FY2025 Annual Results and Corporate Update

Afentra PLC

13 May 2026

 

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION FOR THE PURPOSES OF ARTICLE 7 OF THE MARKET ABUSE REGULATION (EU) 596/2014 AS AMENDED AND TRANSPOSED INTO UK LAW IN ACCORDANCE WITH THE EUROPEAN UNION (WITHDRAWAL) ACT 2018, AS AMENDED BY VIRTUE OF THE MARKET ABUSE (AMENDMENT) (EU EXIT) REGULATIONS 2019 ("UK MAR"). UPON THE PUBLICATION OF THIS ANNOUNCEMENT, SUCH INSIDE INFORMATION IS NOW CONSIDERED TO BE IN THE PUBLIC DOMAIN.

FOR IMMEDIATE RELEASE

13 May 2026

AFENTRA PLC

AUDITED FY2025 ANNUAL RESULTS, REFINANCING & CONCLUSION OF STRATEGIC REVIEW

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 audited annual results for the year ended 31 December 2025 as well as providing detail on its debt refinancing and an update on the Strategic Review process.

Strategic Announcements

-       Strategic Review concluded: The Afentra Board has concluded a comprehensive review of the strategic options to realise maximum value for shareholders from the significant Angolan portfolio assembled since the company's inception in 2021. The Board has determined that given today's announcement of a successful re-financing at a reduced cost of capital, the significant change in the macro environment and the early start to infill drilling focussed on delivering material production and reserves growth, where the company's costs will be carried, Afentra is well placed to pursue the next phase of growth as an independent E&P company, ensuring that the value of Afentra's significant potential will be to the benefit of the Company's shareholders. As a result, the Company is no longer in an "offer period" as defined by the Takeover Code.

-       Debt Refinancing secured: $125 million Gunvor Pre-Payment Facility secured, will replace the existing Reserve Base Lending ("RBL") and Working Capital Facility; 4-year tenor to 2030, lowering cost of debt and providing long-term funding to support the Company's investment programme.

-       Pacassa SW drilling underway: the high impact Pacassa SW well operations were initiated in April, the well, which is carried, has the potential to add material production and reserves with results expected in June 2026.

Post-Period End Highlights

-       Block 3/05 Drilling: fully carried two well programme underway with spud of Pacassa SW

-       Crude Oil Sales & Revenue¹:

o  0.480 mmbbls sold in April at $119.3/bbl average price, generating $57.2 million revenue, of which $30.0 million was received in advance. Hedge related liabilities of $8.0 million to be settled.

o  0.517 mmbbls sold in January at $65.4/bbl average price, generating $33.8 million revenue.

-       Etu Energias transaction revised: Sonangol elected to participate; new SPA signed

-       Net average production: four months to 30 April 2026: 5,968 bopd

-     Kwanza Onshore: eFTG survey completed; KON4 licence awaiting Council of Ministers approval

2025 SUMMARY

2025 Key Highlights

-       2025 Net Average Production (working interest): 6,324 bopd

-       Crude Oil Sales: 1.63 mmbbls sold at $70.2/bbl average price generating $114.4 million revenue

-       Fourfold contingent resources increase: 2C WI contingent resources increased to 87.3 mmboe

-       Block 3/24 award: Afentra's first operatorship, 40% working interest

-       Kwanza Onshore Expansion: KON4 licence contract initialled

-       Year-end position: cash $10.2 million, net debt $21.8 million

Financial Highlights

-       Revenue of $114.4 million

-       Year-end cash of $10.2 million; net debt of $21.8 million

-       Borrowings, RBL drawn $31.5 million; Debt / Adjusted EBITDAX 0.6x

-       Adjusted EBITDAX of $51.7 million and loss after tax of $3.2 million

-       Four liftings totalling 1.63 mmbbls, average price of $70.2/bbl

-       Share purchase programme commenced in 2025 to cover future share award requirements, thereby avoiding dilution; 4,943,128 shares acquired to date at average price of 47.7 pence per share

Operational Highlights

-       Block 3/05 and 3/05A gross average production 21,268 bopd (2024: 21,111 bopd)

-       Reserves & Resources

o  2P WI reserves of 31.9 mmbo, 3-year average reserves replacement of 94% to end 2025

o  2C WI contingent resources of 87.3 mmboe, fourfold increase across Blocks 3/05, 3/05A and 3/24

-       Capex ~$220 million gross (Net: $66 million) covering asset integrity, revamping and drilling preparation

o  28 LWI's delivered during the period, sustaining production performance

o  Water injection averaged 37,798 bwpd; rates of ~50,000 bwpd consistently achieved in Q4 2025

o  FSO recertification work programme completed; formal recertification received in early 2026

-       Portfolio Expansion

o  SPA signed with Etu Energias for additional interest in Block 3/05 and 3/05A; transaction subsequently revised post period to acquire 3.33% - Block 3/05; 3.66% - Block 3/05A

o  Block 3/24 offshore licence awarded with Afentra as operator at 40% working interest

o  KON15 licence formally awarded, 45% non-operated working interest

o  KON4 Risk Service Contract initialled, confirming Afentra as operator at 35% working interest

-       Somaliland Odewayne Block interest transferred to Petrosoma Limited; $1.97 million received in settlement of carry obligations

Refinancing

Afentra has secured a refinancing of its debt facilities through the entry into a $125 million Pre-Payment Facility ("PPF") with Gunvor Group, this will replace its existing RBL Facility and Working Capital Facility with Trafigura and MCB.

The new facility comprises $125 million of committed capacity ($100 million initial advance plus $25 million subsequent advance available in 2027 subject to certain conditions), with an uncommitted accordion to scale facility size based on future production growth. The facility carries an interest rate of Term SOFR plus 6% margin with a 4-year tenor maturing in 2030 and a 12-month principal repayment grace period. The facility is secured against Block 3/05 and Block 3/05A liftings, a total committed volume of 8 mmbbls and a targeted minimum annual commitment of 1.8 mmbbls. Proceeds will be used to refinance the existing Facilities, to fund the Company's near-term work programme and to cover general corporate purposes.

The refinancing significantly lowers the cost of debt and provides funding to support the Company's near-term investment programme. The Company will continue to consider expansion of this facility utilising the uncommitted accordion or other sources of finance to ensure we remain fully funded to maximise the value of our current portfolio and pursue opportunities for further inorganic growth.

Strategic Review

The Board appointed Jefferies to conduct a process which could have resulted in a sale of the Company, under the UK Takeover Panel's Private Sale Process. Jefferies approached a number of potential counterparties, with multiple companies engaging in meaningful due diligence, including further inbound expressions of interest. The oil price volatility, coupled with the significant appreciation in the Afentra share price between initial outreach and the proposal deadline caused a number of parties to withdraw from the process. Ultimately a number of actionable proposals were received and considered by the Board. The Board's assessment of these proposals was that they did not recognise the significant upside value potential within Afentra's current business and therefore concluded that given the change in macro environment and the refinancing announced today that greater value potential is offered by Afentra pursuing the next phase of growth as an independent E&P listed company.

All discussions with potential acquirors have been terminated. As a result, the Company is no longer in an "offer period" as defined by the Takeover Code, and the disclosure requirements pursuant to Rule 8 of the Takeover Code are no longer applicable.

Paul McDade, Chief Executive Officer, commented:

"The year under review saw Afentra further consolidate its position as a fast-growth independent E&P company in Angola, which included a fourfold increase of 2C WI resources to 87.3m mmboe and the continued expansion of our portfolio in Angola, including the award of our first operatorship with a 40% interest in Block 3/24.  Beyond the solid performance of the Company, a strategic review designed to assess all options to accelerate value growth from our accretive Angolan asset portfolio was conducted.  Given the significant changes in the macro environment, the new debt facility, which will significantly lower our cost of capital, and the carry of the two highly prospective wells in Blocks 3/05 focused on materially increasing both reserves and production, the Board has decided Afentra should remain an independent company, to ensure all of our stakeholders benefit from the delivery of the significant upside in our Angolan asset portfolio."  

Investor Webinar Presentation

Afentra plc will host a live online investor presentation via the Investor Meet Company platform on Tuesday 19 May 13:00 BST to update investors and answer questions. The presentation is open to all existing and potential shareholders. Questions can be submitted prior to the event via the Investor Meet Company dashboard until 18 May 2026, 17:00 BST, or at any time during the live presentation.  Investors can sign up to Investor Meet Company for free and add to meet AFENTRA PLC via https://www.investormeetcompany.com/afentra-plc/register-investor

Supporting presentation:

A supporting presentation has been uploaded to Afentra's website:

https://wp-afentra-2025.s3.eu-west-2.amazonaws.com/media/2026/05/Afentra-Investor-Presentation-May-2026.pdf

For further information contact:

Afentra plc [phone]

Paul McDade, CEO

Anastasia Deulina, CFO

Christine Wootliff, Investor Relations

Burson Buchanan (Financial PR) [phone]

Bobby Morse

Barry Archer

George Pope

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

Callum Stewart

Simon Mensley

Ashton Clanfield

Tennyson Securities (Joint Broker) [phone]

Peter Krens

-------------------------

1.     Production figures are reported on a net (working interest) basis; net entitlement volumes are reflected in revenue and cash flow reporting.

2.     Revenue is net of the state's fiscal take (cost oil and profit oil allocation), but prior to deduction of petroleum income tax of ~6.5% (PIT).

About Afentra

Afentra plc (AIM: AET) is an upstream oil and gas company focused on opportunities in Africa. The Company's purpose is to support a responsible energy transition in Africa by establishing itself as a credible partner for divesting IOCs and host governments. Offshore Angola, in the Lower Congo Basin, Afentra holds a 30% non-operated interest in the producing Block 3/05, a 21.33% non-operated interest in Block 3/05A, and a 40% operated interest in Block 3/24 - both Blocks 3/05A and 3/24 are located adjacent to Block 3/05. Onshore Angola, in the western part of the onshore Kwanza Basin, Afentra holds 45% non-operated interests in the prospective Blocks KON15 and KON19. Afentra also holds a 40% non-operated interest in the offshore exploration Block 23 in the Kwanza Basin.

More information is available at www.afentraplc.com or by visiting the Afentra's Curation Showcase.

Inside Information

This announcement contains inside information for the purposes of article 7 of Regulation 2014/596/EU (which forms part of domestic UK law pursuant to the European Union (Withdrawal) Act 2018) and as subsequently amended by the Financial Services Act 2021 ('UK MAR'). Upon publication of this announcement, this inside information (as defined in UK MAR) is now considered to be in the public domain. For the purposes of UK MAR, the person responsible for arranging for the release of this announcement on behalf of Afentra is Paul McDade, Chief Executive Officer.

Standard

Estimates of reserves and resources have been prepared in accordance with the June 2018 Petroleum Resources Management System ("PRMS") as the standard for classification and reporting.

Technical Information

The technical information contained in this announcement has been reviewed and approved by Robin Rindfuss, Head of Sub-Surface at Afentra plc. Robin Rindfuss has over 30 years of experience in oil and gas exploration, production and development. He is a member of the Society of Petroleum Engineers (SPE) and holds a Bachelor of Science (BSc) and a Bachelor of Science Honours (BSc Hons) in Physics and Mathematics from the University of Cape Town.

CHIEF EXECUTIVE OFFICER'S STATEMENT

A disciplined approach to long-term value creation 

In 2025, Afentra delivered significant strategic progress by expanding and diversifying our Angolan portfolio, strengthening the organic growth story in a high-value, low-cost manner. This achievement is a direct result of our growing reputation as a credible and trusted partner to government and local companies. We have cemented our early-mover advantage in Angola's emerging independent sector, creating a strong platform for future value creation.

At the end of 2025, in an effort to ensure we realised maximum value for our shareholders and other stakeholders from the significant Angolan portfolio assembled since the company's inception in 2021 the Board initiated a comprehensive Strategic Review. This review was supported by external advisers and after a thorough consideration of the various options available, the Board has determined that given the successful refinancing at a reduced cost of capital, the significant change in the macro environment and the early commencement of a fully carried two-well infill drilling programme focused on delivering material production and reserves growth, we will pursue the next phase of growth as an independent E&P company. The Board has strong conviction in the prospects to create further significant value for our shareholders.

Targeted portfolio expansion 

The targeted expansion of the portfolio and the award of operated positions in Angola have significantly enhanced Afentra's equity proposition by providing a diverse runway of production, development and low-cost exploration opportunities that can be targeted over the coming years. The opportunities within the portfolio provide significant value catalysts to unlock the next phase of growth, underpinned by our core Block 3/05 producing assets where we are positioned to deliver a step-change in production with the commencement of drilling activities in 2026. 

The disciplined approach we have taken to portfolio strengthening reflects Afentra's strategic priority of value driven growth that delivers long-term returns. Angola continues to provide the supportive operating and jurisdictional backdrop to build out the business and Afentra has established a strong reputation and network that ensures access to the kind of value accretive opportunities that have been capitalised on during this period.  

Afentra's evolution into an Operator, through the award of operatorship on offshore Block 3/24, symbolises the next phase of our stated growth strategy and maturity as a business. The Company will continue to be selective about when to operate, only operating where we can add value through agility and technical excellence. For our non-operated interests, we continue to proactively support the Operator, bringing a deep level of experience and technical insight for the benefit of the partnerships in which we are present. 

The expansion of Afentra's footprint in Angola has focused on two key areas. The first is the area around Block 3/05, that includes Blocks 3/05A and has now been significantly expanded with the addition of Block 3/24 where we see low-risk opportunity to materially increase near-term production and unlock significant reserves and resources - leveraging the existing infrastructure and our deep understanding of the assets and the geology. The second is our growing focus on the onshore Kwanza basin where we believe there is material upside to be unlocked given the historic production and vastly underexplored nature of this area. Based on the significant potential of the portfolio comprised across these two focus areas, we believe there is scope to double existing net production and achieve significant reserves growth in the coming years from the Block 3/05 area, complemented by the high potential and low-cost upside opportunity of the largely untapped onshore Kwanza basin. 

Well placed in an opportunity rich market  

Alongside our near-medium term organic growth plans we think Afentra is uniquely positioned to continue to add further core areas in Angola on account of our established status as a recognised operator and credible technical partner. Angola continues to implement reform in its Oil and Gas industry that encourages investment and there is a recognition in-country of the important role independents can play in meeting the country's production targets. As the regulator, ANPG's fiscal flexibility, combined with commercial awareness, is delivering activity to the benefit of all stakeholders and supporting the government's ambition to grow production - with output stabilising above the 1 million barrels of production per day threshold during the period following the country's exit from OPEC.  

