deliver mutually beneficial outcomes for all stakeholders.

We are proud to be contributing to Angola's development through knowledge sharing and job creation, reflecting our commitment to having both a positive socioeconomic and environmental impact. With decades of experience working in Africa, we are deeply committed to positive community impact and local content development. In 2024, Afentra invested $150,000 in the HALO trust (for the year 2024 and 2025), an international landmine clearing organisation that has been active in Angola for over 30 years and has cleared over 120,000 landmines in this time.

Continued focus on enhancing asset value

Based on the success of the 2023 and 2024 Block 3/05 LWI program, coupled with the infrastructure upgrades resulting in increased water injection rates, a further 40 LWIs are planned during 2025. Going forward heavy workovers, artificial lift solutions, infill drilling, development of appraised discoveries and near-field exploration will provide the opportunity to potentially more than double production in the medium term.

Our enlarged Angolan asset base, both offshore and onshore, means that Afentra is well-positioned for long-term growth. Our commitment to Angola, demonstrated through strategic investments, collaborative partnerships, and a focus on sustainable development, ensures we are not only maximising value for our shareholders but also contributing to the economic and social well-being of the country. We look forward to continuing our journey in Angola, unlocking its vast potential and delivering lasting benefits for all stakeholders.

Angola Asset Summary

Block 3/05

Offshore, Angola, Afentra has a 30% non-operated interest in the producing Block 3/05 and a 21.33% non-operated interest in the adjacent development Block 3/05A. The mid-life fields that reside within the Block 3/05 licence together represent a significant underdeveloped asset with substantial potential to replace reserves, increase production and reduce emissions.

World-class shallow water assets with significant upside potential

Situated 37 km offshore Angola in 40-100 metres water depth, Block 3/05 comprises a portfolio of 8 mid-life producing fields: - Palanca, Impala, Impala SE, Bufalo, Pacassa, Pambi, Cobo, and Oomba. Spanning an area of around 40km by 15km, the licence contains extensive field infrastructure with 157 wells (currently 45 producing and 17 injecting water) and 17 installations, including the Palanca floating storage and offloading (FSO) vessel for oil export.

The fields, which produce from the prolific fractured Albian Pinda carbonate reservoir section, were discovered by Elf Petroleum (now TotalEnergies) in the early 1980s. They were developed using fixed platforms with oil production commencing in 1985. Earlier in the field life waterflooding was successfully implemented to enhance recovery, lowering uncertainty and supporting production forecasts for the assets. Since assuming Operatorship in 2005, Sonangol has concentrated on sustaining production through workovers and asset integrity maintenance.

JV aligned on field life extension and optimisation approach

The JV partnership on Block 3/05 and Block 3/05A are aligned on making data-driven decisions on field optimisation, using proven techniques and technology in a phased approach to cost-effectively upgrade the facilities, increase production, reduce emissions, and unlock the significant potential of these mid-life assets.

The extension of the licence to 2040 and improved fiscal terms, received during 2023, has unlocked investment in Life Extension (LIFEX) activities including increasing production. This includes facility upgrades, production optimisation activities through LWI techniques, and going forward plans are being progressed for subsurface optimisation with rig activities, and the development of surrounding discoveries. The upgrades to the asset integrity of the existing infrastructure will facilitate their use in the development of the numerous discoveries surrounding the existing producing fields.

Early field optimisation and life extension activities demonstrating upside field potential

We were pleased to report that in 2024 field production from Block 3/05 and Block 3/05A increased by 5% to an average of 21,111 bopd. This is the second year of consecutive production growth Strong operational performance post-shutdown positively impacted production and water injection rates: Gross average oil production from only Block 3/05 reached an average of 23,133 bopd (net: 6940 bopd) in December 2024.

The material uplift in production by the end of 2024, and the reserve replacement of 140% (since June 2023) announced post-period end can be attributed to the impact over the 18-month period of the LWI's and increased water injection coupled with material progress on facility recovery to process higher levels of production.

ESG embedded into our activities

Working closely with our JV partners, we aim to balance the socioeconomic benefits that come from production while lowering the environmental impact through targeted initiatives. The 2024 planned maintenance shutdown allowed for the installation of gas metering which will allow a baseline understanding of flare rates, composition and resulting emissions. The data from these new meters will inform the development of a holistic gas management plan to lower emissions through reduced flaring and through utilisation of gas for export.

Block 3/05 non-operated interest

Block 3/05 is operated by Sonangol through a JV partnership under a PSA. In 2023, the Block 3/05 PSA was extended to 2040 with enhanced fiscal terms.

Block 3/05 Work Program

Key achievements on the fields during the year have included achieving zero Lost Time Incidents (LTIs) in 2024 and maintaining the same 87% facilities uptime as in 2023. The JV is making near-term investments with targeted life extension activities, taking a long-term strategic approach to investing in the field to deliver growth and value into the 2030s and beyond.

Futureproofing infrastructure to increase production and reduce emissions

During 2024 the JV commenced a 3-year asset redevelopment plan to extend the field life, optimise and increase production, and reduce GHG emissions, this included the recertification of the Palanca FSO. The recertification of the vessel will lead to no dry dock before 2030. These efforts align with the extended licence for Block 3/05, which now runs through to 2040. Key infrastructure upgrades included enhancements to compressors, power generation systems, and flowlines.

Afentra and the JV are fully aligned on taking a phased and targeted approach to life extension  capital expenditure. This has started with stabilising and sustaining current production, optimising the existing well stock, and will ultimately lead to the next stage of future development through infill drilling and tie-backs of nearby satellite fields.

Stabilise and Sustain Production

The "Stabilise and Sustain" programme, which included the planned 21-day maintenance shutdown in October 2024 focused on four key areas: asset integrity, water management, power systems and gas metering. By upgrading these key areas, we are laying the groundwork for production to increase and a reduction in emissions.

Ramping up water injection

For the JV, achieving higher and more stable injection rates is a key objective, as it will continue to positively impact oil production in the medium term as production rates respond to reservoir pressure increases. During 2024, there was a significant investment in water injection upgrades across the fields with new filters, pumps and meters installed. The implemented upgrades have resulted in an immediate performance improvement, with year-end injection rates at up to 80,000 bwpd. The fields now have significantly higher injection capacity compared to 2022, and the field is now prepared for a planned injection rate ramp-up in 2025 to above 100,000 bwpd using two pumps with a third scheduled to come online later in 2025 resulting in up to 150,000 bwpd of available capacity. Post-period end water injection rates have exceeded 100,000 bwpd.

Light Well Interventions

The LWI campaign carried out during 2024, in continuation of the program that commenced in 2023, involved successfully re-entering 40 wells to carry out matrix and tubing washes, perform water shut offs and re-perforations. The LWIs have continued to demonstrate the benefits and potential of low cost well interventions on these fields with an average gain of around 130 bopd per intervention and with an average payback of less than six weeks.

Gas lift optimisation was carried out in 2024, with seven well improvements and the focus has now shifted to gas compression and further optimisation of the intra-field gas network. Gas meters have also now been installed on the flares, providing accurate measurement and an accurate baseline to measure emission reductions.

Holistic asset gas management

In 2024, significant progress was made in implementing the holistic gas management plan which aims to lower emissions by reducing flaring, mitigating fugitive emissions and looking at gas export options. Three factors are contributing to reduced gas flaring and emissions: increased water injection will lower the GOR, a recent drone survey conducted late 2023 has informed a fugitive emissions mitigation strategy, and new gas meters will enable more accurate emissions monitoring and the development of gas export plans.

Shift to gas and network optimisation, heavy workovers and drilling for 2025-2027

Looking ahead, the focus is shifting to gas compression and network optimisation in 2025, a heavy workover program ,  and preparing for rig-related life extension activities in 2026. In 2024 there was also investment in long lead items to enable future rig related activity.

Collaborative JV workshops have identified a series of low cost and low risk workovers from the extensive inventory of wells currently offline. Initial focus for heavy workovers will be on the Palanca and Impala fields where a number of well reactivation and ESP opportunities have been selected for high grading. Here there is a significant oil in place which is not being effectively accessed and recovered.

There is a significant opportunity to increase production through infill drilling, with no infill wells drilled for over 10 years, and over 20 targets identified. Strong candidates are wells with lower GOR  such as at Pacassa SW or infield wells where existing infrastructure can be used to rapidly bring them onto production. The JV partners are working collaboratively through the selection of infill candidates from Pacassa, Palanca, Impala SE, Buffalo, Cobo, Pambi and Impala fields, with an initial phase of drilling planned to start in 2026, with new infill wells potentially adding 500-2000 bopd of production per well.

Near-field Developments and Exploration

Near-field exploration and development within both Block 3/05 and 3/05A offer significant opportunities to increase oil production further, with the potential for discoveries to hold over 300 mmbo (3/05A) and 100-200 mmbo (3/05). Satellite discoveries have the potential to deliver up to 10,000 bopd through phased development.

Case Study: Afentra and JV technical collaboration drive early production gains from LWIs

Since 2022, Afentra's technical team has been working collaboratively with the JV partnership to advance production optimisation projects as well as longer term planning for field extension and further infield development activities. 

