REG - Afentra PLC - Final Results
24/04/2025 07:02
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RNS Number : 0172G Afentra PLC 24 April 2025
24 April 2025
AFENTRA PLC
UNAUDITED ANNUAL RESULTS FOR THE YEAR ENDED 31 DECEMBER 2024
Afentra plc ("Afentra" or the "Company") (AIM: AET), the upstream oil and gas
company focused on acquiring production and development assets in Africa,
announces its unaudited annual results for the year ended 31 December 2024.
2024 SUMMARY
Key Highlights
• Azule acquisition: completed in May 2024, increasing interest
in Blocks 3/05 (30%) and 3/05A (21.33%).
• Onshore Kwanza basin: secured Blocks KON15 (45%) and KON19
(45%).
• 2024 Net Average Production: 6,229 bopd
• Reserve replacement: 140% replacement with year-end 2P
reserves of 34.2 mmbo
• Oil Sales: four crude liftings generating revenue of $180.9
million.
• Year-End Net Cash Position: $12.6 million with cash balance of
$54.8 million.
Financial and Risk Management Highlights
• Revenue of $180.9 million
• Year-end cash of $54.8 million; net cash position of $12.6
million.
• Borrowings of $41.4 million; total debt / adjusted EBITDAX
0.5x.
• Adjusted EBITDAX of $90.9 million and profit after tax of
$49.8 million.
• Four liftings totaling 2.3 mmbbls, average price of $82.2/bbl
• Placed 2025 hedge programme with ~68% of sales volumes hedged:
combination of $60-65/bbl floors and calls with $80-89/bbl caps.
Operational Highlights
• Block 3/05 and 3/05A gross average production 21,111 bopd
(2023: 20,180 bopd).
• 40 light well interventions (LWIs) delivered 2,000 bopd.
Increased programme planned for 2025.
• Reserve replacement since last CPR of 140% for Block 3/05, as
a result of the LWI programme, increased water injection and infrastructure
optimisation.
• Three year re-development plan launched in 2024, $150 million
gross (Net: $39 million) 1 (#_ftn1) invested in production optimisation, life
extension and emissions reduction. 2025 spend of $180 million (Net: $54
million).
• Successful completion of a 21-day maintenance shutdown in
October enabled key upgrades to power systems, subsea infrastructure and
installation of gas and water metering.
• Water injection capacity significantly enhanced post shutdown,
reaching rates of over 80,000 bwpd. A third pump is scheduled for installation
in 2025, targeting water injection rates of 150,000 bwpd.
• Installation of gas metering to support accurate measurement,
flare reduction and export planning.
• Planning progressed to prepare for first rig related
activities in 2026 and 2027.
• Onshore Kwanza Basin Blocks KON15 and KON19 secured with 45%
non-operated interests. Basin-wide eFTG survey commenced in 2024 and is due to
complete in 2025.
• Initiated support for The HALO Trust's landmine clearance work
in Angola.
Post year-end Summary
• Gross Block 3/05 and Block 3/05A production for Q1 2025
averaged 22,120 bopd (Net: ~6566, bopd).
• Crude lifting of ~466,000 bbls sold at $74.7/bbl, generating
pre-tax sales revenue of $34.8 million.
• Net cash at end of Q1 2025 of around $9.8m with crude oil
stock of around 68,000 bbls.
• Formal signing of onshore Kwanza block KON 15 on 7th April
2025.
• Acquired 381,719 shares in the market through Employee Benefit
Trust to fulfil recent Executive share awards, thereby avoiding issuance of
new shares.
Strategic Focus for 2025
• Continued focus on value driven M&A in Angola and wider
West Africa region.
• Investments in Block 3/05 and Block 3/05A and active JV
partner collaboration to drive:
o progress infrastructure upgrades, increase water injection rates and
deliver well interventions to continue to increase production and improve
asset performance.
o plan for 2026 rig activities to deliver step change in production
performance and continue to deliver reserves replacement.
o continue sustainability initiatives to reduce emissions and deliver gas
export.
• Consolidate position in Onshore Kwanza Basin and complete
evaluation of basin potential.
• Optimise crude offtake, hedging programme, focus on costs and
strengthen corporate balance sheet.
• Continue to purchase shares in the market through Employee
Benefit Trust to meet the requirements of the FSP awards due March 2026, of
around 6.5 million shares.
Paul McDade, Chief Executive Officer, commented:
"2024 marked a year of transformative growth and strategic progress for
Afentra, as we truly established ourselves as an active partner in Angola's
oil and gas industry. With ownership of our offshore assets in place, we were
able to embed ourselves operationally, build strong relationships with our
joint venture partners, and demonstrate the value we can bring as a
technically engaged and commercially disciplined non-operator. Afentra is
fully supporting the operator, taking a long-term approach to maximising value
from the assets through upgrades to asset integrity, production optimisation,
and emissions reduction. We are already seeing tangible results from these
redevelopment activities in enhanced production and reserves.
Opening our Luanda office and appointing an Angola-based Country Manager
reflect our long-term commitment to the country and its energy sector. Further
expanding our footprint, we secured new onshore opportunities through the
award of KON15 and KON19 in an under-exploited yet proven hydrocarbon basin.
Importantly, we've also transformed our balance sheet-generating strong cash
flow and ending the year with a net cash position-laying the foundation for
disciplined growth ahead."
YE 2024 Results Presentation:
https://afentraplc.com/wp-content/uploads/2025/04/2025.04-Afentra-YE-2024-Results-Presentation.pdf
(https://afentraplc.com/wp-content/uploads/2025/04/2025.04-Afentra-YE-2024-Results-Presentation.pdf)
For further information contact:
Afentra plc +44 (0)20 7405 4133
Paul McDade, CEO
Anastasia Deulina, CFO
Christine Wootliff, Investor Relations
Burson Buchanan (Financial PR) +44 (0)20 7466 5000
Ben Romney
Barry Archer
George Pope
Stifel Nicolaus Europe Limited (Nominated Adviser and Joint Broker) +44 (0) 20
7710 7600
Callum Stewart
Simon Mensley
Ashton Clanfield
Tennyson Securities (Joint Broker) +44 (0)20 7186 9033
Peter Krens
About Afentra
Afentra plc (AIM: AET) is an upstream oil and gas company focused on
opportunities in Africa. The Company's purpose is to support a responsible
energy transition in Africa by establishing itself as a credible partner for
divesting IOCs and Host Governments. Offshore Angola, Afentra has a 30%
non-operated interest in the producing Block 3/05 and a 21.33% non-operated
interest in the adjacent development Block 3/05A in the lower Congo basin and
a 40% non-operating interest in the exploration Block 23 in the Kwanza basin.
Onshore Angola, Afentra has a 45% non-operated interest in the prospective
Blocks KON15 and KON19 located in the western part of the onshore Kwanza
basin. Afentra also has a 34% carried interest in the Odewayne Block onshore
southwestern Somaliland.
Standard
Estimates of reserves and resources have been prepared in accordance with the
June 2018 Petroleum Resources Management System ("PRMS") as the standard for
classification and reporting.
Technical Information
The technical information contained in this announcement has been reviewed and
approved by Robin Rindfuss, Head of Sub-Surface at Afentra plc. Robin Rindfuss
has over 30 years of experience in oil and gas exploration, production and
development. He is a member of the Society of Petroleum Engineers (SPE) and
holds a Bachelor of Science (BSc) and a Bachelor of Science Honours (BSc Hons)
in Physics and Mathematics from the University of Cape Town.
Inside Information
This announcement contains inside information for the purposes of article 7 of
Regulation 2014/596/EU (which forms part of domestic UK law pursuant to the
European Union (Withdrawal) Act 2018) and as subsequently amended by the
Financial Services Act 2021 (UK MAR). Upon publication of this announcement,
this inside information (as defined in UK MAR) is now considered to be in the
public domain. For the purposes of UK MAR, the person responsible for
arranging for the release of this announcement on behalf of Afentra is Paul
McDade, Chief Executive Officer.
( )
ChIEF EXECUTIVE OFFICER's Statement
Delivering Value Driven Growth
Introduction
2024 has been a period of transition in which we completed the third of our
production acquisitions in Angola and have started to make material progress
in enhancing the production and reserves from the assets acquired. In
addition, we have expanded our portfolio with new opportunities onshore Angola
which we identified as we further embedded ourselves as a leading Independent
in the evolving landscape of Angola's upstream industry.
The completion of the Azule transaction in May was a watershed moment for
Afentra and provided us with the opportunity to articulate the true
value-accretive nature of these inaugural deals. The fact that we were able
to construct our current portfolio, underpinned by robust cash flow, proven
reserves and material upside, for less than $10m net outflow reflects our
mantra of Value Driven Growth, whereby we seek to grow the business
responsibly alongside an unwavering focus on delivering shareholder value.
Realising the upside
Our focus on value creation is not exclusive to our shareholders but extends
to our broader stakeholders. The completion of the Azule transaction in May
increased Afentra's equity interest by 12%, resulting in a material position
in the high-quality Blocks 3/05 and Block 3/05A. As per our stated business
model, the assumption of a meaningful non-operated interest in any asset
brings a duty to support the Operator and partners in enhancing the value of
our shared assets. A core point of difference at Afentra is the breadth and
depth of our technical expertise. We are working closely with the Operator,
Sonangol, to support them on the optimisation activities on Block 3/05 - as
well as tabling technical solutions to deliver meaningful long-term impact to
the sustainability performance of the assets.
The improved performance of the asset has been a key highlight for 2024 and
has validated our technical view that these assets will provide material scope
for production optimisation for decades to come. The 15-year runway provided
to the Joint Venture partners by the licence extension out to 2040 ensures we
have visibility and confidence in our ability to extract additional value from
the nine producing fields and three discoveries that these diverse and
large-scale blocks contain. The redevelopment works at Block 3/05, along
with well interventions, have resulted in improved production and water
injection performance, and we believe the continuation of the asset
improvement work programme in the coming year will continue this
trajectory.
Block 3/05 and Block 3/05A gross average production has increased from 20,180
bopd (2023) to 21,111 bopd for 2024, an increase of 5%. A successful
maintenance shutdown was delivered that focused on the long-term asset
reliability and integrity which will serve the partnership as we deliver the
next stage of Block 3/05 and Block 3/05A redevelopment. The work performed
in the shutdown has already had a positive impact on water injection resulting
in rates exceeding up to 80,000 bwpd, on one of our key asset targets, versus
an average in 2024 of 23,100 bwpd. The near-term investment in future-proofing
the asset will better enable the partnership to realise full value from the
asset which we believe has significant upside potential. As we presented at
our webinar in June 2024 we consider these assets to be capable of delivering
sustained production at levels above 30,000 bopd and materially higher levels
of reserves. To date we have already added 18mmbo of gross reserves since
acquisition. We remain fully focused on realising this potential upside value
through focused execution.
Expanding the portfolio
Another key development this year has been our further expansion in Angola
through our focus on the onshore Kwanza basin, an under-exploited and
overlooked proven hydrocarbon basin with both low-cost exploration
opportunities and numerous previously producing oil fields that we consider to
have been abandoned prematurely. In July 2024 we were awarded a 45%
non-operated interest in KON19 alongside two local companies and post-period
end in February 2025 we were awarded a 45% non-operated interest in Block
KON15 alongside Sonangol. We believe these onshore licences strategically
complement our offshore activities and provide long-term opportunities in the
form of low-cost exploration in a proven basin - an area of expertise in which
our team has significant experience. It is particularly pleasing to
demonstrate our commitment to further develop the Angolan industry by
partnering with local companies. This approach, coupled with our proven
status and in-country network, may present further opportunities for low-cost
exploration and development in this opportunity-rich area.
Alongside the organic growth opportunities we see within our existing
portfolio and established foothold in Angola, we continue to screen
strategically complementary M&A opportunities and retain strong liquidity
on the balance sheet that will be put to work when we identify an opportunity
that fits our investment criteria. Having completed transactions with both
IOC's and Sonangol in Angola, we have proven our ability to be a credible
counterparty and it is clear that after only three years of operating the
Afentra brand is well regarded within our industry.
We have also demonstrated our Value Driven approach in action through the
funding of all transactions without the requirement to issue new equity and
the efficient use of the debt markets. The strength of cash flow from Block
3/05, which has been optimised through our active management of crude liftings
and a structured hedging policy, means we end the period in a net cash
position. Whilst the recent softening of crude pricing may reduce near-term
asset cashflow, when combined with our strong balance sheet, it may present
further opportunities through the likely acceleration of divestments at
reasonable price points. Afentra remains agile in its approach and is well
positioned to deliver further value accretive transactions in 2025.
Focus on value creation
In summary, 2024 was yet another year of strategic progress that resulted in
value creation for our shareholders and enhanced the value of our overall
proposition by demonstrating the upside potential of our expanding asset
base. Our strategic focus for the current year is to support Sonangol on the
continued delivery of the work programme for Block 3/05 which aims to enhance
production, improve asset integrity and prepare for the next phase of workover
and development drilling. We continue to assess the scope to reduce the
emissions profile of the asset and will begin to see positive trends in this
regard as we ramp up production and commence various initiatives including gas
utilisation.
The market dynamics in our industry continue to evolve and support our purpose
in terms of facilitating a responsible industry transition. We have
established a strong foothold in a country that provides a positive fiscal
environment and a portfolio of compelling opportunities in both the offshore
and onshore areas. We continue to strengthen our working relationship with
key stakeholders in Angola and demonstrate our commitment to the long-term
development of the upstream industry through our establishment of an office in
Luanda and our partnering with local players.
I would like to thank all of our stakeholders, including Sonangol, ANPG, our
partners, and of course our shareholders for their continued support.
Afentra remains committed to enhancing value for all of these stakeholders as
we execute our well-defined growth strategy, and the Company is uniquely
placed to leverage its stable growth platform to deliver the next stage of
value creation.
Operations Review
Asset Summary
Afentra's enlarged asset footprint in Angola, both offshore and onshore
provides a solid platform for material long-term organic and inorganic
growth
Increased exposure to world-class midlife assets, low-cost development and
near-field and short-cycle exploration opportunities with significant upside
potential
In 2024, Afentra completed its third transformative deal offshore Angola. The
acquisition of additional non-operating interests from Azule Energy in Block
3/05 and Block 3/05A increased our interests to 30% and 21.33% respectively
(an increase of 12% in Block 3/05 and 16% in Block 3/05A). . Providing Afentra
with material exposure to these world-class mid-life producing assets that
generate robust cashflows and provide near-term upside potential for organic
growth as well as the opportunity to make an impactful reduction in emissions.
Onshore Angola, in July 2024 Afentra was awarded a 45% non-operated interest
in the KON19 licence alongside Angolan companies ACREP (the Operator) and
Enagol. Post-period end, in February 2025, the Company was also awarded a 45%
non-operated interest in KON15 alongside Sonangol as Operator, further
expanding our footprint onshore. This was signed on April 7(th) 2025. Both
licences are located in the proven, yet under-explored, onshore Kwanza basin.
Entry into this basin, where 11 oilfields have been discovered, offers an
opportunity for low-cost exploration and near-term development by applying
fresh ideas and modern concepts to an area where no new technology has been
applied for 40 years.
Fostering a close working relationship across the Joint Ventures
Since 2022 the Afentra team has developed a strong collaborative working
relationship with Sonangol and the JV partners on Block 3/05 and Block 3/05A.
The JV partners are aligned on making informed data driven decisions on field
optimisation through the deployment of proven industry techniques and the
latest technology, taking a phased approach to manage capital expenditure,
with the aim being to cost effectively optimise and increase production while
simultaneously reducing emissions.
Onshore, Afentra is also working closely with its JV partners on KON19 and
post-period end on KON15 utilising technologies and techniques that the team
have deployed successfully in other regions of Africa. For example, using
basin-wide enhanced Full Tensor Gravity Gradiometry (eFTG) surveying to
undertake a more comprehensive subsurface analysis of the largely unexplored
onshore Kwanza basin.