While our present focus is on Angola, the long-term strategy remains to build a multi-jurisdictional business across target markets in West Africa. In this regard, we continue to screen opportunities that meet with our criteria. Our success in Angola reflects the sheer depth of opportunities available for Afentra. Our disciplined smart deal-making approach to portfolio development means we are able to capitalise on compelling opportunities in Angola that can add scale and sustainable value creation while maintaining balance sheet strength and avoiding shareholder dilution. For Afentra to have assembled its existing portfolio through creative deal structures, without raising any equity, emphasises the value driven approach that is deep-rooted in our corporate identity.  

 Supportive macro tailwinds 

Our value driven approach guides our decision-making processes and we feel that this strategy is more important than ever to create sustainable value for the long-term despite near-term market volatility. Despite the volatility of oil pricing and economic uncertainty, the general market dynamic is unfolding in the way in which we envisaged when Afentra launched in 2021. There is clear pragmatism on long-term oil demand and even stronger rhetoric and support on the need for Africa to develop its large resource potential to support its development and energy transition responsibly.  The global energy transition discourse has increasingly aligned with the long-held view across Africa and other developing nations that oil and gas will continue to play a critical role for decades in meeting growing energy demand. Ensuring the responsible supply of these resources is therefore essential to support economic growth and power emerging economies. These factors support increasing confidence in the longer-term viability of sector investment, and the important role of investors and lenders to fund the necessary investment required to meet the global demand outlook for oil and gas.  

The market volatility that has been a feature in the past couple of years requires a proactive approach and disciplined focus on mitigating business and finance risk. Subsequent to the year-end, this volatility has been amplified by escalating geopolitical tensions in the Middle East, reinforcing the importance of our disciplined approach.  Our active approach to marketing our crude sales backed up by the hedging in place for 2025 ensured our average realised sales price was above crude pricing through the period, averaging $70.2/bbl.  Our hedging policy for 2026 is designed to protect cash flows while retaining upside exposure. The programme remains under active review to secure value, and we will continue to adapt our position in response to market conditions.  

Organic growth momentum  

The year ahead is a pivotal year as we leverage the strong portfolio position we have built and move with momentum to the next phase of Afentra's growth story. On Block 3/05 the partnership post-period has begun drilling and is preparing to execute workover activity to achieve a step-change in production, deliver reserves and resources replacement and ensure sustainable revenue growth for future years.  

In tandem, we are undertaking technical studies on the recently assigned, operated Block 3/24 in preparation for development activity in 2027/28. As the operator, we can bring our focus and experience to fast-track low-cost development of existing discoveries and resources through an infrastructure-led approach utilising the extensive and upgraded Block 3/05 assets, as we seek to unlock the vast potential and value of this new addition to the portfolio. 

We have completed the enhanced Full Tensor Gravity Gradiometry  (eFTG) activity on the onshore Kwanza basin blocks post-period during early 2026 and following interpretation of this data we will plan follow-up 2D seismic. We will also follow with keen interest as peers undertake drilling activities in the adjacent licences. The dual approach of low-cost field reactivation combined with exciting low-cost exploration could yield very material upside for Afentra.  

On track to double production 

2025 was a year of material strategic progress in which we delivered significant portfolio growth through smart deal-making. The Strategic Review considerations have reinforced our view that we have a significant opportunity to continue to build Afentra into a significant value focused independent. We will remain opportunistic and agile in our approach to further portfolio growth and will continue to look for compelling acquisitions in Angola and in other countries in the region where we can build a further core area. 

The current year will be a period of enhanced activity as our organic growth story gains traction with activity across all elements of the portfolio. The cornerstone asset of Block 3/05 is responding well to the investment programme and Afentra remains on track with regards to the production projections previously disclosed to the market. The level of increase to production through 2026 remains dependent on the outcome of the ongoing drilling programme though we remain confident of achieving production of around 30,000 bopd gross (10,000 bopd net) in 2027 as a result of the strong foundations already laid and the activity outlined within this report. This is the first step to our target of doubling our net production from the greater 3/05 area in the coming years. 

To conclude, we are delighted with the progress achieved in 2025 that will enable Afentra to unlock the next phase of growth. We remain confident that the partnership will significantly increase production from Block 3/05 with the arrival of the rig and the start of drilling, and we will also progress the development of the adjacent Blocks 3/05A and 3/24 ensuring long-term delivery of reserves and resources replacement.  As we progress all of this activity we remain committed to improving the emissions profile associated with these assets as we actively explore initiatives to transform emissions into monetised gas. 

Supporting our operational focus will be our underlying discipline on costs and value creation through smart deal-making. Certainly, we feel the evolving market dynamics are supporting Afentra's long-term strategy and we have built a portfolio and reputation in an exciting jurisdiction that leaves us well placed to deliver sustainable value for our shareholders.  

OPERATIONS REVIEW

Asset summary

In 2025, Afentra delivered strengthened operational performance across its core producing assets while significantly expanding its Angolan portfolio, including the award of its first operatorship in Block 3/24 with a 40% interest. This positions the Group for short-cycle, infrastructure-led development and long-term growth.

Continued delivery of operational progress positions the company for the next phase of growth

2025 was a year of continued operational progress for Afentra, marked by stable production across our core assets in Blocks 3/05 and 3/05A and steady advancement of the redevelopment programme. Continued production optimisation and water injection improvement, combined with asset-integrity upgrades have prepared the assets for the future step-change in production through hydraulic workovers, infill drilling and short-cycle developments.

At the same time, Afentra has expanded the scale and diversity of its asset base, positioning the company for substantial value creation and long-term growth. Importantly, the award of our first operatorship in Block 3/24 adds short-cycle, high-value development and near field exploration potential adjacent to the existing infrastructure in Block 3/05.

Afentra's focused approach prioritises investment in producing and development assets to deliver sustained production growth and generates cash flow to support further expansion and underpins a resilient, sustainable business model.

Stable and sustained production through redevelopment and optimisation activities

For 2025, gross production from Blocks 3/05 and 3/05A averaged 21,268 barrels of oil per day (bopd), with peak production exceeding 25,000 bopd, highlighting the blocks potential for future growth. During the year, 28 light well interventions were completed, optimising production levels from existing wells. Upgrades to the water injection facilities continued, with injection rates averaging ~37,800 barrels of water per day (bwpd) (Q4 2025 at ~50,000 bwpd). Maximum spot injection rates were in excess of 80,000 bwpd in 2025. Asset uptime remained stable throughout the period with no major periods of downtime. Opex continues to track around $23/bbl. Additional investment associated with the preparation for the 2026 drilling campaign and accelerated revamping programme increased the 2025 capital programme from $180 million gross to around $220 million gross (Net: $66 million).

Unlocking the next phase of growth

Afentra and its JV partners are positioned to deliver significant, long-term organic growth from the world-class shallow-water assets in Blocks 3/05, 3/05A and 3/24. Our phased, capital-disciplined approach targets increased recovery and production while reducing emissions. This strategy is already delivering tangible results, highlighted by a more than fourfold increase in net 2C contingent resources to 87.3 million barrels of oil equivalent (mmboe). This material uplift underscores the significant upside potential across the portfolio, with the 2026-2027 infill drilling and workover programme anticipated to deliver further significant reserves replacement and production growth. 

The foundation for this growth has been laid since 2023, with the JV focusing on stabilising production and enhancing performance through targeted light well interventions (LWIs), increased water injection capacity, and infrastructure upgrades. This multi-year redevelopment plan has delivered material operational improvements, creating a strong foundation that now enables us to progress into the next phase of ramping up production through infill drilling and the development of satellite discoveries.

Onshore Angola offers significant untapped growth opportunities

Onshore, Afentra expanded its acreage footprint in the Kwanza Basin during 2025 with the award of a non-operated 45% interest in KON15 and the initialling of an RSC on KON4 with final award pending and expected in Q2 2026. Alongside KON19, awarded in 2024, these licences position the company to unlock low-cost early production and exploration opportunities within an under-explored basin. Together, the three blocks offer a complementary portfolio with exposure to a diverse range of play types across both post-salt and pre-salt petroleum systems, as well as multiple opportunities to appraise and redevelop discovered but abandoned oil fields such as Quenguela Norte in KON4 or left behind discoveries like Bamvo in KON15.

The onshore Kwanza Basin presents substantial upside potential as, unlike the Lower Congo and Gabon basins to the north, it has remained under-explored for the past 40 years due to civil war and subsequent access challenges, including extensive minefields. With 11 discovered oilfields, entry into the basin provides a compelling opportunity for low-cost exploration and near-term development, underpinned by the application of modern concepts and technologies to an area largely untouched for decades.

Enhancing asset stewardship

Enhancing asset stewardship is central to Afentra's approach to sustainability and operational integrity, particularly as the Group increases its responsibilities across both operated and non-operated assets. Ensuring the health, safety and security of employees, contractors and local communities remains fundamental to our operations. During the year, Afentra's management visited the facilities on two occasions to review progress on the revamping programme.

In 2025, across Blocks 3/05 and 3/05A production assets, there were zero Lost-Time Incidents (LTI), achieving a period of 2195 LTI-free days. This performance was achieved alongside ongoing maintenance activities and facilities upgrades, reflecting the continued focus on proactive risk management and safe operations. 

Working alongside JV partners, Afentra continues to target emissions reductions through ongoing facilities upgrade programmes aimed at improving asset integrity and operational efficiency. As part of these efforts, five gas flare meters had been installed by year end, with commissioning throughout 2026. This new measured data will support improved management of flaring volumes and help to build targeted emissions reduction plans. 

Partnering for success

Since entering Angola, a core element of Afentra's strategy has been to foster close working relationships with both local and international partners, ensuring alignment on asset management, strategy and the sustainability agenda. Angola is a core market for Afentra, offering significant value-creation potential through abundant resources and a stable and attractive investment environment fostered by ANPG and the Angolan Government. Our commitment is reflected in our expanding in-country presence, including the opening of our Luanda office and the secondment of key personnel within Sonangol.

Afentra has established itself as a trusted and credible partner for government, NOCs and independents. We collaborate closely with Sonangol and M&P on Blocks 3/05 and 3/05A, and with ACREP, Sonangol and Enagol, across our onshore acreage. This partnership-led approach helps reduce costs, unlock value, lower emissions and contribute directly to Angola's energy-transition objectives. The proactive and collaborative stance of the regulator, ANPG, further supports a conducive environment for mutually beneficial outcomes.

We are also proud of our partnership with The HALO Trust, the international landmine-clearance organisation active in Angola for over 30 years and responsible for clearing more than 120,000 landmines. This partnership supports the government's ambition of achieving mine-impact-free status and benefits local communities by making land safe for sustainable development.

Building momentum and future capacity

Afentra enters 2026 with a strengthened platform for growth. Over the past year, the company has expanded and diversified its Angolan portfolio by adding its first offshore operatorship in Block 3/24 and building a complementary onshore position with the non-operated KON15 and KON19 exploration acreage in the Kwanza Basin, and the initialling of an RSC on KON4 with final award pending and expected in Q2 2026. This broader footprint, combined with sustained operational progress, positions the Group for its next phase of short-cycle, infrastructure-led development.

Operational performance across our core offshore assets has continued to improve, with production stabilised, water-injection capacity expanded and asset-integrity upgrades progressing to plan. These advances set the foundation for increased recovery, infill drilling and the development of satellite discoveries, delivering near-term production growth and long-term value.

Onshore, Afentra is now well placed to unlock low-cost early production and high-impact exploration potential within one of Angola's most underexplored basins. Strong collaboration with our partners and the Angolan authorities supports responsible development and enhances the company's long-term growth prospects.

With a focused investment approach, an expanded asset base and clear operational momentum, Afentra is building the capacity to deliver sustained production growth, strong cash generation and long-term shareholder value.

Angola Offshore Lower Congo Basin Blocks 3/05, 3/05A and Block 3/24 

Offshore Angola, in the Congo basin, Afentra holds a material position across a world-class multi-billion-barrel field complex covering 810km². This includes a 30% non-operated interest in producing Block 3/05, a 21.33% non-operated interest in the adjacent development Block 3/05A, and a 40% operated interest in the adjacent exploration Block 3/24.  

World-class assets with significant potential for production and reserves growth 

The Blocks 3/05, 3/05A and 3/24 field area, situated 37km offshore Angola in shallow 30-100m water depths, represents a vast, under-developed asset with substantial potential, with eight producing fields and eight undeveloped discoveries, all within the same prolific fractured Albian aged Pinda carbonate reservoir.  

This is underpinned by established production and extensive infrastructure in Block 3/05, which provides opportunities for production growth and reserve replacement. Furthermore, the adjacent Block 3/05A and Block 3/24 acreage offers significant scope for infrastructure-led development of existing discoveries and future exploration. 

2025 production from Blocks 3/05 and 3/05A 

For 2025, gross production from Block 3/05 and 3/05A averaged 21,268 bopd (2024: 21,111 bopd)  with a clear pathway to potentially more than double production.

Block 3/05 

Spanning an area of around 40km by 15km, Block 3/05 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 the export of oil. The licence consists of eight mid-life producing fields: - Palanca, Impala, Impala SE, Bufalo, Pacassa, Pambi, Cobo, and Oombo, with gross 2P reserves of 106.3 million barrels of oil (mmbo).  

The fields, discovered by Elf Petroleum (now TotalEnergies) in the early 1980s commenced production in 1985 from fixed platforms, which continue to operate today. Peak production was reached in 1998 at 198,000 bopd with field-wide waterflooding successfully used to enhance recovery during early field production. Following the initial period of sustained waterflooding, injection was curtailed in 2015 before being restarted but at a reduced rate in late 2020. The success of this earlier period of sustained waterflooding lowers uncertainty and supports the forward production forecasts, with the current redevelopment plan again targeting sustained field-wide water injection. 

Block 3/05 holds independently audited estimated gross 2C contingent recoverable resources estimated at over 60 mmboe.  The block also contains the undeveloped Bufalo Norte discovery, which has an independent audited estimated  gross 2C contingent resource of over 11.4 mmbo and 38 billion cubic feet (BCF) of gas.

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

Company	Interest
Sonangol (Operator)	36.00%
Afentra	30.00%
M&P	20.00%
Etu Energias	10.00%
NIS Naftagas	4.00%

Block 3/05A 

Block 3/05A contains the undeveloped Punja, Caco and Gazela discoveries with an estimated gross in-place resource of over 309.2 mmboe. An independent audit estimates there to be gross 2C recoverable resources of 98 mmbo and 290 BCF of gas.  

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 650 bopd gross during 2025 (2024: 1,248 bopd gross). This extended production test is helping to establish the long-term resource potential and define the appropriate development strategy for the Gazela field. 