Before joining the licence, our technical team identified the potential for low-cost light well intervention (LWI) workovers to rapidly boost production. Evaluating available wireline log data, historical well completion data, and production history, the team has worked together with the Operator and JV partners to identify and rank LWI candidates.

Through interactive workshops in Luanda, Afentra has facilitated strong collaboration with Sonangol and the JV partners, leveraging our team's extensive geoscience and well engineering experience to develop detailed technical proposals. The proposals encompass a range of intervention options, including acid washes, matrix washes, gas lift valve change-outs, and reperforations to restimulate intervals and to access previously untapped oil zones.

The LWI program has yielded impressive results. In 2023, interventions delivered an additional 4,000 bopd, followed by an additional 2,000 bopd in 2024. These early successes will inform and drive continued LWI programs in subsequent years. 

Furthermore, the JV's collaborative efforts have increased the number of active production wells from 42 to 45 and injection wells from 15 to 17, demonstrating a joint commitment to optimising field performance and maximising the value of the asset. With 95 inactive wells remaining, the potential for future interventions remains substantial.

Block 3/05A

Significant low cost near-field development potential

Adjacent to Block 3/05, Block 3/05A houses the undeveloped Punja, Caco and Gazela discoveries with an estimated in-place resource of 300 million barrels. Afentra estimates gross 2C recoverable resources at 33 million barrels.

The Gazela field, commenced production in 2015, with approximately 2.4 mmbo recovered prior to a wellbore shutdown in 2017. Production was restored in March 2023 with the Gazela-101 well averaging around 1,248 bopd gross during 2024. This extended production test is helping to establish the long-term resource potential and appropriate development strategy. Subsurface mapping has been completed on the Caco and Gazela fault compartments to identify future potential production or injection wells. These will now be ranked alongside other rig related opportunities for selection in the potential 2026 / 2027 drilling campaign.

Development concepts actively being progressed

Given the high gas oil ratio of the Punja field reservoirs, an integrated gas management plan across both Blocks 3/05A and 3/05 is essential to optimise the responsible development of these oil and gas resources. In line with our stated environmental commitments, all alternatives to flaring excess gas from additional developments will be evaluated with the JV before proceeding to sanction future projects. There are a number of zero routine flaring options that will be evaluated, including commercial export of excess gas via the ALNG network which is located in close proximity to existing infrastructure or gas injection into existing fields. Both options will require review and a potential upgrade of the existing compression infrastructure. 

The JV partnership will be progressing the next steps to both Punja and Caco-Gazela in a phased approach to gain appraisal data, reduce uncertainty and generate cash flow through monetising early production. A number of development concepts will be screened and ranked in order to reach an optimised FID in the near term.

The Block 3/05A PSA expires in 2035, having commenced in 2015 and could be extended if production is still ongoing. The Punja undeveloped discovery received marginal field terms in 2024 enhancing the commercial value of this block.

Block 3/05A non-operated interest

Block 3/05A is operated by Sonangol through a JV partnership under a PSA.

Onshore Angola

Blocks KON15 and KON19 (awarded post-period end) offer low-cost near-term exploration potential

Onshore Angola, Afentra was awarded a 45% non-operated interest in both KON19 in July 2024, and post-period end a 45% non-operated interest in KON15. Both licences are in the proven yet under-explored onshore Kwanza basin. Entry into this basin, where 11 oilfields have been discovered, offers a value driven strategic opportunity for near-term and low-cost exploration in a proven basin by applying fresh ideas and modern concepts to an area where no new technology has been applied for 40 years.

KON15 and KON19 are located adjacent to the legacy Tobias and Galinda oil fields and offer significant potential within Angola's prospective post-salt and pre-salt formations. Leveraging existing data, these blocks can be quickly explored and appraised, potentially leading to rapid development and production. These licences will expand Afentra's footprint in this attractive Angolan market by diversifying our portfolio which is principally focused on low cost, long-life stable production and low-risk development assets.

Under-explored proven hydrocarbon basin

The onshore Kwanza basin covers 25,000 km2 and is an underexplored, over-looked proven hydrocarbon basin that has numerous oil fields and discoveries dating back to 1955. The basin produced over 15,000 bopd in the 1960's and 1970's from post-salt traps. Onshore activity declined and ceased during the instability of the Angolan civil war after which the focus was offshore oil and gas field development.

Both KON15 and KON19 blocks were high graded by Afentra in 2023 as they have good signs of a working petroleum system and contain wells that were drilled on salt structures with light oil recovered to surface in one and oil shows in others from post and pre-salt reservoirs. We continue to evaluate additional opportunities utilising technologies and techniques that the team have successfully deployed in other regions of Africa.

For example, although the full work program is yet to be finalised, the initial phase of a basin-wide enhanced Full Tensor Gravity Gradiometry (eFTG) survey, launched in August 2024, has been completed for KON19, with the remaining KON15 phase being completed in 2025. This advanced eFTG technology will facilitate a more comprehensive subsurface analysis of the 25,000km² onshore basin, a largely unexplored region in recent decades and identify prospective regions.

Block KON15 

Block KON19 

Angola -   Block 23 

Afentra also holds a 40% non-operated interest in Block 23, a deepwater exploration licence with a proven hydrocarbon potential and no outstanding work commitment. In 2024 the new Operator Namcor was announced.

Block 23 is a 5,000 km2 exploration and appraisal block located in the offshore section of the Kwanza basin in water depths ranging from 600 to 1,600 meters, with a proven working petroleum system, and is in proximity to TotalEnergies Kaminho future deepwater development. Whilst this large block is covered by modern 2D and 3D seismic data sets, with no outstanding work commitments remaining, much of the block remains under-explored.

Block 23 non-operated interests

Somaliland

Odewayne Block

Afentra also has a 34% carried interest in the onshore Odewayne Block onshore southwestern Somaliland. The Block is an unexplored frontier acreage position covering 22,840km2 offering the opportunity to explore an undrilled onshore rift basin in Africa.

Financial Review

In 2024 we continued to grow our asset base in Angola as we completed our third acquisition on Block 3/05 and Block 3/05A, increasing our interest to 30% and 21.33%, respectively, as well as accessing the onshore Kwanza basin in July by securing a 45% non-operated interest in Block KON19 alongside local companies ACREP (Operator with 45% interest) and Enagol (10%). During the year we also established a presence in Luanda, Angola, through the appointment of a Country Manager in Luanda who opened our local office in Q4. Operationally, we successfully completed four crude oil liftings during the year, generating $180.9 million of revenue, and anticipate a further five liftings in 2025.

Our financial position has undergone a significant transformation in 2024, demonstrating the value generated through strategic acquisitions, stable asset performance and effective management. We ended 2024 with $54.8 million in cash ($19.6 million at 31 December 2023), inclusive of restricted cash balances, achieving an end of year net cash position of $12.6 million (Net debt $12.3 million at 31 December 2023).

We continue to manage our exposure to oil price risk through our hedging strategy and, during 2024, hedged 70% of sales volumes through a combination of put options and collar structures. The hedge portfolio consisted of $70 to $80 per barrel put options, covering 70% of sales volumes, and $90 per barrel call options, covering 29% of sales volumes. For 2025, we have hedged approximately 68% of estimated sales volumes. Our 2025 hedge portfolio consists of a combination of put options with floors ranging between $60 and $65 per barrel covering 68% of estimated sales volumes and call options with caps ranging from $80 to $89 per barrel, covering 44% of estimated sales volumes. The company continues to explore and to evaluate other hedge products in the market consistent with its hedging policy.

In line with Afentra's commitment to avoiding shareholder dilution, the Company has elected to satisfy vested options under the Founders' Share Plan (FSP) through market purchases via an existing Employee Share Benefit Trust (Trust) rather than issuing new Ordinary Shares. Subsequently, the Trust purchased 381,719 shares on the open market at an average price of ~41p. Furthermore , the Trust will continue with the share purchase programme to satisfy the requirements of the employee LTIP and final 2026 FSP vesting. Subject to certain purchase criteria to be agreed with the Trust, the Trust is expected to purchase of up to 6.5 million Ordinary Shares over the rest of 2025/Q1 2026. Full details of the FSP scheme are provided in the Remuneration Committee Report of the Annual Report.

For 2025, our focus on M&A remains unchanged as we continue to seek to build our portfolio via value accretive opportunities in Angola, as well as in other jurisdictions in the West Africa region.  In February of this year, we secured our interest in the onshore Block KON15, thereby securing our second onshore asset in Angola. On asset management, we will look to develop our office presence in Luanda and will continue to work constructively with the Operator and our JV partners on Block 3/05 and Block 3/05A to ensure continued safe operations as well as seeking to develop value accretive opportunities in both existing operations as well as new projects.

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.

EBITDAX (Adjusted) is a non-IFRS financial measure. The Company believes that this non-IFRS financial measure assists investors by excluding the potentially disparate effects between periods of the adjustments specified.

EBITDAX (Adjusted) should not be considered as an alternative to Net income or any other indicator of Afentra plc's performance calculated in accordance with IFRS. Because the definition of EBITDAX (Adjusted) may vary among companies and industries, it may not be comparable to other similarly titled measures used by other companies.