Block 3/05 production increase and reserve replacement through phased
long-term sustainable field extension activities
During 2024, Block 3/05 and Block 3/05A gross production averaged 21,111 bopd,
a 5% increase from the prior year (2023: 20,180 bopd), with peaks exceeding
25,000 bopd. Over 40 light well interventions (LWIs during 2024 added 2,000
bopd, with a similar program planned for 2025. These LWIs and facility
improvements drove a 140% reserve replacement since the last CPR, carried out
in June 2023. Increased water injection will support the reservoir pressure
which is expected to further enhance recovery factors and reduce emissions as
a lower Gas Oil Ratio (GOR) reduces the need for gas flaring.
The Block 3/05 licence extension to 2040 and revised fiscal terms received in
2023 has allowed the JV partnership to strategically invest in infrastructure
upgrades. At the end of 2024 the JV commenced a 3-year asset redevelopment
plan that is designed to extend the field life, optimise and increase
production, enable future development activities and reduce GHG emissions.
As part of the redevelopment plan, a planned 21-day maintenance shutdown was
successfully conducted in October 2024. The shut-down specifically targeted
making upgrades to the power equipment, and the metering systems for water and
gas, improving reliability and enabling reliable emissions monitoring. The
upgrades to the water injection system have resulted in year-end injection
rates increasing to over 80,000 bwpd. Post-year end, Q1 2025 water injection
rates have exceeded 100,000 bwpd. Further upgrades later in 2025 will increase
available capacity up to 150,000 bwpd. The newly installed gas meters will
pave the way for the JV to progress a field-wide gas export plan.
A further shutdown is planned for 2025 in accordance with the asset
redevelopment plans to extend the field life and to ready the infrastructure
for future increases in production. Future development activities include
infill drilling, tie-backs of nearby satellite discoveries, and near-field
exploration within Blocks 3/05 and 3/05A. The JV partnership is actively
evaluating several opportunities, aiming to develop value-generating appraisal
and development well proposals with the potential to add reserves within the
2026-2027 timeframe.
Near-term investment for long-term growth
Given the age and scale of the Block 3/05 infrastructure, the 2024 base
operating expense associated with these assets is attractive at $23/bbl (and
is expected to be similar in 2025). Going forward, production increases
through further optimisation and near-field developments will act to further
reduce the opex/bbl as near-term investment delivers long-term growth and
value. Investment of $150 million gross (net: $39 million() 2 (#_ftn2) ,)
including $40 million gross of life extension costs, was invested in 2024 in
the first year of the 3-year asset redevelopment plan. Gross investment in
2025 will increase to around $180 million (net: $54 million() 3 (#_ftn3)
)with a focus on asset integrity to continue to support our long-term
increased production outlook. The three-year asset redevelopment plan is
expected to be completed during 2027.
Angola: A prime location for portfolio expansion and a platform for wider
growth
Angola has a compelling investment environment, supported by the Angolan
government's stable fiscal regime and its commitment to enacting fiscal and
regulatory reforms designed to encourage investment into its domestic oil and
gas sector.
We view Angola as a core market and a key part of our growth strategy. An
important part of our strategy is to actively collaborate with local partners
like Sonangol, the NOC, and local Angolan companies such as ACREP, Etu
Energias and Enagol to work together to maximise in-country value creation.
The Angolan government, supported by the regulator ANPG's proactive and
collaborative approach is fostering an environment where Afentra can deliver
mutually beneficial outcomes for all stakeholders.
We are proud to be contributing to Angola's development through knowledge
sharing and job creation, reflecting our commitment to having both a positive
socioeconomic and environmental impact. With decades of experience working in
Africa, we are deeply committed to positive community impact and local content
development. In 2024, Afentra invested $150,000 in the HALO trust (for the
year 2024 and 2025), an international landmine clearing organisation that has
been active in Angola for over 30 years and has cleared over 120,000 landmines
in this time.
Continued focus on enhancing asset value
Based on the success of the 2023 and 2024 Block 3/05 LWI program, coupled with
the infrastructure upgrades resulting in increased water injection rates, a
further 40 LWIs are planned during 2025. Going forward heavy workovers,
artificial lift solutions, infill drilling, development of appraised
discoveries and near-field exploration will provide the opportunity to
potentially more than double production in the medium term.
Our enlarged Angolan asset base, both offshore and onshore, means that Afentra
is well-positioned for long-term growth. Our commitment to Angola,
demonstrated through strategic investments, collaborative partnerships, and a
focus on sustainable development, ensures we are not only maximising value for
our shareholders but also contributing to the economic and social well-being
of the country. We look forward to continuing our journey in Angola, unlocking
its vast potential and delivering lasting benefits for all stakeholders.
Angola Asset Summary
Block 3/05
Offshore, Angola, Afentra has a 30% non-operated interest in the producing
Block 3/05 and a 21.33% non-operated interest in the adjacent development
Block 3/05A. The mid-life fields that reside within the Block 3/05 licence
together represent a significant underdeveloped asset with substantial
potential to replace reserves, increase production and reduce emissions.
World-class shallow water assets with significant upside potential
Situated 37 km offshore Angola in 40-100 metres water depth, Block 3/05
comprises a portfolio of 8 mid-life producing fields: - Palanca, Impala,
Impala SE, Bufalo, Pacassa, Pambi, Cobo, and Oomba. Spanning an area of around
40km by 15km, the licence contains extensive field infrastructure with 157
wells (currently 45 producing and 17 injecting water) and 17 installations,
including the Palanca floating storage and offloading (FSO) vessel for oil
export.
The fields, which produce from the prolific fractured Albian Pinda carbonate
reservoir section, were discovered by Elf Petroleum (now TotalEnergies) in the
early 1980s. They were developed using fixed platforms with oil production
commencing in 1985. Earlier in the field life waterflooding was successfully
implemented to enhance recovery, lowering uncertainty and supporting
production forecasts for the assets. Since assuming Operatorship in 2005,
Sonangol has concentrated on sustaining production through workovers and asset
integrity maintenance.
JV aligned on field life extension and optimisation approach
The JV partnership on Block 3/05 and Block 3/05A are aligned on making
data-driven decisions on field optimisation, using proven techniques and
technology in a phased approach to cost-effectively upgrade the facilities,
increase production, reduce emissions, and unlock the significant potential of
these mid-life assets.
The extension of the licence to 2040 and improved fiscal terms, received
during 2023, has unlocked investment in Life Extension (LIFEX) activities
including increasing production. This includes facility upgrades, production
optimisation activities through LWI techniques, and going forward plans are
being progressed for subsurface optimisation with rig activities, and the
development of surrounding discoveries. The upgrades to the asset integrity of
the existing infrastructure will facilitate their use in the development of
the numerous discoveries surrounding the existing producing fields.
Early field optimisation and life extension activities demonstrating upside
field potential
We were pleased to report that in 2024 field production from Block 3/05 and
Block 3/05A increased by 5% to an average of 21,111 bopd. This is the second
year of consecutive production growth Strong operational performance
post-shutdown positively impacted production and water injection rates: Gross
average oil production from only Block 3/05 reached an average of
23,133 bopd (net: 6940 bopd) in December 2024.
The material uplift in production by the end of 2024, and the reserve
replacement of 140% (since June 2023) announced post-period end can be
attributed to the impact over the 18-month period of the LWI's and increased
water injection coupled with material progress on facility recovery to process
higher levels of production.
ESG embedded into our activities
Working closely with our JV partners, we aim to balance the socioeconomic
benefits that come from production while lowering the environmental impact
through targeted initiatives. The 2024 planned maintenance shutdown allowed
for the installation of gas metering which will allow a baseline understanding
of flare rates, composition and resulting emissions. The data from these new
meters will inform the development of a holistic gas management plan to lower
emissions through reduced flaring and through utilisation of gas for export.
Block 3/05 non-operated interest
Block 3/05 is operated by Sonangol through a JV partnership under a PSA. In
2023, the Block 3/05 PSA was extended to 2040 with enhanced fiscal terms.
Company Interest
Sonangol (Operator) 36%
Afentra 30%
M&P 20%
Etu Energias 10%
NIS Naftagas 4%
Block 3/05 Work Program
Key achievements on the fields during the year have included achieving zero
Lost Time Incidents (LTIs) in 2024 and maintaining the same 87% facilities
uptime as in 2023. The JV is making near-term investments with targeted life
extension activities, taking a long-term strategic approach to investing in
the field to deliver growth and value into the 2030s and beyond.
Futureproofing infrastructure to increase production and reduce emissions
During 2024 the JV commenced a 3-year asset redevelopment plan to extend the
field life, optimise and increase production, and reduce GHG emissions, this
included the recertification of the Palanca FSO. The recertification of the
vessel will lead to no dry dock before 2030. These efforts align with the
extended licence for Block 3/05, which now runs through to 2040. Key
infrastructure upgrades included enhancements to compressors, power generation
systems, and flowlines.
Afentra and the JV are fully aligned on taking a phased and targeted approach
to life extension capital expenditure. This has started with stabilising and
sustaining current production, optimising the existing well stock, and will
ultimately lead to the next stage of future development through infill
drilling and tie-backs of nearby satellite fields.
Stabilise and Sustain Production
The "Stabilise and Sustain" programme, which included the planned 21-day
maintenance shutdown in October 2024 focused on four key areas: asset
integrity, water management, power systems and gas metering. By upgrading
these key areas, we are laying the groundwork for production to increase and a
reduction in emissions.
Ramping up water injection
For the JV, achieving higher and more stable injection rates is a key
objective, as it will continue to positively impact oil production in the
medium term as production rates respond to reservoir pressure increases.
During 2024, there was a significant investment in water injection upgrades
across the fields with new filters, pumps and meters installed. The
implemented upgrades have resulted in an immediate performance improvement,
with year-end injection rates at up to 80,000 bwpd. The fields now have
significantly higher injection capacity compared to 2022, and the field is now
prepared for a planned injection rate ramp-up in 2025 to above 100,000 bwpd
using two pumps with a third scheduled to come online later in 2025 resulting
in up to 150,000 bwpd of available capacity. Post-period end water injection
rates have exceeded 100,000 bwpd.
Light Well Interventions
The LWI campaign carried out during 2024, in continuation of the program
that commenced in 2023, involved successfully re-entering 40 wells to carry
out matrix and tubing washes, perform water shut offs and re-perforations. The
LWIs have continued to demonstrate the benefits and potential of low cost well
interventions on these fields with an average gain of around 130 bopd per
intervention and with an average payback of less than six weeks.
Gas lift optimisation was carried out in 2024, with seven well improvements
and the focus has now shifted to gas compression and further optimisation of
the intra-field gas network. Gas meters have also now been installed on the
flares, providing accurate measurement and an accurate baseline to measure
emission reductions.
Holistic asset gas management
In 2024, significant progress was made in implementing the holistic gas
management plan which aims to lower emissions by reducing flaring, mitigating
fugitive emissions and looking at gas export options. Three factors are
contributing to reduced gas flaring and emissions: increased water injection
will lower the GOR, a recent drone survey conducted late 2023 has informed a
fugitive emissions mitigation strategy, and new gas meters will enable more
accurate emissions monitoring and the development of gas export plans.
Shift to gas and network optimisation, heavy workovers and drilling for
2025-2027
Looking ahead, the focus is shifting to gas compression and network
optimisation in 2025, a heavy workover program , and preparing for
rig-related life extension activities in 2026. In 2024 there was also
investment in long lead items to enable future rig related activity.
Collaborative JV workshops have identified a series of low cost and low risk
workovers from the extensive inventory of wells currently offline. Initial
focus for heavy workovers will be on the Palanca and Impala fields where a
number of well reactivation and ESP opportunities have been selected for high
grading. Here there is a significant oil in place which is not being
effectively accessed and recovered.
There is a significant opportunity to increase production through infill
drilling, with no infill wells drilled for over 10 years, and over 20 targets
identified. Strong candidates are wells with lower GOR such as at Pacassa SW
or infield wells where existing infrastructure can be used to rapidly bring
them onto production. The JV partners are working collaboratively through the
selection of infill candidates from Pacassa, Palanca, Impala SE, Buffalo,
Cobo, Pambi and Impala fields, with an initial phase of drilling planned to
start in 2026, with new infill wells potentially adding 500-2000 bopd of
production per well.
Near-field Developments and Exploration
Near-field exploration and development within both Block 3/05 and 3/05A offer
significant opportunities to increase oil production further, with the
potential for discoveries to hold over 300 mmbo (3/05A) and 100-200 mmbo
(3/05). Satellite discoveries have the potential to deliver up to 10,000 bopd
through phased development.
Case Study: Afentra and JV technical collaboration drive early production
gains from LWIs
Since 2022, Afentra's technical team has been working collaboratively with the
JV partnership to advance production optimisation projects as well as longer
term planning for field extension and further infield development
activities.
Before joining the licence, our technical team identified the potential for
low-cost light well intervention (LWI) workovers to rapidly boost production.
Evaluating available wireline log data, historical well completion data, and
production history, the team has worked together with the Operator and JV
partners to identify and rank LWI candidates.
Through interactive workshops in Luanda, Afentra has facilitated strong
collaboration with Sonangol and the JV partners, leveraging our team's
extensive geoscience and well engineering experience to develop detailed
technical proposals. The proposals encompass a range of intervention options,
including acid washes, matrix washes, gas lift valve change-outs, and
reperforations to restimulate intervals and to access previously untapped oil
zones.
The LWI program has yielded impressive results. In 2023, interventions
delivered an additional 4,000 bopd, followed by an additional 2,000 bopd in
2024. These early successes will inform and drive continued LWI programs in
subsequent years.
Furthermore, the JV's collaborative efforts have increased the number of
active production wells from 42 to 45 and injection wells from 15 to 17,
demonstrating a joint commitment to optimising field performance and
maximising the value of the asset. With 95 inactive wells remaining, the
potential for future interventions remains substantial.
Block 3/05A
Significant low cost near-field development potential
Adjacent to Block 3/05, Block 3/05A houses the undeveloped Punja, Caco and
Gazela discoveries with an estimated in-place resource of 300 million barrels.
Afentra estimates gross 2C recoverable resources at 33 million barrels.
The Gazela field, commenced production in 2015, with approximately 2.4 mmbo
recovered prior to a wellbore shutdown in 2017. Production was restored in
March 2023 with the Gazela-101 well averaging around 1,248 bopd gross during
2024. This extended production test is helping to establish the long-term
resource potential and appropriate development strategy. Subsurface mapping
has been completed on the Caco and Gazela fault compartments to identify
future potential production or injection wells. These will now be ranked
alongside other rig related opportunities for selection in the potential 2026
/ 2027 drilling campaign.
Development concepts actively being progressed
Given the high gas oil ratio of the Punja field reservoirs, an integrated gas
management plan across both Blocks 3/05A and 3/05 is essential to optimise the
responsible development of these oil and gas resources. In line with our
stated environmental commitments, all alternatives to flaring excess gas from
additional developments will be evaluated with the JV before proceeding to
sanction future projects. There are a number of zero routine flaring options
that will be evaluated, including commercial export of excess gas via the ALNG
network which is located in close proximity to existing infrastructure or gas
injection into existing fields. Both options will require review and a
potential upgrade of the existing compression infrastructure.
The JV partnership will be progressing the next steps to both Punja and
Caco-Gazela in a phased approach to gain appraisal data, reduce uncertainty
and generate cash flow through monetising early production. A number of
development concepts will be screened and ranked in order to reach an
optimised FID in the near term.
The Block 3/05A PSA expires in 2035, having commenced in 2015 and could be
extended if production is still ongoing. The Punja undeveloped discovery
received marginal field terms in 2024 enhancing the commercial value of this
block.
Block 3/05A non-operated interest
Block 3/05A is operated by Sonangol through a JV partnership under a PSA.
