REG - Tullow Oil PLC - Full Year Results
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RNS Number : 1115C Tullow Oil PLC 28 April 2026
Tullow oil PLC - 2025 FULL Year Results
Significant foundations laid in 2025, including comprehensive refinancing
Operational focus yielding strong performance in the first quarter of 2026
Significant opportunities for value creation through operational delivery and oil price leverage
28 April 2026 - Tullow Oil plc (Tullow), the independent oil and gas
exploration and production group (Group), announces its Full Year Results for
the year ended 31 December 2025. Details of a management presentation and
webcast that will be held at 09:00 today are available on the last page
(#_Management_Presentation_-) of this announcement or visit the Group's
website: www.tullowoil.com (http://www.tullowoil.com)
Ian Perks, Chief Executive Officer, Tullow Oil plc, commented:
"Throughout 2025 and into early 2026, we have delivered against a clear set of
strategic priorities to position Tullow for long-term success. This began with
the consolidation of our business to focus on our high-value assets in Ghana,
with the sale of our non-core assets in Gabon and Kenya, alongside significant
cost reductions. These efforts positioned the company strongly for the
successful refinancing, which completed earlier this month with overwhelming
support from our creditors. This transaction provides Tullow with the strong
financial foundation and flexibility required to deliver value for
stakeholders.
"Operationally, 2026 has started strongly, with momentum building across the
business. We are particularly encouraged by the positive early results from
our Ghana drilling campaign, which highlight the quality and potential of our
world-class assets. A key milestone has been the agreement to purchase the TEN
FPSO, a value-accretive acquisition that significantly improves the field's
economics by eliminating lease costs and providing an opportunity to capture
operating cost savings. Additionally extending the Jubilee and TEN petroleum
agreements to 2040, and higher oil prices have further strengthened our
platform for sustainable growth.
"Looking ahead, we have four more wells scheduled to come onstream in 2026,
and the continued interpretation of 4D and Ocean Bottom Node (OBN) seismic
data which will support future drilling campaigns at Jubilee and TEN, driving
reserves growth and unlocking further value from our assets. Our focus remains
on improving operational performance and executing our business plan."
2025 FULL YEAR RESULTS(1)
· Group working interest oil and gas production averaged 40.4 kboepd
(2024: 51.5 kboepd).
· Revenue of $847 million (2024: $1,287 million), including $19
million hedge costs (2024: $74 million).
· Capital expenditure(2) of $166 million (excluding $29 million in Gabon)
(2024: $179 million, excluding $52 million in Gabon) and decommissioning
expenditure including cash provisioning for future decommissioning of $17
million (2024: $60 million).
· Sales of Tullow's Gabonese and Kenyan assets, completed in July
and September, respectively, realising $347 million proceeds during 2025.
· Adjusted EBITDAX(2) of $586 million (2024: $1,008 million); gross
profit of $247 million (2024: $635 million); profit after tax for the year of
$7 million (2024: $55 million); and loss from continuing operations after tax
of $129 million (2024: $55 million).
· Free cash flow(2) (FCF) of $99 million (2024: $156 million).
· Net debt(2) at year end reduced to $1,353 million (2024: $1,452
million); cash gearing of net debt(2) to adjusted EBITDAX(2) of 2.3 times
(2024: 1.4 times); liquidity headroom of $322 million (2024: $715 million).
· One new Jubilee well (J72-P) brought onstream in July 2025, which
is currently producing c.8 kbopd.
· Average FPSO uptime at Jubilee and TEN of 97%.
2026 FIRST QUARTER PERFORMANCE
· Group working interest oil and gas production averaged 43.4 kboepd
during the first quarter of 2026, underpinning expectations of delivering the
higher end of full year guidance.
· The Petroleum Agreement extensions to 2040 for the Jubilee and TEN
fields were ratified by the Ghanaian parliament in February 2026, unlocking
the potential to book further material oil and gas reserves.
· Tullow secured revised terms for the supply of gas from the Jubilee
field to the end of the extended period at an escalating price of $2.50/mmbtu
and agreed heads of terms for the potential supply of gas from the TEN fields.
· Tullow and the Government of Ghana have also agreed a gas payment
security.
· 2025-26 Ghana drilling programme continues with J74-P onstream in
January 2026 and J75-P onstream in March 2026.
· On 19 February 2026, Tullow signed a Sale and Purchase Agreement to
acquire the TEN FPSO on behalf of the joint venture for a gross consideration
of $205 million ($125.6 million net to Tullow), which is to be paid upon
completion at the end of the first quarter of 2027. Following completion
Tullow intends to maximise operational synergies with the adjacent Jubilee
Field and drive further cost efficiencies which will underpin the longer-term
development of the TEN and Jubilee fields.
2026 OUTLOOK and GUIDANCE
· Group working interest production is expected to be at the higher end
of the previously announced 34-42, including c.6 kboepd of gas.
· A further four Jubilee wells are expected onstream before the end
of the year (three producers and one water injector).
· Capital expenditure(2) of c.$200 million, allocated as follows:
c.$190 million in Ghana and c.$10 million in Côte d'Ivoire.
· Decommissioning spend of c.$5 million for UK; c.$20 million cash
provisioning for Ghana.
· Commodity hedge portfolio protecting c.60% of 2026 forecast sales
volumes whilst retaining material oil price upside exposure.
· Pre-financing cash flow(2) guidance has increased to c.$260-365
million at $70-100/bbl, primarily due to year to date production performance
being above expectations, higher oil price realisations and the higher oil
price assumption used for guidance.
· Free cash flow(2) guidance of $70-175 million at $70-100/bbl.
· Cash flow would increase by c.$40 million from $70/bbl to $80/bbl
and then by a further c.$30 million for every additional $10/bbl increase,
non-linear due to hedges in place.
· Free cash flow guidance includes recovery of 2025 cash call
receivables and c.$40 million gas revenues related to 2026 gas production, but
excludes c.$110 million historical gas receivables and the c.$50 million
receivable related to TEN development debt. Following execution of the Master
Gas Agreement, Tullow has a payment security mechanism for gas. Tullow is
working closely with the Government of Ghana and its agencies to resolve the
historic receivables on a mutually acceptable basis.
· Interpretation of 4D and OBN seismic data ongoing to support well
design and placement in the current drill programme and unlock future reserves
growth in the Jubilee and TEN fields.
· On 27 April 2026, Tullow completed a comprehensive refinancing
transaction, which includes an extension to its Senior Secured Notes and
Glencore facility to November 2028 and May 2030 respectively, and a new $100
million cargo pre-payment facility with Glencore to provide additional
liquidity. The transaction provides a stable platform for Tullow to deliver
its investment programme and realise the full value of its assets.
· Following completion of the comprenhensive refinancing transaction,
Tullow has liquidity headroom of free cash and undrawn facilities in excess of
$200 million.
1. All 2024 comparatives have been adjusted to remove Gabon following
the sale of the Gabonese assets, effective from the start of 2025.
2. Alternative performance measures are reconciled on pages 36 to 39.
Management Presentation - WEBCAST - 09:00 BST 28 April 2026
To access the webcast please use the following link and follow the
instructions provided:
https://meetings.lumiconnect.com/100-007-059-118
(https://eur01.safelinks.protection.outlook.com/?url=https%3A%2F%2Fmeetings.lumiconnect.com%2F100-007-059-118&data=05%7C02%7Cmatthew.evans%40tullowoil.com%7Ccc88f849681c4d95a51508de80e8da2a%7C9d5a858ee6c746a7a63cda2023c57cf8%7C1%7C0%7C639089934646392008%7CUnknown%7CTWFpbGZsb3d8eyJFbXB0eU1hcGkiOnRydWUsIlYiOiIwLjAuMDAwMCIsIlAiOiJXaW4zMiIsIkFOIjoiTWFpbCIsIldUIjoyfQ%3D%3D%7C0%7C%7C%7C&sdata=FN5DAbAvCg4Xvpg9QZVU8XSvgETMXkFdHfYLIkM8o5s%3D&reserved=0)
A replay will be available on the website from midday on 28 April 2026:
https://www.tullowoil.com/investors/results-reports-and-presentations/
(https://www.tullowoil.com/investors/results-reports-and-presentations/)
CONTACTS
Tullow Oil plc Camarco
(London) (London)
ir@tullowoil.com (+44 20 3757 4980)
Matthew Evans Billy Clegg
Georgia Edmonds
Rebecca Waterworth
Notes to editors
Tullow is an independent energy company committed to building a better future
through the responsible oil and gas development of its core producing assets
in Ghana. The Group is quoted on the London and Ghanaian stock exchanges
(symbol: TLW). For further information, please refer to: www.tullowoil.com.
Follow Tullow on:
LinkedIn: www.linkedin.com/company/Tullow-Oil
(http://www.linkedin.com/company/Tullow-Oil)
X: www.X.com/TullowOilplc (http://www.X.com/TullowOilplc)
CHIEF EXECUTIVE OFFICER'S REVIEW
Overview
I was very pleased to be appointed CEO in September 2025. Tullow has many
strengths including its reputation as a trusted partner and responsible
operator on the continent of Africa, the drive and commitment of its people,
and world class assets with significant growth potential. We also have a
number of near-term operational catalysts with the potential to deliver value
to stakeholders in the near term.
Priorities and achievements
I joined Tullow at a pivotal time. My immediate priorities were to work with
the team and our stakeholders to put the Company on a long-term sustainable
financial footing and create a strong foundation to drive operational and
financial performance improvement.
In July, the sale of our assets in Gabon was completed for a total cash
consideration of $307 million net of tax and customary adjustments. In
September we sold our interests in Kenya and have realised the first two
tranches of proceeds, totalling $80 million. A third tranche of $40 million is
due no later than 30 June 2033, subject to a payment schedule linked to the
oil price. The proceeds from these strategic disposals materially reduced our
net debt and strengthened our balance sheet. The successful completion of both
transactions has also reshaped our asset portfolio and we now have a distinct
Ghana-focused operating platform.