Income Statement

Average production from Afentra's interests in Blocks 3/05 and 3/05A increased to 6,229 bopd from 3,509 bopd as a result of the completion of the Azule transaction in May 2024, where Afentra acquired an additional 12% and 16% in Blocks 3/05 and 3/05A, respectively.

2024 revenue, net of off-take fees, of $180.9 million (2023: $26.4 million) from four liftings completed during the year at an average realised price of $82.2/bbl.

Cost of sales during the year totalled $96.7 million (2023: $12.6 million); a full reconciliation is provided in the notes to the accounts (Note 4).

The profit from operations for 2024 was $71.9 million (2023: $2.4 million) as a result of the four liftings in 2024 and increased stake in each block. During the year, net administrative expenditure increased slightly to $12.3 million (2023: $11.5 million).

Finance income (interest on deposits) of $0.1 million (2023: $0.2 million) was received in the year. Finance costs increased during 2024 to $9.0 million (2023: $3.5 million), primarily due to additional drawdowns on the RBL and working capital facilities. Further detail is provided in the notes to the accounts (Note 7).

The profit after tax for the year was $49.8 million (2023: loss after tax $2.7 million):

Group adjusted EBITDAX totalled $90.9 million (2023: $11.1 million):

[1] Total depletion on oil and gas assets in 2024 is the depletion charged to profit and loss ($12.1 million) and absorbed in inventory ($0.2 million). Depreciation on other assets totalled $0.3 million.

The basic and diluted earnings per share for the year was 22.2 cents (2023: 1.2 cents loss) and 20.1 cents (2023: 1.2 cents loss) respectively. No dividend is proposed to be paid for the year ended 31 December 2024 (2023: nil).

Statement of financial position

At the end of 2024, non-current assets totalled $150.2 million (2023: $97.0 million, as restated). The increase is primarily due the further acquisition from Azule of the Company's interests in Block 3/05 and Block 3/05A ($38.3 million) as well as capital expenditure on the two blocks ($26.1 million), offset by depreciation ($12.6 million). Further information can be found in Note 11 to the Annual Financial Statements.

At the end of 2024, current assets stood at $73.9 million (2023: $43.7 million, as restated) including cash and cash equivalents of $46.9 million (2023: $14.7 million), restricted funds of $7.9 million (2023: $4.9 million), trade and other receivables of $11.4 million (2023: $10.7 million as restated), and inventories of $7.5 million (2023: $13.4 million).

At the end of 2024, current liabilities were $71.1 million (2023: $45.9 million as restated) including trade and other payables of $52.9 million (2023: $34.4 million as restated), borrowings of $11.3 million (2023: $6.8 million), contingent consideration of $5.5 million (2023: $4.6 million), and derivative liabilities of $1.3 million (2023: nil). The increase in trade and other payables is related to the Company's increased share of Joint Venture working capital items (Block 3/05 and Block 3/05A).

At the end of 2024, non-current liabilities were $56.9 million (2023: $46.9 million, as restated), comprised primarily of borrowings of $30.1 million (2023: 25.0 million) and contingent consideration of $24.4 million (2023: $21.9 million), and deferred tax of $1.7 million (2023: nil). The increase is primarily due to additional drawdowns on the RBL and working capital facilities during the year. Further information can be found in Note 19.

The Group's net assets increased from $48.0 million at the end of 2023 to $96.1 million as at 31 December 2024, primarily reflecting profits earned during the year.

Cash flow

Net cash inflow from operating activities totalled $85.6 million (2023: $12.3 million). The increase is primarily due to a full year activity on Blocks 3/05 and 3/05A, compounded by additional equity acquisitions relating to these blocks.

Net cash used in investing activities increased to $53.6 million from $45.9 million in 2023. Additions to property plant and equipment was offset by lower asset acquisitions and contingent consideration payments made during the year.

Net cash generated from financing activities totalled $0.1 million compared to $28.0 million in 2023 due to repayments of debt principal and interest.

Accounting Standards

The Group has reported its 2024 and 2023 full year 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.

Anastasia Deulina - Chief Financial Officer

 

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

The statement of comprehensive income has been prepared on the basis that all operations are continuing operations.

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

¹ The comparative information has been restated as a result of a reassessment of Afentra's future liability for decommissioning expenditure and the treatment of joint venture receivable and payable balances. Further information is detailed in Note 29.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

CONSOLIDATED STATEMENT OF CASH FLOWS

COMPANY STATEMENT OF FINANCIAL POSITION

The loss for the financial year within the Company accounts of Afentra plc was $24.9 million (2023: $4.4 million). As provided by s408 of the Companies Act 2006, no individual Statement of Comprehensive Income is provided in respect of the Company.  

 

COMPANY STATEMENT OF CHANGES IN EQUITY

NOTES TO THE FINANCIAL STATEMENTS

1.          Material accounting policies

a)         General information              

Afentra plc (the 'Company') is a public company, limited by shares, incorporated in England under the UK Companies Act 2006. The address of the registered office is 10 St Bride Street, London, EC4A 4AD. The principal activities of the Company and its subsidiaries (the "Group") and the nature of the group's operations include the exploration, development and production of commercial oil and gas.  

These financial statements are presented in US dollars rounded to the nearest thousand, unless stated otherwise. They include the financial statements of Afentra plc and its consolidated subsidiaries. The functional currency of the Company is US dollars .

The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2024 or 2023, but is derived from those accounts. Statutory accounts for 2023 have been delivered to the Registrar of Companies and those for 2024 will be delivered following the Company's Annual General Meeting.

The auditors have reported on those accounts; their reports were unqualified, did not draw attention to any matters by way of emphasis without qualifying their report and did not contain statements under s498(2) or (3) Companies Act 2006.

While the financial information included in this announcement has been prepared in accordance with the recognition and measurement criteria of International Financial Reporting Standards (IFRSs), this announcement does not itself contain sufficient information to comply with IFRSs.

The financial statements have been prepared under the historical cost convention. The principal accounting policies adopted are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.

b)         Basis of accounting and adoption of new and revised standards

The financial statements have been prepared in accordance with UK adopted international accounting standards and with those parts of the Companies Act 2006 applicable to companies reporting under IFRS, except as otherwise stated. As ultimate parent of the Group, the Company has taken advantage of Financial Reporting Standard 101 Reduced Disclosure Framework (FRS 101), which addresses the financial reporting requirements and disclosure exemptions in the individual financial statements of "qualifying entities", that otherwise apply the recognition, measurement and disclosure requirements of UK adopted international accounting standards.  

The disclosure exemption adopted by the Company in accordance with FRS 101 are:  

- a statement of compliance with IFRS (a statement of compliance with FRS 101 is provided instead);

- related party transactions with two or more wholly owned members of the group; and

- a Statement of Cash Flows and related disclosures

In addition, and in accordance with FRS 101, further disclosure exemptions have been applied because equivalent disclosures are included in the consolidated financial statements of Afentra plc. These financial statements do not include certain disclosures in respect of:

  - financial instrument disclosures as required by IFRS 7 Financial Instruments: Disclosures; and

- fair value measurements - details of the valuation techniques and inputs used for fair value measurement of assets and liabilities as per paragraphs 91 to 99 of IFRS 13 Fair Value Measurement.

(i) New and amended standards adopted by the Group:    

The following standards and amendments became effective in the year ended 31 December 2024. 

None of the above standards or amendments have had a material impact on the Group. 

(ii) Standards, amendments and interpretations, which are effective for reporting periods beginning after the date of these financial statements which have not been adopted early: 

At the date of authorisation of these financial statements, the Group has not applied the following new and revised IFRS Accounting Standards that have been issued but are not yet effective:

The Group is currently assessing the effect of these new accounting standards and amendments.  IFRS 18 Presentation and Disclosure in Financial Statements, which was issued by the IASB in April 2024 supersedes IAS 1 and will result in major consequential amendments to IFRS Accounting Standards including IAS 8 Basis of Preparation of Financial Statements (renamed from Accounting Policies, Changes in Accounting Estimates and Errors). Even though IFRS 18 will not have any effect on the recognition and measurement of items in the consolidated financial statements, it is expected to have a significant effect on the presentation and disclosure of certain items. These changes include categorisation and sub-totals in the statement of profit or loss, aggregation/disaggregation and labelling of information, and disclosure of management-defined performance measures.  The Group does not expect to be eligible to apply IFRS 19.

c)         Going concern

The Group's business activities, together with the factors likely to affect its future development, performance, and position are set out in the Operations Review. The financial position of the Group and Company, its cash flows and liquidity position are described in the Financial Review. In addition, Note 23 to the financial statements includes the Group's objectives, policies and processes for managing its capital financial risk, details of its financial instruments and its exposures to credit risk and liquidity risk.

The Group has sufficient cash resources for its working capital needs and its committed capital expenditure programme at least for the next 12 months from the signing of the annual report. Consequently, the Directors believe that both the Group and Company are well placed to manage their business risks successfully.

The Group has sufficient cash resources based on existing cash on balance sheet, proceeds from future oil sales and access to the revolving working capital facility to meet its liabilities as they fall due for a period of at least 12 months from the date of signing these financial statements, based on forecasts covering the period through to 30 April 2026.