Block 3/05A is operated by Sonangol through a JV partnership under a PSA. The Block 3/05A PSA, effective since 2015, is scheduled to expire in 2035, with provisions for extension contingent on continued production. A significant commercial uplift was achieved in 2024, with the Punja undeveloped discovery receiving marginal field terms, further enhancing the economic attractiveness of this block. 

Company	Interest
Sonangol (Operator)	30.33%
M&P	26.67%
Afentra	21.33%
Etu Energias	13.33%
NIS Naftagas	5.33%

Block 3/24 

Afentra operates Block 3/24, a 545 km²  shallow-water licence strategically located adjacent to its core producing assets, Block 3/05 and Block 3/05A. The block contains ten established oil and gas discoveries, including three previously produced fields, with >190 mmbos Stock Tank Oil Initially in Place (STOIIP) and 400 BCF Gas Initially in Place (GIIP). Discovered in the late 1980s, the reservoirs have not been re-evaluated using modern techniques. All discovery wells were tested, with flow rates of up to 6,000 bopd. Block 3/24 is a strategic addition to Afentra's portfolio, offering a unique short-cycle, low-cost, infrastructure-led development potential due to its proximity to Block 3/05, alongside several exploration prospects identified on existing 3D seismic. Following an initial internal review of the discoveries, management estimates a gross 2C contingent resource of 92.4 mmboe.

Block 3/24 is operated by Afentra through a JV partnership under a RSC. 

Company	Interest
Afentra (Operator)	40%
M&P	40%
Sonangol	20%

Block 3/05 Work Programme 

Delivering on the Multi-Year Redevelopment Plan which will Underpin Future Growth 

The 2025 work programme for Block 3/05 successfully continued the advancement of the multi-year re-development plan to enhance asset integrity and boost recovery, alongside a parallel programme of targeted production optimisation through LWIs. These parallel workstreams, combining foundational upgrades with immediate production gains, have prepared the asset for the coming step-change in performance. This readiness was cemented in 2025 by the completion of site surveys, contractor selection, and the ordering of long-lead items for the 2026 drilling and heavy workover campaign. 

Protecting Asset Value: Infrastructure Integrity and Renewal  

A core element of the 2025 work programme was a systematic campaign of infrastructure upgrades designed to enhance asset integrity, improve operational reliability, and ensure the long-term value of the Block 3/05 facilities. 

A major achievement was the safe completion of the FSO Palanca's 18-month recertification process during Q4 2025, with formal recertification received in early 2026. Conducted under the supervision of Bureau Veritas (BV) while the vessel remained in continuous operation, the project successfully recertified the hull, machinery, cranes, and lifting systems. This milestone secures the FSO's operational licence for the long-term, thereby avoiding the need to drydock until beyond 2030. 

In parallel, significant progress was made on a suite of other integrity projects. Work advanced on a comprehensive overhaul of power generation units and the recovery of cranes across the assets, improving water-injection equipment and platform availability whilst enhancing reliability. Collectively, these initiatives are fundamental to mitigating Health, Safety and Environment (HSE) and production risks, reinforcing asset reliability, and providing the stable operational platform required for future growth. 

Production Optimisation 

Alongside the multi-year redevelopment plan, the 2025 work programme delivered value through activities designed to enhance current production and maximise long-term hydrocarbon recovery through LWIs including through-tubing casing logging to identify bypassed oil. 

Continuous Production Optimisation: Light Well Interventions 

During the year, 28 LWIs were completed, targeting incremental production gains from the existing well stock. These low-cost, high-impact activities continue to provide excellent returns, delivering an incremental production increase of approximately 100 bopd with typical short-payback periods. The LWI programme remains a key, cost-effective tool for maximising value from the asset. 

Utilising through-tubing logging to identify bypassed oil  

In addition, utilising through-tubing logging (TTL), 3 wells have been successfully evaluated to identify zones of bypassed oil behind pipe. This new programme initiated in 2025 supports the selection and planning of future well interventions aimed at increasing production, improving waterflood sweep efficiency, and delivering incremental production gains. To date, the success rate has been 100% in identifying unswept oil. 

Enhancing Recovery Through Water Injection Upgrades 

The multi-year project to upgrade the water injection infrastructure is fundamental to unlocking the full potential of Block 3/05 by maintaining reservoir pressure and maximising long-term recovery. Significant progress was made in 2025, with the reinstatement of field-wide injection capability with redundancy in the distribution network being a key achievement. 

Performance increased steadily throughout the year, with average injection rates reaching ~37,800 bwpd. Peak rates were in excess of 80,000 bwpd in 2025, highlighting significant capacity headroom for future injection increases. This performance enabled the joint venture to successfully achieve its strategic objective of a sustained injection rate of ~50,000 bwpd by year-end 2025. This achievement provides a robust platform for future growth, with the ongoing programme designed to ultimately deliver an injection capacity of over 150,000 bwpd beyond 2026. 

Preparing for a Step-Change in Growth 

A primary focus throughout 2025 was the finalisation of planning and the de-risking of the 2026 drilling and hydraulic workover campaign. All critical preparatory milestones were successfully completed during the year. This included the selection of a turnkey drilling contractor and key quality assurance/control (QA/QC) teams, the completion of platform site surveys to validate rig access, the detailed prioritisation of HWO candidates, and the ordering of all necessary long-lead items. 

The  2026 campaign is designed to deliver a material increase in production and marks the next major phase of the redevelopment plan. The scope includes: 

·      Hydraulic Workovers: Maximising the reuse of existing wellbores for both production and injection to enhance recovery in a capital-efficient manner. 

·    Infill Drilling: Targeting reserves in areas of the field that have not been drilled in over a decade, with more than 20 opportunities already identified. 

·    Near-field Exploration: Targeting high-impact structures adjacent to the existing fields that could deliver material uplift. 

·      Production Enhancement: Planning for the installation of Electric Submersible Pumps (ESPs) following the completion of ongoing power system upgrades. 

The campaign's optimised sequencing is designed to balance production rates, operational risk, and capital efficiency, positioning the asset for the planned step-change in production growth. 

Reducing Emissions Through Measurement and Gas Management 

In 2025, the partnership installed new gas-metering systems, improving visibility of flare volumes, composition, and associated emissions. These insights underpin the development of a comprehensive gas-management plan to reduce routine flaring and enhance gas utilisation. This holistic approach is essential for the responsible and efficient monetisation of these oil and gas resources. 

In parallel, a multi-year feasibility study is assessing potential solutions and guiding future investment decisions, ensuring the fields can meet long-term emissions-reduction targets and align with a lower-carbon operating environment. 

A Foundation for Wider Growth 

The foundational work completed in 2025 - enhancing operational reliability, increasing recovery potential, and advancing emissions management - has positioned Afentra for a pivotal year in 2026. The Block 3/05 asset is now fully prepared for the next material phase of investment. 

The arrival of the drilling rig post-period unlocks a step-change in growth, not only through the redevelopment of Block 3/05 but also by creating synergies with the adjacent licences. Block 3/05's extensive infrastructure will serve as a central hub for the low-cost, phased development of satellite discoveries in Block 3/05A and the evaluation of development options for the discoveries in the Afentra-operated Block 3/24. This creates a coordinated, long-term growth framework across the wider area, providing significant operational optionality to drive continuous delivery, portfolio progression, and sustainable value creation in Angola 

Case Study: De-risking the 2026 rig campaign through a technical led approach 

Building on deep technical collaboration within the joint venture since 2022, Afentra's expertise has been central to de-risking the next major phase of investment in Block 3/05: the 2026 drilling, which commenced post-period, and the heavy workover (HWO) campaign. 

Afentra's multi-disciplinary team, with extensive experience across geoscience, reservoir engineering, and drilling, has been instrumental in maturing a high-quality portfolio of opportunities. This involved detailed subsurface analysis to identify and rank over 20 infill drilling targets and prioritise a sequence of capital-efficient HWOs focused on maximising the reuse of existing wells. 

This meticulous technical work was translated into tangible operational readiness in 2025. Through a deeply embedded partnership with the operator, the team supported the completion of all critical preparatory milestones, including platform site surveys, the selection of a turnkey drilling contractor and QA/QC teams, and the ordering of all necessary long-lead items. The result was a fully defined and executable programme for 2026, designed to unlock significant value by reactivating dormant wells and accessing unswept reserves. 

Crucially, the detailed processes, learnings, and technical models developed for the Block 3/05 campaign now serve as a blueprint for Afentra's wider Angolan growth strategy. It provides a repeatable model for evaluating and planning the low-cost development of satellite discoveries in Block 3/05A and maturing the proven discoveries in the Afentra-operated Block 3/24, underpinning the company's ability to deliver sustainable, long-term growth. 

Block 3/05A Work Programme

Block 3/05A, strategically positioned adjacent to the Block 3/05 field infrastructure and Afentra's operated Block 3/24, represents a key growth area for Afentra, housing the undeveloped Punja, Caco, and Gazela discoveries. These assets collectively hold an estimated 300 mmbo of oil in place, with Afentra's gross 2C recoverable resource estimate standing  at 98 mmbo and 290 BCF. 

Our ongoing activities in Block 3/05A are yielding valuable insights. The Gazela field, which initially came online in 2015, saw approximately 2.4 mmbo recovered before a wellbore shutdown in 2017. Following successful restoration in March 2023, the Gazela-101 well has demonstrated robust performance, averaging  650 bopd gross throughout 2025. 

When combined with our detailed subsurface mapping of the Caco and Gazela fault compartments, this extended production test is crucial for de-risking the long-term resource potential and refining our optimal development strategy. The resulting identified well opportunities have been rigorously ranked to strategically inform the  2026/2027 drilling campaign. 

Infrastructure-led Development Potential 

Advancing the development concepts for Block 3/05A remains a high priority. Recognising the high gas-oil ratio of the Punja field reservoirs, an integrated gas management plan spanning both Blocks 3/05A, 3/05 and 3/24 is paramount. This holistic approach is essential for the responsible and efficient monetisation of these oil and gas resources. In alignment with our environmental commitments, we are thoroughly evaluating all alternatives to flaring excess gas from future developments in collaboration with the JV partnership. Multiple options to reduce flaring are under active consideration, including the commercial export of excess gas via the nearby ALNG network or re-injection into existing fields. Both pathways will require a comprehensive review and potential upgrade of existing compression infrastructure. 

The JV partnership is committed to a phased development strategy for Punja and Caco-Gazela. This approach is designed to progressively gather appraisal data, mitigate subsurface uncertainty, and generate early cash flow through initial production. A thorough screening and ranking process for various development concepts is underway, targeting an optimised Final Investment Decision (FID) in the near term. 

Block 3/24 Work Programme

Afentra's operated Block 3/24 offers low-cost, short-cycle development opportunities adjacent to existing infrastructure. The block contains ten proven oil and gas discoveries, including three previously produced fields, and also holds significant infrastructure-led exploration potential. All wells have been tested, delivering flow rates up to 6,000 bopd, with a block-wide volume estimated >190 mmbo STOIIP and 400 BCF GIIP already discovered, though reservoirs have yet to be re-evaluated using modern techniques.  This significant discovered volume underpins a material contingent resource base, with a management estimate of 92.4 mmboe of gross 2C resources, which the work programme is designed to mature towards development.

Located around 5 km from the Block 3/05 producing infrastructure in shallow water, the area is ideal for small-scale platform deployment. The initial development of the block is being fast-tracked, with the focus on the GPQ (Golungo-Palanca NE-Quissama) infrastructure-led development plan. This phased project is targeting an initial production rate of up to 10,000 bopd and is being advanced toward a Final Investment Decision (FID) targeted for Q4 2026.

Case study:

GPQ: Near-term, operated infrastructure-led growth

The initial development focus for Block 3/24 is the Golungo-Palanca NE-Quissama (GPQ) area, which represents a key near-term organic growth catalyst for Afentra. The discoveries are 3 of the 10 identified on the block.

Our strategy is centred on a low-cost, fast-track development. Leveraging the GPQ area's proximity - just 5km from existing Block 3/05 facilities with available capacity and in shallow water - we can minimise capital expenditure with a phased development plan and accelerate time to first oil. The initial development plan focuses on well re-entry and optimisation studies, targeting a Final Investment Decision (FID) in late 2026 for a project with the potential to deliver up to 10,000 bopd (gross).

As Afentra's first operated development, GPQ provides a clear pathway to material value creation. It will unlock previously stranded resources and establish a repeatable, low-cost development blueprint that can be applied to other discoveries, converting the block's significant resources into production and reserves.

Onshore Angola 

Afentra is well-positioned to unlock early production and untapped exploration opportunities in the proven onshore Kwanza basin from KON4, KON15 and KON19 

Untapped hydrocarbon potential 

KON4, KON15 and KON19 are all located in the proven yet significantly under-explored onshore Kwanza basin. This presents an early-stage opportunity with significant growth potential. Entry into this basin, where 11 oil fields have been discovered  (with approximately 400 mmboe of oil in place, of which around 90 mmboe has been produced to date), offers a value-driven strategic opportunity for low-cost redevelopment and near-term and low-cost exploration in a proven basin, by applying fresh ideas and modern concepts to an area where the last exploration well was drilled in 1982 and no new technology has been applied for 40 years. 

These onshore blocks were high graded by Afentra as they have good signs of a working petroleum system and contain wells that were drilled on a variety of structures with light oil recovered to surface in one, and oil shows in others from both post- and pre-salt reservoirs.  

The onshore basin is analogous to nearby regional basins such as the Lower Congo and Gabon basins, which contain over 2 Bn boe and 3.5 Bn boe of discovered reserves respectively. In contrast, the Kwanza basin has less than 100 mmboe of  currently recognised 2P reserves, highlighting its significant untapped potential. 

We continue to evaluate additional opportunities utilising modern technologies such as eFTG and new 2D seismic acquisition alongside techniques that the team have successfully deployed in other regions of Africa. 

Taking a basin-wide approach 

The utilisation of eFTG across KON4, KON15 and KON19 represents the first modern, large-scale geophysical programme in the basin in decades and is designed to provide a new understanding of the subsurface geology. The data from the eFTG survey will be integrated with legacy well and seismic data to de-risk the basin and high-grade the most promising areas. The interpretation of this integrated dataset will then guide the subsequent, more targeted 2D seismic acquisition campaigns, forming the basis for future prospect definition and exploration drilling. This systematic, technology-led approach is fundamental to efficiently unlocking the full exploration potential of Afentra's strategic Kwanza onshore acreage. 

KON4 

In June 2025, Afentra announced that it had initialled an RSC for KON4  with final award pending and expected in Q2 2026. Under the terms of the KON4 RSC, Afentra will be Operator with a 35% equity interest. The Block offers both short-cycle, low-cost production opportunities linked to field redevelopment, alongside low-cost, near-term exploration potential. 