During 2025 we have further strengthened our position in Ghana by securing
alignment with the Government on a suite of agreements that add value to our
portfolio but more importantly provide a stable investment environment that
paves the way for future growth opportunities. In June, together with our
joint venture partners, we reached agreement with the Government of Ghana to
extend our Jubilee and TEN petroleum agreements to 2040, which was ratified in
February 2026. These extensions secure our ability to responsibly develop our
assets in Ghana over the long-term. In addition, Tullow has secured revised
terms for the supply of gas from the Jubilee field to the end of the extended
period at an escalating price of $2.50/mmbtu and agreed heads of terms for the
potential supply of gas from the TEN fields. Tullow and the Government of
Ghana have also agreed a gas payment security mechanism.
In February 2026 we signed an agreement to acquire the TEN FPSO on behalf of
the joint venture for a gross consideration of $205 million ($125.6 million
net). Our net consideration, which is equivalent to approximately one year of
current net lease cost, is expected to be funded by in-year cash flow from TEN
and to be paid upon completion at the end of the first quarter of 2027. In
addition to the removal of the annual lease cost, assuming operatorship of the
FPSO will result in cost savings similar to what has already been achieved at
the adjacent Jubilee field and create further potential synergies which will
underpin the longer-term development of the TEN fields.
The towed streamer 4D seismic and Ocean Bottom Node seismic surveys on the
Jubilee and TEN fields were completed in the first and fourth quarters of
2025, respectively. Interpretation of the 4D seismic data continues to deliver
informative reservoir insights supporting the well design and placement in the
current drill programme and the identification of targets for future
campaigns.
Our focus on capital efficiency and cost optimisation has continued. As a
result, 2025 annual net G&A has reduced to c.$45 million from c.$52
million in 2024 and we are targeting savings of c.$50 million over the three
year period 2025-27.
In April 2026, we completed a comprehensive refinancing transaction; extending
our Senior Secured Notes to November 2028 and the Glencore facility to May
2030, alongside a new $100 million cargo pre-payment facility with Glencore to
enhance liquidity. This pivotal milestone for the Company has secured a
financial runway of over two years, reduced total cash interest and provides a
stable platform for Tullow to deliver its investment programme and unlock the
full potential of its assets.
Financial performance
In 2025, free cash flow of $99 million was lower than expected due to lower
realised revenue towards the end of the year, delayed receipt of the second
Kenya disposal proceeds, which were received in March 2026, and delayed
receipt of cash calls and gas payments from the Government of Ghana.
Government of Ghana receivables at the end of 2025 were c.$225 million net to
Tullow (pre-tax), with c.$65 million related to cash calls, c.$110 million
related to gas payments and c.$50 million related to TEN development debt. We
are working with the Government of Ghana and its agencies to resolve the
historic receivables on a mutually acceptable basis.
Looking ahead, we expect to deliver free cash flow of $70-175 million in 2026
at an oil price range of $70-100/bbl. This cash flow guidance includes
recovery of 2025 cash call receivables from the Government of Ghana and c.$40
million pre-tax gas revenues from 2026 gas production; but excludes c.$110
million in historical gas receivables and c.$50 million receivables related to
TEN development debt.
Operational performance
In 2025, the Group's working interest production averaged 40.4 kboepd,
including 7.1 kboepd of gas. This figure reflects the sale of our Gabonese
assets, which was effective from the beginning of the year. Overall production
was in line with guidance, although towards the lower end, primarily due to
operational challenges at Jubilee during the first half of the year.
Performance improved in the second half, supported by the good performance
from the first new Jubilee production well, which was brought onstream in July
and averaged c.10 kbopd in the second half of 2025. A second well (J74-P) was
brought onstream in January 2026 and a third well (J75-P) in March 2026.
Group working interest production for 2026 is expected to be 32-42 kboepd,
including c.6 kboepd of gas production. This range reflects the decline from
existing well stock, which we are working hard to mitigate through improving
waterflood and fluid lift optimisation, offset by additional production from
the ongoing drill campaign. However, based on production performance in the
first quarter, we expect to be at the high end of the production guidance
range for the full year.
Ghana
In Ghana operational efficiency remained high with average facility uptime
across the FPSOs averaging 97% and a combined average oil production rate of
c.32.5 kbopd net in 2025. Production performance in the first quarter of 2026
has been strong, with Ghanaian oil production growing to 35.4 kbopd.
Gross oil production from the Jubilee field averaged 60.9 kbopd (net: 23.7
kbopd) in 2025. In the first half of the year, production was challenged by
higher-than-expected water cut from certain wells, which affected riser
stability on the eastern side of the field. To address this, riser based gas
lift was introduced on the east side, successfully restoring and stabilising
production in June. Looking ahead, riser based gas lift for the western side
of Jubilee has been approved and is expected to deliver further support to
production rates once fully implemented in 2027.
Cumulative voidage replacement grew to 107% in the second half of 2025, as
issues in the seawater lift system have been resolved. This will support
improved reservoir pressure management and stabilise production going forward.
Gross oil production from the TEN fields averaged 16.0 kbopd (net: 8.8 kbopd)
during 2025. This was above expectations supported by well zonal optimisation
in Enyenra and water injection optimisation activities. The TEN FPSO flare tip
was replaced in May, resulting in a c.50% reduction in routine flaring from
July 2025 onwards.
As a result of the extension of our Ghanaian Petroleum Agreements to 2040, we
expect to realise an increase in net 2P reserves of over 10 mmboe.
Furthermore, as part of this arrangement, from 20 July 2036 Ghana National
Petroleum Corporation's share in the field will increase by a further 10% and
the respective joint venture partners' shares will decrease pro rata.
Net gas production in Ghana averaged 6.8 kboepd in 2025.
Six Jubilee wells are expected onstream in 2026 (five producers and one water
injector), two of which are already onstream (J74-P and J75-P). The next three
producers are expected to come onstream in June and July, with the final well
(water injector) due onstream in September.
To sustain production rates and counteract natural declines in reservoir
output, waterflood operations are being optimised to maintain reservoir
pressure and enhance oil recovery, and well production is being carefully
managed via the riser system with the assistance of riser based gas lift.
Non-operated and exploration portfolios
As highlighted above, the sale of our Gabonese and Kenyan assets completed in
July and September, respectively.
We are aware of a tax assessment for c.$170 million from the Kenya Revenue
Authority relating to alleged underpaid VAT and Capital Gains Tax on the
disposal. Our clear and firm position is that the assessment is wholly without
merit and we intend to contest it through the regular objection process. There
will be no cash outflow in respect of lodging these objections, nor do we
expect cash outflow on completion of the appeal process.
In Côte d'Ivoire, the Espoir field licence expiry is due in July 2026.
Planning is under way to transfer the asset to Petroci.
We have taken the decision to exit exploration licences in Côte d'Ivoire
(CI-524 and CI-703) and have completed our exit in Argentina (MLO 114, MLO 119
and MLO122).
Reserves and resources
At the end of 2025, audited 2P reserves were 100.4 mmboe (2024: 164.5 mmboe).
The reserves reduction includes 14.7 mmboe of Group production during 2025,
the disposal of the Gabon assets (36.0 mmboe), a downward revision on Jubilee
reflecting production performance (11.8 mmboe) and a minor reduction on TEN
(1.6 mmboe), which reflects rephasing of projects and an earlier assumed
cessation of production due to a lower evaluation oil price.
Our asset base continues to have significant value, and as at 31 December
2025, the Group's audited 2P NPV10 was c.$1.27 billion, at our independent
reserves auditors price deck starting $62.29/bbl in 2026 and rising to
$66.24/bbl in 2030 with 2% inflation applied from 2030 onwards.
The Group's audited 2C resources of c.200 mmboe at the end of 2025 (2024:
c.700 mmboe) reflect the material opportunity we have to mature resources into
reserves to realise sustained long-term production. A number of tangible
near-term projects are being matured during 2026 to realise this, including
opportunities to install subsea pumps and undertake further infill drilling on
Jubilee and TEN and the potential monetisation of gas resources.
Sustainability
Sustainability underpins our business strategy and our approach focuses on
three core themes: people, climate and nature.
Our Net Zero by 2030 commitment is a core aspect of our sustainable approach
and following the implementation of process improvements and modifications on
our FPSOs in Ghana during the year, we further reduced routine flaring by 22%.
Our community development programmes continue to focus on improving
education and employability in our host communities and creating opportunities
for local employment and entrepreneurship.
Governance
On 8 April 2026, we announced the appointment of four new independent
Non-Executive Directors to enhance the Company's governance framework and to
comply with the previously announced requirements of the refinancing
transaction. The appointment of Henry Steel is with effect from 8 April 2026
and he will also serve as Senior Independent Director. The appointments of
Garrett Soden, Euan Shirlaw and James Peterkin will become effective on 1 May
2026.
Outlook
In 2025 we laid the foundations for improved performance and created a number
of potential growth opportunities. In the near term, we will focus on
continuing to optimise our cash flow delivery, through better cash flow
management, further cost reductions and reduction of the receivables from the
Government of Ghana. Furthermore following the purchase of the TEN FPSO, we
will look to capture synergies with the Jubilee FPSO whilst reducing costs and
removing the significant annual lease payment.
Operationally, we are excited by the potential of the 4D seismic and OBN data
to unlock future drilling campaigns in Jubilee and TEN. Nearer-term, we are
encouraged by the positive start to the 2025-26 Jubilee drill campaign. There
are a number of incremental opportunities beyond new wells that we are
pursuing to improve production, including multi-phase pumps, riser based gas
lift and workover campaigns. These projects have the potential for rapid
payback with relatively low risk.
With the refinancing transaction completed and strong operational momentum
across the business, Tullow is well positioned to deliver our Business Plan
and target near-term upside. As we look to the year ahead we remain focused on
improving the performance of our world-class assets and executing our Business
Plan to deliver value for stakeholders.