Company Interest
Sonangol (Operator) 33.33%
M&P 26.67%
Afentra 21.33%
Etu Energias 13.33%
NIS Naftagas 5.33%
Onshore Angola
Blocks KON15 and KON19 (awarded post-period end) offer low-cost near-term
exploration potential
Onshore Angola, Afentra was awarded a 45% non-operated interest in both KON19
in July 2024, and post-period end a 45% non-operated interest in KON15. Both
licences are in the proven yet under-explored onshore Kwanza basin. Entry into
this basin, where 11 oilfields have been discovered, offers a value driven
strategic opportunity for near-term and low-cost exploration in a proven basin
by applying fresh ideas and modern concepts to an area where no new technology
has been applied for 40 years.
KON15 and KON19 are located adjacent to the legacy Tobias and Galinda oil
fields and offer significant potential within Angola's prospective post-salt
and pre-salt formations. Leveraging existing data, these blocks can be quickly
explored and appraised, potentially leading to rapid development and
production. These licences will expand Afentra's footprint in this attractive
Angolan market by diversifying our portfolio which is principally focused on
low cost, long-life stable production and low-risk development assets.
Under-explored proven hydrocarbon basin
The onshore Kwanza basin covers 25,000 km2 and is an underexplored,
over-looked proven hydrocarbon basin that has numerous oil fields and
discoveries dating back to 1955. The basin produced over 15,000 bopd in the
1960's and 1970's from post-salt traps. Onshore activity declined and ceased
during the instability of the Angolan civil war after which the focus was
offshore oil and gas field development.
Both KON15 and KON19 blocks were high graded by Afentra in 2023 as they have
good signs of a working petroleum system and contain wells that were drilled
on salt structures with light oil recovered to surface in one and oil shows in
others from post and pre-salt reservoirs. We continue to evaluate additional
opportunities utilising technologies and techniques that the team have
successfully deployed in other regions of Africa.
For example, although the full work program is yet to be finalised, the
initial phase of a basin-wide enhanced Full Tensor Gravity Gradiometry (eFTG)
survey, launched in August 2024, has been completed for KON19, with the
remaining KON15 phase being completed in 2025. This advanced eFTG technology
will facilitate a more comprehensive subsurface analysis of the 25,000km²
onshore basin, a largely unexplored region in recent decades and identify
prospective regions.
Block KON15
Company Interest
Sonangol P&P (Operator) 55%
Afentra 45%
Block KON19
Company Interest
ACREP (Operator) 45%
Afentra 45%
Enagol 10%
Angola - Block 23
Afentra also holds a 40% non-operated interest in Block 23, a deepwater
exploration licence with a proven hydrocarbon potential and no outstanding
work commitment. In 2024 the new Operator Namcor was announced.
Block 23 is a 5,000 km2 exploration and appraisal block located in the
offshore section of the Kwanza basin in water depths ranging from 600 to 1,600
meters, with a proven working petroleum system, and is in proximity to
TotalEnergies Kaminho future deepwater development. Whilst this large block is
covered by modern 2D and 3D seismic data sets, with no outstanding work
commitments remaining, much of the block remains under-explored.
Block 23 non-operated interests
Company Interest
Namcor (Operator) 4 (#_ftn4) 40%
Afentra 40%
Sonangol 20%
Somaliland
Odewayne Block
Afentra also has a 34% carried interest in the onshore Odewayne Block onshore
southwestern Somaliland. The Block is an unexplored frontier acreage position
covering 22,840km2 offering the opportunity to explore an undrilled onshore
rift basin in Africa.
Financial Review
In 2024 we continued to grow our asset base in Angola as we completed our
third acquisition on Block 3/05 and Block 3/05A, increasing our interest to
30% and 21.33%, respectively, as well as accessing the onshore Kwanza basin in
July by securing a 45% non-operated interest in Block KON19 alongside local
companies ACREP (Operator with 45% interest) and Enagol (10%). During the year
we also established a presence in Luanda, Angola, through the appointment of a
Country Manager in Luanda who opened our local office in Q4. Operationally, we
successfully completed four crude oil liftings during the year, generating
$180.9 million of revenue, and anticipate a further five liftings in 2025.
Our financial position has undergone a significant transformation in 2024,
demonstrating the value generated through strategic acquisitions, stable asset
performance and effective management. We ended 2024 with $54.8 million in cash
($19.6 million at 31 December 2023), inclusive of restricted cash balances,
achieving an end of year net cash position of $12.6 million (Net debt $12.3
million at 31 December 2023).
We continue to manage our exposure to oil price risk through our hedging
strategy and, during 2024, hedged 70% of sales volumes through a combination
of put options and collar structures. The hedge portfolio consisted of $70 to
$80 per barrel put options, covering 70% of sales volumes, and $90 per barrel
call options, covering 29% of sales volumes. For 2025, we have hedged
approximately 68% of estimated sales volumes. Our 2025 hedge portfolio
consists of a combination of put options with floors ranging between $60 and
$65 per barrel covering 68% of estimated sales volumes and call options with
caps ranging from $80 to $89 per barrel, covering 44% of estimated sales
volumes. The company continues to explore and to evaluate other hedge products
in the market consistent with its hedging policy.
In line with Afentra's commitment to avoiding shareholder dilution, the
Company has elected to satisfy vested options under the Founders' Share Plan
(FSP) through market purchases via an existing Employee Share Benefit Trust
(Trust) rather than issuing new Ordinary Shares. Subsequently, the Trust
purchased 381,719 shares on the open market at an average price of ~41p.
Furthermore, the Trust will continue with the share purchase programme to
satisfy the requirements of the employee LTIP and final 2026 FSP vesting.
Subject to certain purchase criteria to be agreed with the Trust, the Trust is
expected to purchase of up to 6.5 million Ordinary Shares over the rest of
2025/Q1 2026. Full details of the FSP scheme are provided in the Remuneration
Committee Report of the Annual Report.
For 2025, our focus on M&A remains unchanged as we continue to seek to
build our portfolio via value accretive opportunities in Angola, as well as in
other jurisdictions in the West Africa region. In February of this year, we
secured our interest in the onshore Block KON15, thereby securing our second
onshore asset in Angola. On asset management, we will look to develop our
office presence in Luanda and will continue to work constructively with the
Operator and our JV partners on Block 3/05 and Block 3/05A to ensure continued
safe operations as well as seeking to develop value accretive opportunities in
both existing operations as well as new projects.
Selected financial data 2024 2023
Sales volume mmbo 2.3 0.3
Realised oil price $/bbl 82.2 88.0
Total revenue $ million 180.9 26.4
Cash and cash equivalents $ million 46.9 14.7
Restricted funds $ million 7.9 4.9
Borrowings $ million (41.4) (31.7)
Net cash/(debt) $ million 12.6 (12.3)
Adjusted EBITDAX $ million 90.9 11.1
Profit/(loss) after tax $ million 49.8 (2.7)
Year-end share price Pence 46.1 37.0
Non-IFRS measures
The Group uses certain measures of performance that are not specifically
defined under IFRS or other generally accepted accounting principles. EBITDAX
(Adjusted) represents earnings before interest, taxation, depreciation, total
depletion and amortisation, impairment and expected credit loss allowances,
share-based payments, provisions, and pre-licence expenditure. Additionally,
in any given period, the Company may have significant, unusual or
non-recurring items which may be excluded from EBITDAX (Adjusted) for that
period. When applicable, these items are fully disclosed and incorporated into
the reconciliation provided below.
EBITDAX (Adjusted) is a non-IFRS financial measure. The Company believes that
this non-IFRS financial measure assists investors by excluding the potentially
disparate effects between periods of the adjustments specified.
EBITDAX (Adjusted) should not be considered as an alternative to Net income or
any other indicator of Afentra plc's performance calculated in accordance with
IFRS. Because the definition of EBITDAX (Adjusted) may vary among companies
and industries, it may not be comparable to other similarly titled measures
used by other companies.
Income Statement
Average production from Afentra's interests in Blocks 3/05 and 3/05A increased
to 6,229 bopd from 3,509 bopd as a result of the completion of the Azule
transaction in May 2024, where Afentra acquired an additional 12% and 16% in
Blocks 3/05 and 3/05A, respectively.
2024 revenue, net of off-take fees, of $180.9 million (2023: $26.4 million)
from four liftings completed during the year at an average realised price of
$82.2/bbl.
Cost of sales during the year totalled $96.7 million (2023: $12.6 million); a
full reconciliation is provided in the notes to the accounts (Note 4).
The profit from operations for 2024 was $71.9 million (2023: $2.4 million) as
a result of the four liftings in 2024 and increased stake in each block.
During the year, net administrative expenditure increased slightly to $12.3
million (2023: $11.5 million).
Finance income (interest on deposits) of $0.1 million (2023: $0.2 million) was
received in the year. Finance costs increased during 2024 to $9.0 million
(2023: $3.5 million), primarily due to additional drawdowns on the RBL and
working capital facilities. Further detail is provided in the notes to the
accounts (Note 7).
The profit after tax for the year was $49.8 million (2023: loss after tax $2.7
million):
$' Million
2023 loss after tax (2.7)
Increase in revenue 154.5
Increase in cost of sales (84.2)
Increase in G&A and pre-licence costs (0.8)
Increase in net finance costs (5.6)
Increase in tax expense (11.4)
2024 profit after tax 49.8
Group adjusted EBITDAX totalled $90.9 million (2023: $11.1 million):
2024 2023
$' Million $' Million
Profit/(loss) after tax 49.8 (2.7)
Net finance costs 8.9 3.3
Depletion and depreciation(1) 12.6 2.9
Pre-licence costs 1.8 4.8
Share-based payment charge 1.0 1.0
Expected credit loss allowances 3.6 -
Taxation 13.2 1.8
Total EBITDAX (Adjusted) 90.9 11.1
1 Total depletion on oil and gas assets in 2024 is the depletion charged to
profit and loss ($12.1 million) and absorbed in inventory ($0.2 million).
Depreciation on other assets totalled $0.3 million.
The basic and diluted earnings per share for the year was 22.2 cents (2023:
1.2 cents loss) and 20.1 cents (2023: 1.2 cents loss) respectively. No
dividend is proposed to be paid for the year ended 31 December 2024 (2023:
nil).
Statement of financial position
At the end of 2024, non-current assets totalled $150.2 million (2023: $97.0
million, as restated). The increase is primarily due the further acquisition
from Azule of the Company's interests in Block 3/05 and Block 3/05A ($38.3
million) as well as capital expenditure on the two blocks ($26.1 million),
offset by depreciation ($12.6 million). Further information can be found in
Note 11 to the Annual Financial Statements.
At the end of 2024, current assets stood at $73.9 million (2023: $43.7
million, as restated) including cash and cash equivalents of $46.9 million
(2023: $14.7 million), restricted funds of $7.9 million (2023: $4.9 million),
trade and other receivables of $11.4 million (2023: $10.7 million as
restated), and inventories of $7.5 million (2023: $13.4 million).
At the end of 2024, current liabilities were $71.1 million (2023: $45.9
million as restated) including trade and other payables of $52.9 million
(2023: $34.4 million as restated), borrowings of $11.3 million (2023: $6.8
million), contingent consideration of $5.5 million (2023: $4.6 million), and
derivative liabilities of $1.3 million (2023: nil). The increase in trade and
other payables is related to the Company's increased share of Joint Venture
working capital items (Block 3/05 and Block 3/05A).
At the end of 2024, non-current liabilities were $56.9 million (2023: $46.9
million, as restated), comprised primarily of borrowings of $30.1 million
(2023: 25.0 million) and contingent consideration of $24.4 million (2023:
$21.9 million), and deferred tax of $1.7 million (2023: nil). The increase is
primarily due to additional drawdowns on the RBL and working capital
facilities during the year. Further information can be found in Note 19.
The Group's net assets increased from $48.0 million at the end of 2023 to
$96.1 million as at 31 December 2024, primarily reflecting profits earned
during the year.
Cash flow
Net cash inflow from operating activities totalled $85.6 million (2023: $12.3
million). The increase is primarily due to a full year activity on Blocks 3/05
and 3/05A, compounded by additional equity acquisitions relating to these
blocks.
Net cash used in investing activities increased to $53.6 million from $45.9
million in 2023. Additions to property plant and equipment was offset by lower
asset acquisitions and contingent consideration payments made during the year.
Net cash generated from financing activities totalled $0.1 million compared to
$28.0 million in 2023 due to repayments of debt principal and interest.
Accounting Standards
The Group has reported its 2024 and 2023 full year accounts in accordance with
UK adopted international accounting standards.
Cautionary statement
This financial report contains certain forward-looking statements that are
subject to the usual risk factors and uncertainties associated with the oil
and gas exploration and production business. Whilst the Directors believe the
expectation reflected herein to be reasonable in light of the information
available up to the time of their approval of this report, the actual outcome
may be materially different owing to factors either beyond the Group's control
or otherwise within the Group's control but, for example, owing to a change of
plan or strategy. Accordingly, no reliance may be placed on the
forward-looking statements.