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 capital expenditure programme by the Joint Venture. The Board also notes the implementation of the hedging policy and is confident in the utilisation of commodity-based derivatives to manage oil price downside risk.  The existing financial covenants, the tests of which for current borrowings, have been passed for the Historic Ratio (Net debt/EBITDA) and the Gross liquidity test, and 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.

d)          Basis of consolidation

(i)         Subsidiaries

The consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is recognised where an investor is exposed, or has rights, to variable returns from its investment with the investee and has the ability to affect these returns through its power over the investee.

The results of subsidiaries acquired or disposed of during the year are included in the Statement of Comprehensive Income from the effective date of acquisition or up to the effective date of disposal, as appropriate.

Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used into line with those used by the Group.

(ii)           Transactions eliminated on consolidation  

Intra-group balances and any unrealised gains and losses, or income and expenses arising from intra-group transactions, are eliminated in preparing the consolidated financial statements. 

e)         Joint arrangements

The Group is a party to a joint arrangement regardless of whether the Group has joint control of the arrangement. Where the contractual arrangement confers joint control over the relevant activities to the Group and at least one other party, then the Group classifies its interest in the joint arrangement as joint operations or joint ventures in accordance with IFRS11. Joint control is assessed under the same principles as control over subsidiaries. If there is no joint control, then the Group classifies its interest in the joint arrangement as a party to a joint arrangement. In assessing the classification of interests in joint arrangements, the Group considers: 

·    the structure of the joint arrangement;

·    the contractual terms of the joint arrangement; and 

·    any other facts and circumstances.

The Group accounts for its interests in joint arrangements by recognising its share of assets, liabilities, revenues, and expenses in accordance with its contractually conferred rights and obligations. 

The Group's material arrangements comprise non-operated interests in Block 3/05 (30%) and Block 3/05A (21.33%) located offshore Angola in the Lower Congo Basin.

f)           Revenue

Revenue is derived from the sales of oil from the interests held in Angola. Revenue from the sale of crude oil is recognised when performance conditions in the sales contract are satisfied and it is probable that the Group will collect consideration to which it is entitled. For crude oil, the performance condition is the delivery of the oil through lifting or on delivery of the oil into an infrastructure. Revenue is measured at the fair value of the consideration to which the company expects to be entitled in exchange for transferring promised goods and/or services to a customer, excluding amounts collected on behalf of third parties.

Under/overlift

Any production imbalance that may arise as a result of lifted volumes being different to produced volumes has been recognised as an adjustment to cost of sales, with the balance being recognised within inventory/trade and other receivables when we have lifted less than our share of production (underlifted) and trade and other payables when we have lifted more than our share of production (overlifted). Underlifted barrels are valued at cost and overlifted barrels at market value.

g)         Oil and gas interests

Commercial reserves

Commercial reserves, at the 2P level,  are proven and probable oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. This implies a 50% probability that the quantity of recoverable reserves will be more than the amount estimated as proven and probable reserves and a 50% probability that it will be less.

Capitalisation

Pre-acquisition costs on oil and gas assets are recognised in the profit or loss when incurred. Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and commercial appraisal costs, and other directly attributable costs of exploration and appraisal, including technical and administrative costs, are capitalised as intangible exploration and evaluation (E&E) assets. The assessment of what constitutes an individual E&E asset is based on technical criteria but essentially either a single licence area or contiguous licence areas with consistent geological features are designated as individual E&E assets. Costs relating to the exploration and evaluation of oil and gas interests are carried forward until the existence, or otherwise, of commercial reserves have been determined.

E&E costs are not amortised prior to the conclusion of appraisal activities. Once active exploration is completed the asset is assessed for impairment. If commercial reserves are discovered then the carrying value of the E&E asset is reclassified as a development and production (D&P) asset, following development sanction, but only after the carrying value is assessed for impairment and, where appropriate, its carrying value adjusted. The E&E asset is written off to the profit or loss if it is subsequently assessed that commercial reserves have not been discovered.

Costs associated with D&P assets, including the costs of facilities, wells and subsea equipment, are capitalised within Property, Plant & Equipment.

Impairment

In accordance with IFRS 6, E&E assets are reviewed for impairment when circumstances arise which indicate that the carrying value of an E&E asset exceeds the recoverable amount. The recoverable amount of the individual asset is determined as the higher of its fair value less costs to sell and its value in use. Impairment losses resulting from an impairment review are recognized within the Statement of Comprehensive Income. 

Impaired assets are reviewed annually to determine whether any substantial change to their fair value amounts previously impaired would require reversal. 

An impairment loss is reversed if the recoverable amount increases as a result of a change in the estimates used to determine the recoverable amount, but not to an amount higher than the carrying amount that would have been determined (net of depletion or amortisation) had no impairment loss been recognised in prior periods. Impairment charges and reversal of impairments are recorded within total administration expenses in the Statement of Comprehensive Income.

Depreciation, depletion, and amortisation of D&P assets

All expenditure carried within each field is amortised from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field-by-field basis or by a group of fields which are reliant on common infrastructure. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs required to recover the commercial reserves remaining. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively.

Decommissioning and pre-funded amounts

Provisions for decommissioning are recognised when the Group has a present legal or constructive obligation, which generally arises when a well is drilled or equipment installed. The provision for future decommissioning is calculated, based on future cash flows discounted at a pre-tax discount rate to reflect risks specific to the costs. An amount equivalent to the initial provision for decommissioning costs is capitalised and amortised over the life of the underlying asset.

Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. The unwinding of the discount on the decommissioning provision is included as a finance cost.

The Group's interest in the amounts previously pre-funded for decommissioning obligations are recognised in accordance with IAS 37 Provisions, Contingent Liabilities and Contingent Assets and IFRIC 5 Rights to Interests arising from Decommissioning, Restoration and Environmental Rehabilitation Funds. Where the Group is not liable to pay decommissioning costs if the funds previously deposited are not made available, the amounts previously pre-funded are not recognised separately, but are included in the cost estimate of the residual provision for decommissioning.

h)            Property, plant and equipment assets other than oil and gas assets  

Property, plant and equipment other than oil and gas assets are stated at cost less accumulated depreciation and any provision for impairment. Depreciation is provided at rates estimated to write off the cost, less estimated residual value, of each asset over its expected useful life as follows:

Office lease: straight-line over the lease term

Computer and office equipment: 33% straight-line

i)              Foreign currencies

The US dollar is the functional and reporting currency of the Company and the reporting currency of the Group. Transactions denominated in other currencies are translated into US dollars at the rate of exchange at the date of the transaction. Assets and liabilities in other currencies are translated into US dollars at the rate of exchange at the reporting date. All exchange differences arising from such translations are recorded in the Statement of Comprehensive Income.

The results of entities with a functional currency other than the US dollar are translated at the average rates of exchange during the period and their statement of financial position at the rates ruling at the reporting date. Exchange differences arising on translation of the opening net assets and on translation of the results of such entities are recorded through the currency translation reserve.

j)             Taxation

Current tax - Angola

The activities relating to the Angolan branch are subject to tax in Angola. Angolan tax is calculated on the basis of revenue rather than the profits of the branch. Petroleum income tax is calculated on the basis of profit oil which is valued by the tax reference prices determined by the Ministry of Finance on a quarterly basis. From 1 January 2024 the group has applied the foreign branch election that ringfences the profits in Angola to only be subject to Angolan tax.

Current tax - United Kingdom

Tax is payable based upon taxable profit for the year. Taxable profit differs from net profit as reported in the Statement of Comprehensive Income because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. Any Group liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

k)         Investments in subsidiaries

Investments in subsidiaries are carried at cost less accumulated impairment losses. Investments in subsidiaries are assessed for impairment in line with the requirements of IAS36 and, where evidence of non-recoverability is identified, an appropriate impairment loss is recorded.

l)          Leases

In accordance with IFRS16, the Group recognises a right-of-use asset and a lease liability on the balance sheet at the lease commencement date. The Group assesses the right-of-use asset for impairment when such indicators exist. At the commencement date, the Group measures the lease liability at the present value of the future unpaid lease payments at that date, discounted using the interest rate implicit in the lease if that rate is readily available, or the Group's incremental borrowing rate .

m)        Financial instruments

Trade receivables

Trade receivables are recognised and carried at the original invoice amount less any provision for expected credit loss (ECL). Other receivables are recognised and measured at nominal value less any provision for ECL.

The Group applies the expected credit loss model in respect of trade receivables. The Group tracks changes in credit risk and recognises a loss allowance based on lifetime ECLs at each reporting date.

Amounts due from subsidiaries

Amounts due from subsidiaries are recognised and measured at nominal value less any provision for ECL.

The Company applies the expected credit loss model in respect of amounts due from subsidiaries. The Company tracks changes in credit risk and recognises a loss allowance based on lifetime ECLs at each reporting date.

Cash and cash equivalents

Cash and cash equivalents consist of cash, bank deposits, and highly liquid financial instruments with maturities of three months or less.

Restricted cash

Restricted cash consists of bank deposits which are subject to restrictions due to legislation, regulation or contractual arrangements. Please see Note 16 for detailed disclosure.