1. Alternative performance measures are reconciled on pages 36 to 39.
Finance review
Income Statement
Income Statement (key metrics) 2025 2024 Restated(2)
Revenue ($m)
Sales volume (boepd) 32,600 44,400
Realised oil price ($/bbl) 66.2 75.9
Total revenue 847 1,287
Operating income/(costs) ($m)
Underlying cash operating costs (1) (203) (198)
Depreciation, Depletion and Amortisation (DD&A) of oil and gas and leased (371) (412)
assets
DD&A before impairment charges ($/bbl) 25.3 21.9
Overlift and oil stock movements (28) (42)
Administrative expenses (45) (52)
Exploration costs written off (2) (202)
Impairment reversal of property, plant and equipment (PP&E), net 5 12
Net financing costs (263) (275)
(Loss)/profit for the year from continuing activities before tax (63) 174
Income tax expense (67) (229)
Loss for the year from continuing activities (129) (55)
Adjusted EBITDAX (1) 586 1,008
Basic loss per share (cents) (8.8) (3.8)
1. Alternative performance measures are reconciled on pages 36 to 39.
2. Amounts above are presented excluding discontinued operations in Gabon.
Refer to note 8.
Revenue
Sales oil volumes
During the year, there were 32,600 boepd (2024: 44,400 boepd) of liftings. The
decrease was driven by a reduction of 4.5 liftings in Ghana with 10 in Jubilee
(2024: 13) and 3 in TEN (2024: 4.5).
Realised oil price ($/bbl)
The Group's realised oil price after hedging for the period was $66.2/bbl
(2024: $75.9/bbl) and before hedging $67.8/bbl (2024: $80.5/bbl). Lower oil
prices and lower hedged volumes subject to price caps compared to 2024 have
resulted in a lower hedge loss which decreased total revenue by $19 million
(2024: $74 million).
Gas sales
Included in Total revenue of $847 million are gas sales of $59 million of
which $54 million relates to Ghana. During the year, the Group exported 44,503
mmscf (gross) of gas at an average price of $3.08/mmbtu in Ghana (2024: 33,660
mmscf (gross) at $2.97/mmbtu).
Cost of sales
Underlying cash operating costs
Underlying cash operating costs amounted to $203 million; $13.8/boe (2024:
$198 million; $10.5/boe). This consists of Ghana $166 million; $11.6/boe
(2024: $157 million; $8.6/boe), Côte d'Ivoire $23 million; $53.7/boe (2024:
$22 million; $42.7/boe) and Corporate $14 million (2024: $18 million). The
movement is primarily driven by Jubilee shutdown and FPSO Class related
maintenance costs offset by a decrease in routine operating costs.
Depreciation, depletion and amortisation
DD&A charges before impairment on production and development assets
amounted to $371 million; $25.3/boe (2024: $412 million; $21.9/boe). This
decrease in DD&A is mainly attributable to lower Jubilee field production
compared to the prior year.
Overlift and oil stock movements
The Group recognised an overlift expense of $28 million (2024: $42 million).
The decrease in overlift expense is driven by timing of liftings and lower oil
prices at the 2025 year end.
Administrative expenses
Administrative expenses of $45 million (2024: $52 million) have decreased in
2025 despite the inflationary environment. This is largely due to targeted
cost optimisation initiatives undertaken in 2025 together with the broader
Group restructuring following the disposal of the Gabon and Kenya assets. The
full year impact of the cost optimisations is expected to realise in 2026,
which together with additional cost optimisation initiatives is estimated to
generate c.$50 million savings over the next three years.
Impairment of property, plant and equipment
The Group recognised a net impairment reversal on PP&E of $5 million in
2025 (2024: Net impairment reversal of $12 million), mainly driven by changes
to estimates on the cost of decommissioning for certain UK assets, partially
offset by impairment of capital expenditure in Cote D'Ivoire. The $35 million
impairment in the TEN fields recognised in the 2025 half-year results has been
fully reversed at the year end. This followed an assessment which determined
that the net present value of TEN, reflecting the impact of the acquisition of
the FPSO as disclosed in the Events since 31 December 2025 section, was equal
to the carrying value of the PP&E, TEN FPSO net lease liability and
associated deferred tax balances.
Net financing costs
Net financing costs for the year were $263 million (2024: $275 million). Lower
net interest expense on borrowings and obligations under leases was partially
offset by debt arrangement fees incurred in 2025 and a reduced interest
income.
A reconciliation of net financing costs is included in note 6.
Taxation
The overall adjusted net tax expense of $67 million (2024: $229 million) primarily relates to tax charges in respect of the Group's production activities in West Africa, reduced by deferred tax credits associated with future UK decommissioning assets, exploration write-offs and impairments.
Based on a loss before tax for the period of $63 million (2024: profit of $174 million), the effective tax rate (ETR) is (106.0%) (2024:131.7%). After adjusting for non-recurring amounts related to exploration write-offs, disposals, impairments, provisions and their associated deferred tax benefit, the Group's adjusted tax rate is (125.5%) (2024: 71.1%). In the UK, there is net interest and hedging expense of $162 million (2024: $195 million), however, there is no UK tax benefit as in previous periods.
The Group has applied the exception from recognising and disclosing deferred
tax assets and liabilities arising from the implementation of Pillar Two
income taxes. Based on full year actuals, the Group has not identified any
exposure to Pillar Two income taxes in jurisdictions where the safe harbour
thresholds are not met. Accordingly, no Pillar Two income tax charges or
related deferred tax effects have been recognised for the period.
Detailed analysis of ETR for underlying business - Continuing operations
Analysis of adjusted ETR ($m) Adjusted profit/(loss) Tax Adjusted
before tax
(expense)/credit
effective tax rate
Ghana 2025 184.6 (70.3) 38.1%
2024 580.3 (208.6) 35.9%
Corporate 2025 (205.3) 2.0 1.0%
2024 (270.3) (5.7) (2.1%)
Other non-operated & exploration 2025 (33.1) 0.8 2.4%
2024 (7.8) (0.7) (8.7%)
Total 2025 (53.8) (67.5) (125.5%)
2024 302.2 (215.0) 71.1%
Detailed analysis of ETR - Discontinued operations
Analysis of adjusted ETR ($m) Adjusted profit/(loss) Tax Adjusted
before tax
(expense)/credit
effective tax rate
Gabon 2025 62.0 (44.9) 72.5%
2024 119.3 (38.2) 32.0%
Total 2025 62.0 (44.9) 72.5%
2024 119.3 (38.2) 32.0%
Adjusted EBITDAX
Adjusted EBITDAX for the year was $586 million (2024: $1,008 million). The
decrease in the period was mainly driven by lower revenue.
Loss for the year from continuing activities and loss per share
The loss for the year from continuing activities amounted to $129 million
(2024: $55 million loss). The loss after tax was driven mainly by lower
revenue, offset by lower income tax expense in the current year. Basic loss
per share was 8.8 cents (2024: loss per share of 3.8 cents).
Balance sheet and liquidity management
Key metrics 2025 2024
Capital investment ($m)(1) 195 231
Derivative financial instruments ($m) 1 (12)
Borrowings ($m) (1,659) (1,976)
Underlying operating cash flow ($m)(1) 221 668
Free cash flow ($m)(1) 99 156
Net debt ($m)(1) 1,353 1,452
Gearing (times)(1,2) 2.3 1.4
1. Alternative performance measures are reconciled on pages 36 to 39.
2. Gearing presented above excludes discontinued operations in Gabon.
Capital investment
Capital expenditure amounted to $195 million (2024: $231 million) out of which
$191 million was invested in production and development activities (2024: $206
million) with a $146 million spend in Ghana (2024: $148 million), $28 million
in Gabon (2024: $40 million), $14 million in Cote D'Ivoire (2024: $12 million)
and $3 million in Kenya (2024: $6 million). $122 million of capital investment
related to Jubilee (2024: $134 million), mainly comprising $85 million of
drilling costs (2024: $103 million). Investment in exploration and appraisal
activities was $4 million (2024: $25 million).
The Group's 2026 capital expenditure is expected to be c.$200 million,
comprising c.$190 million in Ghana and c.$10 million in Cote D'Ivoire. Ghana
capex is expected to include c.$180 million relating to Jubilee, primarily
drilling costs of c.$150 million.
Decommissioning
Decommissioning expenditure was $5 million (2024: $49 million), and $12
million of cash provisioning for future decommissioning in Ghana (2024: $12
million). The Group's decommissioning budget in 2026 is c.$25 million of which
c.$20 million is cash provisioning for future decommissioning in Ghana.
Subject to programme scheduling, at the end of 2026 it is expected that c.$12
million of decommissioning liabilities in the UK will remain.
Derivative financial instruments
The Group has a material hedge portfolio in place to protect against commodity
price volatility and to ensure the availability of cash flow for re-investment
in capital programmes that are driving business delivery, whilst retaining
access to oil price upside.
At 31 December 2025, the Group's hedge portfolio provides downside protection
for c.50% of forecast production entitlements in the first half of 2026 with
c.$58/bbl weighted average floors across all structures; while retaining
strategic upside participation across for the same period, with only c.30% of
forecast production entitlements capped with collars at a weighted average
sold call of c.$74/bbl, and c.7% of forecast production entitlements secured
with three-way collars with $70-$80/bbl call spreads. To date, the Group's
hedge portfolio in the second half of the year is comprised of collars
providing downside protection for c.20% of forecast production entitlements
with c.$59/bbl weighted average floors, and upside capped at c.$75/bbl.
All financial instruments that are initially recognised and subsequently
measured at fair value have been classified in accordance with the hierarchy
described in IFRS 13 Fair Value Measurement. Fair value is the amount for
which the asset or liability could be exchanged in an arm's length transaction
at the relevant date. Where available, fair values are determined using quoted
prices in active markets (Level 1). To the extent that market prices are not
available, fair values are estimated by reference to market-based transactions
or using standard valuation techniques for the applicable instruments and
commodities involved (Level 2).
All of the Group's derivatives are Level 2 (2024: Level 2). There were no
transfers between fair value levels during the year.
At 31 December 2025, the Group's derivative instruments had a net positive
fair value of $1 million (2024: net negative $12 million).