Anastasia Deulina - Chief Financial Officer
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME
For the years ended 31 December
2024 2023
Note $000 $000
Revenue 3 180,860 26,390
Cost of sales 4 (96,656) (12,571)
Gross profit 84,204 13,819
Other administrative expenses (10,439) (6,647)
Pre-licence costs (1,828) (4,810)
Total administrative expenses (12,267) (11,457)
Profit from operations 5 71,937 2,362
Finance income 7 106 240
Finance costs 7 (9,000) (3,508)
Profit/(loss) before tax 63,043 (906)
Income tax 8 (13,225) (1,799)
49,818 (2,705)
Profit/(loss) for the year attributable to the owners of the parent
Items that may be reclassified subsequently to profit or loss
(35) (96)
Foreign exchange differences on translation of foreign operations
Total other comprehensive loss for the year (35) (96)
Total comprehensive income/(loss) for the year attributable to the owners of 49,783 (2,801)
the parent
Basic earnings/(loss) per share (US cents) 9 22.2 (1.2)
Diluted earnings/(loss) per share (US cents) 9 20.1 (1.2)
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
2024 2023
Restated (1)
Note $000 $000
Non-current assets
Intangible exploration and evaluation assets 10 22,479 21,867
Property, plant and equipment 11 127,699 75,131
150,178 96,998
Current assets
Inventories 13 7,464 13,441
Trade and other receivables 14 11,428 10,729
Derivative assets 27 196 -
Cash and cash equivalents 15 46,880 14,729
Restricted funds 16 7,930 4,850
73,898 43,749
Total assets 224,076 140,747
Current liabilities
Borrowings 19 11,271 6,752
Trade and other payables 20 52,939 34,396
Derivative liabilities 27 1,279 -
Contingent consideration 21 5,535 4,621
Lease liability 22 97 155
71,121 45,924
Non-current liabilities
Borrowings 19 30,145 24,951
Contingent consideration provision 21 24,367 21,863
Provisions - 37
Deferred tax liability 8 1,661 -
Lease liability 22 685 -
56,858 46,851
Total liabilities 127,979 92,775
Equity attributable to equity holders of the Company
Share capital 17 28,914 28,143
Currency translation reserve 18 (333) (298)
Share option reserve 18 842 965
Retained earnings 18 66,674 19,162
96,097 47,972
Total liabilities and equity 224,076 140,747
(1) The comparative information has been restated as a result of a
reassessment of Afentra's future liability for decommissioning expenditure and
the treatment of joint venture receivable and payable balances. Further
information is detailed in Note 29.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Equity attributable to equity holders of the Company
Share Currency Share Retained Total
capital
translation
option
earnings
reserve
reserve
Note $000 $000 $000 $000 $000
At 1 January 2023 28,143 (202) - 21,867 49,808
Loss for the year - - - (2,705) (2,705)
Currency translation adjustments - (96) - - (96)
Total comprehensive loss for the year attributable to the owners of the parent - (96) - (2,705) (2,801)
Share-based payment charge for the year - - 965 - 965
At 31 December 2023 28,143 (298) 965 19,162 47,972
Profit for the year - - - 49,818 49,818
Currency translation adjustments - (35) - - (35)
Total comprehensive profit/(loss) for the year attributable to the owners of - (35) - 49,818 49,783
the parent
Share-based payment charge for the year - - 989 - 989
Share options exercised 25 771 - (1,112) (2,306) (2,647)
At 31 December 2024 28,914 (333) 842 66,674 96,097
CONSOLIDATED STATEMENT OF CASH FLOWS
For the years ended 31 December
2024 2023
Restated
Note $000 $000
Operating activities:
Profit/(loss) before tax 63,043 (906)
Adjusted for:
Depreciation, depletion and amortisation 11 12,643 2,880
Share-based payment expense 25 989 965
Tax payments related to share-based payments 25 (2,702) -
Expected credit loss 4 3,600 -
Unrealised losses on derivatives 1,200 -
Hedge cost (117) -
Finance income 7 (106) (240)
Finance costs 7 9,000 3,508
Operating cash flow prior to working capital movements 87,550 6,207
Decrease in inventories 17,442 4,789
(Increase)/decrease in trade and other receivables (4,336) 5,809
Decrease in trade and other payables (5,304) (2,688)
Increase in provisions - 3
Cash flow generated from operating activities 95,352 14,120
Income tax paid (9,762) (1,799)
Net cash flow generated from operating activities 85,590 12,321
Investing activities
Asset acquisitions 24 (28,428) (48,126)
Interest received 7 106 240
Purchase of property, plant and equipment 11 (19,997) (3,316)
Exploration and evaluation costs 10 (612) (43)
Cash inflow from restricted funds - 5,350
Contingent consideration paid 21 (4,621) -
Net cash used in investing activities (53,552) (45,895)
Financing activities
Drawdown on loan 19 35,748 45,066
Principal repayments on loan facilities 19 (27,364) (14,367)
Cash outflow from restricted funds (3,080) --
Interest paid (5,051) (2,504)
Principal and interest paid on lease liability 22 (160) (245)
Net cash generated from financing activities 93 27,950
Net increase/(decrease) in cash and cash equivalents 32,131 (5,624)
Cash and cash equivalents at beginning of year 14,729 20,384
Effect of foreign exchange rate changes 20 (31)
Cash and cash equivalents at end of year 15 46,880 14,729
COMPANY STATEMENT OF FINANCIAL POSITION
As at 31 December
2024 2023
Note $000 $000
Non-current assets
Trade and other receivables 14 14,109 35,527
Investments in subsidiaries 12 20,140 21,105
534,249 56,632
Current assets
Trade and other receivables 14 4,167 10,329
Cash and cash equivalents 15 8,267 4,413
12,434 14,742
Total assets 46,683 71,374
Current liabilities
Trade and other payables 20 27,928 28,741
27,928 28,741
Total liabilities 27,928 28,741
Equity
Share capital 17 28,914 28,143
Share option reserve 18 1,183 965
Retained earnings 18 (11,342) 13,525
Total equity 18,755 42,633
Total liabilities and equity 46,683 71,374
The loss for the financial year within the Company accounts of Afentra plc was
$24.9 million (2023: $4.4 million). As provided by s408 of the Companies Act
2006, no individual Statement of Comprehensive Income is provided in respect
of the Company.
COMPANY STATEMENT OF CHANGES IN EQUITY
Share Share Retained Total
capital
option
earnings
reserve
$000 $000 $000 $000
At 1 January 2023 28,143 - 17,951 46,094
Loss for the year - - (4,426) (4,426)
Share-based payment charge for the year - 965 - 965
At 31 December 2023 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 25 771 (771) - -
At 31 December 2024 28,914 1,183 (11,342) 18,755
NOTES TO THE FINANCIAL STATEMENTS
1. Material accounting policies
a) General information
Afentra plc (the 'Company') is a public company, limited by shares,
incorporated in England under the UK Companies Act 2006. The address of the
registered office is 10 St Bride Street, London, EC4A 4AD. The principal
activities of the Company and its subsidiaries (the "Group") and the nature of
the group's operations include the exploration, development and production of
commercial oil and gas.
These financial statements are presented in US dollars rounded to the nearest
thousand, unless stated otherwise. They include the financial statements of
Afentra plc and its consolidated subsidiaries. The functional currency of the
Company is US dollars.
The financial information set out above does not constitute the Company's
statutory accounts for the years ended 31 December 2024 or 2023, but is
derived from those accounts. Statutory accounts for 2023 have been delivered
to the Registrar of Companies and those for 2024 will be delivered following
the Company's Annual General Meeting.
The auditors have reported on those accounts; their reports were unqualified,
did not draw attention to any matters by way of emphasis without qualifying
their report and did not contain statements under s498(2) or (3) Companies Act
2006.
While the financial information included in this announcement has been
prepared in accordance with the recognition and measurement criteria of
International Financial Reporting Standards (IFRSs), this announcement does
not itself contain sufficient information to comply with IFRSs.
The financial statements have been prepared under the historical cost
convention. The principal accounting policies adopted are set out
below. These policies have been consistently applied to all the years
presented, unless otherwise stated.
b) Basis of accounting and adoption of new and revised
standards
The financial statements have been prepared in accordance with UK adopted
international accounting standards and with those parts of the Companies Act
2006 applicable to companies reporting under IFRS, except as otherwise
stated. As ultimate parent of the Group, the Company has taken advantage of
Financial Reporting Standard 101 Reduced Disclosure Framework (FRS 101), which
addresses the financial reporting requirements and disclosure exemptions in
the individual financial statements of "qualifying entities", that otherwise
apply the recognition, measurement and disclosure requirements of UK adopted
international accounting standards.
The disclosure exemption adopted by the Company in accordance with FRS 101
are:
- a statement of compliance with IFRS (a statement of compliance with FRS 101
is provided instead);
- related party transactions with two or more wholly owned members of the
group; and
- a Statement of Cash Flows and related disclosures
In addition, and in accordance with FRS 101, further disclosure exemptions
have been applied because equivalent disclosures are included in the
consolidated financial statements of Afentra plc. These financial statements
do not include certain disclosures in respect of:
- financial instrument disclosures as required by IFRS 7 Financial
Instruments: Disclosures; and
- fair value measurements - details of the valuation techniques and inputs
used for fair value measurement of assets and liabilities as per paragraphs 91
to 99 of IFRS 13 Fair Value Measurement.
(i) New and amended standards adopted by the Group:
The following standards and amendments became effective in the year ended 31
December 2024.
Standard Description Effective date
IAS 7 / IFRS 7 Amendment - Supplier Finance Arrangements 1 January 2024
IFRS 16 Amendment - Leases (Lease Liability in a Sale and Leaseback) 1 January 2024
IAS 1 Amendment - Classification of Liabilities as Current or Non-current and 1 January 2024
Non-current Liabilities with Covenants
IAS 1 Amendment - Liabilities with Covenants 1 January 2024
None of the above standards or amendments have had a material impact on the
Group.
(ii) Standards, amendments and interpretations, which are effective for
reporting periods beginning after the date of these financial statements which
have not been adopted early:
At the date of authorisation of these financial statements, the Group has not
applied the following new and revised IFRS Accounting Standards that have been
issued but are not yet effective:
Standard Description Effective date
IAS 21 Amendment - Lack of Exchangeability 1 January 2025
IFRS 7 / IFRS 9 Amendment - Classification and Measurement of Financial Instruments 1 January 2026
IFRS 7 / IFRS 9 Amendment - Contracts Referencing Nature-dependent Electricity (previously 1 January 2026
Power Purchase Agreements)
IFRS 18 Presentation and Disclosure in Financial Statements 1 January 2027
IFRS 19 Subsidiaries without Public Accountability: Disclosures 1 January 2027
The Group is currently assessing the effect of these new accounting standards
and amendments. IFRS 18 Presentation and Disclosure in Financial Statements,
which was issued by the IASB in April 2024 supersedes IAS 1 and will result in
major consequential amendments to IFRS Accounting Standards including IAS 8
Basis of Preparation of Financial Statements (renamed from Accounting
Policies, Changes in Accounting Estimates and Errors). Even though IFRS 18
will not have any effect on the recognition and measurement of items in the
consolidated financial statements, it is expected to have a significant effect
on the presentation and disclosure of certain items. These changes include
categorisation and sub-totals in the statement of profit or loss,
aggregation/disaggregation and labelling of information, and disclosure of
management-defined performance measures. The Group does not expect to be
eligible to apply IFRS 19.
c) Going concern
The Group's business activities, together with the factors likely to affect
its future development, performance, and position are set out in the
Operations Review. The financial position of the Group and Company, its cash
flows and liquidity position are described in the Financial Review. In
addition, Note 23 to the financial statements includes the Group's objectives,
policies and processes for managing its capital financial risk, details of its
financial instruments and its exposures to credit risk and liquidity risk.
The Group has sufficient cash resources for its working capital needs and its
committed capital expenditure programme at least for the next 12 months from
the signing of the annual report. Consequently, the Directors believe that
both the Group and Company are well placed to manage their business risks
successfully.
The Group has sufficient cash resources based on existing cash on balance
sheet, proceeds from future oil sales and access to the revolving working
capital facility to meet its liabilities as they fall due for a period of at
least 12 months from the date of signing these financial statements, based on
forecasts covering the period through to 30 April 2026.
The Board has looked at a combination of downside scenarios, including a
production shortfall alongside higher costs and lower than anticipated oil
prices. The impact of the downside scenarios can be mitigated by a combination
of existing hedges and rephasing of certain projects included in the
preliminary capital expenditure programme by the Joint Venture. The Board also
notes the implementation of the hedging policy and is confident in the
utilisation of commodity-based derivatives to manage oil price downside
risk. The existing financial covenants, the tests of which for current
borrowings, have been passed for the Historic Ratio (Net debt/EBITDA) and the
Gross liquidity test, and are not forecast to be breached within the going
concern period. Thus, the Board believes it is appropriate to continue to
adopt the going concern basis of accounting in preparation of the financial
statements.
The Directors have, at the time of approving the financial statements, a
reasonable expectation that the Group has adequate resources to continue in
operational existence for the foreseeable future.
d) Basis of consolidation
(i) Subsidiaries
The consolidated financial statements incorporate the financial statements of
the Company and entities controlled by the Company (its subsidiaries) made up
to 31 December each year. Control is recognised where an investor is exposed,
or has rights, to variable returns from its investment with the investee and
has the ability to affect these returns through its power over the investee.
The results of subsidiaries acquired or disposed of during the year are
included in the Statement of Comprehensive Income from the effective date of
acquisition or up to the effective date of disposal, as appropriate.
Where necessary, adjustments are made to the financial statements of
subsidiaries to bring the accounting policies used into line with those used
by the Group.
(ii) Transactions eliminated on consolidation
Intra-group balances and any unrealised gains and losses, or income and
expenses arising from intra-group transactions, are eliminated in preparing
the consolidated financial statements.
e) Joint arrangements
The Group is a party to a joint arrangement regardless of whether the Group
has joint control of the arrangement. Where the contractual arrangement
confers joint control over the relevant activities to the Group and at least
one other party, then the Group classifies its interest in the joint
arrangement as joint operations or joint ventures in accordance with IFRS11.
Joint control is assessed under the same principles as control over
subsidiaries. If there is no joint control, then the Group classifies its
interest in the joint arrangement as a party to a joint arrangement. In
assessing the classification of interests in joint arrangements, the Group
considers:
· the structure of the joint arrangement;
· the contractual terms of the joint arrangement; and
· any other facts and circumstances.
The Group accounts for its interests in joint arrangements by recognising its
share of assets, liabilities, revenues, and expenses in accordance with its
contractually conferred rights and obligations.
The Group's material arrangements comprise non-operated interests in Block
3/05 (30%) and Block 3/05A (21.33%) located offshore Angola in the Lower Congo
Basin.
f) Revenue
Revenue is derived from the sales of oil from the interests held in Angola.
Revenue from the sale of crude oil is recognised when performance conditions
in the sales contract are satisfied and it is probable that the Group will
collect consideration to which it is entitled. For crude oil, the performance
condition is the delivery of the oil through lifting or on delivery of the oil
into an infrastructure. Revenue is measured at the fair value of the
consideration to which the company expects to be entitled in exchange for
transferring promised goods and/or services to a customer, excluding amounts
collected on behalf of third parties.
Under/overlift
Any production imbalance that may arise as a result of lifted volumes being
different to produced volumes has been recognised as an adjustment to cost of
sales, with the balance being recognised within inventory/trade and other
receivables when we have lifted less than our share of production
(underlifted) and trade and other payables when we have lifted more than our
share of production (overlifted). Underlifted barrels are valued at cost and
overlifted barrels at market value.
g) Oil and gas interests
Commercial reserves
Commercial reserves, at the 2P level, are proven and probable oil and gas
reserves, which are defined as the estimated quantities of crude oil, natural
gas and natural gas liquids which geological, geophysical and engineering data
demonstrate with a specified degree of certainty to be recoverable in future
years from known reservoirs and which are considered commercially producible.
This implies a 50% probability that the quantity of recoverable reserves will
be more than the amount estimated as proven and probable reserves and a 50%
probability that it will be less.
Capitalisation
Pre-acquisition costs on oil and gas assets are recognised in the profit or
loss when incurred. Costs incurred after rights to explore have been obtained,
such as geological and geophysical surveys, drilling and commercial appraisal
costs, and other directly attributable costs of exploration and appraisal,
including technical and administrative costs, are capitalised as intangible
exploration and evaluation (E&E) assets. The assessment of what
constitutes an individual E&E asset is based on technical criteria but
essentially either a single licence area or contiguous licence areas with
consistent geological features are designated as individual E&E assets.
Costs relating to the exploration and evaluation of oil and gas interests are
carried forward until the existence, or otherwise, of commercial reserves have
been determined.
E&E costs are not amortised prior to the conclusion of appraisal
activities. Once active exploration is completed the asset is assessed for
impairment. If commercial reserves are discovered then the carrying value of
the E&E asset is reclassified as a development and production (D&P)
asset, following development sanction, but only after the carrying value is
assessed for impairment and, where appropriate, its carrying value adjusted.
The E&E asset is written off to the profit or loss if it is subsequently
assessed that commercial reserves have not been discovered.
Costs associated with D&P assets, including the costs of facilities, wells
and subsea equipment, are capitalised within Property, Plant & Equipment.
Impairment
In accordance with IFRS 6, E&E assets are reviewed for impairment when
circumstances arise which indicate that the carrying value of an E&E asset
exceeds the recoverable amount. The recoverable amount of the individual asset
is determined as the higher of its fair value less costs to sell and its value
in use. Impairment losses resulting from an impairment review are recognized
within the Statement of Comprehensive Income.
Impaired assets are reviewed annually to determine whether any substantial
change to their fair value amounts previously impaired would require
reversal.
An impairment loss is reversed if the recoverable amount increases as a result
of a change in the estimates used to determine the recoverable amount, but not
to an amount higher than the carrying amount that would have been determined
(net of depletion or amortisation) had no impairment loss been recognised in
prior periods. Impairment charges and reversal of impairments are recorded
within total administration expenses in the Statement of Comprehensive Income.
Depreciation, depletion, and amortisation of D&P assets
All expenditure carried within each field is amortised from the commencement
of production on a unit of production basis, which is the ratio of oil and gas
production in the period to the estimated quantities of commercial reserves at
the end of the period plus the production in the period, generally on a
field-by-field basis or by a group of fields which are reliant on common
infrastructure. Costs used in the unit of production calculation comprise the
net book value of capitalised costs plus the estimated future field
development costs required to recover the commercial reserves remaining.
Changes in the estimates of commercial reserves or future field development
costs are dealt with prospectively.
Decommissioning and pre-funded amounts
Provisions for decommissioning are recognised when the Group has a present
legal or constructive obligation, which generally arises when a well is
drilled or equipment installed. The provision for future decommissioning is
calculated, based on future cash flows discounted at a pre-tax discount rate
to reflect risks specific to the costs. An amount equivalent to the initial
provision for decommissioning costs is capitalised and amortised over the life
of the underlying asset.