Block KON4 covers 1,387 sqkm and is situated in a historically productive area of the onshore Kwanza Basin. The Block features the Quenguela Norte field - the largest Angolan onshore discovery to date - estimated to hold over 200 mmbo of discovered oil in place. The field achieved peak production of 12,000 bopd, with 46 mmbo recovered before it was eventually shut-in and abandoned in 1999. This represents an opportunity to unlock significant value through the reactivation of this and other legacy oil fields, supported by modern technology and redevelopment techniques that have advanced considerably since the fields were last in production decades ago. The commercialisation plan is aided by the fields' proximity to infrastructure, creating a pathway for early production export to the Luanda refinery.  

During January 2026, the KON4 joint venture commenced acquisition of the eFTG survey, with data acquisition targeted for completion in Q1 2026, followed by the interpretation phase. Field reconnaissance has also been completed to assess infrastructure, access routes and the surrounding community landscape. The new eFTG dataset, together with legacy seismic and well information, will be integrated to update the subsurface model and play analysis, refining priority areas for redevelopment. This will be followed by planning for future well re-entries and 2D seismic acquisition, including environmental permitting and early-stage vendor engagement.  

KON 15 and KON19 

Afentra holds a 45% non-operated interest in both KON15 and KON19. The blocks are located adjacent to the legacy Tobias and Galinda oil fields and offer significant potential within Angola's prospective post- and pre-salt formations. With significant advances in exploration technology since the last well was drilled over 40 years ago, these blocks can now be rapidly explored and appraised, potentially leading to early development and production. Supported by a favourable investment environment, 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.  

The initial phase of a basin-wide eFTG survey, launched in August 2024, has now been completed for KON19, with remaining infill lines on KON15 completed post-period in early 2026. This advanced eFTG technology will enable a more comprehensive subsurface analysis of the 25,000 km² onshore Kwanza basin - an area largely unexplored in recent decades - and help identify the most prospective regions. The eFTG interpretation will guide the design of  future 2D seismic surveys and identify priority areas. Environmental and regulatory preparations for 2D seismic acquisition and future field operations are ongoing, with acquisition expected in 2026 and interpretation to follow in 2027. Together, the eFTG and new 2D seismic results will support prospect definition and future exploration well planning. 

Block KON15  

Company	Interest
Sonangol P&P (Operator)	55%
Afentra	45%

Block KON19  

Company	Interest
ACREP (Operator)	45%
Afentra	45%
Enagol	10%

Angola 

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.

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. 

Company	Interest
TBC	40%
Afentra	40%
Sonangol	20%

FINANCIAL REVIEW

Financial discipline and strategic execution

In 2025, despite a soft commodity market, Afentra demonstrated prudent financial management generating $114.4 million from four liftings in 2025, with the additional monetisation of ~360,000 barrels stock in January 2026. Building on our historic successes, we reinvested in our core assets and expanded our portfolio by signing the Etu SPA to increase our interests in Blocks 3/05 and 3/05A and securing Block 3/24 (our first operatorship) and the KON15 licence.

With the softening of commodity prices and the capped nature of our RBL facility we have carefully managed our financial position during 2025 including through a selective use of cargo pre-payment facility in Q4 2025. Overall our financial  position remained stable in 2025, with a focus on increased capital investment in Angola. We ended 2025 with $10.2 million in cash ($54.8 million at 31 December 2024), inclusive of restricted cash balances, and an end of year net debt position of $21.8 million (net cash $12.6 million at 31 December 2024). A full reconciliation of net debt is provided in note 20 to the Consolidated Financial Statements. Our Debt to EBITDAX ratio of 0.6x  has been flat vs 0.5x at 31 December 2024. Subsequent to the year end, in May 2026, the Company entered into a new prepayment financing arrangement with a subsidiary of Gunvor Group. The facility will replace the Company's existing financing structure and is intended to support the Company's ongoing investment programme.

We completed four liftings during the period, at an average realised price of $70.2/bbl, resulting in revenue of $114.4 million. A fifth lifting, originally scheduled for December 2025, was deferred to January 2026 when we sold our first cargo of crude oil for the year of approximately 0.5 mmbo at a sales price of $65.4/bbl resulting in additional revenue of $33.8 million, of which $17.1 million was received in advance, in December 2025. This has been recorded as a contract liability on the 2025 balance sheet.

We continue to manage our exposure to oil price risk through our hedging strategy and historically have hedged approximately 70% of 2025 production through a combination of put options and collar structures. Currently, approximately 44% of 2026 projected sales are hedged using a combination of put options with strike prices ranging from $60/bbl to $68/bbl and collar structures with call option ranging from $78/bbl to $92/bbl. The hedging programme will continue to be under active review to evaluate further opportunities.

Our asset base build out continued at pace.  Acquisition of the ETU's interests further simplifies management of the Block 3/05 and Block 3/05A licenses with Sonangol's election to participate in the transaction being an important endorsement signifying alignment of interests between the JV partners and Sonangol as well as highlighting the importance of the Block 3/05 and Block 3/05A to the state of Angola. In March 2026, Afentra signed a new SPA with Etu reflecting its revised pro rata share of the acquisition. Under the revised transaction, our net upfront payment is $15.2 million, with contingent consideration of up to $6.74 million. At completion our participating interest in Block 3/05 will increase to 33.33% and our participating interest in Block 3/05A will increase to 24.99%. The effective date of the transaction is 31 December 2023, which is expected to result in a significantly reduced payment on completion. The completion of the acquisition is subject to the satisfaction of customary conditions precedent, including approval by the relevant governmental agencies and the operator. Strategically, the acquisition consolidates Afentra's position across its core offshore portfolio, enhances alignment within the joint venture, and delivers an immediate uplift in production and reserves. Also offshore Angola, the award of the Block 3/24 licence was completed in December, following ministerial approval, with Afentra as operator at 40% working interest.

Onshore, we increased our presence in the Kwanza basin in April by securing a 45% non-operated interest in Block KON 15 alongside Sonangol (operator with 55% interest). The KON 4 Risk Service Contract (RSC) was initialled in June, with completion of the award expected in H1 2026.

During the year, we completed the transfer of our 34% non-operated participating interest in the Odewayne Block, Somaliland, to Petrosoma Limited for cash proceeds of $1.97 million, which we received in December. The disposal of this non-core asset resulted in a $19.5 million accounting loss on disposal.

As described in our 2024 Annual Report, in line with our commitment to avoid shareholder dilution, we have elected to satisfy vested options under the Founders' Share Plan ("FSP") and employee Long-term Incentive Plans ("LTIP") through market purchases via an existing Employee Share Benefit Trust (the "Trust") rather than issuing new ordinary shares. During the year ended 31 December 2025, the Trust purchased 4.5 million shares on the open market at an average price of  48p per share. Since 31 December 2025, the Trust purchased an additional 0.4 million shares at an average price of 47p per share and 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 agreed with the Trust, in aggregate the Trust is expected to purchase around 6.5 million ordinary shares over 2025 and 2026.

We continue to develop our office presence in Luanda, signing a lease on a new office in July 2025 and expanding our presence to four full staff members, all of them Angola nationals supported by a number of the local Angolan contractors.

With the conclusion of a comprehensive review of the strategic options that resulted in the determination to pursue the next phase of growth as an independent E&P company based on the strong prospects in front of the Company our focus remains unchanged as we continue to seek to strengthen and exploit our portfolio in Angola and seek value accretive license acquisitions and M&A opportunities in Angola as well as in other jurisdictions in West Africa.

Selected financial data		2025	2024
Sales volume	mmbo	1.6	2.3
Realised oil price	$/bbl	70.2	82.2
Total revenue	$ million	114.4	180.9
Cash and cash equivalents	$ million	5.1	46.9
Restricted funds	$ million	5.0	7.9
Borrowings	$ million	(31.1)	(41.4)
Net (debt)/cash	$ million	(21.8)	12.6
Adjusted EBITDAX	$ million	51.7	90.2
(Loss)/profit after tax	$ million	(3.2)	52.4
Year-end share price	Pence	41.4	46.1

Non-IFRS measures

The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles.

EBITDAX (Adjusted) represents earnings before interest, taxation, depreciation, total depletion and amortisation, impairment and expected credit loss allowances, share-based payments, provisions, and pre-licence expenditure. Additionally, in any given period, the Company may have significant, unusual or non-recurring items which may be excluded from EBITDAX (Adjusted) for that period. When applicable, these items are fully disclosed and incorporated into the reconciliation provided below. The Company believes this measure assists investors by excluding the potentially disparate effects between periods of the adjustments specified.

Debt to EBITDAX is calculated as total debt divided by EBITDAX and is presented to assist users of the financial statements in evaluating the Group's financial leverage and its ability to service debt from operating earnings.

EBITDAX (Adjusted) and Debt to EBITDAX are non-IFRS financial measures. EBITDAX (Adjusted) and Debt to EBITDAX should not be considered as alternatives to net income or any other indicator of Afentra plc's performance calculated in accordance with IFRS. Because the definition of EBITDAX (Adjusted) and Debt to EBITDAX may vary among companies and industries, they may not be comparable to other similarly titled measures used by other companies.

Income Statement

Revenue from four liftings completed during the year, net of off-take fees, was $114.4 million (2024: $180.9 million). The decrease is attributed to lower oil prices, with an average realised price of $70.2/bbl (2024: $82.2/bbl) and a decrease in sales volumes to 1.6 mmbo (2024: 2.3 mmbo).

Cost of sales during the year totalled $69.2 million (2024: $94.1 million); a full reconciliation is provided in the notes to the accounts (Note 4).

The profit from operations for 2025 decreased to $21.5 million (2024: $74.5 million) as a result of lower revenues described above, the $19.5 million loss on disposal of the Odewayne Block (2024: nil), a $0.5 million impairment of the Block 23 exploration asset (2024: nil), and a $1.6 million expected credit loss (2024: nil). This was offset by a $13.2 million non-cash gain on revaluation of the provision for contingent consideration. During the year, net administrative expenditure increased to $15.3 million (2024: $12.3 million), primarily due to increases in staff costs and corporate advisors.

Finance costs decreased during 2025 to $7.8 million (2024: $9.0 million), reflecting principal repayments on the RBL facility. Further detail is provided in the notes to the accounts (Note 8).

The loss after tax for the year was $3.2 million (2024: $52.4 million profit after tax):

	$' Million
2024 profit after tax	52.4
Decrease in revenue	(66.5)
Decrease in cost of sales	24.9
Increase in G&A and pre-licence costs	(3.0)
Decrease in net finance costs	1.1
Increase in non-recurring losses and impairments	(21.6)
Increase in fair value gains on contingent consideration	13.2
Increase in tax expense	(3.7)
2025 loss after tax	(3.2)

Group adjusted EBITDAX totalled $51.7 million (2024: $90.2 million):

	2025	2024
	$' Million	$' Million
(Loss)/profit after tax	(3.2)	52.4
Net finance costs	7.7	8.9
Depletion and depreciation	18.4	12.9
Pre-licence costs	1.6	1.8
Gain on revaluation of contingent consideration provision	(13.2)	-
Loss on disposal and impairment of exploration assets	20.0	-
Expected credit loss allowances	1.6	-
Share-based payment charge	1.9	1.0
Taxation	16.9	13.2
Total EBITDAX (Adjusted)	51.7	90.2

The basic and diluted loss per share for the year was 1.4 cents (2024: basic earnings per share of 23.3 cents and diluted earnings per share of 21.1 cents). No dividend is proposed to be paid for the year ended 31 December 2025 (2024: nil).

Statement of financial position

At the end of 2025, non-current assets totalled $172.6 million (2024: $153.5 million). The increase is primarily due to capital expenditure on Blocks 3/05 and 3/05A ($62.0 million), offset by depreciation ($22.2 million) and the disposal of Odewayne ($21.4 million). Further information can be found in Note 12 to the Financial Statements.

At the end of 2025, current assets stood at $47.0 million (2024: $73.1 million) including inventories of $25.0 million (2024: $7.5 million), trade and other receivables of $11.6 million (2024: $10.6 million), cash and cash equivalents of $5.1 million (2024: $46.9 million), and restricted funds of $5.0 million (2024: $7.9 million). The increase in the inventories balance is primarily due to the deferral of the December lifting to 2026.

At the end of 2025, current liabilities were $83.4 million (2024: $71.1 million) including trade and other payables of $68.8 million (2024: $52.9 million), borrowings of $10.9 million (2024: $11.3 million), and contingent consideration of $3.5 million (2024: $5.5 million). There were no derivative liabilities at 31 December 2025 (2024: $1.3 million). The increase in trade and other payables is primarily due to the recognition of a $17.1 million contract liability, relating to revenue received in advance for the January 2026 lifting.

At the end of 2025, non-current liabilities were $42.4 million (2024: $56.9 million), comprised of borrowings of $20.2 million (2024: $30.1 million), contingent consideration of $9.9 million (2024: $24.4 million), and deferred tax of $11.5 million (2024: $1.7 million). The decrease is primarily due to lower provision for contingent consideration, as a result of the lower oil price environment, and repayments of debt principal, offset by an increase in deferred tax.

The Group's net assets decreased from $98.6 million at the end of 2024 to $93.8 million as at 31 December 2025, reflecting the loss for the year and purchases of Afentra shares to satisfy the vesting of 2026 FSP and staff LTIPs.

Cash flow

Net cash inflow from operating activities totalled $29.6 million (2024: $85.6 million). The decrease is primarily due to a decrease in revenues in 2025 as a result of lower oil prices and sales volumes.

Net cash used in investing activities decreased to $52.3 million from $53.6 million in 2024. Increased additions to property, plant and equipment in 2025 were offset by proceeds received on the disposal of Odewayne and non-recurrence of the 2024 asset acquisition.

Net cash used in financing activities totalled $19.0 million, compared to $0.1 million generated from financing activities in 2024, reflecting repayments of debt principal and interest and purchases of Afentra shares under the 2025 share purchase programme.