The following table demonstrates the timing, volumes and prices of the Group's
commodity hedge portfolio at year end:
1H26 hedge portfolio at 31 December 2025 bopd Bought put Sold Bought
(floor) call call
Straight puts 3,750 $58.20 - -
Collars 10,200 $58.48 $75.17 -
Three-way collars (call spread) 2,224 $57.99 $69.90 $79.90
Total/Weighted average 16,174 $58.35 $74.23 $79.90
2H26 hedge portfolio at 31 December 2025 bopd Bought put Sold Bought
(floor) call call
Straight puts - - - -
Collars 7,500 $58.97 $74.88 -
Three-way collars (call spread) - - - -
Total/Weighted average 7,500 $58.97 $74.88 -
Since the balance sheet date, the Group has secured additional downside
protection for 9,750 bopd, 12,000 bopd and 5,500 bopd for the periods 2H26,
1H27 and 2H27, respectively.
Borrowings
On 3 March 2025, the Group repaid in full its Senior Notes. The principal
repayment of $493 million and accrued interest to maturity were funded from a
combination of drawing down the remaining balance of $270 million under the
Glencore Facility and cash on balance sheet.
On 29 April 2025, the Group made a drawdown under its Revolving Credit
Facility (RCF) to manage near-term working capital.
On 15 May 2025, the Group made the annual prepayment of $100 million of the
Senior Secured Notes due 2026 (2026 Notes).
On 21 May 2025, the Group entered into an extension of its RCF to 31 October
2025 at reduced commitments of $150 million. On 29 July 2025, the Group repaid
and cancelled in full the $150 million RCF.
As at 31 December 2025, the Group's total drawn debt reduced to $1,685
million, consisting of $1,285 million nominal value 2026 Notes and $400
million outstanding under the Glencore facility.
Management regularly reviews options for optimising the Group's capital
structure and may seek to refinance, retire or purchase any or all of its
outstanding debt from time to time through new debt refinancings and/or cash
purchases or exchanges in the open market, privately negotiated transactions
or otherwise.
Credit ratings
The Group maintains credit ratings with Standard & Poor's (S&P's) and
Moody's Investors Service (Moody's).
On 17 April 2025, S&P revised the Group's corporate credit rating and the
rating of the 2026 Notes to CCC+ with negative outlook from B-.
On 2 October 2025, S&P revised the Group's corporate credit rating and the
rating of the 2026 Notes to CCC with negative outlook.
On 28 November 2025, S&P revised the Group's corporate credit rating and
the rating of the 2026 Notes to CCC- with negative outlook.
On 13 May 2025, Moody's revised the Group's corporate credit rating and the
rating of the 2026 Notes to Caa2 with negative outlook from Caa1.
On 8 December 2025, Moody's revised the Group's corporate credit rating to Ca
with negative outlook from Caa2 and the rating of the 2026 Notes to Caa3.
Underlying operating cash flow and free cash flow
Underlying operating cash flow for the year was $221 million (2024: $668
million), reflecting a decrease of $447 million. This was primarily driven by
$620 million decline in cash revenue due to lower sales volumes and reduced
oil prices, and higher cash operating costs and working capital of $68
million. These factors were partially offset by lower cash and royalty taxes
of $241 million.
Free cash flow for the year decreased to $99 million (2024: $156 million).
Underlying operating cashflow reduced by $447 million, as outlined above. This
decrease was largely offset by proceeds from disposals of $334 million as well
as lower net cash used in other investing activities, reduced lease payments
related to capital activities and decommissioning costs, which decreased by
$28 million, $22 million, and $28 million, respectively. There was an increase
in the finance costs of $13 million, mainly due to debt arrangement fees, as
well as an impact of foreign exchange loss of $9 million.
Net debt and gearing
Reconciliation of net debt $m
FY 2024 net debt 1,452.3
Sales revenue (962.4)
Operating costs 202.9
Other operating and administrative expenses 164.1
Operating cash flow before working capital movements (595.4)
Movement in working capital 133.8
Tax paid 127.3
Purchases of intangible exploration and evaluation assets and property, plant 195.6
and equipment
Other investing activities (345.1)
Other financing activities 358.3
Debt arrangement fees 19.7
Foreign exchange loss on cash 6.5
FY 2025 net debt 1,353.0
1. Amounts above are presented including discontinued operations in Gabon.
Net debt reduced by $99.3 million during the year to $1,353.0 million on 31
December 2025 (2024: $1,452.3 million), consisting of $1,285 million Senior
Secured Notes due 2026 and $400 million Secured Notes Facility, less cash and
cash equivalents.
The gearing ratio has increased to 2.3 times (2024: 1.4 times) due to a
decrease in Adjusted EBITDAX from lower revenue in the current year as
explained above.
Ghana tax assessments
The Group has two ongoing disputed tax assessments that relate to the
disallowance of loan interest deductions for the fiscal years 2010 - 2020 and
proceeds received by Tullow Oil plc under Tullow's corporate Business
Interruption Insurance policy. Both were referred to international arbitration
in 2023, with first hearings scheduled for 2025. The parties initially agreed
a procedural timetable for the loan interest arbitration under which the first
Tribunal hearing was due to have been held in the week commencing 30th June
2025. This has now been postponed to September 2026 allowing more time to
conclude the negotiations. The hearing on the Business Interruption Insurance
proceeds was held in November 2025, and a ruling can be expected during the
first half of 2026. The Group continues to engage with the Government of
Ghana, including the Ghana Revenue Authority (GRA), with the aim of resolving
the assessments on a mutually acceptable basis.
Kenya tax assessments
The Group is aware of a tax assessment for c.$170 million from the Kenya
Revenue Authority relating to alleged underpaid VAT and Capital Gains Tax on
the disposal of its 100% shareholding in its Kenyan subsidiary, Tullow Kenya
BV, to the Gulf Energy Group for a minimum consideration of $120 million. The
Group's clear and firm position is that the assessment is wholly without
merit, and it intends in conjunction with Gulf Energy to contest the
assessment through the regular objection process. There will be no cash
outflow in respect of lodging these objections, nor does the Group expect cash
outflow on completion of its appeal process. Therefore, a provision for
uncertain tax treatments in respect of this risk has not been recorded.
Liquidity risk management and going concern
The Directors consider the going concern assessment period to be up to 30
April 2027.
On 27 April 2026, the Group announced the completion of its refinancing
transaction to address the maturity of $1.285 billion senior secured notes
(the 2026 Notes). Following a repayment of $100 million of principal amount of
the 2026 Notes at par, the Group issued $1.185 billion new notes maturing 15
November 2028 to existing holders plus $25 million fungible new notes to
Glencore (together the New Notes) in exchange for the cancellation in full of
the 2026 Notes. Further, a $400 million loan provided by Glencore was extended
by two years to mature on 15 May 2030, with $21 million in accrued interest
and $2 million payment in kind fees added to the loan balance on completion.
The Group also entered into a revolving $100 million cargo prepayment facility
maturing on 15 November 2028 with Glencore which is undrawn and will be
primarily used for working capital purposes and to provide a liquidity buffer
in a downside scenario.
The New Notes, the Glencore loan and the cargo prepayment facility do not have
any maintenance covenants. If a legally binding sale and purchase agreement
has not been entered into within nine months of commencement of an M&A
process (such process to commence before the end of 2026), the maturities of
the New Notes and the cargo prepayment facility will be brought forward to 15
May 2028 (unless extended by approval of a Super Majority of holders of the
New Notes), which is outside of the going concern assessment period.
Governance will be enhanced with the addition of three new Independent
Non-Executive Directors (INEDs) to Tullow's Board of Directors. The New Notes
include a semi-annual forward-looking cash sweep whereby freely available
cash will be required to repay the New Notes subject to the condition that
rolling 15-month projected liquidity on the last date of each calendar month
within the projection period (under certain downside assumptions) is equal to
or exceeds $100 million.
The Group closely monitors and manages its liquidity headroom. Cash forecasts
are regularly produced, and sensitivities run for different scenarios covering
key judgements and assumptions including, but not limited to, changes in
commodity prices, different production rates from the Group's producing assets
and different outcomes on ongoing disputes or litigations and the timing of
any associated cash outflows.
Management has applied the following oil price assumptions for the going
concern assessment based on forward prices and market forecasts:
Base Case: $76/bbl for 2026; $70/bbl for 2027.
Low Case: $66/bbl for 2026; $65/bbl for 2027.
To consider the principal risks to the cash flow projections, a sensitivity
analysis has been performed which is represented in the Low Case, which
management considers to be severe, but plausible, given the cumulative impact
of the sensitivities applied. The most significant risk would be a sustained
decline in oil prices. The analysis has been tested by including a 10%
production decrease and a 5% increase in operating costs compared to the Base
Case. Management has also considered additional outflows in respect of all
ongoing disputes and litigations within the Low Case, with an additional $33
million outflow included for the cases expected to progress in the going
concern period. Based on the legal opinions received by management, the
remaining disputes and litigations are not expected to conclude within the
going concern period or have remote outcomes, therefore no outflows have been
included in that respect in the Low Case. In the event of negative outcomes
after the going concern period, management would use all available court
processes to appeal such rulings, which, based on observable court timelines,
would likely take in excess of a further year.
Following completion of the refinancing transaction the Directors have
concluded that the material uncertainties noted in the 2024 Annual Report and
Accounts, associated with implementing a refinancing proposal no longer exist.
Upon completion of the refinancing transaction, the Group had in excess of
$200 million liquidity headroom of undrawn and available debt facilities and
free cash. The Group's forecasts show that the Group will be able to operate
within its current debt facilities and have sufficient financial headroom for
the going concern assessment period under the Base Case and the Low Case.
These forecasts assume full availability of the $100 million cargo prepayment
facility, which remains undrawn under the Base Case. Furthermore, management
has performed a reverse stress test and the average oil price throughout the
going concern period required to reduce headroom to zero during the assessment
period is $32/bbl.
Based on the analysis above, the Directors have a reasonable expectation that
the Company has adequate resources to continue in operational existence for
the going concern assessment period to 30 April 2027. On this basis the Board
have prepared the Financial Statements on a going concern basis.