Changes in the estimated timing of decommissioning or decommissioning cost
estimates are dealt with prospectively by recording an adjustment to the
provision, and a corresponding adjustment to property, plant and equipment.
The unwinding of the discount on the decommissioning provision is included as
a finance cost.
The Group's interest in the amounts previously pre-funded for decommissioning
obligations are recognised in accordance with IAS 37 Provisions, Contingent
Liabilities and Contingent Assets and IFRIC 5 Rights to Interests arising from
Decommissioning, Restoration and Environmental Rehabilitation Funds. Where the
Group is not liable to pay decommissioning costs if the funds previously
deposited are not made available, the amounts previously pre-funded are not
recognised separately, but are included in the cost estimate of the residual
provision for decommissioning.
h) Property, plant and equipment assets other than oil
and gas assets
Property, plant and equipment other than oil and gas assets are stated at cost
less accumulated depreciation and any provision for impairment. Depreciation
is provided at rates estimated to write off the cost, less estimated residual
value, of each asset over its expected useful life as follows:
Office lease: straight-line over the lease term
Computer and office equipment: 33% straight-line
i) Foreign currencies
The US dollar is the functional and reporting currency of the Company and the
reporting currency of the Group. Transactions denominated in other currencies
are translated into US dollars at the rate of exchange at the date of the
transaction. Assets and liabilities in other currencies are translated into US
dollars at the rate of exchange at the reporting date. All exchange
differences arising from such translations are recorded in the Statement of
Comprehensive Income.
The results of entities with a functional currency other than the US dollar
are translated at the average rates of exchange during the period and their
statement of financial position at the rates ruling at the reporting date.
Exchange differences arising on translation of the opening net assets and on
translation of the results of such entities are recorded through the currency
translation reserve.
j) Taxation
Current tax - Angola
The activities relating to the Angolan branch are subject to tax in Angola.
Angolan tax is calculated on the basis of revenue rather than the profits of
the branch. Petroleum income tax is calculated on the basis of profit oil
which is valued by the tax reference prices determined by the Ministry of
Finance on a quarterly basis. From 1 January 2024 the group has applied the
foreign branch election that ringfences the profits in Angola to only be
subject to Angolan tax.
Current tax - United Kingdom
Tax is payable based upon taxable profit for the year. Taxable profit differs
from net profit as reported in the Statement of Comprehensive Income because
it excludes items of income or expense that are taxable or deductible in other
years and it further excludes items that are never taxable or deductible. Any
Group liability for current tax is calculated using tax rates that have been
enacted or substantively enacted by the reporting date.
k) Investments in subsidiaries
Investments in subsidiaries are carried at cost less accumulated impairment
losses. Investments in subsidiaries are assessed for impairment in line with
the requirements of IAS36 and, where evidence of non-recoverability is
identified, an appropriate impairment loss is recorded.
l) Leases
In accordance with IFRS16, the Group recognises a right-of-use asset and a
lease liability on the balance sheet at the lease commencement date. The Group
assesses the right-of-use asset for impairment when such indicators exist. At
the commencement date, the Group measures the lease liability at the present
value of the future unpaid lease payments at that date, discounted using the
interest rate implicit in the lease if that rate is readily available, or the
Group's incremental borrowing rate.
m) Financial instruments
Trade receivables
Trade receivables are recognised and carried at the original invoice amount
less any provision for expected credit loss (ECL). Other receivables are
recognised and measured at nominal value less any provision for ECL.
The Group applies the expected credit loss model in respect of trade
receivables. The Group tracks changes in credit risk and recognises a loss
allowance based on lifetime ECLs at each reporting date.
Amounts due from subsidiaries
Amounts due from subsidiaries are recognised and measured at nominal value
less any provision for ECL.
The Company applies the expected credit loss model in respect of amounts due
from subsidiaries. The Company tracks changes in credit risk and recognises a
loss allowance based on lifetime ECLs at each reporting date.
Cash and cash equivalents
Cash and cash equivalents consist of cash, bank deposits, and highly liquid
financial instruments with maturities of three months or less.
Restricted cash
Restricted cash consists of bank deposits which are subject to restrictions
due to legislation, regulation or contractual arrangements. Please see Note 16
for detailed disclosure.
Trade payables
Trade payables are stated at amortised cost.
Borrowings and loans
Interest bearing bank loans and overdrafts are recorded at the proceeds
received. Finance charges relating to securing the loans and overdrafts are
capitalised as part of the loan and amortised over the repayment term period
of the loan.
Financial liabilities and equity
Financial liabilities and equity instruments are classified according to the
substance of the contractual arrangements entered into. An equity instrument
is any contract that evidences a residual interest in the asset of the Group
after deducting all of its liabilities. Equity instruments issued by the
Company are recorded at the proceeds received net of direct issue costs.
Derivative financial instruments and hedging activities
Derivative financial instruments are measured at fair value and are not
designated as hedging instruments. Changes in fair value are recorded as a
gain or loss as within the Statement of Comprehensive Income.
n) Pension costs
The Group operates a number of defined contribution pension schemes. The
amount charged to the Statement of Comprehensive Income for these schemes is
the contributions payable in the year. Differences between contributions
payable in the year and contributions actually paid are shown as either
accruals or prepayments in the Statement of Financial Position.
o) Segment reporting
Operating segments are reported in a manner consistent with the internal
reporting provided to the chief operating decision maker (CODM). The CODM has
been identified as the Board of Directors. The Group currently operates only
in Africa and is supported by the United Kingdom head office which is not
deemed to be an operating segment as it does not generate any revenue outside
of the operations in Africa. As the Group only has one operating segment no
further breakdown has been provided.
p) Inventories
Oil Inventories are stated at the lower of cost or net realisable value. The
cost comprises direct materials, direct labour, overheads, and other charges
incurred in the production and storage of oil. Other inventories are stated at
the lower of cost and net realisable value. The cost of materials is the
purchase cost determined on a first-in first-out basis.
q) Share-based payments
Employees (including senior executives) of the Company receive remuneration in
the form of share-based payment transactions which are equity settled. The
cost of equity-settled transactions with employees is measured by reference to
the fair value at the date on which they are granted. The fair value is
determined by an external valuer using an appropriate pricing model.
The estimated cost of equity-settled transactions is recognised in the profit
and loss account as an expense, together with a corresponding increase in
equity. This expense and adjustment to equity is recognised over the period in
which the performance and/or service conditions are measured (the "vesting
period"), ending on the date on which the relevant participants become fully
entitled to the award (the "vesting date").
The cumulative expense recognised for equity-settled transactions at each
reporting date until the vesting date reflects the extent to which the vesting
period has expired and the Company's best estimate of the number of equity
instruments that will ultimately vest. The Income Statement charge or credit
for a period represents the movement in cumulative expense recognised as at
the beginning and end of that period.
The key areas of estimation regarding share-based payments are share price
volatility and estimated lapse rates, due to service conditions and
non-performance conditions not being met.
No adjustments are made in respect of market conditions not being met.
Similarly, the number of instruments and the grant-date fair value are not
adjusted, even if the outcome of the market condition differs from the initial
estimate.
Where the terms of an equity-settled award are modified, the minimum expense
recognised is the expense as if the terms had not been modified. An additional
expense is recognised for any modification, which increases the total fair
value of the share-based payment arrangement, or is otherwise beneficial to
the employee as measured at the date of modification.
Where an equity-settled award is cancelled, it is treated as if it had vested
on the date of cancellation, and any expense not yet recognised for the award
is recognised immediately. However, if a new award is substituted for the
cancelled award, and designated as a replacement award on the date that it is
granted, the cancelled and new awards are treated as if they were a
modification of the original award, as described in the previous paragraph.
The dilutive effect of outstanding options is reflected as additional share
dilution in the computation of earnings per share.
Although all awards are deemed to be equity settled, the Company may decide to
settle the awards in cash, without raising new share capital. If no new share
capital is issued to the market then the settlement of the award becomes a
true cash cost to the Company. The likelihood and magnitude of this
liability remain unknown until vest date, with the Company making the final
decision regarding settlement until near the vest date, and as such no
liability for this possible cash outflow is recognised in the accounts. Where
tax payments associated with share-based payments are required to be paid in
cash, the arrangement continues to be accounted for as equity settled.
2. Critical accounting judgements and estimates
In the application of the Group's accounting policies, which are described in
Note 1, the Directors are required to make judgements, estimates, and
assumptions about the carrying amounts of assets and liabilities that are not
readily apparent from other sources. The estimates and associated assumptions
are based on historical experience and other factors that are considered to be
relevant. Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognised in the period in which the
estimate is revised if the revision affects only that period, or in the period
of the revision and future periods if the revision affects both current and
future periods.
Judgements
The following are the critical judgements, apart from those involving
estimations (which are presented separately below), that the directors have
made in the process of applying the group's accounting policies and that have
the most significant effect on the amounts recognised in financial statements.
Business combinations and asset acquisitions
The Group has acquired working interests in producing oil blocks and judgement
is required to determine whether the acquisition should be accounted for as an
asset acquisition or a business combination. The Group assessed joint control,
as determined under IFRS11, does not exist among the contractor partners to
the arrangement because there are several combinations of partners who can
combine to meet the passmark vote for strategic and financial decisions.
No specific accounting guidance exists for an acquisition of a working
interest in a producing oil block where joint control does not exist and
management have determined the acquisition will be accounted for as an asset
acquisition under IFRS3 which requires an allocation of the consideration
across the identified assets and liabilities based on their relative fair
values.
See Note 24 for further information on the acquisitions of oil and gas assets
in the year.
Impairment of E&E assets
Management is required to assess oil and gas assets for indicators of
impairment and has considered the economic value of individual E&E assets.
E&E assets are subject to a separate review for indicators of impairment,
by reference to the impairment indicators set out in IFRS6, which is
inherently judgmental.
After reviewing the feasibility of the asset detailed in the Operations Review
and considering the key factors including: the extension to the current period
and further exploration work streams planned in 2025, management did not note
any impairment indicators that would result in a full impairment review to be
undertaken.
The Directors judgement was that a full impairment review wasn't required and
thus no impairments were recognised during the year by the Group.
Refer to Note 10 for further information on E&E assets.
Pre-funded decommissioning liabilities
Where decommissioning liabilities have been pre-funded by the contractor
group, a judgement was made that the contractor group would be discharged of
its obligation to decommission the field should the pre-funding not be made
available when due. As required IAS 37 Provisions, Contingent Liabilities and
Contingent Assets and IFRIC 5 Rights to Interests arising from
Decommissioning, Restoration and Environmental Rehabilitation Funds where the
Group is not liable to pay decommissioning costs if the funds previously
deposited are not made available, the amounts previously pre-funded are not
recognised separately, but are included in the cost estimate of the residual
provision for decommissioning. For further information refer to Note 29.
Estimates and assumptions
The key assumptions concerning the future, and other key sources of estimation
uncertainty at the reporting period that may have a significant risk of
causing a material adjustment to the carrying amounts of assets and
liabilities within the next financial year, are discussed below.
Contingent consideration
Contingent consideration in relation to the asset acquisitions of Blocks 3/05
and 3/05A in Angola is accounted for as a financial liability at fair value at
the date of the acquisition with any subsequent remeasurements recognised in
profit or loss. These fair values are based on risk adjusted future cash flows
discounted using the appropriate discount rates. Management utilise a scenario
based approach to estimate the likely contingent payments under each scenario
and then apply a probability to each scenario.
The sensitivity of the elements of contingent consideration to changes in the
probabilities of the scenarios and to the discount rates is disclosed in Note
21.
Key estimates relating to the Company Statement of Financial Position
Expected credit loss provision
IFRS9 requires the Company to make assumptions when implementing the
forward-looking expected credit loss (ECL) model. This model is required to
assess intercompany loan receivables held by Afentra plc.
Arriving at the ECL allowance involved considering different scenarios for the
recovery of the intercompany loan receivables, the possible credit losses that
could arise, and the probabilities of these scenarios occurring. The following
was considered: the exploration project risk, country risk, expected future
oil prices, the value of the potential reserves, the ability to sell the
project, and the ability to find a new farm-out partner. The Company's
intercompany receivable balance is $18.0 million after an ECL allowance of
$29.1 million. During the year the Company impaired its intercompany loan
receivable from Afentra (UK) Limited by $20.0 million. This impairment is
eliminated on consolidation and does not impact the Group results.
Refer to Note 14 for further information.
Investment in subsidiaries
If circumstances indicate that impairment may exist, investments in subsidiary
undertakings of the Company are evaluated using market values, where
available, or the discounted expected future cash flows of the investment. If
these cash flows are lower than the Company's carrying value of the
investment, an impairment charge is recorded in the Company. Where impairments
have been booked against the underlying exploration assets, the investments in
subsidiaries are written down to reflect their recoverable value. Evaluation
of impairments on such investments involves significant management judgement
and may differ from actual results.
As at 31 December 2024, Company investments in subsidiaries totalled $20.1
million. During the year the Company impaired its $2.0 million investment in
Afentra (UK) Limited. This impairment is eliminated on consolidation and does
not impact the Group results.
Refer to Note 12 for further information on investments in subsidiaries.
3. Revenue
Revenue is earned from the sale of crude oil produced in Angola,
Africa. Revenue by major customer during 2024 was 67% Maurel & Prom and
33% Trafigura (2023: 100% and nil respectively).
4. Cost of sales
2024 2023
$000 $000
Production costs 82,642 11,726
Depletion of property, plant and equipment - oil and gas 12,341 2,600
Depletion absorbed into inventories (241) (1,755)
Losses on oil price derivatives 1,914 -
Total cost of sales 96,656 12,571
All cost of sales relate to operations in Angola, Africa. Included in
production costs above is an expected credit loss provision of $3.6 million
(2023: nil).
5. Profit from operations
2024 2023
Profit from operations is stated after charging: Note $000 $000
Cost of sales 4 96,656 12,571
Staff costs 6 7,571 6,536
Reverse takeover related costs - 1,580
Depreciation of property, plant and equipment 11 302 280
Impact of foreign exchange on profit (63) 40
An analysis of auditor's remuneration is as follows:
Fees payable for the audit of the Group's annual accounts 294 131
Audit of the Company's subsidiaries pursuant to legislation 41 5
Total audit fees 335 136
Included in the fees payable for the audit of the Group's annual accounts is
$95,000 related to 2023. No non-audit services were received.
6. Employee information
The average number of employees (including executive and non-executive
directors) of the Group and Company was as follows:
Group Company
2024 2023 2024 2023
Corporate 15 10 - -
Non-executive 3 3 3 3
18 13 3 3
Group and Company employee costs during the year amounted to:
Group Company
2024 2023 2024 2023
$000 $000 $000 $000
Wages and salaries 4,766 4,669 272 212
Social security costs 1,483 622 13 15
Other pension costs 333 280 - -
Share-based payments 989 965 - -
7,571 6,536 285 227
Key management personnel include executive and non-executive Directors who
have been paid $2.6 million (2023: $2.8 million). See Remuneration Committee
Report of the Annual Report and Note 26 for additional detail. The highest
paid Director in the current year received $893k (2023: $782k).
A portion of the Group's staff costs and associated overheads are expensed as
pre-licence expenditure ($0.6 million) or capitalised ($46k). In 2024 this
amounted to $0.6 million (2023: $4.8 million).
7. Finance income and
costs
2024 2023
$000 $000
Finance income:
Interest earned on short-term deposits 106 240
Total finance income 106 240
2024 2023
$000 $000
Finance costs:
Interest on borrowings 5,684 1,764
Interest accretion on contingent consideration 2,305 -
Finance and arrangement fees 748 392
Interest expense for leasing arrangement 18 18
Bank charges 11 14
Fair value adjustment on contingent consideration 297 -
Other finance fees (63) 1,320
Total finance costs 9,000 3,508
All finance income and finance costs are measured at amortised cost, apart
from the fair value adjustment on contingent consideration which is measured
at fair value through profit and loss. No finance income or finance costs are
measure at fair value through other comprehensive income.