Trade payables

Trade payables are stated at amortised cost.

Borrowings and loans

Interest bearing bank loans and overdrafts are recorded at the proceeds received. Finance charges relating to securing the loans and overdrafts are capitalised as part of the loan and amortised over the repayment term period of the loan.

Financial liabilities and equity

Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the asset of the Group after deducting all of its liabilities. Equity instruments issued by the Company are recorded at the proceeds received net of direct issue costs.

Derivative financial instruments and hedging activities

Derivative financial instruments are measured at fair value and are not designated as hedging instruments. Changes in fair value are recorded as a gain or loss as within the Statement of Comprehensive Income.

n)         Pension costs

The Group operates a number of defined contribution pension schemes. The amount charged to the Statement of Comprehensive Income for these schemes is the contributions payable in the year. Differences between contributions payable in the year and contributions actually paid are shown as either accruals or prepayments in the Statement of Financial Position.

o)         Segment reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker (CODM). The CODM has been identified as the Board of Directors. The Group currently operates only in Africa and is supported by the United Kingdom head office which is not deemed to be an operating segment as it does not generate any revenue outside of the operations in Africa. As the Group only has one operating segment no further breakdown has been provided.

p)         Inventories

Oil Inventories are stated at the lower of cost or net realisable value. The cost comprises direct materials, direct labour, overheads, and other charges incurred in the production and storage of oil. Other inventories are stated at the lower of cost and net realisable value. The cost of materials is the purchase cost determined on a first-in first-out basis.

q)          Share-based payments

Employees (including senior executives) of the Company receive remuneration in the form of share-based payment transactions which are equity settled. The cost of equity-settled transactions with employees is measured by reference to the fair value at the date on which they are granted. The fair value is determined by an external valuer using an appropriate pricing model.

The estimated cost of equity-settled transactions is recognised in the profit and loss account as an expense, together with a corresponding increase in equity. This expense and adjustment to equity is recognised over the period in which the performance and/or service conditions are measured (the "vesting period"), ending on the date on which the relevant participants become fully entitled to the award (the "vesting date").

The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Company's best estimate of the number of equity instruments that will ultimately vest. The Income Statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

The key areas of estimation regarding share-based payments are share price volatility and estimated lapse rates, due to service conditions and non-performance conditions not being met.

No adjustments are made in respect of market conditions not being met. Similarly, the number of instruments and the grant-date fair value are not adjusted, even if the outcome of the market condition differs from the initial estimate.

Where the terms of an equity-settled award are modified, the minimum expense recognised is the expense as if the terms had not been modified. An additional expense is recognised for any modification, which increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employee as measured at the date of modification.

Where an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. However, if a new award is substituted for the cancelled award, and designated as a replacement award on the date that it is granted, the cancelled and new awards are treated as if they were a modification of the original award, as described in the previous paragraph.

The dilutive effect of outstanding options is reflected as additional share dilution in the computation of earnings per share.

Although all awards are deemed to be equity settled, the Company may decide to settle the awards in cash, without raising new share capital. If no new share capital is issued to the market then the settlement of the award becomes a true cash cost to the Company.  The likelihood and magnitude of this liability remain unknown until vest date, with the Company making the final decision regarding settlement until near the vest date, and as such no liability for this possible cash outflow is recognised in the accounts.  Where tax payments associated with share-based payments are required to be paid in cash, the arrangement continues to be accounted for as equity settled.

2.          Critical accounting judgements and estimates

In the application of the Group's accounting policies, which are described in Note 1, the Directors are required to make judgements, estimates, and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods.

Judgements

The following are the critical judgements, apart from those involving estimations (which are presented separately below), that the directors have made in the process of applying the group's accounting policies and that have the most significant effect on the amounts recognised in financial statements.

Business combinations and asset acquisitions

The Group has acquired working interests in producing oil blocks and judgement is required to determine whether the acquisition should be accounted for as an asset acquisition or a business combination. The Group assessed joint control, as determined under IFRS11, does not exist among the contractor partners to the arrangement because there are several combinations of partners who can combine to meet the passmark vote for strategic and financial decisions.

No specific accounting guidance exists for an acquisition of a working interest in a producing oil block where joint control does not exist and management have determined the acquisition will be accounted for as an asset acquisition under IFRS3 which requires an allocation of the consideration across the identified assets and liabilities based on their relative fair values.

See Note 24 for further information on the acquisitions of oil and gas assets in the year.

Impairment of E&E assets

Management is required to assess oil and gas assets for indicators of impairment and has considered the economic value of individual E&E assets. E&E assets are subject to a separate review for indicators of impairment, by reference to the impairment indicators set out in IFRS6, which is inherently judgmental. 

After reviewing the feasibility of the asset detailed in the Operations Review and considering the key factors including: the extension to the current period and further exploration work streams planned in 2025, management did not note any impairment indicators that would result in a full impairment review to be undertaken. 

The Directors judgement was that a full impairment review wasn't required and thus no impairments were recognised during the year by the Group.

Refer to Note 10 for further information on E&E assets.

Pre-funded decommissioning liabilities

Where decommissioning liabilities have been pre-funded by the contractor group, a judgement was made that the contractor group would be discharged of its obligation to decommission the field should the pre-funding not be made available when due. As required IAS 37 Provisions, Contingent Liabilities and Contingent Assets and IFRIC 5 Rights to Interests arising from Decommissioning, Restoration and Environmental Rehabilitation Funds where the Group is not liable to pay decommissioning costs if the funds previously deposited are not made available, the amounts previously pre-funded are not recognised separately, but are included in the cost estimate of the residual provision for decommissioning.  For further information refer to Note 29.

Estimates and assumptions

The key assumptions concerning the future, and other key sources of estimation uncertainty at the reporting period that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.

Contingent consideration

Contingent consideration in relation to the asset acquisitions of Blocks 3/05 and 3/05A in Angola is accounted for as a financial liability at fair value at the date of the acquisition with any subsequent remeasurements recognised in profit or loss. These fair values are based on risk adjusted future cash flows discounted using the appropriate discount rates. Management utilise a scenario based approach to estimate the likely contingent payments under each scenario and then apply a probability to each scenario.

The sensitivity of the elements of contingent consideration to changes in the probabilities of the scenarios and to the discount rates is disclosed in Note 21.

Key estimates relating to the Company Statement of Financial Position

Expected credit loss provision 

IFRS9 requires the Company to make assumptions when implementing the forward-looking expected credit loss (ECL) model. This model is required to assess intercompany loan receivables held by Afentra plc.

Arriving at the ECL allowance involved considering different scenarios for the recovery of the intercompany loan receivables, the possible credit losses that could arise, and the probabilities of these scenarios occurring. The following was considered: the exploration project risk, country risk, expected future oil prices, the value of the potential reserves, the ability to sell the project, and the ability to find a new farm-out partner. The Company's intercompany receivable balance is $18.0 million after an ECL allowance of $29.1 million. During the year the Company impaired its intercompany loan receivable from Afentra (UK) Limited by $20.0 million. This impairment is eliminated on consolidation and does not impact the Group results.

Refer to Note 14 for further information.

Investment in subsidiaries

If circumstances indicate that impairment may exist, investments in subsidiary undertakings of the Company are evaluated using market values, where available, or the discounted expected future cash flows of the investment. If these cash flows are lower than the Company's carrying value of the investment, an impairment charge is recorded in the Company. Where impairments have been booked against the underlying exploration assets, the investments in subsidiaries are written down to reflect their recoverable value. Evaluation of impairments on such investments involves significant management judgement and may differ from actual results.

As at 31 December 2024, Company investments in subsidiaries totalled $20.1 million. During the year the Company impaired its $2.0 million investment in Afentra (UK) Limited. This impairment is eliminated on consolidation and does not impact the Group results.

Refer to Note 12 for further information on investments in subsidiaries.

3.          Revenue

Revenue is earned from the sale of crude oil produced in Angola, Africa.  Revenue by major customer during 2024 was 67% Maurel & Prom and 33% Trafigura (2023: 100% and nil respectively).

4.          Cost of sales

All cost of sales relate to operations in Angola, Africa. Included in production costs above is an expected credit loss provision of $3.6 million (2023: nil).

5.          Profit from operations 

Included in the fees payable for the audit of the Group's annual accounts is $95,000 related to 2023. No non-audit services were received.

6.          Employee information

The average number of employees (including executive and non-executive directors) of the Group and Company was as follows:

Group and Company employee costs during the year amounted to:

Key management personnel include executive and non-executive Directors who have been paid $2.6 million (2023: $2.8 million). See Remuneration Committee Report of the Annual Report and Note 26 for additional detail. The highest paid Director in the current year received $893k (2023: $782k).

A portion of the Group's staff costs and associated overheads are expensed as pre-licence expenditure ($0.6 million) or capitalised ($46k). In 2024 this amounted to $0.6 million (2023: $4.8 million).

7.          Finance income and costs                                                                                      

All finance income and finance costs are measured at amortised cost, apart from the fair value adjustment on contingent consideration which is measured at fair value through profit and loss. No finance income or finance costs are measure at fair value through other comprehensive income.