Events since 31 December 2025
TEN FPSO Purchase
On 19 February 2026, Tullow signed a Sale and Purchase Agreement (SPA) to
acquire the TEN FPSO on behalf of the joint venture for a gross consideration
of $205.0 million ($125.6 million net to Tullow), which is to be paid upon
completion at the end of the first quarter of 2027.
The lease modification to include an obligation to purchase the FPSO, together
with the update to the lease term, constitutes a lease remeasurement in
accordance with IFRS 16 Leases. As at the date of the SPA, the remeasurement
will result in a reduction in the lease liability, a reduction in the
right-of-use asset, and a corresponding decrease in the receivable from the
joint venture partners, as the value of the gross undiscounted lease payments
will decrease from $716.7 million to $424.9 million. As the assessment of the
financial impacts is ongoing, these cannot be disclosed in the Annual Report
and Accounts.Accordingly, the relevant disclosure will be made in the 2026
half-year results.
Extension of the Petroleum Agreements in Ghana
On 20 February 2026, Tullow announced that the extension of its West Cape
Three Points and Deep Water Tano Petroleum Agreements, which cover the Jubilee
and TEN fields, was ratified by the Ghanaian Parliament. Accordingly, these
agreements have been extended to 31 December 2040, and from 20 July 2036 Ghana
National Petroleum Corporation's share in the field will increase by a further
10% interest and the joint venture partners' shares will decrease pro rata.
In addition, Tullow has secured revised terms for the supply of gas from the
Jubilee field to the end of the extended period at an escalating price of
$2.50/mmbtu and heads of terms for the potential supply of gas from TEN.
Tullow and the Government of Ghana have also agreed a gas payment security
mechanism.
Refinancing transaction
On 20 February 2026, Tullow announced that it had entered into a binding
Lock-Up Agreement to implement a refinancing transaction with holders of c.66%
10.25% senior secured notes due May 2026 (the Senior Secured Notes) and with
Glencore Energy UK Limited (Glencore). Key features of the transaction
included:
· Release of Senior Secured Notes and issuance of new Extended Notes
maturing 15 November 2028, together with a paydown of $100 million, extending
the Company's debt maturity profile.
· Glencore's existing $400 million Secured Notes Facility released
and issuance of new Glencore Junior Notes of an equal amount maturing 15 May
2030.
· Strengthened liquidity position through a new $100 million super
senior Cargo Prepayment Facility provided by Glencore, complemented by a
reduced all-in cash interest profile through Payment-In-Kind (PIK) only
interest on the Glencore Junior Notes.
· Existing equity remains in place and no new shares are anticipated
to be issued in connection with the refinancing transaction.
On 26 February 2026, Tullow announced that holders of over 90% of its Senior
Secured Notes have acceded to the Lock-Up Agreement in support of the
Company's refinancing transaction, meeting the necessary threshold required to
implement it by way of consent solicitation.
On 25 March 2026, Tullow launched a consent solicitation to obtain formal
consents from the holders of the Notes required in connection with the
implementation of the refinancing transaction.
On 8 April 2026, Tullow announced that holders representing over 97% of the
outstanding principal amount of its existing notes had provided consents to
approve amendments to the indenture and intercreditor agreement, the release
and exchange of the existing notes for new notes, and related waivers to
permit the release of collateral, in each case in connection with the proposed
refinancing transaction.
On 27 April 2026, Tullow announced the completion of the refinancing
transaction.As the assessment of the financial impacts is ongoing, these
cannot be disclosed in the Annual Report and Accounts. Accordingly, the
relevant disclosure will be made in the 2026 half-year results.
Receipt of Tranche B payment for sale of Kenya assets
On 9 March 2026, Tullow received $36 million proceeds of the Tranche B payment
under the terms of the SPA announced on 21 July 2025 for the sale of its
entire working interest in Kenya. The final 10% of Tranche B proceeds ($4
million), was received on 1 April 2026 following completion of transition
support services.
Board of Directors appointments
On 8 April 2026, Tullow has announced the appointment of four independent
Non‑Executive Directors (Henry Steel, Garrett Soden, Euan Shirlaw and James
Peterkin) to its Board of Directors. Henry Steel's appointment was effective
immediately. The other appointments were conditional on completion of the
refinancing, which closed on 27 April 2026, and will become effective on 1 May
2026. The appointments will be subject to election by shareholders at the
Annual General Meeting in June.
These are all non-adjusting events as at 31 December 2025 as defined by IAS 10
Events after the Reporting Period.
There have not been any other events since 31 December 2025 that have resulted
in a material impact on the year end results.
Group income statement
Year ended 31 December 2025
$m Notes 2025 2024 Restated(1)
Revenue 847.0 1,287.2
Other operating income - insurance proceeds 4.2 -
Cost of sales 5 (603.9) (652.5)
Gross profit 247.3 634.7
Administrative expenses 5 (45.0) (52.2)
Restructuring provisions 5 (7.2) (7.1)
Expected credit loss reversal/(charge) on trade receivables 5 6.6 (6.6)
Loss on disposal 8 (4.5) -
Exploration costs written off 9 (2.1) (202.3)
Impairment reversal of property, plant and equipment, net 10 4.8 11.8
Provisions reversal 5 - 70.4
Operating profit 199.9 448.7
Finance income 6 63.4 69.2
Finance costs 6 (326.0) (344.2)
(Loss)/Profit for the year from continuing operations before tax (62.7) 173.7
Income tax expense 7 (66.5) (228.7)
Loss for the year from continuing operations (129.2) (55.0)
Discontinued operations
Profit after tax from discontinued operations 135.7 109.6
Profit for the year 6.5 54.6
Attributable to
Owners of the Company 6.5 54.6
Earnings per ordinary share ¢ ¢
Basic 0.4 3.7
Diluted 0.4 3.6
Loss per ordinary share from continuing operations ¢ ¢
Basic (8.8) (3.8)
Diluted (8.8) (3.8)
1. Comparative amounts have been restated to present Gabon as a discontinued
operation. Refer to note 8.
Group statement of comprehensive income and expense
Year ended 31 December 2025
$m 2025 2024
Profit for the year 6.5 54.6
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
Gain/(losses) arising in the year 0.3 (28.5)
Losses arising in the year - time value (5.8) (21.9)
Reclassification adjustments for items included in profit on realisation - 47.5
Reclassification adjustments for items included in loss on realisation - time 18.8 26.1
value
Exchange differences on translation of foreign operations (7.7) 2.0
Net other comprehensive income for the year 5.6 25.2
Total comprehensive income for the year 12.1 79.8
Attributable to
Owners of the Company 12.1 79.8
Group balance sheet
As at 31 December 2025
$m Notes 2025 2024
Assets
Non-current asset
Goodwill 12 - 44.9
Intangible exploration and evaluation assets 9 - 109.1
Property, plant and equipment 10 1,894.3 2,324.1
Other non-current assets 11 300.2 340.8
Deferred tax assets 5.0 8.3
2,199.5 2,827.2
Current assets
Inventories 90.1 132.4
Trade receivables 179.2 137.9
Other current assets 11 472.9 391.9
Current tax assets 2.9 6.9
Derivative financial instruments 2.0 0.1
Cash and cash equivalents 332.2 555.1
1,079.3 1,224.3
Total assets 3,278.8 4,051.5
Liabilities
Current liabilities
Trade and other payables 13 (638.4) (736.5)
Borrowings (1,277.9) (589.4)
Provisions 15 (5.5) (24.3)
Current tax liabilities (140.5) (175.3)
Derivative financial instruments (0.6) (11.9)
(2,062.9) (1,537.4)
Non-current liabilities
Trade and other payables 13 (493.0) (665.9)
Borrowings (381.0) (1,386.4)
Provisions 15 (257.3) (321.5)
Deferred tax liabilities (337.5) (413.0)
(1,468.8) (2,786.8)
Total liabilities (3,531.7) (4,324.2)
Net liabilities (252.9) (272.7)
Equity
Called-up share capital 218.6 217.5
Share premium 1,294.7 1,294.7
Foreign currency translation reserve (250.1) (242.4)
Hedge reserve 0.4 0.1
Hedge reserve - time value 0.9 (12.1)
Merger reserve 755.2 755.2
Retained earnings (2,272.6) (2,285.7)
Equity attributable to equity holders of the Company (252.9) (272.7)
Total equity (252.9) (272.7)
Group statement of changes in equity
Year ended 31 December 2025
$m Share Share Foreign currency translation reserve¹ Hedge Hedge Merger reserve(3) Retained earnings Total
capital
premium
reserve²
reserve - time
value²
At 1 January 2024 216.7 1,294.7 (244.4) (18.9) (16.3) 755.2 (2,346.4) (359.4)
Profit for the period - - - - - - 54.6 54.6
Hedges, net of tax - - - 19.0 4.2 - - 23.2
Currency translation adjustments - - 2.0 - - - - 2.0
Total comprehensive income - - 2.0 19.0 4.2 - 54.6 79.8
Exercise of employee share options 0.8 - - - - - (0.8) -
Share-based payment charges - - - - - - 6.9 6.9
At 1 January 2025 217.5 1,294.7 (242.4) 0.1 (12.1) 755.2 (2,285.7) (272.7)
Profit for the period - - - - - - 6.5 6.5
Hedges, net of tax - - - 0.3 13.0 - - 13.3
Currency translation adjustments - - (7.7) - - - - (7.7)
Total comprehensive income - - (7.7) 0.3 13.0 - 6.5 12.1
Exercise of employee share options 1.1 - - - - - (1.1) -
Share-based payment charges - - - - - - 7.7 7.7
At 31 December 2025 218.6 1,294.7 (250.1) 0.4 0.9 755.2 (2,272.6) (252.9)
1. The foreign currency translation reserve represents exchange gains and
losses arising on translation of foreign currency subsidiaries, monetary items
receivable from or payable to a foreign operation for which settlement is
neither planned nor likely to occur, which form part of the net investment in
a foreign operation.
2. The hedge reserve represents gains and losses on derivatives classified
as effective cash flow hedges.
3. The merger reserve represents the premium on shares issued in relation to
acquisitions.