8. Taxation
The tax charge for the year is calculated by applying the applicable standard
rate of tax as follows:
2024 2023
$000 $000
Current tax
UK corporation tax at 25% (2023: 23.52%) - 1,799
Double tax relief - (1,799)
Foreign tax 11,564 1,799
Total current tax expense 11,564 1,799
Deferred income tax
Increase in deferred tax liability 1,661 -
Deferred tax expense 1,661 -
Income tax 13,225 1,799
Profit/(loss) before tax 63,043 (906)
Tax on loss on ordinary activities at standard UK corporation tax rate of 25% 15,761 (213)
(2023: 23.52%)
Effects of:
Expenses not deductible for tax purposes 1,913 444
Accelerated capital allowances 1,661 -
Deferred tax movement on provisions not provided - (79)
Tax losses carried forward 4,335 1,641
Other tax rates applicable outside the UK (10,383) -
Other tax adjustments (62) 6
Tax charge for the year 13,225 1,799
Current tax
An election under s18A CTA 2009 has been made by the Group to exempt profits
and disallow losses of its foreign permanent establishment in Angola. This
election is effective for the year commencing 1 January 2024 and all
subsequent accounting periods.
A significant proportion of the Group's profit before taxation arose in Angola
where the effective rate of taxation differs from that in the UK. In Angola,
current income tax is determined by applying a tax rate of 50% to the Profit
Oil lifted during the period. Accordingly, the Group's tax charge will
continue to vary according to the tax rates applicable to operations in Angola
where pre-tax profits arise.
Deferred tax
At the reporting date the Group had an unrecognised deferred tax asset of
$35.2 million (2023: $34.0 million) relating primarily to unused tax losses
and unutilised capital allowances in the United Kingdom with no expiry date.
No deferred tax asset has been recognised due to the uncertainty of future
profit streams against which these losses could be utilized.
Profits generated in Angola are subject to Angolan tax which is calculated on
a profit oil basis. A temporary difference arises due to accelerated capital
allowances being in excess of the unit of production depreciation applied by
the Group and consequently a deferred tax liability of $1.7 million has been
recognized during the year (2023:Nil).
9. Earnings/(loss) per share
Earnings per share (EPS) and loss per share (LPS) is calculated by dividing
the earnings attributable to ordinary shareholders by the weighted average
number of shares outstanding during the period. Diluted EPS/(LPS) is
calculated using the weighted average number of shares adjusted to assume the
conversion of all dilutive potential ordinary shares. Share options and awards
are not included in the dilutive calculation for loss making periods because
they are anti-dilutive.
The dilutive effect of share awards outstanding is the total possible award
number and does not take into account vesting conditions potentially not met,
or the Group's expectation that these awards will be settled net of tax, that
will reduce the impact of the dilutive effect of the awards.
2024 2023
$000 $000
Profit/(loss) for the year 49,818 (2,705)
Weighted average number of ordinary shares in issue during the year 224,922,157 220,053,520
EPS/(LPS) (US cents) 22.2 (1.2)
Total possible dilutive effect of share awards outstanding 23,488,622 -
Fully diluted average number of ordinary shares during the year 248,410,779 220,053,520
Diluted EPS/(LPS) (US cents) 20.1 (1.2)
10. Exploration and evaluation assets
Group
$000
Net book value at 1 January 2023 21,324
Additions during the year 500
Acquisitions during the year 43
Net book value at 31 December 2023 21,867
Additions during the year 612
Net book value at 31 December 2024 22,479
The Group's intangible assets as at 31 December 2024 comprise:
- Block 23 PSA, Angola: Afentra Angola Ltd 40% and Sonangol
(Operator) 60%.
- Block KON 19, Angola: Afentra Angola Ltd (Operator) 45%, ACREP
45%, and Enagol 10%.
- Odewayne PSA, Somaliland: Afentra (East Africa) Limited 34%
(fully carried), Genel Energy Somaliland Limited (Operator) 50%, and Petrosoma
16%.
11. Property, plant and equipment
Oil and gas assets Office Lease Computer and office equipment Total
Group $000 $000 $000 $000
Cost
At 1 January 2023 - 1,143 349 1,492
Modification during the year - 22 9 31
Acquisitions during the year 71,356 71,356
Additions during the year 6,066 - 18 6,084
Disposals during the year - - (5) (5)
At 31 December 2023 77,422 1,165 371 78,958
Acquisitions during the year 38,288 - - 38,288
Additions during the year 26,073 769 81 26,923
At 31 December 2024 141,783 1,934 452 144,169
Accumulated depreciation and impairment
At 1 January 2023 - (785) (167) (952)
Charge for the year (2,600) (190) (90) (2,880)
Disposals during the year - - 5 5
At 31 December 2023 (2,600) (975) (252) (3,827)
Charge for the year (12,341) (217) (85) (12,643)
At 31 December 2024 (14,941) (1,192) (337) (16,470)
Net book value at 31 December 2024 126,842 742 115 127,699
Net book value at 31 December 2023 74,822 190 119 75,131
The Group's oil and gas assets as at 31 December 2024 comprise:
- Block 3/05 PSA, Angola: Afentra Angola Ltd 30%, Sonangol
(Operator) 36%, M&P 20%, Etu Energias 10%, and NIS-Naftagas 4%.
- Block 3/05A PSA, Angola: Afentra Angola Ltd 21.33%, Sonangol
(Operator) 33.33%, M&P 26.68%, Etu Energias 13.33%, and NIS-Naftagas
5.33%.
See Note 24 for further information on the acquisitions to oil and gas assets
in the year.
The right-of-use asset (office lease) is depreciated on a straight-line basis
over the lease contract term. During 2024 the lease on our old office expired
and a new lease was entered into. The current lease term is for five years,
ending in 2029. See Note 1 and Note 22 for further details.
12. Investment in subsidiaries
Company
$000
At 1 January 2023 20,140
Additions during the year 965
At 1 December 2023 21,105
Additions during the year 989
Impairment (1,954)
At 31 December 2024 20,140
See Note 2 for further detail on the impairment assessment methodology. The
subsidiary undertakings of the Group as at 31 December 2024 are listed below:
Country of incorporation Class of shares held Type of ownership Proportion of Proportion of Nature of business
voting rights held 2024 voting rights held 2023
Afentra (UK) Limited United Kingdom ((4)) Ordinary Direct 100% 100% Exploration for oil
and gas
Afentra (Angola) Ltd ((1)) United Kingdom ((4)) Ordinary Direct 100% 100% Extraction of crude petroleum
Afentra (Northwest Africa) Limited Jersey, CI ((5)) Ordinary Direct 100% 100% Exploration for oil and gas
Afentra Holdings Limited ((2)) Jersey, CI ((5)) Ordinary Indirect 100% 100% Investment holding company
Afentra (East Africa) Limited ((3)) Jersey, CI ((5)) Ordinary Indirect 100% 100% Exploration for oil
and gas
Afentra (Offshore Developments) Ltd United Kingdom ((4)) Ordinary Direct 100% nil Extraction of crude petroleum
Afentra (Onshore Developments) Ltd ((6)) United Kingdom ((4)) 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)) Formerly Afentra Overseas Limited
13. Inventories
2024 2023
$000 $000
Group
Oil stock 1,415 9,658
Warehouse stock and materials 6,049 3,783
7,464 13,441
Oil stock inventory is stated at the lower of cost and net realisable
value. There were no write-downs of inventory during the year (2023: nil).
14. Trade and other receivables
Current Group Company
2024 2023 2024 2023
Restated
$000 $000 $000 $000
Trade receivables 123 90 - -
Amounts due from subsidiary undertakings - - 3,916 10,063
Underlift receivables - 3,123 - -
Joint venture receivables (1) 9,096 7,089 - -
Other receivables 218 218 200 212
Prepayments and accrued income 1,991 209 51 54
Total current trade and other receivables 11,428 10,729 4,167 10,329
(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.
Non-current Company
2024 2023
$000 $000
Amounts due from subsidiary undertakings 14,109 35,527
Total non-current trade and other receivables 14,109 35,527
Trade and other receivables consist of current receivables that the Group
views as recoverable in the short term.
Credit loss allowances for amounts due from subsidiary undertakings amount to
$29.1 million (2023: $9.1 million). Material adverse changes in the underlying
value of the Odewayne E&E asset could result in future credit losses on
our intercompany receivables in the future. Restructuring of the Company's
intercompany positions could result in the reversal of historical intercompany
credit losses. There is no impact to the Group Consolidated Statement of
Profit or Loss and Other Comprehensive Income or the Consolidated Statement of
Financial Position from credit losses on intercompany receivables, or the
subsequent reversal thereof.
The Directors consider that the carrying amount of trade and other receivables
is a reliable estimate of their fair value.
Transactions between subsidiaries are non-interest earning and are repayable
on demand, with the exception of the intercompany balance between Afentra plc
and Afentra (Angola) Limited, which is interest earning.
See Note 1 for details (Financial instruments - Trade receivables).
15. Cash and cash equivalents
Group Company
2024 2023 2024 2023
$000 $000 $000 $000
Cash at bank available on demand 46,877 14,725 8,267 4,413
Cash on hand 3 4 - -
46,880 14,729 8,267 4,413
16. Restricted funds
The restricted funds as at 31 December 2024 is a $7.9 million cash deposit
held in the Debt Service Reserve Account (DSRA) as required by the Reserve
Based Lending agreement. The amount held represents the next tranche of debt
principal and associated interest payments due. As at 31 December 2023, there
was $4.9 million held in a Citibank escrow account in respect of the Azule
acquisition.
17. Share capital
Ordinary shares (10p) $000
Authorised, called up, allotted and fully paid
At 1 January 2024 220,053,520 28,143
Issued on Share Options Exercised 6,102,470 771
At 31 December 2024 226,155,990 28,914
18. Reserves
Reserves within equity are as follows:
Share capital
Amounts subscribed for share capital at nominal value. There are no
restrictions on dividends or repayment of capital.
Share option reserve
Cumulative amounts charged in respect of employee share option arrangements.
See Note 25 for further details.
Currency translation reserve
The foreign currency translation reserve is comprised of movements that relate
to the retranslation of the subsidiaries whose functional currencies are not
designated in US dollars.
Retained earnings
Cumulative net gains and losses recognised in the Statement of Comprehensive
Income less any amounts reflected directly in other reserves.
19. Borrowings
The Group drew down on both the Reserve-based lending (RBL) and Working
Capital facilities in order to finance the INA, Sonangol, and Azule
acquisitions in 2023 and 2024. As at 31 December 2024, the Group has drawn
down $42.0 million on the RBL and repaid all amounts drawn down under the
Working Capital facility. The key terms of our debt facilities are shown
below:
RBL facility
· $51.8 million comprised of three separate drawdowns
· 5-year tenor to May 2028
· 8% margin over 3-month SOFR (Secured Overnight Financing Rate)
· Semi- annual linear amortisations
· DSRA commitment
· Key financial covenants of Afentra (Angola) Limited's Net Debt to
EBITDA < 3:1 and Group Liquidity Test >1.2x
Working Capital revolving committed credit facility
· $30.0 million maximum based on prior month oil inventories on
hand (100% undrawn as at 31 December 2024)
· 5-year tenor to May 2028
· 4.75% margin over 1-month SOFR
· Repayable with proceeds from liftings
2024 2023
$000 $000
Current
Reserve Based Lending facility 11,271 6,752
Working Capital facility - -
Total current borrowings 11,271 6,752
2024 2023
$000 $000
Non-current
Reserve Based Lending Facility 30,145 24,951
Total non -current borrowings 30,145 24,951
2024 2023
$000 $000
Borrowings
At 1 January 2024 31,703 -
Loan drawdowns 35,748 48,003
Interest charge 4,942 1,152
Repayments (32,306) (15,519)
Movement in unamortised debt arrangement cost 587 (2,545)
Interest accrued 742 612
At 31 December 2024 41,416 31,703
A charge is placed on Afentra (Angola) Ltd shares to Mauritius Commercial Bank
Limited as required by the terms of the debt facilities.
Net cash/(debt)
The table below details our net cash/(debt) as at 31 December 2024 and 2023:
2024 2023
$000 $000
Cash and cash equivalents 46,880 14,729
Restricted Funds 7,930 4,850
Borrowings (41,416) (31,703)
Lease liability (782) (155)
Net cash/(debt) 12,612 (12,279)
Changes in Net cash/(debt) for the periods presented in this report were as
follows:
Liabilities Assets
Borrowings Leases Sub total Cash/-restricted funds Total
Net cash as at 1 January 2023 - (337) (337) 30,584 30,247
Financing cashflows (45,066) - (45,066) - (45,066)
Lease payments - 164 164 - 164
Loan repayments 14,367 - 14,367 - 14,367
Other changes (1) - - - (11,005) (11,005)
Interest expense (2,156) - (2,156) - (2,156)
Interest payments 1,152 18 1,170 - 1,170
Net debt as at 31 December 2023 (31,703) (155) (31,858) 19,579 (12,279)
Financing cashflows (35,748) - (35,748) - (35,748)
Lease payments - 160 160 - 160
Loan repayments 27,364 - 27,364 - 27,364
Other changes (1) (587) (769) (1,356) 35,231 33,875
Interest expense (5,684) (18) (5,702) - (5,702)
Interest payments 4,942 - 4,942 - 4,942
Net cash as at 31 December 2024 (41,416) (782) (42,198) 54,810 12,612
(1) Other charges comprise:
- Borrowings: amortisation of prepaid finance fees
- Leases: accretion
- Cash: net funds received / spent
20. Trade and other payables
Group Company
2024 2023 2024 2023
Restated
$000 $000 $000 $000
Trade payables 1,046 929 117 909
Joint venture balances (1) 47,529 29,774 11 -
Amounts owed to subsidiary undertakings - - 27,517 27,540
Income taxes payable 1,802 - - -
Accruals 2,562 3,693 283 292
Total trade and other payables 52,939 34,396 27,928 28,741
(1) Comprised of our share of amounts owed to suppliers by the Operator of the
Joint Venture (on behalf of the contractor group) for unpaid invoices and
unbilled value of work done.
The Directors consider that the carrying amount of trade and other payables is
a reliable estimate of their fair value. Transactions between subsidiaries are
non-interest bearing and repayable on demand.
21. Contingent consideration
The movement in contingent consideration during 2024 and 2023 is detailed in
the table below:
Group
$000
As at 1 January 2023 -
Asset acquisitions 26,484
As at 31 December 2023 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
Contingent consideration is presented on the Consolidated Statement of
Financial Position as:
2024 2023
$000 $000
Contingent consideration
Current 5,535 4,621
Non-current 24,367 21,863
The current portion of contingent consideration relates to amounts paid during
the first quarter of 2025 based on thresholds met previously. Refer to Note 30
- Subsequent events.
Contingent consideration is payable to SNL, INA, and Azule on Blocks 3/05 and
3/05A:
INA acquisition (2023):
· Tranche 1: The contingent consideration for 3/05 relates to the
2023 and 2024 production levels and a realised Brent price hurdle up to an
annual cap of $2.0 million (now completed); and
· Tranche 2: The contingent consideration for 3/05A relates to the
successful future development of the Caco Gazela and Punja development areas,
with production and oil price hurdles. The maximum payable for these
development areas is $5.0 million.
· During the year, the Group paid contingent consideration of $1.1
million to INA related to 2023, during Q1 2025, an additional and final
payment of $1.2 million was made in respect of Tranche 1 related to 2024.
SNL acquisition (2023):
· The contingent consideration for the SNL acquisition is payable
annually over the next ten years from acquisition in each year where
production hurdle is reached and the realised oil price exceeds $65/bbl. The
maximum annual amount payable is $3.5 million, potentially resulting in a
total maximum payment of $35 million over ten years.