Accounting Standards

The Group has reported its 2025 and 2024 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 - 13 May 2026

The Strategic Report was approved by the Board of Directors and signed on its behalf by:

Paul McDade - Chief Executive Officer - 13 May 2026

FULL FINANCIAL STATEMENTS

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

	For the years ended 31 December
		2025		2024
	Note	$000		$000
Revenue	3	114,385		180,860
Cost of sales	4	(69,223)		(94,124)
Expected credit loss on joint venture receivables	15	(1,616)		-
Gross profit		43,546		86,736
Other administrative expenses		(13,730)		(10,439)
Pre-licence costs		(1,562)		(1,828)
Total administrative expenses		(15,292)		(12,267)
Loss on disposal of intangible assets	5	(19,505)		-
Impairment of intangible asset	5	(500)		-
Gain on revaluation of contingent consideration provision	22	13,235		-
Profit from operations	6	21,484		74,469
Finance income	8	33		106
Finance costs	8	(7,758)		(9,000)
Profit before tax		13,759		65,575
Income tax	9	(16,946)		(13,225)
(Loss)/profit for the year attributable to the owners of the parent		(3,187)		52,350
Items that may be reclassified subsequently to profit or loss
Foreign exchange differences on translation of foreign operations		(96)		(35)
Total other comprehensive loss for the year ([1])		(96)		(35)
Total comprehensive (loss)/income for the year attributable to the owners of the parent		(3,283)		52,315
Basic (loss)/earnings per share (US cents)	10	(1.4)		23.3
Diluted (loss)/earnings per share (US cents)	10	(1.4)		21.1

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

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

		As at 31 December
		2025		2024
	Note	$000		$000
Non-current assets
Intangible exploration and evaluation assets	11	1,332		22,479
Property, plant and equipment	12	171,229		131,041
		172,561		153,520
Current assets
Inventories	14	25,012		7,464
Trade and other receivables	15	11,623		10,618
Derivative assets	27	225		196
Cash and cash equivalents	16	5,145		46,880
Restricted funds	17	5,044		7,930
		47,049		73,088
Total assets		219,610		226,608
Current liabilities
Borrowings	20	10,874		11,271
Trade and other payables	21	68,811		52,939
Derivative liabilities	27	-		1,279
Contingent consideration provision	22	3,500		5,535
Lease liability	23	240		97
		83,425		71,121
Non-current liabilities
Borrowings	20	20,227		30,145
Contingent consideration provision	22	9,932		24,367
Deferred tax liability	9	11,520		1,661
Lease liability	23	674		685
		42,353		56,858
Total liabilities		125,778		127,979
Equity attributable to equity holders of the Company
Share capital	18	28,914		28,914
Currency translation reserve	19	(429)		(333)
Share option reserve	19	2,117		842
Own shares reserve	19	(2,789)		-
Retained earnings	19	66,019		69,206
		93,832		98,629
Total liabilities and equity		219,610		226,608

The financial statements of Afentra plc, registered number 01757721, were approved by the Board of Directors and authorised for issue on 13 May 2026.

Signed on behalf of the Board of Directors

Paul McDade - Chief Executive Officer  

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

			Equity attributable to equity holders of the Company
		Share capital	Currency translation reserve	Share option reserve	Own shares reserve	Retained earnings	Total
	Note	$000	$000	$000	$000	$000	$000
At 1 January 2024		28,143	(298)	965	-	19,162	47,972
Profit for the year		-	-	-	-	52,350	52,350
Currency translation adjustments		-	(35)	-	-	-	(35)
Total comprehensive profit/(loss) for the year attributable to the owners of the parent		-	(35)	-	-	52,350	52,315
Share-based payment charge for the year		-	-	989	-	-	989
Share options exercised		771	-	(1,112)	-	(2,306)	(2,647)
At 31 December 2024		28,914	(333)	842	-	69,206	98,629
Loss for the year		-	-	-	-	(3,187)	(3,187)
Currency translation adjustments		-	(96)	-	-	-	(96)
Total comprehensive loss for the year attributable to the owners of the parent		-	(96)	-	-	(3,187)	(3,283)
Share-based payment charge for the year		-	-	1,872	-	-	1,872
Shares purchased		-	-		(3,106)	-	(3,106)
Share options exercised	25	-	-	(597)	317	-	(280)
At 31 December 2025		28,914	(429)	2,117	(2,789)	66,019	93,832

CONSOLIDATED STATEMENT OF CASH FLOWS

		For the years ended 31 December
		2025		2024
	Note	$000		$000
Operating activities:
Profit before tax		13,759		65,575
Adjusted for:
Depreciation, depletion and amortisation	12	22,233		12,873
Share-based payment expense	25	1,872		989
Tax payments related to share-based payments	25	(280)		(2,702)
Unrealised (gains)/losses on derivatives		(1,308)		1,200
Loss on disposal of intangible asset	5	19,505		-
Impairment of intangible asset	5	500		-
Hedge cost		-		(117)
Expected credit loss		1,616		-
Gain on revaluation of contingent consideration		(13,235)		-
Finance income	8	(33)		(106)
Finance costs	8	7,758		9,000
Operating cash flow prior to working capital movements		52,387		86,712
(Increase)/decrease in inventories		(17,548)		21,403
Increase in trade and other receivables		(871)		(7,459)
Increase/(decrease) in trade and other payables		4,534		(5,304)
Cash flow generated from operating activities		38,502		95,352
Income tax paid		(8,889)		(9,762)
Net cash flow generated from operating activities		29,613		85,590
Investing activities
Asset acquisitions		-		(28,428)
Deposit for asset acquisitions		(1,750)		-
Interest received	8	33		106
Purchase of property, plant and equipment	12	(49,029)		(19,997)
Exploration and evaluation costs	11	(830)		(612)
Sales proceeds on Odewayne disposal		1,972		-
Cash inflow from restricted funds		2,886			-
Contingent consideration paid	22	(5,544)		(4,621)
Net cash used in investing activities		(52,262)		(53,552)
Financing activities
Drawdown on loan facilities	20	2,400		35,748
Principal repayments on loan facilities	20	(12,905)		(27,364)
Cash outflow from restricted funds		-		(3,080)
Shares acquired for settlement of share-based payments		(3,106)		-
Interest paid		(5,172)		(5,051)
Principal and interest paid on lease liability	23	(201)		(160)
Net cash (used in)/generated from financing activities		(18,984)		93
Net (decrease)/increase in cash and cash equivalents		(41,633)		32,131
Cash and cash equivalents at beginning of year		46,880		14,729
Effect of foreign exchange rate changes		(102)		20
Cash and cash equivalents at end of year	16	5,145		46,880

COMPANY STATEMENT OF FINANCIAL POSITION

		As at 31 December
		2025		2024
	Note	$000		$000
Non-current assets
Trade and other receivables	15	25,139		14,109
Investments in subsidiaries	13	-		20,140
		325,139		34,249
Current assets
Trade and other receivables	15	5,340		4,167
Cash and cash equivalents	16	3,590		8,267
		8,930		12,434
Total assets		34,069		46,683
Current liabilities
Trade and other payables	21	539		411
Borrowings from group companies	20	-		27,517
		539		27,928
Total liabilities		539		27,928
Equity
Share capital	18	28,914		28,914
Share option reserve		2,738		1,183
Own shares reserve		(2,789)		-
Retained earnings		4,667		(11,342)
Total equity		33,530		18,755
Total liabilities and equity		34,069		46,683

The profit for the financial year within the Company accounts of Afentra plc was $16.0 million (2024: $24.9 million loss). As permitted by s408 of the Companies Act 2006, no individual Statement of Comprehensive Income is provided in respect of the Company. 

The financial statements of Afentra plc, registered number 01757721, were approved by the Board of Directors and authorised for issue on 13 May 2026. 

Signed on behalf of the Board of Directors 

Paul McDade - Chief Executive Officer

COMPANY STATEMENT OF CHANGES IN EQUITY

		Share capital	Share option reserve	Own shares reserve	Retained earnings	Total
		$000	$000	$000	$000	$000
At 1 January 2024		28,143	965	-	13,525	42,633
Loss for the year		-	-	-	(24,867)	(24,867)
Share-based payment charge for the year		-	989	-	-	989
Share options exercised		771	(771)	-	-	-
At 31 December 2024		28,914	1,183	-	(11,342)	18,755
Profit for the year		-	-	-	16,009	16,009
Share-based payment charge for the year		-	1,872	-	-	1,872
Shares purchased		-	-	(3,106)	-	(3,106)
Share options exercised	25	-	(317)	317	-	-
At 31 December 2025		28,914	2,738	(2,789)	4,667	33,530

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 the United Kingdom under the UK Companies Act 2006 and is registered in England and Wales. 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. Foreign operations are included in accordance with the policies set out in note 1 (i).

The financial statements have been prepared under the historical cost convention except for derivative financial instruments, including contingent consideration provision, which have been measured at fair value through profit or loss. 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 preparation and presentation of financial information

The Group financial statements have been prepared in accordance with UK adopted international accounting standards. As ultimate parent of the Group, the Company's financial statements have been prepared in accordance with Financial Reporting Standard 101 Reduced Disclosure Framework (FRS 101).

The financial information for the year ended 31 December 2025 does not constitute statutory accounts as defined in sections 435 (1) and (2) of the Companies Act 2006. Statutory accounts for the year ended 31 December 2024 have been delivered to the Registrar of Companies and those for 2025 will be delivered following the Company's annual general meeting. The auditor's report on these accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis of matter and did not contain a statement under section 498 (2) or (3) of the Companies Act 2006.

The accounting policies applied are consistent with those adopted and disclosed in the Group's Financial Statements for the year ended 31 December 2024. There have been a number of amendments to accounting standards and new interpretations issued by the International Accounting Standards Board which were applicable from 1 January 2025, however, these have not any impact on the accounting policies, methods of computation or presentation applied by the Group. Further details on new International Financial Reporting Standards adopted will be disclosed in the 2025 Annual Report and Accounts.

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2025 reporting periods and have not been early adopted by the Group. These standards are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions.

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 on pages. The financial position of the Group and Company, its cash flows and liquidity position are described in the Financial Review. In addition, Note 24 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 newly agreed prepayment 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 31 May 2027.  

The Board has considered a combination of downside scenarios, including production shortfalls alongside higher costs and lower than anticipated oil prices. The impact of these downside scenarios can be mitigated through a combination of existing hedges and the rephasing of certain projects included in the preliminary capital expenditure programme by the Joint Venture. The Board also notes the continued implementation of the hedging policy and is confident in the utilisation of commodity-based derivatives to manage oil price downside risk. As part of this assessment, the Directors have considered the principal financial covenant under the new prepayment facility, being the Advance Life Cover Ratio ("ALCR"), which requires forecast revenues attributable to the secured assets to maintain a minimum cover ratio of 1.30x against outstanding indebtedness. Based on the Group's forecasts and sensitivities performed, the ALCR covenant is not forecast to be breached during the going concern assessment 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. Refer to Note 13 for a list of the Group's subsidiaries as at 31 December 2025.

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. 

As of 31 December 2025, 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, and KON 15 (45%) and KON 19 (45%) located onshore in Angola. In addition to its non-operated interests, the Group has a material operated arrangement in Block 3/24 (40%) also located offshore Angola.

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 recognised 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. 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.

Deferred tax

Deferred income taxes are calculated using the balance sheet liability method on temporary differences. Deferred tax is generally provided on the difference between the carrying amounts of assets and liabilities and their tax bases. However, deferred tax is not provided on the initial recognition of goodwill, nor on the initial recognition of an asset or liability unless the related transaction is a business combination or affects tax or accounting profit. Deferred tax on temporary differences associated with shares in subsidiaries and joint ventures is not provided if reversal of these temporary differences can be controlled by the Group and it is probable that reversal will not occur in the foreseeable future. Tax losses available to be carried forward as well as other income tax credits to the Group are assessed for recognition as deferred tax assets.

Deferred tax liabilities are provided in full, with no discounting. Deferred tax assets are recognised to the extent that it is probable that the underlying deductible temporary difference will be able to be offset against future taxable income. Current and deferred tax assets and liabilities are calculated at tax rates that are expected to apply to their respective period of realisation, provided they are enacted or substantively enacted at the reporting date.

Changes in deferred tax assets or liabilities are recognised as a component of tax expense in the statement of comprehensive income, except where they relate to items that are charged or credited directly to equity in which case the related deferred tax is also charged or credited directly to equity.

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

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 

The Company applies the ECL 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.

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

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 funds

Restricted funds 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 recognised at their fair value, net of transaction costs, and subsequently measured at amortised cost using the effective interest method. 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. Entity-wide disclosures in relation to revenues from external customers for each product and service, information about major customers, and  geographical information has been included in the relevant notes.

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.

r)       Share purchases

The Company established an Employee Benefit Trust (EBT) to administer the share options schemes with its employees. The EBT is a legal arrangement controlled by the trustee, which acts for the Company on behalf of the employees, who are employed via the subsidiaries Afentra (UK) Limited and Afentra (Angola) Limited.  As the Company has indirect control over the assets of the trust, under IFRS, the results of the EBT are consolidated into the Group.

The Company instructed the EBT to periodically purchase shares in the market in order to settle the Founder Share Plan (FSP) and Long Term Incentive Plans (LTIP) on vest.

The cost to purchase these shares has been deducted from equity and recorded as a separate category of equity (Own shares reserve) until such time that the shares vest with the respective employees. Upon vesting, the cost of the shares in this reserve will be offset against the Share option reserve.

Shares held in the Own shares reserve are excluded from the calculation of weighted average shares outstanding for the purposes of Earnings and Diluted earnings per share.

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 pass mark 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.

Measurement of deferred tax

The acquisition of the Group's working interest in Block 3/05 in Angola was an asset acquisition and did not meet the definition of a business combination. Deferred tax was not recognised on acquisition as the deductible temporary difference between the tax base and acquisition value was subject to the Initial Recognition Exemption (IRE) under IAS 12. Since acquisition there has been significant further movements in the Block 3/05 carrying value and tax base. Judgement is required to determine when there is a new temporary difference to be recognised. The Group has determined that deferred tax should be recognised on the taxable temporary differences that have arisen after the deductible temporary difference subject to the IRE had reduced to nil.

The Group must determine the tax base of its Block 3/05 D&P asset and evaluate whether the associated Production Sharing Contract cost recovery pool in Angola should be included within this tax base. IAS 12 defines the tax base of an asset as the amount that will be deductible for tax purposes against taxable economic benefits that will flow to an entity when it recovers the carrying amount of the asset. Management considers that the cost pool forms part of the tax base of Block 3/05, and is not a separate tax attribute, as it is recoverable only through production of Block 3/05, it extinguishes if Block 3/05 production ceases, it transfers with the Block 3/05 asset, it does not survive independently from Block 3/05, and does not belong to the taxpayer separate from the asset. If the cost recovery pool was considered a separate tax attribute, similar to an unused tax loss, a deferred tax asset would be recognised to the extent this was considered recoverable.

Refer to Note 9 for further information on deferred tax liabilities.

Impairment of E&E assets

Management is required to assess E&E 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. 

Following this review, Management assessed the Block 23 E&E asset to be impaired and has recorded an impairment loss of $0.5 million in the Consolidated Statement of Profit or Loss and Other Comprehensive Income.

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 2026, management did not note any impairment indicators on any other blocks that would result in a full impairment review to be undertaken. 