Group cash flow statement
Year ended 31 December 2025
$m Notes 2025 2024
Cash flows from operating activities
(Loss)/Profit for the year from continuing operations before tax (62.7) 173.7
Profit for the year from discontinued operations before tax 221.9 147.8
Profit for the year before tax 159.2 321.5
Adjustments for:
Depreciation, depletion and amortisation 10 376.0 444.2
Asset revaluation 12 - (38.9)
Gain on disposals, net 8 (160.8) -
Taxes paid in kind 7 (3.8) (6.3)
Exploration costs written off 9 7.4 212.6
Impairment reversal of property, plant and equipment, net 10 (4.8) (11.8)
Provisions/(Provisions reversal), net 7.2 (63.3)
Payment for provisions 15 (37.9) (0.7)
Decommissioning expenditure 15 (17.6) (45.0)
Share-based payment charge 7.7 6.9
Finance income 6 (64.1) (71.5)
Finance costs 6 326.9 345.6
Operating cash flow before working capital movements 595.4 1,093.3
(Increase)/decrease in trade and other receivables (78.5) 0.7
Decrease/(increase) in inventories 20.5 (25.1)
(Decrease)/increase in trade payables (75.8) 49.9
Cash generated from operating activities 461.6 1,118.8
Income taxes paid (127.3) (360.3)
Net cash from operating activities 334.3 758.5
Cash flows from investing activities
Proceeds from disposals, net of transaction costs 334.2 -
Purchase of additional interests in a joint operation - (8.1)
Purchase of intangible exploration and evaluation assets (7.6) (27.8)
Purchase of property, plant and equipment (188.0) (196.7)
Interest received 10.9 19.5
Net cash from/(used in) investing activities 149.5 (213.1)
Cash flows from financing activities
Debt arrangement fees (19.7) -
Repayment of borrowings (742.5) (100.0)
Drawdown of borrowings 420.3 -
Payment of obligations under leases 14 (142.1) (169.0)
Finance costs paid (216.2) (223.2)
Net cash used in financing activities (700.2) (492.2)
Net (decrease)/increase in cash and cash equivalents (216.4) 53.2
Cash and cash equivalents at beginning of year 555.1 499.0
Foreign exchange (loss)/gain (6.5) 2.9
Cash and cash equivalents at end of year 332.2 555.1
Notes to the financial statements
Year ended 31 December 2025
1. Basis of preparation and presentation of financial information
The Financial Statements have been prepared in accordance with United Kingdom
adopted international accounting standards (UK-adopted IFRSs) and
International Financial Reporting Standards adopted pursuant to Regulation
(EC) No. 1606/2002 as it applies in the European Union. The financial
reporting framework that has been applied in the preparation of the Parent
Company Financial Statements is applicable law and United Kingdom Accounting
Standards, including FRS 101 Reduced Disclosure Framework (United Kingdom
Generally Accepted Accounting Practice).
The financial information for the year ended 31 December 2025 does not
constitute statutory accounts as defined in sections 435 (1) and (2) of the
Companies Act 2006. Statutory accounts for the year ended 31 December 2024
have been delivered to the Registrar of Companies and those for 2025 will be
delivered following the Company's annual general meeting. The auditor's report
on these accounts was unqualified, did not include a reference to any matters
to which the auditor drew attention by way of emphasis of matter and did not
contain a statement under section 498 (2) or (3) of the Companies Act 2006.
The Financial Statements have been prepared on the historical cost basis,
except for derivative financial instruments and contingent consideration,
which have been measured at fair value which are carried at fair value less
cost to sell. The Financial Statements are presented in US dollars and all
values are rounded to the nearest $0.1 million, except where otherwise stated.
The accounting policies applied are consistent with those adopted and
disclosed in the Group's Financial Statements for the year ended 31 December
2024. There have been a number of amendments to accounting standards and new
interpretations issued by the International Accounting Standards Board which
were applicable from 1 January 2025, however, these have not any impact on the
accounting policies, methods of computation or presentation applied by the
Group. Further details on new International Financial Reporting Standards
adopted will be disclosed in the 2025 Annual Report and Accounts.
Certain new accounting standards and interpretations have been published that
are not mandatory for 31 December 2025 reporting periods and have not been
early adopted by the Group. These standards are not expected to have a
material impact on the entity in the current or future reporting periods and
on foreseeable future transactions.
2. Earnings/(loss) per ordinary share
Basic earnings/(loss) per ordinary share amounts are calculated by dividing
net profit/(loss) for the year attributable to ordinary equity holders of the
Parent by the weighted average number of ordinary shares outstanding during
the year.
Diluted earnings per ordinary share amounts are calculated by dividing net
profit/(loss) for the year attributable to ordinary equity holders of the
Parent by the weighted average number of ordinary shares outstanding during
the year plus the weighted average number of dilutive ordinary shares that
would be issued if employee and other share options were converted into
ordinary shares.
3. 2025 Annual Report and Accounts
The 2025 Annual Report and Accounts will be mailed in May 2026 only to those
shareholders who have elected to receive it. Otherwise, shareholders will be
notified that the Annual Report and Accounts are available on the Group's
website (www.tullowoil.com). Copies of the Annual Report and Accounts will
also be available from the Company's registered office at Building 9, Chiswick
Park, 566 Chiswick High Road, London, W4 5XT.
4. Segmental Reporting
Following the disposals of operations in Gabon and Kenya in 2025 (refer to
note 8), the information reported to the Group's Chief Executive Officer for
the purposes of resource allocation and assessment of segment performance is
now focused on two Business Units: Ghana and Other, which contain non-operated
producing assets in Cote D'Ivoire, decommissioning assets and exploration
activities. Therefore, the Group's reportable segments under IFRS 8 are Ghana
and Other.
The following tables present revenue, profit and certain asset and liability
information regarding the Group's reportable business segments for the years
ended 31 December 2025 and 31 December 2024. The table for the year ended 31
December 2024 has been restated to reflect the new reportable segments of the
business.
$m Ghana Other(4) Corporate Total
2025
Sales revenue by origin 833.0 32.8 (18.8) 847.0
Other operating income - - 4.2 4.2
Segment result(1) 285.4 (9.2) (26.2) 250.0
Loss on disposal (4.5)
Unallocated expenses(2) (45.6)
Operating profit 199.9
Finance income 63.4
Finance costs (326.0)
Loss before tax (62.7)
Income tax expense (66.5)
Loss after tax (129.2)
Total assets 2,852.1 33.0 393.7 3,278.8
Total liabilities(3) (1,733.8) (81.0) (1,716.9) (3,531.7)
Other segment information
Capital expenditure:
Property, plant and equipment 115.6 37.6 0.2 153.4
Intangible exploration and evaluation assets - 6.8 - 6.8
Depletion, depreciation and amortization (359.3) (12.6) (4.1) (376.0)
Impairment reversal of property, plant and equipment, net - 2.8 2.0 4.8
Exploration costs written off - (2.1) - (2.1)
1. Segment result is a non-IFRS measure which includes gross profit,
exploration costs written off and impairment of property, plant and equipment.
See reconciliation below.
2. Unallocated expenditure relates to general and administrative expenses not
specifically attributable to a geographic area.
3. Total liabilities - Corporate comprise the Group's external debt and
other non-attributable liabilities.
4. Other excludes results attributable to Gabon, which is classified as
discontinued operations (refer to note 8).
Reconciliation of segment result
$m 2025 2024
Segment result 250.0 444.2
Add back
Exploration costs written off 2.1 202.3
Impairment reversal of property, plant and equipment (4.8) (11.8)
Gross profit 247.3 634.7
4. Segmental reporting continued
$m Ghana Other(4) Corporate Total
2024 (restated)
Sales revenue by origin 1,325.4 35.4 (73.6) 1,287.2
Segment result(1) 722.6 (186.8) (91.6) 444.2
Provisions reversal 70.4
Unallocated expenses(2) (65.9)
Operating profit 448.7
Finance income 69.2
Finance costs (344.2)
Profit before tax 173.7
Income tax expense (228.7)
Loss after tax (55.0)
Total assets 3,164.3 422.1 465.1 4,051.5
Total liabilities(3) (1,978.4) (266.2) (2,079.6) (4,324.2)
Other segment information
Capital expenditure:
Property, plant and equipment 126.4 124.5 2.6 253.5
Intangible exploration and evaluation assets 0.2 34.5 - 34.7
Depletion, depreciation and amortisation (401.4) (39.7) (3.1) (444.2)
Impairment reversal of property, plant and equipment, net - 11.8 - 11.8
Exploration costs written off - (212.6) - (212.6)
1. Segment result is a non-IFRS measure which includes gross profit,
exploration costs written off and impairment of property, plant and equipment.
See reconciliation above.
2. Unallocated expenditure relates to general and administrative expenses
not specifically attributable to a geographic area.
3. Total liabilities - Corporate comprise of the Group's external debt,
derivative financial instruments and other non-attributable liabilities.
4. Other excludes results attributable to Gabon, which is classified as
discontinued operations (refer to note 8).
5. Other costs
$m 2025 2024 Restated(3)
Cost of sales
Operating costs 202.9 197.8
Depletion and amortisation of oil and gas and leased assets(1) 371.4 412.1
Overlift, underlift and oil stock movements 28.3 42.1
Share-based payment charge included in cost of sales 0.5 0.4
Other cost of sales 0.8 0.1
Total cost of sales 603.9 652.5
Administrative expenses
Share-based payment charge included in administrative expenses 7.2 6.5
Depreciation of other fixed assets 4.6 6.5
Other administrative costs 33.2 39.2
Total administrative expenses 45.0 52.2
Provisions/(provisions reversal)(2) 7.2 (63.3)
1. Depreciation expense on leased assets of $67.7
million (2024: $91.4 million) as per note 10 includes a charge of $2.1 million
(2024: $4.1 million) on leased administrative assets, which is presented in
administrative expenses in the income statement. The remaining balance of
$65.6 million (2024: $87.3 million) relates to other leased assets and is
included in cost of sales.
2. This includes a provision for restructuring and
redundancy costs of $7.2 million (2024: $7.1 million). The prior year balance
includes reduction in other provisions of $70.4 million.