· During the year, the Group paid contingent consideration of $3.5
million to Sonangol in respect of 2023, with an additional payment of $3.5
million made in Q1 2025 in respect of 2024.
Azule acquisition (2024):
· Tranche 1: The contingent consideration for the Azule acquisition
includes up to $21 million over the next three years from 1 January 2023,
subject to certain oil price and Block 3/05 production hurdles, with an annual
cap of $7 million.
· Tranche 2: Further contingent considerations of up to $15 million
are linked to the successful future development of certain Block 3/05A
discoveries and associated oil price and production hurdles.
· During the year (as part of the completion) the Group paid
contingent consideration of $1.2 million to Azule in respect of 2023, as well
as an additional payment of $0.9 million in Q1 2025 in respect of 2024.
These contingent payments are measured at fair value and changes in fair value
are recognised in profit or loss.
Management have reviewed the contingent payments related to the above
acquisitions, which are dependent upon production levels, future oil price
hurdles, and future 3/05A developments. Judgement has been applied to the
probability of the circumstances occurring that would give rise to some or all
of the future payments. For each tranche of contingent consideration
Management have applied a multiple scenario approach to each tranche along
with the related weightings of probability resulting in an expected amount
payable. The base case scenario, which has the greatest weighting is based on
the Brent forward curve, with an average oil price of $72/bbl in 2025, $68/bbl
in 2026, and $67/bbl in 2027.
Management has applied a discount rate that approximates to the incremental
borrowing rate in arriving at a present value at the balance sheet date of the
probable future liabilities. The discount rate is based on a market rate of
9.1% (2023: 9.1%). Management is therefore satisfied with the liabilities
recorded at the balance sheet date in respect of these contingent future
events.
Applying Management's judgements discussed above, has resulted in contingent
consideration of $29.9 million. A 2% increase in the discount rate would
result in a reduction in the contingent consideration liability of $1.7
million. A 2% decrease in the discount rate would result in an increase in
contingent consideration of $1.9 million. The impact of removing the
scenarios that have an expectation the realised Brent price hurdles will not
be met (5% original weighting) and including a relative increase in the base
case scenarios would increase the contingent consideration by $0.7 million. In
the event of a sustained low oil price scenario, for any years where the
average Brent oil price is below $65/bbl, we expect that the price related
element of the non-current contingent consideration would be reversed.
22. Leases
During the year, the Group entered into a new lease on a new head office in
London following the expiration of the previous head office lease. The Group
recognizes a right-of-use asset in a consistent manner to its property, plant
and equipment (see Note 11).
The Company recognises lease liabilities in relation to the head office in
accordance with IFRS16. These liabilities are measured at the present value of
the total lease payments, discounted using the lessee's incremental borrowing
rate. The incremental borrowing rate applied to the lease liabilities was
9.74%.
The depreciation charge in 2024 was $217k (2023: $190k) (see Note 11) with an
interest expense in 2024 of $18k (2023: $18k) (see Note 7). Cash outflow of
principal payments in 2024 was $142k (2023: $227k).
Lease liabilities are presented in the statement of financial position as
follows:
2024 2023
$000 $000
Current 97 155
Non-current 685 -
782 155
Extension options are included in the lease liability when, based on
Management's judgement, it is reasonably certain that an extension will be
exercised. As at 31 December 2024, the contractual maturities of the Company's
lease liabilities are as follows:
Within one year Between one to two years Over two years Total Interest Carrying amount
$000 $000 $000 $000 $000 $000
Group
Lease liability 172 229 592 993 (211) 782
23. Financial instruments
Capital risk and liquidity risk management
The Group and Company are not subject to externally imposed capital
requirements. The capital structure of the Group and Company consists of cash
and cash equivalents held for working capital purposes and equity attributable
to the equity holders of the parent, comprising issued capital, reserves and
retained earnings as disclosed in the Statement of Changes in Equity. The
Group and Company use cash flow models and budgets, which are regularly
updated, to monitor liquidity risk.
Details of the significant accounting policies and methods adopted, including
the criteria for recognition, the basis of measurement, and the basis on which
income and expenses are recognised, in respect of each material class of
financial asset, financial liability and equity instrument are disclosed in
Note 1 to the financial statements.
Due to the short-term nature of these assets and liabilities, such values
approximate their fair values as at 31 December 2024 and 31 December 2023.
Carrying amount
2024 2023
Restated
Group $000 $000
Financial assets at amortised cost
Cash and cash equivalents 46,880 14,729
Restricted funds 7,930 4,850
Trade and other receivables 9,437 10,520
Total 64,247 30,099
Financial liabilities at amortised cost
Trade and other payables 52,939 34,396
Borrowings due within one year 11,271 6,752
Non-current borrowings 30,145 24,951
Total 94,355 66,099
Of the above assets and liabilities due to the short-term nature, carrying
amounts approximate their fair values at 31 December 2024 and 31 December 2023
except for non-current borrowings, for which the fair value is based upon a
market rate of 9.1% and therefore having a fair value of $34.7 million (2023:
$27.4 million) against the carrying amount of $30.1 million (2023: $25.0
million).
The Group carries the assets and liabilities below at fair value through
profit and loss.
Fair value
2024 2023
Group $000 $000
Financial assets at fair value
Derivative hedge assets 196 -
2024 2023
Financial liabilities at fair value $000 $000
Derivative hedge liabilities 1,279 -
Contingent consideration 29,902 26,484
Total 31,181 26,484
Derivative hedge assets and liabilities are financial assets and liabilities
measured through profit or loss with a level 2 fair value hierarchy
classification. In the normal course of business the Group enters into
derivative financial instruments to manage its exposure to oil price
volatility.
Contingent consideration is a financial liability measured through profit or
loss with a level 3 fair value hierarchy classification. Contingent
consideration was valued using a discounted cash flow and scenario analysis
method. The main inputs in the valuation process were discount rates, forecast
realised crude oil prices and future production. See Note 21 for details of
the sensitivity analysis performed.
There were no transfers between fair value levels during the year.
Financial risk
We are exposed to several financial risks, including oil and gas price
volatility, credit risk, liquidity risk, foreign currency risk, and interest
rate risk. Our policy is to reduce our exposure to these risks, where
possible, within boundaries deemed appropriate by our management team. This
may include the use of derivative instruments. Oil price volatility may also
impact our contingent consideration liability, where market price hurdles have
been included in the terms.
Interest rate risk
Our exposure to interest rate risk relates mainly to our floating rate
borrowings and balances of surplus funds placed with financial institutions.
We monitor this risk and will implement our hedging policy if and when
required.
Interest rate sensitivity analysis
The sensitivity analysis below has been determined based on the exposure to
interest rates at the reporting date and assumes the amount of the balances at
the reporting date were outstanding for the whole year. A 100 basis point
change represents management's estimate of a possible change in interest rates
at the reporting date. If interest rates had been 100 basis points higher or
lower, and all other variables were held constant, our profits and equity
would be impacted as follows:
Increase Decrease
2024 2024 2024 2023
$000 $000 $000 $000
Cash and cash equivalents 469 147 (469) (147)
Borrowings (414) (317) 414 317
Foreign currency risk
The Company's functional currency is the US dollar, being the currency in
which the majority of the Group's expenditure is transacted. Small elements of
its management, services and treasury functions are held and transacted in
Pounds Sterling, Euro or Angolan Kwanza. The Group does not enter into
derivative transactions to manage its foreign currency. Foreign currency risk
is not considered material to the Group and Company.
The table below details our financial assets and liabilities that are held in
currencies other than US$:
Financial assets
Group
2024 2023
$000 $000
Cash and cash equivalents
- US$ 45,951 1 13,222
- GBP 885 1,507
- EUR 1 -
- AOA 43 -
46,880 14,729
Group
2024 2023
Restated
$000 $000
Trade and other receivables
- US$ (1) 9,359 10,231
- GBP 78 289
9,437 10,520
1This includes an ECL allowance of $3.6 million relating to our share of an
aged balance receivable by the joint venture.
Financial liabilities
Group
2024 2023
Restated
$000 $000
Trade and other payables
- US$ 50,854 31,351
- GBP 1,867 3,045
- EUR 217 -
- AOA 1 -
52,939 34,396
Credit risk management
The Group has to manage its currency exposures and the credit risk associated
with the credit quality of the financial institutions in which the Group
maintains its cash resources. At the year end the Group held approximately
98.0% (2023: 89.8%) of its cash in US dollars. Most of the counterparties are
creditworthy financial institutions and, as such, we do not expect any
significant loss to result from non-performance by such counterparties. The
Group continues to proactively monitor its treasury management to ensure an
appropriate balance of the safety of funds and maximisation of yield.
Trade and other receivables are non-interest bearing. The Group does not hold
any collateral as security and the Group does not hold any significant
allowance in the impairment account for trade and other receivables as they
relate to counterparties with no default history. Default is considered to be
where payments have been outstanding for more than 60 days. Apart from
derivative hedge assets there are no financial assets held at fair value.
The Group's maximum exposure to credit risk is $66.2 million, based on our
cash and cash equivalents, restricted cash, and trade and other receivables.
Our cash balances are held with creditworthy financial institutions and there
has been no significant increase in the credit risk of our debtors during the
period.
Liquidity and interest rate tables
Management reviews budgeted cash forecasts regularly to ensure there is enough
cash on hand to repay financing obligations and operational expenses as they
become due. Additionally, the Group has access to a rotating Working Capital
Credit Facility of up to $30 million. The following table details the
remaining contractual maturity of our financial assets and liabilities, based
on the undiscounted cash flows of on the earliest date on which the Group can
be required to pay.
The table includes both interest and principal including cashflows on actual
contractual arrangements.
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 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 - -
Contingent consideration 5,535 - 24,367 29,902 - -
Derivative financial instruments:
Forward foreign exchange contracts - outflow 1,279 - - 1,279 - -
Forward foreign exchange contracts - inflow (196) - - (196) - -
15,594 55,137 62,659 133,390 11,810 42,020
As at 31 December 2023 (Restated)
Non-derivative financial liabilities:
Borrowings 5,065 5,413 34,901 45,379 11,743 33,636
Trade and other payables 76 29,774 - 29,850 - -
5,141 35,187 34,901 75,229 11,743 33,636
24. Asset acquisitions
During the year the Group completed the acquisition of further interests in
Block 3/05 (12%) and Block 3/05A (16%) offshore Angola for a net $28.4 million
payment with subsequent contingent payments estimated at $5.4 million. See
Note 21 for details of the contingent consideration.
Block 3/05 Block 3/05A Total
$000 $000 $000
Consideration
Initial consideration 47,500 1,000 48,500
Actual adjustments from effective date (15,151) (6,096) (21,247)
Contingent consideration - Extension of Block 3/05 licence 1,175 - 1,175
Consideration paid 33,524 (5,096) 28,428
Contingent consideration - Oil price and production linked future developments 1,415 4,022 5,437
Total consideration 34,939 (1,074) 33,865
Net assets
Oil and gas properties 36,051 2,237 38,288
Other non-current assets (decommissioning fund) 52,166 - 52,166
Non-current provision (decommissioning) (52,166) - (52,166)
Inventory (oil stock) 11,036 429 11,465
Joint venture partner balance (4,092) 2,961 (1,131)
Joint venture working capital (1) (8,056) (6,701) (14,757)
Net assets acquired 34,939 (1,074) 33,865
(1)Comprised of our share of the working capital balances of the Operator of
the Joint Venture which include accounts payable, accruals, accounts
receivable, and non-oil inventory.
The Group performed an assessment of the Azule acquisition to determine
whether the acquisition should be accounted for as an asset acquisition or a
business combination. Consistent with the acquisitions in 2023 from INA and
SNL, the Group established that, under IFRS11, joint control does not exist,
and therefore the Group have deemed the acquisition to qualify as an
acquisition of a group of assets and liabilities, and not of a business.
Furthermore, the Group gave regard to guidance included under IFRS11- Joint
Arrangements, and will account for its share of the income, expenses, assets,
and liabilities from the acquisition date.
The total consideration was allocated to assets and liabilities based on their
relative fair values.
25. Share-based payments
The table below details the movement in share option reserve:
2024 2023
$000 $000
At 1 January 965 -
Arising in the year 989 965
Options exercised (1,112) -
At 31 December 842 965
During the year, Afentra plc operated four share incentive schemes:
· Founder Share Plan (FSP)
· Long-term Incentive Plan (LTIP)
· Executive Director Long-term Incentive Plan (EDLTIP)
· Non-Executive Director Option plan (NEDP)
Details of the schemes are summarised below:
Founder Share Plan
Under the FSP, the founders are eligible to receive 15% of the growth in
returns of the Company over the five year period commencing from its admission
to AIM on 16 March 2021. The awards are expressed as a percentage of the total
maximum potential award, being 10% of the Company's issued share capital.
Should a hurdle of doubling the Total Shareholder Return (TSR) over the
five-year period be met, the awards will be converted into nil cost options
over ordinary shares of 10p each in the share capital of the Company.
For the purpose of determining the fair value of an award, the following
assumptions have been applied and a valuation calculation run through the
Monte Carlo Model:
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 2024 is 14
months.
At 31 December 2024 no options were exercisable.
During 2024 the first measurement date was reached and 10,235,080 nil cost
options were vested and exercised. The share price at time of exercise was
£0.39.
Long-term Incentive Plan
The awards issued under the LTIP are nil-cost options to acquire ordinary
shares in the Company, subject to a performance condition. For the purpose of
determining whether the condition has been met, the TSR of the Company is
measured over a three year performance period, commencing at the grant date.
The awards have been valued using the Monte Carlo model, which calculates a
fair value based on a large number of randomly generated simulations of the
Company's TSR.
Award date 16 Mar 21 1 Nov 22 30 Sep and 3 Oct 22 1 Mar 23 6 and 13 Dec 23 20 Feb and 1 Mar 24 24 Oct 24 19 Dec 24
Weighted average share price at grant date £0.15 £0.30 £0.30 £0.28 £0.30 £0.39 £0.50 £0.49
Risk free rate 1.90% 4.20% 4.23% 3.75% 3.92% 4.12% 3.87% 4.21%
Dividend yield 0% 0% 0% 0% 0% 0% 0% 0%
Volatility of Company share price 40% 54% 54% 55% 54% 52% 52% 52%
Weighted average fair value £0.04 £0.16 £0.16 £0.15 £0.16 £0.21 £0.27 £0.25
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:
2024 2023
No. No.
At 1 January 2,774,439 1,893,460
Granted 1,059,036 880,979
Forfeited (557,521) -
Exercised (1,251,460) -
At 31 December 2,024,494 2,774,439
The weighted average exercise price of outstanding options is £nil.
The weighted average remaining contractual life as at 31 December 2024 is 20
months.
Executive Director LTIP
The awards issued under the EDLTIP are nil-cost options to acquire ordinary
shares in the Company, subject to a performance condition. For the purpose of
determining whether the condition has been met, the TSR of the Company is
measured each year over a three year performance period, commencing at the
grant date. The awards have been valued using the Monte Carlo model, which
calculates a fair value based on a large number of randomly generated
simulations of the Company's TSR.
Award date 2024
Weighted average share price at grant date £0.57
Exercise price nil
Risk-free rate 4.05%
Dividend yield 0%
Volatility of Company share price 49%
Fair Value per award £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.
2024 2023
No. No.
At 1 January - -
Granted 3,228,373 -
At 31 December 3,228,373 -
The weighted average exercise price of outstanding options is nil.
The weighted average remaining contractual life as at 31 December 2024 is 30
months.
Non-Executive Director Option plan (NEDP)
The awards issued under the NEDP are options to acquire ordinary shares in the
Company at a set price. These options are subject only to a continued
employment condition. The awards will vest three years after grant date and
participants can exercise these awards up to the ten year anniversary of the
grant date.
The awards have been valued using the Black-Scholes option pricing formula.
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.