8.          Taxation

The tax charge for the year is calculated by applying the applicable standard rate of tax as follows:

Current tax

An election under s18A CTA 2009 has been made by the Group to exempt profits and disallow losses of its foreign permanent establishment in Angola. This election is effective for the year commencing 1 January 2024 and all subsequent accounting periods.

A significant proportion of the Group's profit before taxation arose in Angola where the effective rate of taxation differs from that in the UK. In Angola, current income tax is determined by applying a tax rate of 50% to the Profit Oil lifted during the period. Accordingly, the Group's tax charge will continue to vary according to the tax rates applicable to operations in Angola where pre-tax profits arise.

Deferred tax

At the reporting date the Group had an unrecognised deferred tax asset of $35.2 million (2023: $34.0 million) relating primarily to unused tax losses and unutilised capital allowances in the United Kingdom with no expiry date. No deferred tax asset has been recognised due to the uncertainty of future profit streams against which these losses could be utilized.

Profits generated in Angola are subject to Angolan tax which is calculated on a profit oil basis. A temporary difference arises due to accelerated capital allowances being in excess of the unit of production depreciation applied by the Group and consequently a deferred tax liability of $1.7 million has been recognized during the year (2023:Nil).

9.          Earnings/(loss) per share

Earnings per share (EPS) and loss per share (LPS) is calculated by dividing the earnings attributable to ordinary shareholders by the weighted average number of shares outstanding during the period. Diluted EPS/(LPS) 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.  

10.        Exploration and evaluation assets

The Group's intangible assets as at 31 December 2024 comprise:

-       Block 23 PSA, Angola: Afentra Angola Ltd 40% and Sonangol (Operator) 60%.

-       Block KON 19, Angola: Afentra Angola Ltd (Operator) 45%, ACREP 45%, and Enagol 10%.

-       Odewayne PSA, Somaliland: Afentra (East Africa) Limited 34% (fully carried), Genel Energy Somaliland Limited (Operator) 50%, and Petrosoma 16%.

11.        Property, plant and equipment

The Group's oil and gas assets as at 31 December 2024 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%.

See Note 24 for further information on the acquisitions to oil and gas assets in the year.

The right-of-use asset (office lease) is depreciated on a straight-line basis over the lease contract term. During 2024 the lease on our old office expired and a new lease was entered into. The current lease term is for five years, ending in 2029. See Note 1 and Note 22 for further details .

12.       Investment in subsidiaries

See Note 2 for further detail on the impairment assessment methodology. The subsidiary undertakings of the Group as at 31 December 2024 are listed below :

⁽¹⁾ Holder of Afentra (Angola), Lda - (Sucursal em Angola) a local branch in Angola

⁽²⁾ Held directly by Afentra (Northwest Africa) Limited

⁽³⁾ Held directly by Afentra Holdings Limited

⁽⁴⁾ Registered address - 10 St Bride Street, London, EC4A 4AD

⁽⁵⁾ Registered address - IFC5, St Helier, Jersey, JE1 1^ST

⁽⁶⁾ Formerly Afentra Overseas Limited

13.       Inventories

Oil stock inventory is stated at the lower of cost and net realisable value.  There were no write-downs of inventory during the year (2023: nil).

14.       Trade and other receivables

¹ Comprised of our share of amounts receivable by the Operator (on behalf of the contractor group)  for transportation and processing of crude, tariffs, and other receivables.

Trade and other receivables consist of current receivables that the Group views as recoverable in the short term.

Credit loss allowances for amounts due from subsidiary undertakings amount to $29.1 million (2023: $9.1 million). Material adverse changes in the underlying value of the Odewayne E&E asset could result in future credit losses on our intercompany receivables in the future. Restructuring of the Company's intercompany positions could result in the reversal of historical intercompany credit losses. There is no impact to the Group Consolidated Statement of Profit or Loss and Other Comprehensive Income or the Consolidated Statement of Financial Position from credit losses on intercompany receivables, or the subsequent reversal thereof.

The Directors consider that the carrying amount of trade and other receivables is a reliable estimate of their fair value.

Transactions between subsidiaries are non-interest earning and are repayable on demand, with the exception of the intercompany balance between Afentra plc and Afentra (Angola) Limited, which is interest earning.

See Note 1 for details (Financial instruments - Trade receivables).

15.       Cash and cash equivalents

16.       Restricted funds

The restricted funds as at 31 December 2024 is a $7.9 million cash deposit held in the Debt Service Reserve Account (DSRA) as required by the Reserve Based Lending agreement. The amount held represents the next tranche of debt principal and associated interest payments due. As at 31 December 2023, there was $4.9 million held in a Citibank escrow account in respect of the Azule acquisition.

17.       Share capital

18.       Reserves

Reserves within equity are as follows:

Share capital

Amounts subscribed for share capital at nominal value. There are no restrictions on dividends or repayment of capital.

Share option reserve

Cumulative amounts charged in respect of employee share option arrangements. See Note 25 for further details. 

Currency translation reserve

The foreign currency translation reserve is comprised of movements that relate to the retranslation of the subsidiaries whose functional currencies are not designated in US dollars.

Retained earnings

Cumulative net gains and losses recognised in the Statement of Comprehensive Income less any amounts reflected directly in other reserves.

19.       Borrowings

The Group drew down on both the Reserve-based lending (RBL) and Working Capital facilities in order to finance the INA, Sonangol, and Azule acquisitions in 2023 and 2024. As at 31 December 2024, the Group has drawn down $42.0 million on the RBL and repaid all amounts drawn down under the Working Capital facility. The key terms of our debt facilities are shown below:

RBL facility

·      $51.8 million comprised of three separate drawdowns

·      5-year tenor to May 2028

·      8% margin over 3-month SOFR (Secured Overnight Financing Rate)

·      Semi- annual linear amortisations

·      DSRA commitment

·      Key financial covenants of Afentra (Angola) Limited's Net Debt to EBITDA < 3:1 and Group Liquidity Test >1.2x

Working Capital revolving committed credit facility

·      $30.0 million maximum based on prior month oil inventories on hand (100% undrawn as at 31 December 2024)

·      5-year tenor to May 2028

·      4.75% margin over 1-month SOFR

·      Repayable with proceeds from liftings 

A charge is placed on Afentra (Angola) Ltd shares to Mauritius Commercial Bank Limited as required by the terms of the debt facilities.

Net cash/(debt)

The table below details our net cash/(debt) as at 31 December 2024 and 2023:

Changes in Net cash/(debt) for the periods presented in this report were as follows:

¹ Other charges comprise:

- Borrowings: amortisation of prepaid finance fees

- Leases: accretion

- Cash: net funds received / spent

20.       Trade and other payables

¹ Comprised of our share of amounts owed to suppliers by the Operator of the Joint Venture (on behalf of the contractor group) for unpaid invoices and unbilled value of work done.

The Directors consider that the carrying amount of trade and other payables is a reliable estimate of their fair value. Transactions between subsidiaries are non-interest bearing and repayable on demand.

21.       Contingent consideration

The movement in contingent consideration during 2024 and 2023 is detailed in the table below:

Contingent consideration is presented on the Consolidated Statement of Financial Position as:

The current portion of contingent consideration relates to amounts paid during the first quarter of 2025 based on thresholds met previously. Refer to Note 30 - Subsequent events.

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 levels and a realised Brent price hurdle up to an annual cap of $2.0 million (now completed); and

·      Tranche 2: The contingent consideration for 3/05A relates to the successful future development of the Caco Gazela and Punja development areas, with production and oil price hurdles. The maximum payable for these development areas is $5.0 million.

·      During the year, the Group paid contingent consideration of $1.1 million to INA related to 2023, during Q1 2025, an additional and final payment of $1.2 million was made in respect of Tranche 1 related to 2024.

SNL acquisition (2023):

·      The contingent consideration for the SNL acquisition is payable annually over the next ten years from acquisition in each year where 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 ten years.

·      During the year, the Group paid contingent consideration of $3.5 million to Sonangol in respect of 2023, with an additional payment of $3.5 million made in Q1 2025 in respect of 2024. 

Azule acquisition (2024):

·      Tranche 1: The contingent consideration for the Azule acquisition includes up to $21 million over the next three years from 1 January 2023, subject to certain oil price and Block 3/05 production hurdles, with an annual cap of $7 million.

·      Tranche 2: Further contingent considerations of up to $15 million are linked to the successful future development of certain Block 3/05A discoveries and associated oil price and production hurdles.

·      During the year (as part of the completion) the Group paid contingent consideration of $1.2 million to Azule in respect of 2023, as well as an additional payment of $0.9 million in Q1 2025 in respect of 2024.

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, with an average oil price of $72/bbl in 2025, $68/bbl in 2026, and $67/bbl in 2027.

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 9.1% (2023: 9.1%). Management is therefore satisfied with the liabilities recorded at the balance sheet date in respect of these contingent future events.