3. Comparative amounts have been restated to present
Gabon as a discontinued operation. Refer to note 8.
6. Net financing costs
$m 2025 2024 Restated(1)
Interest on bank overdrafts and borrowings 206.3 211.5
Interest on obligations for leases 97.0 119.7
Total borrowing costs 303.3 331.2
Finance and arrangement fees(2) 10.7 3.0
Other interest expense 0.6 -
Unwinding of discount on decommissioning provisions(3) 11.4 10.0
Total finance costs 326.0 344.2
Interest income on amounts due from joint venture partners for leases (37.9) (48.1)
Other finance income (25.5) (21.1)
Total finance income (63.4) (69.2)
Net financing costs 262.6 275.0
1. Comparative amounts have been restated to present Gabon as a discontinued
operation. Refer to note 8.
2. Finance and arrangement fees mostly relate to costs incurred in
unsuccessful refinancing activities. Costs relating to the refinancing
transaction announced in February 2026 are recognised in Prepayments (note 11)
and will be capitalised on completion of the transaction in 2026.
3. This is excluding $0.8 million of unwinding of discount on
decommissioning provsions in Gabon (2024: $1.4 million).
7. Taxation on profit on continuing activities
$m 2025 2024
Restated(1)
Current tax on profits for the year
Foreign tax 96.6 259.1
Adjustments in respect of prior periods (0.3) (1.6)
Total corporate tax 96.3 257.5
UK petroleum revenue tax - (2.4)
Total current tax 96.3 255.1
Deferred tax
Origination and reversal of temporary differences
UK corporation tax (24.9) (19.1)
Foreign tax (5.5) (11.1)
Adjustments in respect of prior periods 2.8 (0.1)
Total deferred corporate tax (27.6) (30.3)
Deferred UK petroleum revenue tax (2.2) 3.9
Total deferred tax (29.8) (26.4)
Total income tax expense 66.5 228.7
1. Comparative amounts have been restated to present Gabon as a discontinued
operation. Refer to note 8.
$m 2025 2024
Restated(1)
(Loss)/ Profit from continuing activities before tax (62.7) 173.7
Tax on (loss)/ profit from continuing activities at the standard UK (15.7) 43.4
corporation
tax rate of 25% (2024: 25%)
Effects of:
Non-deductible exploration expenditure 0.4 50.3
Other non-deductible expenses 5.3 (3.5)
Net deferred tax asset not recognised 56.4 78.2
Utilisation of tax losses not previously recognised (0.2) (0.6)
Adjustment relating to prior years 2.5 (1.7)
Other tax rates applicable outside the UK 16.6 62.6
Tax impact of acquisitions and disposals 1.2 -
Total income tax expense for the year 66.5 228.7
1. Comparative amounts have been restated to present Gabon as a discontinued
operation. Refer to note 8.
Uncertain tax treatments
The Group is subject to various material claims which arise in the ordinary
course of its business in various jurisdictions, including cost recovery
claims, claims from regulatory bodies and both corporate income tax and
indirect tax claims. The Group is in formal dispute proceedings regarding a
number of these tax claims. The resolution of tax positions, through
negotiation with the relevant tax authorities or litigation, can take several
years to complete. In assessing whether these claims should be provided for in
the Financial Statements, management has considered them in the context of the
applicable laws and relevant contracts for the countries concerned. Management
has applied judgement in assessing the likely outcome of the claims and has
estimated the financial impact based on external tax and legal advice and
prior experience of such claims.
Provisions for uncertain tax treatments of $78.3 million (2024: $80.8 million)
are included in income tax payable of $76.7 million (2024: $79.0 million) and
provisions of $1.7 million (2024: $1.8 million). Where these matters
relate to expenditure which is capitalised within intangible exploration and
evaluation assets and property, plant and equipment, any difference between
the amounts accrued and the amounts settled is capitalised in the relevant
asset balance, subject to applicable impairment indicators. Where these
matters relate to producing activities or historical issues, any differences
between the accrued and settled amounts are taken to the Group income
statement.
Due to the uncertainty of such tax items, it is possible that on conclusion of
an open tax matter at a future date, the outcome may differ significantly from
management's estimate. If the Group was unsuccessful in defending
itself from all these claims, the result would be additional liabilities of
$582.7 million (2024: $608.7 million) excluding interest and penalties. In
management's view the likelihood of the crystallisation of these liabilities
and the associated interest and penalties is remote.
7. Taxation on profit on continuing activities continued
The provisions and contingent liabilities relating to uncertain tax treatments
have decreased following the conclusion of tax authority challenges and
matters lapsing under the statute of limitations, but have increased,
following new claims being initiated and extrapolation of exposures through to
31 December 2025, giving rise to an overall decrease in provision of $2.5
million and decrease in contingent liability of $26.0 million.
Ghana tax assessments
In October 2021, Tullow Ghana Limited (TGL) filed a Request for Arbitration
with the International Chamber of Commerce (ICC) disputing the $320.3 million
Branch Profits Remittance Tax (BPRT) assessment issued as part of the direct
tax audit for the financial years 2014 to 2016. The Ghana Revenue Authority
(GRA) is seeking to apply BPRT under a law which the Group considers is not
applicable to TGL, since it falls outside the tax regime provided for in the
Petroleum Agreements and relevant double tax treaties. Two hearings took place
in November 2023 and June 2024. On 24 December 2024, the BPRT Tribunal issued
its ruling to the ICC, which delivered its award on 2 January 2025 with regard
to the BPRT arbitration with the Government of Ghana. The Tribunal determined
that BPRT is not applicable to Tullow Ghana since it falls outside the tax
regime provided for in the Petroleum Agreements. This means that Tullow Ghana
is not liable to pay the $320.3 million BPRT assessment issued by the GRA,
and Tullow has no future exposure to BPRT in respect of its operations under
the Petroleum Agreements.
In December 2022, TGL received a $190.5 million corporate income tax
assessment and payment demand from the GRA relating to the disallowance of
loan interest for the financial years 2010 to 2020. The Group has previously
disclosed assessments by the GRA relating to the same issue; this revised
assessment supersedes all previous claims. The Group considers the assessment
to breach TGL's rights under its Petroleum Agreements. In February 2023, TGL
filed a Request for Arbitration with the ICC disputing the assessment, with
the suspension of TGL's obligation to pay any amount in relation to the
assessment until the dispute is formally resolved. The parties initially
agreed a procedural timetable for the arbitration under which the first
Tribunal hearing was to be held in July 2025. This has now been postponed to
September 2026 allowing more time to continue settlement negotiations.
In December 2022, TGL received a $196.5 million corporate income tax
assessment and payment demand from the GRA relating to proceeds received by
Tullow during the financial years 2016 to 2019 under Tullow's corporate
Business Interruption insurance policy. The Group considers the assessment to
breach TGL's rights under its Petroleum Agreements. In February 2023, TGL
filed a Request for Arbitration to the ICC disputing the assessment, with the
suspension of TGL's obligation to pay any amount in relation to the assessment
until the dispute is formally resolved. The first Tribunal hearing was
held in November 2025 and a ruling is expected mid-year 2026.
The Group continues to engage with the Government of Ghana with the aim of
resolving these tax disputes on a mutually acceptable basis.
Kenya tax assessments
The Group is aware of a tax assessment for c.$170 million from the Kenya
Revenue Authority relating to alleged underpaid VAT and Capital Gains Tax on
the disposal of its 100% shareholding in its Kenyan subsidiary, Tullow Kenya
BV, to the Gulf Energy Group for a minimum consideration of $120 million. The
Group's clear and firm position is that the assessment is wholly without
merit, and it intends in conjunction with Gulf Energy to contest the
assessment through the regular objection process. There will be no cash
outflow in respect of lodging these objections, nor does the Group expect cash
outflow on completion of its appeal process. Therefore, a provision for
uncertain tax treatments in respect of this risk has not been recorded.
Bangladesh litigation
The National Board of Revenue (NBR) is seeking to disallow $118 million of tax
relief in respect of development costs incurred by Tullow Bangladesh Limited
(TBL). The NBR subsequently issued a payment demand to TBL in February 2020
for Taka 3,094 million requesting payment by 15 March 2020. The amount in USD
including legal costs is c.$29 million. However, under the Production Sharing
Contract (PSC), the government is required to indemnify TBL against all taxes
levied by any public authority, and the share of production paid to
Petrobangla (PB), Bangladesh's national oil company, is deemed to include all
taxes due, which PB is then obliged to pay to the NBR. TBL sent the payment
demand to PB and the government requesting the payment or discharge of the
payment demand under their respective PSC indemnities. On 14 June 2021, TBL
issued a formal notice of dispute under the PSC to the government and PB.
A further request for payment was received from NBR on 28 October 2021
demanding settlement by 15 November 2021. Arbitration proceedings were
initiated under the PSC on 29 December 2021, and a hearing of the merits of
the case were heard by the Tribunal on 20 May 2024. Final written
submissions were made to the Tribunal in September 2024. The Tribunal has
informed both parties that a ruling can be expected during the first half of
2026.
Other items
Other items totalling $166.6 million (2024: $192.3 million) comprise exposures
in respect of claims for corporation tax from disallowed expenditure or
withholding taxes that are either currently under discussion with the tax
authorities or which arise from known issues for periods not yet under audit.
Timing of cash-flows
While it is not possible to estimate the timing and amount of tax cash flows
in relation to possible outcomes with certainty, management anticipates that
there will not be material cash taxes paid in excess of the amounts provided
for uncertain tax treatments.
8. Asset disposals and discontinued operations
Gabon
On 29 July 2025, Tullow completed the sale of Tullow Oil Gabon SA to the Gabon
Oil Company for a total cash consideration of $307 million, net of tax and
customary adjustments. The transaction was a corporate sale of Tullow's entire
Gabonese portfolio of assets, representing c.10 kbopd of production and c.36
million barrels of 2P reserves. The transaction was subject to a capital gains
tax of $51.7 million as agreed with the Gabon Tax Authority, payable by the
Gabon Oil Company. This was recorded as an income tax expense with a
corresponding pre-tax gain on disposal and no deferred tax recognised.