The Directors judgement was that, with the exception of Block 23, a full impairment review wasn't required.

Refer to Note 11 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.

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 provision

The provision for 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 the contingent consideration provision to changes in the probabilities of the scenarios and to the discount rates is disclosed in Note 22.

The value of the contingent consideration provision as at 31 December 2025 was $13.5 million (2024: $29.9 million).

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 Company's intercompany receivable balance is $30.1 million after an ECL allowance of $18.8 million. During the year the Company impaired its intercompany loan receivable from Afentra (East Africa) Limited by $9.4 million and reversed a $20.0 million historical credit loss from 2024 relating to Afentra (UK) Limited. Both the impairment and reversal of impairment are eliminated on consolidation and do not impact the Group results.

Refer to Note 15 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.  

During the year the Company impaired its $1.9 million investment in Afentra (UK) Limited. This impairment is eliminated on consolidation and does not impact the Group results.

Refer to Note 13 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 2025 was 61% Trafigura and 39% Maurel & Prom (2024: 33% and 67% respectively).

4.       Cost of sales 

	2025	2024
	$000	$000
Production costs (1)	50,547	79,880
Depletion of property, plant and equipment - oil and gas	21,936	12,571
Depletion absorbed into inventories	(3,827)	(241)
Losses on oil price derivatives	567	1,914
Total cost of sales	69,223	94,124

⁽¹⁾ Production costs are stated net of the $3.1 million (2024: $2.5 million) of processing fees recovered from Block 3/05 for its use of the Palanca Terminal.

All cost of sales relate to operations in Angola, Africa.

5.       Losses on disposal and impairments of intangible assets

	2025	2024
	$000	$000
Loss on disposal of intangible assets	19,505	-
Impairment of intangible assets	500	-

On 18 December 2025, the Group completed the transfer of its 34% non-operated participating interest in the Odewayne Block, Somaliland ("Odewayne") to Petrosoma Limited ("Petrosoma"), who have assumed all rights and obligations relating to Odewayne. The Group signed a settlement agreement with the Operator Genel Energy Somaliland Limited ("Genel") and received $1.97 million in respect of settling Genel's carry obligations to Afentra relating to Odewayne. As part of the same transaction, Genel has transferred its participating interest in the Production Sharing Agreement ("PSA") to Petrosoma. The transaction resulted in a $19.5 million loss on disposal. Afentra has no remaining rights or obligations relating to Odewayne including in respect of environmental or decommissioning obligations.

We review the carrying value of our intangible E&E assets when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. During 2025, we impaired our $0.5 million E&E asset relating to the Block 23 PSA in Angola due to the expected expiry of the licence in December 2026.

6.       Profit from operations 

		2025	2024
Profit from operations is stated after charging:	Note	$000	$000
Cost of sales	4	69,223	94,124
Staff costs	7	9,588	7,571
Depreciation of non-D&P assets	12	297	302
Impact of foreign exchange on profit		(30)	(63)
An analysis of auditor's remuneration is as follows:
Fees payable for the audit of the Group's annual accounts		418	294
Audit of the Company's subsidiaries pursuant to legislation		15	41
Total audit fees		433	335

Included in the fees payable for the audit of the Group's annual accounts is $63,000 related to 2024. No non-audit services were received.

7.       Employee information

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

	Group		Company
	2025	2024	2025	2024
Corporate	19	15	-	-
Non-Executive	3	3	3	3
	22	18	3	3

Group and Company employee costs during the year amounted to:

	Group		Company
	2025	2024	2025	2024
	$000	$000	$000	$000
Wages and salaries	6,212	4,766	262	272
Social security costs	947	1,483	1	13
Other pension costs	557	333	-	-
Share-based payments	1,872	989	-	-
	9,588	7,571	263	285

Key management personnel include Executive and Non-Executive Directors who have been paid $4.2 million (2024: $3.5 million). The highest paid Director in the current year received $1.4 million (2024: $1.2 million).

During 2025, the aggregate of all gains made by all Directors on the exercise of share options was $385k (2024: $5.1 million). The amount attributable to the highest paid Director was $160k (2024: $2.1 million).

A portion of the Group's staff costs and associated overheads are expensed as pre-licence expenditure ($1.3 million) or capitalised ($102k). In 2024, this amounted to $0.6 million and $46k  respectively.

8.       Finance income and costs

			2025	2024
			$000	$000
Finance income:
Interest earned on short-term deposits			33	106
Total finance income			33	106
			2025	2024
			$000	$000
Finance costs:
Interest on borrowings			4,485	5,684
Interest accretion on contingent consideration provision			2,309	2,305
Finance and arrangement fees			643	748
Interest expense for leasing arrangement			87	18
Bank charges			264	11
Fair value adjustment on contingent consideration provision			-	297
Other finance fees			(30)	(63)
Total finance costs			7,758	9,000

9.         Taxation

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

			2025	2024*
			$000	$000
Current tax
UK corporation tax at 25% (2024: 25%)			-	-
Foreign tax			7,087	11,564
Total current tax expense			7,087	11,564
Deferred income tax
Increase in deferred tax liability			9,859	1,661
Deferred tax expense			9,859	1,661
Income tax			16,946	13,225
Profit before tax			13,759	65,575
Tax on profit on ordinary activities at the Angolan Petroleum Income Tax rate of 50% (2024: 50%)*			6,880	32,788
Effects of:
Expenses not deductible / (income not taxable) for tax purposes			(148)	1,944
Utilisation of acquired cost pool subject to initial recognition exemption and uplift on capital investment			(9,647)	(30,668)
Tax losses carried forward			4,484	4,326
Effects of overseas tax rates			15,444	4,898
Other tax adjustments			(67)	(63)
Tax charge for the year			16,946	13,225

*2024 reconciliation has been restated at the Angolan rate of 50% instead of the UK rate of 25% to ensure better comparability with 2025. Utilisation of acquired cost pool subject to initial recognition exemption has been extracted from the Effects of overseas tax rates

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 related to carried forward UK tax losses of $160.5 million (2024: $140.1 million) and deductible temporary differences related to the excess of capital allowances over the carrying value property plant and equipment of $2.1 million (2024: $2.6m) in the United Kingdom. Neither of these tax attributes have an expiry date. No deferred tax asset has been recognised due to the uncertainty of future profit streams against which these losses could be utilised.

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 $11.5 million has been recognised during the year (2024: $1.7 million).

The following is the analysis of the recognised deferred tax balances (after offset) for financial reporting purposes:

			2025	2024
			$000	$000
Deferred tax liabilities
At 1 January			1,661	-
Deferred tax charge to the income statement for the year			9,859	1,661
At 31 December			11,520	1,661
Comprised of:
Temporary differences between the tax base and carrying value of D&P assets in Angola			11,520	1,661

10.     (Loss)/earnings per share

Earnings per share (EPS) 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. 

		2025	2024
		$000	$000
(Loss)/profit for the year		(3,187)	52,350
Weighted average number of ordinary shares in issue during the year (1)		224,788,003	224,922,157
(LPS)/EPS (US cents)		(1.4)	23.3
Total possible dilutive effect of share awards outstanding		25,157,151	23,488,622
Fully diluted average number of ordinary shares during the year		249,945,154	248,410,779
Diluted EPS (US cents)		(1.4)	21.1

⁽¹⁾ Weighted average number of ordinary shares in issue excludes 4.9 million own shares purchased during the year.

11.     Exploration and evaluation assets

			Group
			$000
Net book value at 1 January 2024			21,867
Additions			612
Net book value at 31 December 2024			22,479
Additions			830
Disposals			(21,477)
Impairments			(500)
Net book value at 31 December 2025			1,332

The Group's interests in intangible assets relating to oil exploration licences and the respective participating interests as at 31 December 2025 comprise:

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

-     Block KON 15 PSA, Angola: Afentra (Angola) Ltd 45%, Sonangol (Operator) 55%.

-     Block 3/24 RSC, Angola: Afentra (Angola) Ltd (Operator) 40%, M&P 40%, Sonangol 20% (carried during exploration phase).

During the year ended 31 December 2025, the Group completed the transfer of its 34% non-operated participating interest in the Odewayne Block, Somaliland ("Odewayne") to Petrosoma Limited ("Petrosoma") who have assumed all rights and obligations relating to Odewayne. The Group signed a settlement agreement with the Operator Genel Energy Somaliland Limited ("Genel") and received $1.97 million in respect of settling Genel's carry obligations to Afentra relating to Odewayne. As part of the same transaction Genel has transferred its participating interest in the PSA to Petrosoma. The transaction resulted in a $19.5 million loss on disposal. Afentra has no remaining rights or obligations relating to Odewayne including in respect of environmental or decommissioning obligations.

During the year the Group impaired its $0.5 million E&E asset relating to the Block 23 PSA in Angola.

12.     Property, plant and equipment

	Oil and gas assets	Office Lease	Computer and office equipment	Total
Group	$000	$000	$000	$000
Cost
At 1 January 2024	77,422	1,165	371	78,958
Acquisitions during the year	38,288	-	-	38,288
Additions during the year	29,645	769	81	30,495
At 31 December 2024	145,355	1,934	452	147,741
Additions during the year	61,981	188	188	62,357
Effect of changes in foreign exchange rates	-	58	32	90
At 31 December 2025	207,336	2,180	672	210,188
Accumulated depreciation
At 1 January 2024	(2,600)	(975)	(252)	(3,827)
Charge for the year	(12,571)	(217)	(85)	(12,873)
At 31 December 2024	(15,171)	(1,192)	(337)	(16,700)
Charge for the year	(21,936)	(192)	(105)	(22,233)
Effect of changes in foreign exchange rates	-	(2)	(24)	(26)
At 31 December 2025	(37,107)	(1,386)	(466)	(38,959)
Net book value at 31 December 2025	170,229	794	206	171,229
Net book value at 31 December 2024	130,184	742	115	131,041

The Group's oil and gas assets as at 31 December 2025 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 26.67%, Etu Energias 13.33%, and NIS-Naftagas 5.33%.

The right-of-use asset (office lease) is depreciated on a straight-line basis over the lease contract term. During 2025 the Group entered in a new lease on office space in Luanda, Angola. The lease term is for three years, ending in 2028. See Note 1 and Note 23 for further details.

13.     Investment in subsidiaries

						Company
						$000
At 1 January 2024						21,105
Additions during the year						989
Impairment						(1,954)
At 31 December 2024						20,140
Additions during the year						1,872
Reversal of impairment (1)						7,368
Return of capital (1)						(27,508)
Impairment						(1,872)
At 31 December 2025						-

⁽¹⁾ Following internal group restructurings during the year, a historical impairment on one of the Company's subsidiaries, Afentra (Northwest Africa) Limited (ANWA), was reversed. Subsequent to this impairment reversal, the Company received a distribution of $27.5 million from Afentra (Northwest Africa) Limited, representing a return of capital originally invested.

See Note 2 for further detail on the impairment assessment methodology. The subsidiary undertakings of the Group as at 31 December 2025 are listed below:

	Country of incorporation	Registration number	Class of shares held	Type of ownership	Proportion of voting rights held 2025	Proportion of voting rights held 2024	Nature of business
Afentra (UK) Limited (6)	United Kingdom (4)	04087253	Ordinary	Direct	100%	100%	Exploration for oil and gas
Afentra (Angola) Ltd (1)	United Kingdom (4)	14048343	Ordinary	Direct	100%	100%	Extraction of crude petroleum
Afentra (Northwest Africa) Limited	Jersey, CI (5)	85203	Ordinary	Direct	100%	100%	Exploration for oil and gas
Afentra Holdings Limited (2)	Jersey, CI (5)	85730	Ordinary	Indirect	100%	100%	Investment holding company
Afentra (East Africa) Limited (3)	Jersey, CI (5)	110371	Ordinary	Indirect	100%	100%	Exploration for oil and gas
Afentra (Offshore Developments) Ltd (6)	United Kingdom (4)	16082097	Ordinary	Direct	100%	100%	Extraction of crude petroleum
Afentra (Onshore Developments) Ltd (6)	United Kingdom (4)	09353584	Ordinary	Direct	100%	100%	Extraction of crude petroleum

⁽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⁾ Afentra (UK) Ltd, Afentra (Offshore Developments) Ltd and Afentra (Onshore Developments) Limited are each exempt from the requirements of the UK Companies Act 2006 relating to the audit of individual accounts by virtue of Section 479A Companies Act 2006.

14.     Inventories

		2025	2024
		$000	$000
Oil stock		16,830	1,415
Warehouse stock and materials		8,182	6,049
		25,012	7,464

Inventory is stated at the lower of cost and net realisable value. There were no write-downs of inventory during the year (2024: nil).

15.     Trade and other receivables

Current		Group		Company
		2025	2024	2025	2024
		$000	$000	$000	$000
Trade receivables		75	123	74	-
Amounts due from subsidiary undertakings		-	-	5,000	3,916
Underlift receivables		734	-	-	-
Joint venture receivables (1)		7,757	8,286	-	-
Deposit paid for asset acquisition		1,750	-	-	-
Other receivables		1,011	218	116	200
Prepayments and accrued income		296	1,991	150	51
Total current trade and other receivables		11,623	10,618	5,340	4,167

⁽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. During the year, the Group recognised an impairment credit loss allowance of $1.6 million (2024: nil).

Non-current				Company
				2025	2024
				$000	$000
Amounts due from subsidiary undertakings				25,139	14,109
Total non-current trade and other receivables				25,139	14,109

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 $18.8 million (2024: $29.1 million). Following the disposal of Odewayne in December 2025, the Company recognised a further allowance of $9.4 million on the Company's loan to Afentra (East Africa) Limited. This has been offset by a reversal of the $20.0 million historical credit loss from 2024 as a result of the restructuring of the Company's intercompany positions in 2025. 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 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).

16.     Cash and cash equivalents

		Group			Company
		2025	2024	2025		2024
		$000	$000	$000		$000
Cash at bank available on demand		5,141	46,877	3,590		8,267
Cash on hand		4	3	-		-
		5,145	46,880	3,590		8,267

17.     Restricted funds

Restricted funds as at 31 December 2025 relate to a $5.0 million (2024: $7.9 million) cash deposit held in the Debt Service Reserve Account (DSRA), as required by the Reserve Based Lending agreement, to be used for the next instalment of principal and interest payment due.

18.     Share capital

	Ordinary shares (10p)	$000
Authorised, called up, allotted and fully paid
At 1 January 2025	226,155,990	28,914
At 31 December 2025	226,155,990	28,914

As of 31 December 2025, 4.3 million of the above shares are held in the EBT (2024: nil).

19.     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. 