Applying Management's judgements discussed above, has resulted in contingent consideration of $29.9 million. A 2% increase in the discount rate would result in a reduction in the contingent consideration liability of $1.7 million. A 2% decrease in the discount rate would result in an increase in contingent consideration of $1.9 million. The impact of removing the scenarios that have an expectation the realised Brent price hurdles will not be met (5% original weighting) and including a relative increase in the base case scenarios would increase the contingent consideration by $0.7 million. In the event of a sustained low oil price scenario, for any years where the average Brent oil price is below $65/bbl, we expect that the price related element of the non-current contingent consideration would be reversed.

22.       Leases

During the year, the Group entered into a new lease on a new head office in London following the expiration of the previous head office lease. The Group recognizes a right-of-use asset in a consistent manner to its property, plant and equipment (see Note 11).

The Company recognises lease liabilities in relation to the head office in accordance with IFRS16. These liabilities are measured at the present value of the total lease payments, discounted using the lessee's incremental borrowing rate. The incremental borrowing rate applied to the lease liabilities was 9.74%.

The depreciation charge in 2024 was $217k (2023: $190k) (see Note 11) with an interest expense in 2024 of $18k (2023: $18k) (see Note 7). Cash outflow of principal payments in 2024 was $142k (2023: $227k).

Lease liabilities are presented in the statement of financial position as follows:

Extension options are included in the lease liability when, based on Management's judgement, it is reasonably certain that an extension will be exercised. As at 31 December 2024, the contractual maturities of the Company's lease liabilities are as follows:

23.       Financial instruments

Capital risk and liquidity risk management

The Group and Company are not subject to externally imposed capital requirements. The capital structure of the Group and Company consists of cash and cash equivalents held for working capital purposes and equity attributable to the equity holders of the parent, comprising issued capital, reserves and retained earnings as disclosed in the Statement of Changes in Equity. The Group and Company use cash flow models and budgets, which are regularly updated, to monitor liquidity risk.

Details of the significant accounting policies and methods adopted, including the criteria for recognition, the basis of measurement, and the basis on which income and expenses are recognised, in respect of each material class of financial asset, financial liability and equity instrument are disclosed in Note 1 to the financial statements.

Due to the short-term nature of these assets and liabilities, such values approximate their fair values as at 31 December 2024 and 31 December 2023.

Of the above assets and liabilities due to the short-term nature, carrying amounts approximate their fair values at 31 December 2024 and 31 December 2023 except for non-current borrowings, for which the fair value is based upon a market rate of 9.1% and therefore having a fair value of $34.7 million (2023: $27.4 million) against the carrying amount of $30.1 million (2023: $25.0 million).

The Group carries the assets and liabilities below at fair value through profit and loss.

Derivative hedge assets and liabilities are financial assets and liabilities measured through profit or loss with a level 2 fair value hierarchy classification. In the normal course of business the Group enters into derivative financial instruments to manage its exposure to oil price volatility.

Contingent consideration is a financial liability measured through profit or loss with a level 3 fair value hierarchy classification. Contingent consideration was valued using a discounted cash flow and scenario analysis method. The main inputs in the valuation process were discount rates, forecast realised crude oil prices and future production. See Note 21 for details of the sensitivity analysis performed.

There were no transfers between fair value levels during the year.

Financial risk

We are exposed to several financial risks, including oil and gas price volatility, credit risk, liquidity risk, foreign currency risk, and interest rate risk. Our policy is to reduce our exposure to these risks, where possible, within boundaries deemed appropriate by our management team. This may include the use of derivative instruments. Oil price volatility may also impact our contingent consideration liability, where market price hurdles have been included in the terms.

Interest rate risk

Our exposure to interest rate risk relates mainly to our floating rate borrowings and balances of surplus funds placed with financial institutions. We monitor this risk and will implement our hedging policy if and when required.

Interest rate sensitivity analysis  

The sensitivity analysis below has been determined based on the exposure to interest rates at the reporting date and assumes the amount of the balances at the reporting date were outstanding for the whole year.   A 100 basis point change represents management's estimate of a possible change in interest rates at the reporting date. If interest rates had been 100 basis points higher or lower, and all other variables were held constant, our profits and equity would be impacted as follows:  

Foreign currency risk

The Company's functional currency is the US dollar, being the currency in which the majority of the Group's expenditure is transacted. Small elements of its management, services and treasury functions are held and transacted in Pounds Sterling, Euro or Angolan Kwanza. The Group does not enter into derivative transactions to manage its foreign currency. Foreign currency risk is not considered material to the Group and Company.

The table below details our financial assets and liabilities that are held in currencies other than US$ :

Financial assets

1 This includes an ECL allowance of $3.6 million relating to our share of an aged balance receivable by the joint venture.

Financial liabilities

Credit risk management

The Group has to manage its currency exposures and the credit risk associated with the credit quality of the financial institutions in which the Group maintains its cash resources. At the year end the Group held approximately 98.0% (2023: 89.8%) of its cash in US dollars. Most of the counterparties are creditworthy financial institutions and, as such, we do not expect any significant loss to result from non-performance by such counterparties. The Group continues to proactively monitor its treasury management to ensure an appropriate balance of the safety of funds and maximisation of yield.

Trade and other receivables are non-interest bearing. The Group does not hold any collateral as security and the Group does not hold any significant allowance in the impairment account for trade and other receivables as they relate to counterparties with no default history. Default is considered to be where payments have been outstanding for more than 60 days. Apart from derivative hedge assets there are no financial assets held at fair value.

The Group's maximum exposure to credit risk is $66.2 million, based on our cash and cash equivalents, restricted cash, and trade and other receivables. Our cash balances are held with creditworthy financial institutions and there has been no significant increase in the credit risk of our debtors during the period.

Liquidity and interest rate tables

Management reviews budgeted cash forecasts regularly to ensure there is enough cash on hand to repay financing obligations and operational expenses as they become due. Additionally, the Group has access to a rotating Working Capital Credit Facility of up to $30 million. The following table details the remaining contractual maturity of our financial assets and liabilities, based on the undiscounted cash flows of on the earliest date on which the Group can be required to pay.

The table includes both interest and principal including cashflows on actual contractual arrangements.

24.       Asset acquisitions 

During the year the Group completed the acquisition of further interests in Block 3/05 (12%) and Block 3/05A (16%) offshore Angola for a net $28.4 million payment with subsequent contingent payments estimated at $5.4 million. See Note 21 for details of the contingent consideration.

¹ Comprised of our share of the working capital balances of the Operator of the Joint Venture which include accounts payable, accruals, accounts receivable, and non-oil inventory.

The Group performed an assessment of the Azule acquisition to determine whether the acquisition should be accounted for as an asset acquisition or a business combination. Consistent with the acquisitions in 2023 from INA and SNL, the Group established that, under IFRS11, joint control does not exist, and therefore the Group have deemed the acquisition to qualify as an acquisition of a group of assets and liabilities, and not of a business. Furthermore, the Group gave regard to guidance included under IFRS11- Joint Arrangements, and will account for its share of the income, expenses, assets, and liabilities from the acquisition date.

The total consideration was allocated to assets and liabilities based on their relative fair values.

25.          Share-based payments

The table below details the movement in share option reserve:

During the year, Afentra plc operated four share incentive schemes:

·      Founder Share Plan (FSP)

·      Long-term Incentive Plan (LTIP)

·      Executive Director Long-term Incentive Plan (EDLTIP)

·      Non-Executive Director Option plan (NEDP)

Details of the schemes are summarised below:

Founder Share Plan

Under the FSP, the founders are eligible to receive 15% of the growth in returns of the Company over the five year period commencing from its admission to AIM on 16 March 2021. The awards are expressed as a percentage of the total maximum potential award, being 10% of the Company's issued share capital.

Should a hurdle of doubling the Total Shareholder Return (TSR) over the five-year period be met, the awards will be converted into nil cost options over ordinary shares of 10p each in the share capital of the Company.

For the purpose of determining the fair value of an award, the following assumptions have been applied and a valuation calculation run through the Monte Carlo Model:

The risk-free rate assumption has been set as the yield as at the grant date on zero coupon government bonds of a term commensurate with the remaining performance period.

The volatility assumptions are based on the daily share price volatility over a historical period prior to the respective dates of grant with length commensurate to the expected life.

The weighted average exercise price of outstanding options is nil.

The weighted average remaining contractual life as at 31 December 2024 is 14 months.

At 31 December 2024 no options were exercisable.

During 2024 the first measurement date was reached and 10,235,080 nil cost options were vested and exercised.  The share price at time of exercise was £0.39.

Long-term Incentive Plan

The awards issued under the LTIP are nil-cost options to acquire ordinary shares in the Company, subject to a performance condition. For the purpose of determining whether the condition has been met, the TSR of the Company is measured over a three year performance period, commencing at the grant date. The awards have been valued using the Monte Carlo model, which calculates a fair value based on a large number of randomly generated simulations of the Company's TSR.

The risk-free rate assumption has been set as the yield as at the grant date on zero coupon government bonds with remaining term commensurate with the remaining projection period.

The volatility assumptions are based on the daily share price volatility over a historical period prior to the respective dates of grant with length commensurate to the expected life.

The table below details the movement in share awards for the year:

The weighted average exercise price of outstanding options is £nil.

The weighted average remaining contractual life as at 31 December 2024 is 20 months.

