REG - Afentra PLC - FY2025 Annual Results and Corporate Update
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RNS Number : 1365E 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 & Revenue(1):
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
(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
(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 +44 (0)20 7405 4133
Paul McDade, CEO
Anastasia Deulina, CFO
Christine Wootliff, Investor Relations
Burson Buchanan (Financial PR) +44 (0)20 7466 5000
Bobby Morse
Barry Archer
George Pope
Stifel Nicolaus Europe Limited (Nominated Adviser and Joint Broker) +44 (0) 20
7710 7600
Callum Stewart
Simon Mensley
Ashton Clanfield
Tennyson Securities (Joint Broker) +44 (0)20 7186 9033
Peter Krens
-------------------------
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
(https://url.uk.m.mimecastprotect.com/s/iIb8CM8yMs25LVskhnS8t1eC/) or by
visiting the Afentra's Curation Showcase
(https://url.uk.m.mimecastprotect.com/s/m1Q9CNkzNfZNQ5Hji5SyCzDb) .
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 810km(2). 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 km(2) 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 (3,283) 52,315
the parent
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 Currency Share Own shares Retained Total
capital
translation
option
reserve
earnings
reserve
reserve
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 - (35) - - 52,350 52,315
the parent
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 Share Own shares reserve Retained Total
capital
option
earnings
reserve
$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 6,880 32,788
of 50% (2024: 50%)*
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 (9,647) (30,668)
uplift on capital investment
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 11,520 1,661
assets in Angola
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 Proportion of Nature of business
voting rights held 2025 voting rights held 2024
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
(#_ftnref1) (( 1 )) During the reporting period, the items recognised in OCI
did not give rise to any current or deferred tax effects
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