Own share reserve

The own shares reserve represents the cost of shares in the parent entity purchased in the market and held by the parent entity's EBT to satisfy options under the Group's share options plans. The number of ordinary shares held by the EBT at 31 December 2025 was 4.3 million (2024: nil).

		No. shares	$000
As at 1 January 2024		-	-
As at 31 December 2024		-	-
Purchased		4,902,426	3,106
Vested		(559,629)	(317)
As at 31 December 2025		4,342,797	2,789

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.

20.     Borrowings

The Group drew down on both the Reserve Based Lending (RBL) and Working Capital (WC) facilities in order to finance the INA, Sonangol, and Azule acquisitions in 2023 and 2024. As at 31 December 2025, the Group has principal outstanding of $31.5 million on the RBL and nil on the WC 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, tested biannually at each redetermination date, being 31 March and 30 September.

During the period, a waiver was sought and received for the Group Liquidity Test covenant. Subsequently, in May 2026, the Group has refinanced this facility and this covenant is no longer measured. Refer to Note 29 - Subsequent events for further details on the refinancing.

WC revolving committed credit facility

·      $30.0 million maximum based on prior month oil inventories on hand (100% undrawn as at 31 December 2025)

·      5-year tenor to May 2028

·      4.75% margin over 1-month SOFR

·      Repayable with proceeds from liftings 

		2025	2024
		$000	$000
Current
Reserve Based Lending facility		10,874	11,271
Working Capital facility		-	-
Total current borrowings		10,874	11,271
		2025	2024
		$000	$000
Non-current
Reserve Based Lending Facility		20,227	30,145
Total non -current borrowings		20,227	30,145

		2025	2024
		$000	$000
Borrowings
At 1 January		41,416	31,703
Loan drawdowns		2,400	35,748
Interest charge		4,485	5,684
Principal repayments		(12,905)	(27,364)
Interest paid		(4,882)	(4,942)
Amortisation of capitalised arrangement fees		587	587
At 31 December		31,101	41,416

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

Net (debt)/cash

The table below details our net (debt)/cash as at 31 December 2025 and 2024:

		2025	2024
		$000	$000
Cash and cash equivalents		5,145	46,880
Restricted funds		5,044	7,930
Borrowings		(31,101)	(41,416)
Lease liabilities		(914)	(782)
Net (debt)/cash		(21,826)	12,612

Changes in liabilities arising from financing activities  for the periods presented in this report were as follows:

	Borrowings	Leases	Total
At 1 January 2024	(31,703)	(155)	(31,858)
Financing cashflows	(35,748)	-	(35,748)
Lease payments	-	160	160
Loan repayments	27,364	-	27,364
Other changes (1)	(587)	(769)	(1,356)
Interest expense	(5,684)	(18)	(5,702)
Interest payments	4,942	-	4,942
At 31 December 2024	(41,416)	(782)	(42,198)
Financing cashflows	(2,400)	-	(2,400)
Lease payments	-	201	201
Loan repayments	12,905	-	12,905
Other changes (1)	(587)	(246)	(833)
Interest expense	(4,485)	(87)	(4,572)
Interest payments	4,882	-	4,882
At 31 December 2025	(31,101)	(914)	(32,015)

21.     Trade and other payables

	Group		Company
	2025	2024	2025	2024
	$000	$000	$000	$000
Trade payables	214	903	139	117
Joint venture balances (1)	48,440	47,529	-	11
Contract liability (2)	17,100	-	-	-
Amounts owed to subsidiary undertakings (3)	-	-	-	27,517
Income taxes payable	-	1,802	-	-
Social security and PAYE liabilities	188	143	-	-
Accruals	2,869	2,562	400	283
Total trade and other payables	68,811	52,939	539	27,928

⁽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.

⁽²⁾ Reflects proceeds received in advance for the sale of oil lifted on 21 January 2026. The remaining $16.7 million was received on 5 February 2026.

⁽³⁾ During the year the Company received a distribution of $27.5 million from its subsidiary ANWA representing a return capital originally invested. This distribution was recorded against the amounts owed by the Company to ANWA.

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.

22.     Contingent consideration provision

The movement in the contingent consideration provision during 2025 and 2024 is detailed in the table below:

Group $000 As at 1 January 2024 26,484 Asset acquisitions 5,437 Accretion of interest 2,305 Payments (4,621) Changes in fair value 297 As at 31 December 2024 29,902 Accretion of interest 2,309 Payments (5,544) Changes in fair value (13,235) As at 31 December 2025 13,432

The provision for contingent consideration is presented on the Consolidated Statement of Financial Position as:

		2025	2024
		$000	$000
Contingent consideration provision
Current		3,500	5,535
Non-current		9,932	24,367

The current portion of the provision for contingent consideration payable relates to amounts paid during the first quarter of 2026 based on thresholds met previously. Refer to Note 29 - 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 thresholds and a realised Brent price hurdle, subject to an annual cap of $2.0 million. During the year, the Group paid contingent consideration of $1.2 million to INA in respect of calendar year 2024 relating to Tranche 1. Tranche 1 has since expired and no further payments will become due.

·       Tranche 2 - Caco-Gazela and Punja (Development Milestones):

The contingent consideration for 3/05A is linked to the future development of the Caco-Gazela and Punja development areas.

Caco-Gazela Development Area:

The contingent consideration relating to the Caco-Gazela development area has now lapsed as the production threshold was not satisfied within the measurement period, with no payments due.

Punja Development Area:

The Punja contingent consideration is comprised off a one-of payment of $2.5 million, payable if:

·    first oil occurs before 2028,

·    cumulative production exceeds one million barrels within 24 months of first oil, and

·    the average Brent price for the preceding 12 months exceeds $65/bbl.

If these conditions are not satisfied, the entitlement lapses with no payment due. Based on the current stage of development, and expected timelines to first oil, the Group does not currently expect any contingent consideration to be payable in 2026.

SNL acquisition (2023): 

·       The contingent consideration for the SNL acquisition is payable annually over the next ten years from acquisition in each year where the 15,000 barrel of oil equivalent (BOE) average daily production hurdle is reached and the realised oil price exceeds $65/bbl. The maximum annual amount payable is $3.5 million, potentially resulting in a total maximum payment of $35 million over the ten years to 2032.

·       During the year, the Group paid contingent consideration of $3.5 million to Sonangol in relation to calendar year 2024. A further $3.5 million was paid during Q1 2026 in relation to calendar year 2025. 

Azule acquisition (2024):

·       Tranche 1:

The contingent consideration for the Azule acquisition related to oil price and Block 3/05 production hurdles for the 2023, 2024, and 2025 production years, subject to an annual cap of $7.0 million and an aggregate cap of $21.0 million (now completed). During the year, the Group paid contingent consideration of $0.9 million to Azule in respect of Tranche 1. Tranche 1 has since expired and no further payments will become due.

·       Tranche 2 - Block 3/05A Discoveries:

Further contingent consideration of up to $15 million is linked to the future development of the Caco-Gazela and Punja discoveries.

Caco-Gazela Discovery:

On the Caco-Gazela Trigger Date (12 months following recommencement), a payment of $7.5 million will become payable if:

·    the average Brent price for the preceding 12 months is at or above $75/bbl, and

·    average daily production exceeds 5,000 BOE per day.

Punja Discovery:

On the Punja Trigger Date (12 months following first oil), a payment of $7.5 million will become payable if:

·    the average Brent price for the preceding 12 months is at or above $75/bbl, and

·    average daily production exceeds 5,000 BOE per day.

If these conditions are not satisfied, the relevant contingent consideration lapses with no payment due. Based on the current stage of development of the relevant Block 3/05A discoveries, and expected timelines to first oil and recommencement, the Group does not currently expect any contingent consideration to be payable in respect of Tranche 2 in 2026.

These contingent payments are measured at fair value and changes in fair value are recognised in profit or loss.

Management have reviewed the contingent payments related to the above acquisitions, which are dependent upon production levels, future oil price hurdles, and future 3/05A developments. Judgement has been applied to the probability of the circumstances occurring that would give rise to some or all of the future payments. For each tranche of contingent consideration Management have applied a multiple scenario approach to each tranche along with the related weightings of probability resulting in an expected amount payable. The base case scenario, which has the greatest weighting is based on the Brent forward curve at year end, with an average oil price of $60/bbl in 2026, $61/bbl in 2027, and $62/bbl in 2028. 

Management has applied a discount rate that approximates to the incremental borrowing rate in arriving at a present value at the balance sheet date of the probable future liabilities. The discount rate is based on a market rate of 10.4% (2024: 9.1%). 

Applying Management's judgements discussed above, has resulted in an estimated fair value of the contingent consideration provision of $13.4 million at year end (2024: $29.9 million). A 2% increase in the discount rate would result in a reduction in the contingent consideration liability of $0.8 million. A 2% decrease in the discount rate would result in an increase in contingent consideration provision of $0.9 million. The impact of removing the scenarios that have an expectation the realised Brent price hurdles will not be met in the long term (5% original weighting) and including a relative increase in the base case scenarios would increase the contingent consideration provision by $0.3 million. In the event of a sustained low oil price scenario, where the average Brent oil price remains below $65/bbl, the non-current contingent consideration would be reversed. Subsequent to year end, there has been a significant increase in oil price forecasting. Using oil price forward curves observed in March and April 2026 would have resulted in an increase in the non-current provision for contingent liabilities of $6.6 million.

23.     Leases

During the year, the Group entered into a new lease on a local office in Luanda. The Group recognises a right-of-use asset in a consistent manner to its property, plant and equipment (see Note 12).

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 9.09%.

The depreciation charge in 2025 was $192k (2024: $217k) (see Note 12) with an interest expense in 2025 of $87k (2024: $18k) (see Note 8). Cash outflow of principal payments in 2025 was $114k (2024: $142k).

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

		2025	2024
		$000	$000
Current		240	97
Non-current		674	685
		914	782

Extension options will be 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 2025, the contractual maturities of the Company's lease liabilities are as follows:

	Within one year	Between one to two years	Over two years	Total	Interest	Carrying amount
	$000	$000	$000	$000	$000	$000
Group
Lease liability	336	319	426	1,081	(167)	914

24.     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 material 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 2025 and 31 December 2024.

		Carrying amount
		2025	2024
Group		$000	$000
Financial assets at amortised cost
Cash and cash equivalents		5,145	46,880
Restricted funds		5,044	7,930
Trade and other receivables		9,577	8,627
Total		19,766	63,437
Financial liabilities at amortised cost
Trade and other payables		68,811	52,939
Borrowings due within one year		10,874	11,271
Non-current borrowings		20,227	30,145
Total		99,912	94,355

Of the above assets and liabilities, due to the short-term nature, carrying amounts approximate their fair values at 31 December 2025 and 31 December 2024 except for non-current borrowings, for which the fair value is based upon a market rate of 10.4% and resulting in a fair value of $20.1 million (2024: $34.7 million) against the carrying amount of $20.2 million (2024: $30.1 million).

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

		Fair value
		2025	2024
Group		$000	$000
Financial assets at fair value
Derivative hedge assets		225	196
		2025	2024
Financial liabilities at fair value		$000	$000
Derivative hedge liabilities		-	1,279
Contingent consideration provision		13,432	29,902
Total		13,432	31,181

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 22 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 to manage oil price volatility. 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: 

	Increase		Decrease
	2025	2024	2025	2024
	$000	$000	$000	$000
Cash and cash equivalents	51	469	(51)	(469)
Borrowings	(311)	(414)	311	414

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 by currency:

Financial assets

		Group
		2025	2024
		$000	$000
Cash and cash equivalents
- US$		4,6700	45,951
- GBP		376	885
- EUR		2	1
- AOA		97	43
		5,145	46,880

		Group
		2025	2024
		$000	$000
Trade and other receivables
- US$		11,117	8,549
- GBP		210	78
		11,327	8,627

Financial liabilities

		Group
		2025	2024
		$000	$000
Trade and other payables
- US$		66,533	50,854
- GBP		2,065	1,867
- EUR		207	217
- AOA		6	1
		68,811	52,939

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 95% (2024: 98%) of its cash in US dollars. These balances are held with 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. Apart from derivative hedge assets there are no financial assets held at fair value.

The Group's maximum exposure to credit risk is $21.7 million (31 December 2024: $65.4 million), based on our cash and cash equivalents, restricted funds, 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.

Joint venture receivables are subject to the expected credit loss model. The Group applies the IFRS 9 simplified approach to measuring expected credit losses which uses a lifetime expected loss allowance for joint venture receivables. We estimate expected credit losses based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts of events which may affect the collectability.  The allowance for credit losses reflects the net amount expected to be collected. Any change in credit allowance is reflected in the Consolidated Statement of Operations. Amounts are written off against the allowance in the period when efforts to collect a balance have been exhausted. Any write-offs in excess of credit allowance by category of financial asset reduces the asset's carrying amount and is reflected in the Consolidated Statement of Operations.

The movement in the expected credit loss allowance during 2025 and 2024 is detailed in the table below:

	Group
	$000
As at 1 January 2024	-
As at 31 December 2024	-
Increase in loss allowance recognised in profit or loss	1,616
As at 31 December 2025	1,616

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

	Less than six months	Six months to one year	One to six years	Total	Interest	Principal
	$000	$000	$000	$000	$000	$000
Group
As at 31 December 2025
Non-derivative financial liabilities:
Borrowings	7,144	6,837	23,917	37,898	6,383	31,515
Trade and other payables	214	65,728	-	65,942	-	-
Derivative financial instruments:
Contingent consideration	3,500	-	15,350	18,850	-	-
Forward foreign exchange contracts - outflow	-	-	-	-	-	-
Forward foreign exchange contracts - inflow	(225)	-	-	(225)	-	-
	10,633	72,565	39,267	122,465	6,383	31,515
As at 31 December 2024
Non-derivative financial liabilities:
Borrowings	7,930	7,608	38,292	53,830	11,810	42,020
Trade and other payables	1,046	47,529	-	48,575	-	-
Derivative financial instruments:
Contingent consideration	5,535	-	34,851	40,386	-	-
Forward foreign exchange contracts - outflow	1,279	-	-	1,279	-	-
Forward foreign exchange contracts - inflow	(196)	-	-	(196)	-	-
	15,594	55,137	73,143	143,874	11,810	42,020

25.       Share-based payments

The table below details the movement in share option reserve:

		2025	2024
		$000	$000
At 1 January		842	965
Arising in the year		1,872	989
Options exercised		(597)	(1,112)
At 31 December		2,117	842

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 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:

Award date	2022
Weighted average share price at grant date	£0.15
Exercise price	nil
Risk free rate	1.88%
Dividend yield	0%
Volatility of Company share price	44%

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 2025 is 2.5 months.

At 31 December 2025 no options were exercisable.