Executive Director LTIP

The awards issued under the EDLTIP are nil-cost options to acquire ordinary shares in the Company, subject to a performance condition. For the purpose of determining whether the condition has been met, the TSR of the Company is measured each year over a three year performance period, commencing at the grant date. The awards have been valued using the Monte Carlo model, which calculates a fair value based on a large number of randomly generated simulations of the Company's TSR.

The risk-free rate assumption has been set as the yield as at the grant date on zero coupon government bonds of a term commensurate with the remaining performance period.

The volatility assumptions are based on the daily share price volatility over a historical period prior to the respective dates of grant with length commensurate to the expected life.

The weighted average exercise price of outstanding options is nil.

The weighted average remaining contractual life as at 31 December 2024 is 30 months.

Non-Executive Director Option plan (NEDP)

The awards issued under the NEDP are options to acquire ordinary shares in the Company at a set price.  These options are subject only to a continued employment condition.  The awards will vest three years after grant date and participants can exercise these awards up to the ten year anniversary of the grant date.

The awards have been valued using the Black-Scholes option pricing formula.

The risk-free rate assumption has been set as the yield as at the grant date on zero coupon government bonds of a term commensurate with the remaining performance period.

The volatility assumptions are based on the daily share price volatility over a historical period prior to the respective dates of grant with length commensurate to the expected life.

The weighted average exercise price of outstanding options is nil.

The weighted average remaining contractual life as at 31 December 2024 is 30 months.

Employees (including Senior Executives) of the Company receive remuneration in the form of share-based payment transactions which are equity settled. The cost of equity-settled transactions with employees is measured by reference to the fair value at the date on which they are granted. The fair value is determined by an external valuer using an appropriate pricing model. Although these awards are deemed to be equity settled, an employee may elect to receive their entitled settlement, in whole or in part, in cash.

The estimated cost of equity-settled transactions is recognised in the profit and loss account as an expense, together with a corresponding increase in equity. This expense and adjustment to equity is recognised over the period in which the performance and/or service conditions are measured (the 'vesting period'), ending on the date on which the relevant participants become fully entitled to the award (the 'vesting date').

The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Company's best estimate of the number of equity instruments that will ultimately vest. The Income Statement charge for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

The key areas of estimation regarding share-based payments are share price volatility and estimated lapse rates due to service conditions and non-performance conditions not being met.

No adjustments are made in respect of market conditions not being met. Similarly, the number of instruments and the grant-date fair value are not adjusted, even if the outcome of the market condition differs from the initial estimate.

Where the terms of an equity-settled award are modified, the minimum expense recognised is the expense as if the terms had not been modified. An additional expense is recognised for any modification, which increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employee as measured at the date of modification.

Where an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. However, if a new award is substituted for the cancelled award, and designated as a replacement award on the date that it is granted, the cancelled and new awards are treated as if they were a modification of the original award, as described in the previous paragraph.

In April 2024 a number of share option awards vested which were settled through both the issue of shares and the payment of cash to HMRC for the related taxes. In the interim accounts for the six-month period ended 30 June 2024, the cash tax payment was treated as a "cash settled" share-based payment, and an expense of $2.3 million was recognised in other administrative expenses. As part of the preparation of the year-end financial statements, it was identified that as Afentra had an obligation (rather than a choice) to settle these employment related taxes in cash, IFRS 2.33 requires that the transaction is classified in its entirety as an equity-settled share-based payment transaction. Accordingly, in the full year results this transaction has been recognised within equity, as $2.3 million directly to retained earnings. In the interim accounts for the period to 30 June 2025, the profit after tax for 30 June 2024 comparative period will be restated from the previously disclosed $22.2 million to $24.5 million to reflect this impact of this reclassification.

The dilutive effect of outstanding options is reflected as additional share dilution in the computation of earnings per share.

26.           Related party transactions

Details of Directors' remuneration, which comprise key management personnel, are provided below:

Further information on Directors' remuneration is detailed in the Remuneration Committee Report of the Annual Report 2024. The Executive Directors (three) exercised share options during the year.

The Company's subsidiaries are listed in Note 12. The following table provides the balances which are outstanding with subsidiary undertakings at the balance sheet date:  

Amounts due from subsidiary undertakings are interest free apart from the amount receivable from Afentra (Angola) Limited which earns interest at a rate equal to the relevant US Treasury Bill rate plus a margin of 0.5%. The average interest rate on the loan to Afentra (Angola) Limited was 5.6% in 2024 (2023: 2.8%). During the year the Company recognised interest receivable from Afentra (Angola) Limited of $0.79 million (2023: $0.64 million).

The Group and Company has no other disclosed related party transactions.

27.          Derivative assets and liabilities

The company manages its exposure to oil price risk through commodity price hedging. In 2024, Afentra hedged 70% of its sales volumes through a combination of put options and collar structures. The hedge portfolio consisted of put options ranging included $70 to $80 per barrel covering 70% of sales volumes and call option of $90 per barrel covering 29% of sales volumes.

28.          Commitments

The Parent Company has provided a guarantee over the debt of Afentra (Angola) Limited and letters of support to Afentra (UK) Limited, Afentra (Onshore Developments) Limited, Afentra (Offshore Developments) Limited, Afentra (East Africa) Limited, and Afentra Holdings Limited.

29.          Restatement of decommissioning provision and associated pre-funding asset 

We have restated the Group's balance sheet to reflect a change in our accounting for the pre-funded liability to settle the future decommissioning obligation associated with Block 3/05, and the treatment of joint venture receivable and payable balances.

As of 31 December 2023, the pre-funding asset was presented as a non-current asset to be recovered from the Concessionaire and the decommissioning liability as a non-current liability on the balance sheet. Following investigation, independent and authoritative information was obtained during the second half of 2024 that provided certainty that the contractual position was that the contractor group would be discharged of its obligation to decommission the field should the pre-funding not be made available when due. The information received during 2024 confirmed the legal position at 31 December 2023, namely that the Group will not be liable for the decommissioning costs if the funds are not made available when due, and accordingly we have restated the 2023 balance sheet, in line with the requirements of IFRIC 5 and IAS 37, and the measurement of the decommissioning liability, including our evaluation of any future outflows, has been reduced by the amount already pre-funded by the contractor group. The decommissioning liability and the associated pre-funding asset were initially recognised during 2023 and that is the earliest period impacted.

As of 31 December 2023, the Group's $7 million share of the Block 3/05 joint venture receivable balance was offset against the payables position as it was anticipated that it would be settled net of the larger joint venture payable balance. Following investigation, information was obtained during the second half of 2024 that confirmed that the contracting group did not have the legal right to offset these separate receivable and payable balances. Consequently, we have restated the 2023 balance sheet. There is a consequential impact on the 2023 consolidated statement of cash flows, and the movement in the respective working capital balances has also been restated. There is no impact on the 2023 profit or equity position.

The table below highlights the impact of the restatement on the 31 December 2023 and 30 June 2024 consolidated statements of financial position (there is no impact to the Statement of Comprehensive Income):

Contingencies

The latest approved estimate of the total cost for the contractor group to abandon the field at the end of the contract period in 2040 is $574 million (Afentra's share is $172 million), of which $554 million (Afentra's share is $166 million) has been pre-funded by the contractor group. The amounts pre-funded were deposited between 2004 and 2012 and substantially did not accrue interest on consequence of the manner in which they were held. The funds were deposited with the Concessionaire and will not be released to the contractor group until required for the purposes of abandoning the field.

On the basis that we consider that the contractor group will be discharged of its obligation to decommission, we do not forecast any further expenditure occurring over and above that which has been pre-funded ($554 million gross). We have therefore accounted for any future possible expenditure as a contingent liability as, while not considered probable, there remains a remote possibility of any future increase to the estimated cost to abandon the field or any unfunded balance being called by the Concessionaire. Commercial sensitivities associated with any future increase in the cost to decommission the field and interest accrued precluded a range of potential estimates being disclosed.

30.          Subsequent events

Subsequent to the Balance Sheet date of 31 December 2024, the following business deliverables occurred:

·      During Q1 2025, the Group made contingent consideration payments of $3.5 million, $1.2 million, and $0.9 million to Sonangol, INA, and Azule respectively.

·      On 28 March 2025, the Group made a scheduled redetermination payment on its RBL facility of $7.9 million comprised of $5.3 million debt principal and $2.6 million accrued interest.

·      On 19 February 2025, Afentra provided an update on its latest Competent Person's Report (CPR) for Block 3/05. As of 31 December 2024, total net 2P working interest reserves stand at 34.2 million barrels of oil (mmbo), (gross 114 mmbo). Since the previous CPR in June 2023, gross production of approximately 11 mmbo was offset by a gross increase in reserves of 15.4 mmbo resulting in a reserve replacement ratio of 140% over the 18-month period. Contingent resources on Block 3/05 have also increased since the last CPR with net working interest 2C resources of 13.8 mmbo (gross 46 mmbo)

·      On 24 February 2025, Afentra announced the formal approval by Presidential Decree of the onshore licence KON15, the formal signing of the contract occurred on 07 April 2025. Under the terms of the KON15 award, Afentra has secured a 45% non-operating interest in the block, alongside Sonangol who will be block operator.