2024 2023
No. No.
At 1 January - -
Granted 4,500,000 -
At 31 December 4,500,000 -
The weighted average exercise price of outstanding options is nil.
The weighted average remaining contractual life as at 31 December 2024 is 30
months.
Employees (including Senior Executives) of the Company receive remuneration in
the form of share-based payment transactions which are equity settled. The
cost of equity-settled transactions with employees is measured by reference to
the fair value at the date on which they are granted. The fair value is
determined by an external valuer using an appropriate pricing model. Although
these awards are deemed to be equity settled, an employee may elect to receive
their entitled settlement, in whole or in part, in cash.
The estimated cost of equity-settled transactions is recognised in the profit
and loss account as an expense, together with a corresponding increase in
equity. This expense and adjustment to equity is recognised over the period in
which the performance and/or service conditions are measured (the 'vesting
period'), ending on the date on which the relevant participants become fully
entitled to the award (the 'vesting date').
The cumulative expense recognised for equity-settled transactions at each
reporting date until the vesting date reflects the extent to which the vesting
period has expired and the Company's best estimate of the number of equity
instruments that will ultimately vest. The Income Statement charge for a
period represents the movement in cumulative expense recognised as at the
beginning and end of that period.
The key areas of estimation regarding share-based payments are share price
volatility and estimated lapse rates due to service conditions and
non-performance conditions not being met.
No adjustments are made in respect of market conditions not being met.
Similarly, the number of instruments and the grant-date fair value are not
adjusted, even if the outcome of the market condition differs from the initial
estimate.
Where the terms of an equity-settled award are modified, the minimum expense
recognised is the expense as if the terms had not been modified. An additional
expense is recognised for any modification, which increases the total fair
value of the share-based payment arrangement, or is otherwise beneficial to
the employee as measured at the date of modification.
Where an equity-settled award is cancelled, it is treated as if it had vested
on the date of cancellation, and any expense not yet recognised for the award
is recognised immediately. However, if a new award is substituted for the
cancelled award, and designated as a replacement award on the date that it is
granted, the cancelled and new awards are treated as if they were a
modification of the original award, as described in the previous paragraph.
In April 2024 a number of share option awards vested which were settled
through both the issue of shares and the payment of cash to HMRC for the
related taxes. In the interim accounts for the six-month period ended 30 June
2024, the cash tax payment was treated as a "cash settled" share-based
payment, and an expense of $2.3 million was recognised in other administrative
expenses. As part of the preparation of the year-end financial statements, it
was identified that as Afentra had an obligation (rather than a choice) to
settle these employment related taxes in cash, IFRS 2.33 requires that the
transaction is classified in its entirety as an equity-settled share-based
payment transaction. Accordingly, in the full year results this transaction
has been recognised within equity, as $2.3 million directly to retained
earnings. In the interim accounts for the period to 30 June 2025, the profit
after tax for 30 June 2024 comparative period will be restated from the
previously disclosed $22.2 million to $24.5 million to reflect this impact of
this reclassification.
The dilutive effect of outstanding options is reflected as additional share
dilution in the computation of earnings per share.
26. Related party transactions
Details of Directors' remuneration, which comprise key management personnel,
are provided below:
Group Company
2024 2023 2024 2023
$000 $000 $000 $000
Short-term employee benefits 2,521 2,684 351 212
Defined contribution pension 128 120 - -
Share-based payments 897 843 275 -
3,546 3,647 626 212
Further information on Directors' remuneration is detailed in the Remuneration
Committee Report of the Annual Report 2024. The Executive Directors (three)
exercised share options during the year.
The Company's subsidiaries are listed in Note 12. The following table provides
the balances which are outstanding with subsidiary undertakings at the balance
sheet date:
2024 2023
$000 $000
Amounts due from subsidiary undertakings 18,025 45,590
Amounts due to subsidiary undertakings (27,517) (27,540)
Amounts due from subsidiary undertakings are interest free apart from the
amount receivable from Afentra (Angola) Limited which earns interest at a rate
equal to the relevant US Treasury Bill rate plus a margin of 0.5%. The average
interest rate on the loan to Afentra (Angola) Limited was 5.6% in 2024 (2023:
2.8%). During the year the Company recognised interest receivable from Afentra
(Angola) Limited of $0.79 million (2023: $0.64 million).
The Group and Company has no other disclosed related party transactions.
27. Derivative assets and liabilities
2024 2023
$000 $000
Derivative assets 196 -
Derivative liabilities (1,279) -
The company manages its exposure to oil price risk through commodity price
hedging. In 2024, Afentra hedged 70% of its sales volumes through a
combination of put options and collar structures. The hedge portfolio
consisted of put options ranging included $70 to $80 per barrel covering 70%
of sales volumes and call option of $90 per barrel covering 29% of sales
volumes.
28. Commitments
The Parent Company has provided a guarantee over the debt of Afentra (Angola)
Limited and letters of support to Afentra (UK) Limited, Afentra (Onshore
Developments) Limited, Afentra (Offshore Developments) Limited, Afentra (East
Africa) Limited, and Afentra Holdings Limited.
29. Restatement of decommissioning provision and associated
pre-funding asset
We have restated the Group's balance sheet to reflect a change in our
accounting for the pre-funded liability to settle the future decommissioning
obligation associated with Block 3/05, and the treatment of joint venture
receivable and payable balances.
As of 31 December 2023, the pre-funding asset was presented as a non-current
asset to be recovered from the Concessionaire and the decommissioning
liability as a non-current liability on the balance sheet. Following
investigation, independent and authoritative information was obtained during
the second half of 2024 that provided certainty that the contractual position
was that the contractor group would be discharged of its obligation to
decommission the field should the pre-funding not be made available when
due. The information received during 2024 confirmed the legal position at 31
December 2023, namely that the Group will not be liable for the
decommissioning costs if the funds are not made available when due, and
accordingly we have restated the 2023 balance sheet, in line with the
requirements of IFRIC 5 and IAS 37, and the measurement of the decommissioning
liability, including our evaluation of any future outflows, has been reduced
by the amount already pre-funded by the contractor group. The decommissioning
liability and the associated pre-funding asset were initially recognised
during 2023 and that is the earliest period impacted.
As of 31 December 2023, the Group's $7 million share of the Block 3/05 joint
venture receivable balance was offset against the payables position as it was
anticipated that it would be settled net of the larger joint venture payable
balance. Following investigation, information was obtained during the second
half of 2024 that confirmed that the contracting group did not have the legal
right to offset these separate receivable and payable balances. Consequently,
we have restated the 2023 balance sheet. There is a consequential impact on
the 2023 consolidated statement of cash flows, and the movement in the
respective working capital balances has also been restated. There is no impact
on the 2023 profit or equity position.
The table below highlights the impact of the restatement on the 31 December
2023 and 30 June 2024 consolidated statements of financial position (there is
no impact to the Statement of Comprehensive Income):
31 December 2023 30 June 2024
Financial statement line item affected: As previously reported Impact of restatement Restated As previously reported Impact of restatement Restated
$000 $000 $000 $000 $000 $000
Trade and other receivables 3,640 7,089 10,729 46,443 13,593 60,036
Total current assets 36,660 7,089 43,749 75,958 13,593 89,551
Other non-current assets (Decommissioning fund) 76,973 (76,973) - 130,882 (130,882) -
Total non-current assets 173,971 (76,973) 96,998 269,164 (130,882) 138,282
Total assets 210,631 (69,884) 140,747 345,122 (117,289) 227,833
Trade and other payables 27,307 7,089 34,396 54,941 13,593 68,534
Total current liabilities 38,835 7,089 45,924 96,964 13,593 110,557
Provisions 77,010 (76,973) 37 130,919 (130,882) 37
Total non-current liabilities 123,824 (76,973) 46,851 178,087 (130,882) 47,205
Total liabilities 162,659 (69,884) 92,775 275,051 (117,289) 157,762
Total equity and liabilities 210,631 (69,884) 140,747 345,122 (117,289) 227,833
Contingencies
The latest approved estimate of the total cost for the contractor group to
abandon the field at the end of the contract period in 2040 is $574 million
(Afentra's share is $172 million), of which $554 million (Afentra's share is
$166 million) has been pre-funded by the contractor group. The amounts
pre-funded were deposited between 2004 and 2012 and substantially did not
accrue interest on consequence of the manner in which they were held. The
funds were deposited with the Concessionaire and will not be released to the
contractor group until required for the purposes of abandoning the field.
On the basis that we consider that the contractor group will be discharged of
its obligation to decommission, we do not forecast any further expenditure
occurring over and above that which has been pre-funded ($554 million gross).
We have therefore accounted for any future possible expenditure as a
contingent liability as, while not considered probable, there remains a remote
possibility of any future increase to the estimated cost to abandon the field
or any unfunded balance being called by the Concessionaire. Commercial
sensitivities associated with any future increase in the cost to decommission
the field and interest accrued precluded a range of potential estimates being
disclosed.
30. Subsequent events
Subsequent to the Balance Sheet date of 31 December 2024, the following
business deliverables occurred:
· During Q1 2025, the Group made contingent consideration payments
of $3.5 million, $1.2 million, and $0.9 million to Sonangol, INA, and Azule
respectively.
· On 28 March 2025, the Group made a scheduled redetermination
payment on its RBL facility of $7.9 million comprised of $5.3 million debt
principal and $2.6 million accrued interest.
· On 19 February 2025, Afentra provided an update on its latest
Competent Person's Report (CPR) for Block 3/05. As of 31 December 2024, total
net 2P working interest reserves stand at 34.2 million barrels of oil (mmbo),
(gross 114 mmbo). Since the previous CPR in June 2023, gross production of
approximately 11 mmbo was offset by a gross increase in reserves of 15.4 mmbo
resulting in a reserve replacement ratio of 140% over the 18-month period.
Contingent resources on Block 3/05 have also increased since the last CPR with
net working interest 2C resources of 13.8 mmbo (gross 46 mmbo)
· On 24 February 2025, Afentra announced the formal approval by
Presidential Decree of the onshore licence KON15, the formal signing of the
contract occurred on 07 April 2025. Under the terms of the KON15 award,
Afentra has secured a 45% non-operating interest in the block, alongside
Sonangol who will be block operator.
Definitions and Glossary of Terms
$
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
ABC
Anti-Bribery and Corruption
AIM
AIM, a SME Growth market of the London Stock Exchange
AGM
Annual General Meeting
ALNG
The Angola LNG project
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)
Articles
The Articles of Association of the Company
Block
3/05
The contract area described in and covered by the Block 3/05 PSA
Block
3/05A
The contract area described in the Block 3/05A PSA
Block
23
The contract area described in and covered by the Block 23 PSA
Board
The Board of Directors of the Company
bbls
Barrels of oil ('k-' / 'mm-' / 'bn-' for thousand / million / billion)
Bopd
Barrels of oil per day ('k-' / 'mm-' for thousand / million)
Bwpd
Barrels water injected per day
CCRA
Climate Change Risk Assessment
CODM
Chief operating decision maker
Companies Act or Companies Act The Companies Act 2006, as
amended2006
Company
Afentra plc
CPR
Competent Persons Report
CSR
Corporate Social Responsibility
D&P
Development and production assets
DSRA
Debt service reserve account
Directors
The Directors of the Company
ECL
Expected credit loss
E&E
Exploration and evaluation assets
EDLPTIP
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
EITI
Extractive Industries Transparency Initiative
Entitlement
Reserves
Entitlement production/reserves refers to the share of
oil/gas that a company is entitled to receive based on fiscal and contractual
agreements governing the specific asset.
EOR
Enhanced Oil Recovery
ERCe
ERC Equipoise Limited (author of the Competent Person's Report)
ESP
Electrical Submersible Pumps
Farm-in &
farm-out
A transaction under which one party (farm-out party) transfers
part of its interest to a contract to another party (farm-in party) in
exchange for a consideration which may comprise the obligation to pay for some
of the farm-out party costs relating to the contract and a cash sum for past
costs incurred by the farm-out party
FEED
Front-End Engineering Design
FID
Final investment decision
FSO
Floating storage and offloading
FSP
Founders' Share Plan
G&A
General and administrative
GBP
Pounds sterling
G&G
Geological and geophysical
Genel
Energy
Genel Energy Somaliland Limited
GHG
Greenhouse gases
GOR
Gas Oil Ratio
Group
The Company and its subsidiary undertakings
H&S
Health and Safety
HSSE
Health, Safety, Security and Environment
hydrocarbons
Organic compounds of carbon and hydrogen
IAS
International Accounting Standards
IFRS
International Financial Reporting Standards
INA
INA-Indstrija Nafte d.d
IOC
International oil company
IPCC
Intergovernmental Panel on Climate Change
JV
Joint venture
JOA
Joint operating agreement
k
Thousands
km
Kilometre(s)
km2
Square kilometre(s)
KPIs
Key performance indicators
lead
Indication of a potential exploration prospect
LiDAR
Light Detection and Ranging
Lifex
Life extension capex
LNG
Liquefied Natural Gas
LSE
London Stock Exchange
LTI
Lost time Injury
LTIP
Long-term incentive plan
LWI
Light Well Intervention
M&A
Mergers and acquisitions
m
Metre(s)
MVO
Market Value Options
NED
Non-Executive Director
NEDP
Non-Executive Director Option plan
NFA
No Further Activity - forecast without new Capex invested
NGO
Non-governmental organisation
NOCs
National oil company
O&G
Oil and gas
OECD
Organisation for Economic Cooperation and Development
OIW
Oil in water
Op.
Operator
Opex
Operating expenditure
Opex/bbl
Gross operating expenditure / 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
RTO
Reverse takeover (pursuant to Rule 14 of the AIM Rules)
SPA
Sale and Purchase Agreements
Seismic
Data, obtained using a sound source and receiver, that is processed to provide
a representation of a vertical cross-section through the subsurface layers
SOFR
Secured Overnight Financing Rate
Shares
10p ordinary shares
Shareholders
Ordinary shareholders of 10p each in the Company
Subsidiary
A subsidiary undertaking as defined in the 2006 Act
Sonangol
Sonangol Pesquisa e Producao S.A.
Sonangol
EP
Sociedade Nacional de Combustíveis de Angola, Empresa Pública
TCFD
Task force on Climate-related Financial Disclosure
Third and Fourth Period
Exploration terms: Third Period is to May 2025 with a work
commitment of 500km 2D seismic acquisition; Fourth Period is to October 2026
with a work commitment of 1,000km 2D seismic acquisition and one exploration
well
Trafigura
Trafigura PTE
TRIF
Total Recordable Incident Frequency
TSR
Total Shareholder Return
United Kingdom or UK
The United Kingdom of Great Britain and Northern
Ireland
Working Interest or
WI A Company's
equity interest in a project before reduction for royalties or production
share owed to others under the applicable fiscal terms
ZRF
Zero Routine Flaring
1 (#_ftnref1) Net 2024 investment reflects spending attributable to
Afentra's working interests in Block 3/05 and 3/05A during the year, both pre
and post the Azule transaction completion in May 2024, and does not reflect
pro-rata spend based on Afentra's current working interests.
2 (#_ftnref2) Net 2024 investment reflects spending attributable to
Afentra's working interests in Block 3/05 and 3/05A during the year, both pre
and post the Azule transaction completion in May 2024, and does not reflect
pro-rata spend based on Afentra's current working interests.
3 (#_ftnref3) Number reflects Afentra's working interest in Block 3/05
& Block 3/05A.
4 (#_ftnref4) Awaiting completion of transaction.
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. END FR EZLBLEZLZBBXRecent news on Afentra
See all newsREG - Afentra PLC - Final Results
AnnouncementREG - Afentra PLC - Chair Succession and Board Changes
AnnouncementREG - Afentra PLC - FSP, LTIP Award & Director/PDMR Dealings
AnnouncementREG - Afentra PLC - Responds to Media Speculation
AnnouncementREG - Afentra PLC - Award of KON 15 License - Onshore Angola
Announcement