During 2024 and 2025 the first and second measurement dates were reached and 20,470,160 and 1,440,448 nil cost options were vested and exercised respectively. 50% of each award was vested and exercised immediately. The share price at time of exercise was £0.39 in 2024 and £0.40 in 2025. The remaining 50% is expected to vest on the third measurement date, in 2026.

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

		2025	2024
		No.	No.
At 1 January		11,770,320	22,005,400
Exercised		(720,224)	(10,235,080)
At 31 December		11,050,096	11,770,320

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.

	2022		2023		2024			2025
Award date	1 Nov	30 Sep, 3 Oct	1 Mar	6 and 13 Dec	20 Feb, 1 Mar	24 Oct	19 Dec	6 Jan	3 Feb	1 Mar
Weighted average share price at grant date	£0.30	£0.30	£0.28	£0.30	£0.39	£0.50	£0.49	£0.46	£0.50	£0.46
Risk free rate	4.20%	4.23%	3.75%	3.92%	4.12%	3.87%	4.21%	4.25%	4.03%	4.02%
Dividend yield	0%	0%	0%	0%	0%	0%	0%	0%	0%	0%
Volatility of Company share price	54%	54%	55%	54%	52%	52%	52%	51%	51%	51%
Weighted average fair value	£0.16	£0.16	£0.15	£0.16	£0.21	£0.27	£0.25	£0.25	£0.25	£0.22

	2025
Award date	3 Mar	11 Mar	1 Apr	15 Jul (1)	15 Jul (2)	15 Jul (3)	1 Oct	16 Oct	1 Dec
Weighted average share price at grant date	£0.46	£0.44	£0.40	£0.46	£0.41	£0.41	£0.51	£0.47	£0.44
Risk free rate	4.05%	4.04%	4.04%	3.70%	3.89%	3.72%	3.81%	3.67%	3.62%
Dividend yield	0%	0%	0%	0%	0%	0%	0%	0%	0%
Volatility of Company share price	51%	51%	52%	42%	n/a	n/a	43%	43%	42%
Weighted average fair value	£0.21	£0.18	£0.23	£0.25	£0.51	£0.51	£0.21	£0.17	£0.03

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:

		2025	2024
		No.	No.
At 1 January		2,024,494	2,774,439
Granted		2,113,263	1,059,036
Forfeited		(130,835)	(557,521)
Exercised		(360,000)	(1,251,460)
At 31 December		3,646,922	2,024,494

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

The weighted average remaining contractual life as at 31 December 2025 is 15 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.

Award date		2025	2024
Weighted average share price at grant date		£0.42	£0.57
Exercise price		Nil	nil
Risk-free rate		4.07%	4.05%
Dividend yield		0%	0%
Volatility of Company share price		52%	49%
Fair Value per award		£0.19	£0.27

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.

		2025	2024
		No.	No.
At 1 January		3,228,373	-
Granted		4,356,560	3,228,373
At 31 December		7,584,933	3,228,373

The weighted average exercise price of outstanding options is nil.

The weighted average remaining contractual life as at 31 December 2025 is 23 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.

Award date			2024
Weighted average share price at grant date			£0.57
Exercise price			£0.57
Risk free rate			3.92%
Dividend yield			0%
Volatility of Company share price			53.3%
Fair Value per award			£0.31

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.

		2025	2024
		No.	No.
At 1 January		4,500,000	-
Granted		-	4,500,000
Forfeited		(1,050,750)	-
At 31 December		3,449,250	4,500,000

The weighted average exercise price of outstanding options is nil.

The weighted average remaining contractual life as at 31 December 2025 is 18 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.

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:

	Group		Company
	2025	2024	2025	2024
	$000	$000	$000	$000
Short-term employee benefits	2,502	2,521	278	351
Defined contribution pension	146	128	-	-
Share-based payments	1,522	897	498	275
	4,170	3,546	776	626

The Executive Directors (three) exercised share options during the year.

The Company's subsidiaries are listed in Note 13. The following table provides the balances which are outstanding with subsidiary undertakings at the balance sheet date: 

		2025	2024
		$000	$000
Amounts due from subsidiary undertakings		30,139	18,025
Amounts due to subsidiary undertakings		-	(27,517)

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 4.9% in 2025 (2024: 5.6%). During the year the Company recognised interest receivable from Afentra (Angola) Limited of $0.2 million (2024: $0.8 million).

In 2025, the Company's subsidiary Afentra (Angola) Limited provided guarantee over the amount due from another subsidiary, Afentra (UK) Limited, to the Company.

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

27.       Derivative assets and liabilities

		2025	2024
		$000	$000
Derivative assets		225	196
Derivative liabilities		-	(1,279)

The company manages its exposure to oil price risk through commodity price hedging. In 2025, Afentra hedged approximately 86% of its sales volumes through a combination of put options and collar structures. The hedge portfolio comprised put options with strike prices between $60 and $65 per barrel, covering 86% of sales volumes, and call options with strike prices between $80 and $89 per barrel, covering 56% of sales volumes. Currently, approximately 44% of 2026 projected sales are hedged using a combination of put options with strike prices ranging from $60/bbl to $68/bbl and collar structures with call options ranging from $78/bbl to $92/bbl. The hedging programme will continue to be under active review to seek further opportunities to increase the programme.

28.       Commitments and contingencies

Pre-funded decommissioning liabilities

The Group has a pre-funded liability to settle the future decommissioning obligation associated with Block 3/05. 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 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.

Parent company guarantee

The Parent Company has provided a guarantee over the debt of Afentra (Angola) Limited as well as a guarantee under Section 479C of the UK Companies Act 2006 for exemption from statutory audit for the following companies: Afentra (UK) Limited; Afentra (Onshore Developments) Limited; and Afentra (Offshore Developments) Limited.

Capital commitments

Under the terms of exploration licenses in Angola, the Group has committed to undertake minimum work programs which consist of seismic acquisition, geological studies, and exploration drilling. As of 31 December 2025, the Group's share of minimum exploration expenditures amounted to $6.5 million, expected to be incurred over the next two exploration phases (2026-2030).

29.       Subsequent events

Contingent resource upgrade

On 13 January 2026, Afentra announced a material upgrade to its contingent resources following an independent audit and internal assessment. This resulted in a more than fourfold increase in net working interest 2C contingent resources to 87.3 mmboe (gross 302.6 mmboe). The upgrade incorporates discoveries on Blocks 3/05 & 3/05A and a new assessment of the recently awarded Block 3/24, demonstrating the significant organic growth potential across the portfolio.

Competent person's report update

 On 5 February 2026 post-period, Afentra announced the results of its latest independent reserves report for its Angolan assets. As of 31 December 2025, total net 2P working interest reserves stand at approximately 31.9 mmbo (vs 34.2 mmbo as of 31 December 2024). Reserve additions in 2025 broadly offset production of 7.5 mmbo, contributing to a 3-year average reserve replacement ratio of 94%, reflecting sustained reserve replacement despite ongoing production without infill drilling.

Contingent consideration

On 17 March 2026, the Group made a contingent consideration payment of $3.5 million to Sonangol.

Debt repayments

On 31 March 2026, the Group made an interest only redetermination payment on its RBL facility of $1.9 million.

Debt refinancing

In May 2026, Afentra entered into a prepayment financing arrangement with a subsidiary of Gunvor Group for up to US$125 million, structured in two tranches and with a four-year tenor. The first tranche of $100 million is immediately available and a committed facility; the second tranche of $25 million is subject to further conditions precedent. The facility will replace the Company's existing debt facilities and is secured against future crude oil deliveries from its Angolan assets, with repayment primarily effected through cargo liftings. Proceeds are intended to support refinancing of existing arrangements and to fund ongoing capital and operational expenditure across the portfolio.

Sonangol joins Etu transaction

Post-period Sonangol joins the transaction to acquire interests from Etu Energias. As a result, Afentra will acquire a 3.33% interest in Block 3/05 and a 3.66% interest in Block 3/05A, with completion expected in Q2 2026. This development enhances alignment within the Joint Venture partnership. Post-completion, Afentra's interest will increase to 33.33% in Block 3/05 and 24.99% in Block 3/05A.

Block 3/05 accelerated drilling programme

Post-period, the Company announced that a rig opportunity provided by Sonangol allowed the Joint Venture to accelerate the planned two-well drilling programme on Block 3/05. The programme commenced with the Pacassa SW exploration well, marking the start of the execution phase of the Company's organic growth strategy.

Share purchase programme

Since 31 December 2025, the Company purchased approximately 0.4 million shares on AIM through the EBT, with a weighted average share price of £0.47, to satisfy the requirements of the employee LTIP and final 2026 FSP vesting.

Maintaining financial discipline in a volatile market

Escalating geopolitical tensions in the Middle East have increased volatility in global energy markets. The Board is monitoring the situation closely, which reinforces the importance of the Company's disciplined financial strategy and approach to risk management.

GLOSSARY

Term	Definition
$	US dollars
2D	Two dimensional
2C	Denotes best estimate of Contingent Resources
2P	Denotes the best estimate of Reserves. The sum of Proved plus Probable Reserves
ACREP	ACREP Exploração Petrolífera SA
AIM	AIM, a SME Growth market of the London Stock Exchange
AGM	Annual General Meeting
ALNG	Angola LNG (gas export network)
ANPG	Agência Nacional de Petróleo, Gás e Biocombustíveis (holder of the mining rights of Exploration, Development and Production of liquid and gaseous hydrocarbons in Angola)
BCF	Billion Cubic Feet
Block 3/05	The contract area described in and covered by the Block 3/05 PSA
Block 3/05A	The contract area described in the Block 3/05A PSA
Block 3/24	The contract area described in the Block 3/24 RSC
Block 23	The contract area described in and covered by the Block 23 PSA
Board	The Board of Directors of the Company
bopd	Barrels of oil per day ('k-' / 'mm-' for thousand / million)
bwpd	Barrels water injected per day
Company	Afentra plc
Companies Act	The Companies Act 2006, as amended 2006
CPR	Competent Persons Report
Directors	The Directors of the Company
ECL	Expected credit loss
E&E	Exploration and evaluation assets
E&P	Exploration and production
eFTG	enhanced Full Tensor Gravity Gradiometry
EDLTIP	Executive Director Long-term Incentive Plan
E&P	Exploration and production
EPS/LPS	Earnings/loss per share
EBITDAX (Adjusted)	Earnings before interest, taxation, depreciation, total depletion and amortisation, impairment and expected credit loss allowances, share-based payments, provisions, and pre-licence expenditure. Additionally, in any given period, significant, unusual or non-recurring items may be excluded from EBITDAX (Adjusted) for that period.
Entitlement Reserves	Entitlement production/reserves refers to the share of oil/gas that a company is entitled to receive based on fiscal and contractual agreements governing the specific asset.
ESG	Environmental, Social and Governance
ESP	Electrical Submersible Pumps
FID	Final investment decision
FSO	Floating storage and offloading
FSP	Founders' Share Plan
FTSE	Financial Times Stock Exchange
G&A	General and administrative
GAAP	Generally Accepted Accounting Principles (referenced alongside IFRS)
GBP	Pounds sterling
G&G	Geological and geophysical
GHG	Greenhouse gases
GIIP	Gas initially in place
GOR	Gas Oil Ratio
GPQ	Golungo-Palanca NE-Quissama
GRI	Global Reporting Initiative
Group	Afentra plc and its subsidiary undertakings
hydrocarbons	Organic compounds of carbon and hydrogen
HSE	Health, Safety and Environment
HWO	Heavy Workover
IAS	International Accounting Standards
IEA	International Energy Agency
IFC	International Finance Corporation
IFRS	International Financial Reporting Standards
IOC	International oil company
IPIECA	International Petroleum Industry Environmental Conservation Association
JV	Joint venture
JOA	Joint operating agreement
k	Thousands
km	Kilometre(s)
km2	Square kilometre(s)
KON	Kwanza Onshore
KPI	Key performance indicators
lead	Indication of a potential exploration prospect
LDAR	Leak Detection and Repair
LiDAR	Light Detection and Ranging
LNG	Liquefied Natural Gas
LSE	London Stock Exchange
LTIP	Long-term incentive plan
LWI	Light Well Intervention
M&A	Mergers and acquisitions
M&P	Maurel & Prom (JV partner on Blocks 3/05 and 3/05A)
m	Metre(s)
mmbo	Million barrels of oil
mmboe	Million barrels of oil equivalent
mmcfd	Million cubic feet per day
MUFG	MUFG Corporate Markets (Company Registrar)
MVO	Market Value Options
NED	Non-Executive Director
NEDP	Non-Executive Director Option plan
NIS	NIS Naftagas (JV partner on Blocks 3/05 and 3/05A)
O&G	Oil and gas
OIW	Oil in water
Op.	Operator
OPEC	Organisation of the Petroleum Exporting Countries
Opex	Operating expenditure
Opex/bbl	Gross operating cost / Gross production
Ordinary Shares	ordinary shares of 10 pence each
Petroleum	Oil, gas, condensate and natural gas liquids
Petrosoma	Petrosoma Limited (JV partner in Somaliland)
Plc	Public limited company
Prospect	An area of exploration in which hydrocarbons have been predicted to exist in economic quantity. A group of prospects of a similar nature constitutes a play.
PSA	Production sharing agreement
PWTS	Produced Water Treatment System
QCA Code	QCA (Quoted Companies Alliance) Corporate Governance Code 2023
RBL	Reserve-Based Lending
Reserves	Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must satisfy four criteria; they must be discovered, recoverable, commercial and remaining based on the development projects applied. Reserves are further categorised in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterised by development and production status
RSC	Risk Service Contract
SASB	Sustainability Accounting Standards Board
SDGs	Sustainable Development Goals
SECR	Streamlined Energy and Carbon Reporting
SPA	Sale and Purchase Agreement
Seismic	Data, obtained using a sound source and receiver, that is processed to provide a representation of a vertical cross-section through the subsurface layers
Shares	10p ordinary shares
Shareholders	Ordinary shareholders of 10p each in the Company
STOIIP	Stock tank oil initially in place
Subsidiary	A subsidiary undertaking as defined in the 2006 Act
Sonangol	Sonangol Pesquisa e Producao S.A.
Sonangol EP	Sociedade Nacional de Combustíveis de Angola, Empresa Pública
TBC	To be confirmed
TSR	Total Shareholder Return
TTL	Through tubing logging
United Kingdom or UK	The United Kingdom of Great Britain and Northern Ireland
Working Interest or WI	A Company's equity interest in a project before reduction for royalties or production share owed to others under the applicable fiscal terms

---

^([1]) During the reporting period, the items recognised in OCI did not give rise to any current or deferred tax effects

 

END