This represents a disposal of a separate major geographical area of operations
under IFRS 5 Non-current Assets Held for Sale and Discontinued Operation, and
as such the results of operations in Gabon have been presented as a
discontinued operation for the years ended 31 December 2025 and 2024.
The results from discontinued operations for the year are presented below:
$m 2025 2024
Discontinued operations
Revenue 115.4 247.7
Cost of sales (53.1) (128.4)
Gross profit 62.3 119.3
Administrative expenses (0.2) (1.0)
Asset revaluation - 38.9
Exploration costs written off (5.3) (10.3)
Operating profit 56.8 146.9
Finance income 0.7 2.3
Finance costs (0.9) (1.4)
Profit before tax 56.6 147.8
Income tax expense (34.5) (38.2)
Profit after tax 22.1 109.6
Gain on disposal 165.3 -
Tax on gain on disposal (51.7) -
Profit after tax from discontinued operations 135.7 109.6
Earnings per share from discontinued operations, ¢ 2025 2024
Basic 9.3 7.5
Diluted 9.0 7.1
The net cash flows generated/(incurred) by Tullow Oil Gabon SA are as follows:
$m 2025 2024
Cash flows from operating activities (24.2) 21.4
Cash flows from investing activities (87.7) (45.7)
Cash flows from financing activities 114.9 22.2
Net cash inflow/(outflow) 3.0 (2.1)
8. Asset disposals and discontinued operations continued
The net assets disposed from the transaction and the subsequent gain on
disposal for the year ended 31 December 2025 are as follows:
$m 2025
Goodwill 44.9
Intangible exploration and evaluation assets 6.1
Property, plant and equipment 204.5
Inventories 21.8
Trade receivables 26.0
Other current assets 0.1
Cash and cash equivalents 0.9
Total assets disposed 304.3
Trade and other payables (16.1)
Current tax liabilities (18.9)
Provisions (35.9)
Deferred tax liabilities (48.4)
Total liabilities disposed (119.3)
Net assets disposed 185.0
$m 2025
Cash consideration 307.1
Capital gains tax paid by Gabon Oil Company 51.7
Net assets disposed (185.0)
Transaction costs (8.5)
Gain on disposal 165.3
8. Asset disposals and discontinued operations continued
Kenya
On 25 September 2025, Tullow completed the sale of Tullow Kenya BV, which
holds Tullow's entire working interest in Kenya, to Auron Energy E&P
Limited, an affiliate of Gulf Energy Limited, for a total consideration of at
least $120 million. The consideration is split into $40 million payment
received on completion (Tranche A), $40 million receivable at the earlier of
Field Development Plan (FDP) approval or 30 June 2026 (Tranche B), and $40
million receivable no later than 2033 (Tranche C), subject to the following
payment schedule:
· Payments of $2 million per quarter starting in the third quarter
of 2028, provided Dated Brent oil price averaged at least $65/bbl during the
preceding quarter.
· If $40 million in aggregate has not been paid by 30 June 2033,
the remainder will be due as a bullet payment at that point irrespective of
the prevailing oil price.
In addition, Tullow is entitled to royalty payments subject to subject to oil
price, resource, and production related conditions. Tullow also retains a
back-in right for a 30% participation in potential future development phases
at no cost.
$36 million proceeds of the Tranche B was received on 9 March 2026. The final
10% of Tranche B proceeds ($4 million), was received on 1 April following
completion of transition support services.
Tullow Kenya BV is not presented as a discontinued operation for the year
ended 31 December 2025 as it is not a major line of business for the
Group.
The net assets disposed from the transaction and the subsequent loss on
disposal for the year ended 31 December 2025 are as follows:
$m 2025
Intangible exploration and evaluation assets 107.7
Trade receivables 8.4
Other current assets 0.4
Cash and cash equivalents 1.8
Total assets disposed 118.3
Trade and other payables (5.1)
Total liabilities disposed (5.1)
Net assets disposed 113.2
$m 2025
Consideration(1) 110.5
Net assets disposed (113.2)
Transaction costs (1.8)
Loss on disposal (4.5)
1. Consideration relates to $40 million cash received (Tranche A) and the
present value of Tranches B-C. No amount has been recognised with respect to
the royalty payments and the back-in right as their fair value cannot be
reliably estimated as of the reporting date.
Net proceeds from disposals of $334.2 million were received during the year,
comprising cash consideration of $347.0 million, less transaction cost of
$10.3 million and cash disposed of $2.7 million relating to disposals in Kenya
and Gabon, as well as $0.2 million of other disposals.
9. Intangible exploration and evaluation assets
$m 2025 2024
At 1 January 109.1 287.0
Additions 6.8 34.7
Exploration costs written off (2.1) (212.6)
Disposals(1) (113.8) -
At 31 December - 109.1
1. This balance relates to assets in Gabon and Kenya. Refer to note 8.
The below table provides a summary of the exploration costs written off on a
pre-tax basis by country.
Country CGU Rationale for 2025 write-off 2025 2025
Write-off
Remaining recoverable amount
$m
$m
Argentina MLO114, MLO119 and MLO122 a 1.2 -
Côte d'Ivoire Block 524 and Block 803 b 0.5 -
Other Various c 0.4 -
Total write-off 2.1
a. Licence period concluded in October 2025.
b. Licence periods concluded in May 2025 for Block 803 and August 2025 for
Block 524.
c. Current year expenditure on assets previously written off.
d. In addition to the exploration costs written off stated above, $5.3
million has been recognised in Gabon relating to uncommercial well costs
incurred in DE8 and Simba cash-generating units (CGUs). This is presented as
discontinued operations in note 8.
Country CGU Rationale for 2024 write-off 2024 Write-off restated(e)
$m
2024 Remaining recoverable amount
$m
Argentina MLO114, MLO119 and MLO122 a 38.8 -
Côte d'Ivoire Block 524 and Block 803 a 15.5 -
Kenya Blocks 10BB and 13T b 145.4 103.2
New Ventures Various c 1.3 -
Uganda Exploration areas 1, 1A, 2 and 3A d 0.8 -
Other Various 0.5 -
Total write-off 202.3
a. No further activity planned following unsuccessful farm-down efforts.
b. Delay in farm-down and extension of Field Development Plan review period.
c. New Ventures expenditure is written off as incurred.
d. Indirect tax movement on previously disposed or written-off assets.
e. In addition to the exploration costs written off stated above, $10.3
million has been recognised in Gabon relating to uncommercial well costs
incurred in Simba CGU. This is presented as discontinued operations in note 8.
10. Property, plant and equipment
$m 2025 2025 2025 2025 2024 2024 2024 2024
Oil and gas assets
Other fixed assets
Right-of-use assets
Total
Oil and gas assets
Other fixed assets
Right-of-use assets
Total
Cost
At 1 January 11,513.8 23.4 1,124.4 12,661.6 11,282.1 21.9 1,268.8 12,572.8
Additions 153.1 0.3 - 153.4 151.6 3.1 1.4 156.1
Acquisitions - - - - 97.4 - - 97.4
Disposal (718.0) (2.4) - (720.4) - - - -
Asset retirement - - - - - (1.3) (145.3) (146.6)
Currency translation adjustments 78.0 0.9 2.2 81.1 (17.3) (0.3) (0.5) (18.1)
At 31 December 11,026.9 22.2 1,126.6 12,175.7 11,513.8 23.4 1,124.4 12,661.6
Depreciation, depletion and amortization and impairment
At 1 January (9,698.9) (18.6) (620.0) (10,337.5) (9,377.7) (17.5) (644.8) (10,040.0)
Charge for the year (305.8) (2.5) (67.7) (376.0) (350.3) (2.5) (91.4) (444.2)
Impairment reversal 2.8 - 2.0 4.8 11.8 - - 11.8
Capitalised depreciation - - (8.3) (8.3) - - (29.5) (29.5)
Disposal 513.6 2.3 - 515.9 - - - -
Asset retirement - - - - - 1.3 145.3 146.6
Currency translation adjustments (78.0) (0.6) (1.7) (80.3) 17.3 0.1 0.4 17.8
At 31 December (9,566.3) (19.4) (695.7) (10,281.4) (9,698.9) (18.6) (620.0) (10,337.5)
Net book value at 31 December 1,460.6 2.8 430.9 1,894.3 1,814.9 4.8 504.4 2,324.1
The Group applied the following nominal oil price assumption for impairment
assessments:
Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 onwards
2025 $60/bbl $64/bbl $70/bbl $70/bbl $70/bbl $70/bbl inflated at 2%
2024 $74/bbl $71/bbl $75/bbl $75/bbl $75/bbl $75/bbl inflated at 2%
Trigger for 2025 Pre-tax discount rate assumption 2025 Remaining recoverable amount(e)
Impairment/ (reversal)
2025 Impairment/ (reversal)
$m $m
Espoir (Cote D'Ivoire) a 4.5 n/a -
Mauritania b 0.2 n/a -
UK CGU b,c (7.5) n/a -
UK Corporate d (2.0) n/a -
Impairment reversal (4.8) -
a. Impairment of capital expenditure in excess of accumulated depreciation
as the NPV of the asset is nil.
b. Change to decommissioning estimate.
c. The fields in the UK are grouped into one CGU as all fields share
critical gas infrastructure.
d. Partial reversal of previously recognised impairment of right-of-use
asset relating to office space.
e. The remaining recoverable amount of the asset is its value in use.
The $35.0 million impairment in the TEN fields recognised at 30 June 2025 has
been fully reversed at the year end. This change has been recognised following
an assessment which determined that the fair value less cost of disposal
(FVLCD) of TEN of $41.4 million was materially equal to the total carrying
value of the CGU. FVLCD reflects the impact of the acquisition of the FPSO, as
a market participant would have assumed the successful completion of the
purchase transaction when pricing the asset. A pre-tax discount rate of 14%
was applied in the assessment.
Oil prices stated above are benchmark prices to which an individual field
price differential is applied. All impairment assessments are prepared on a
VIU or FVLCD basis using discounted future cash flows based on 2P reserves
profiles. A reduction or increase in the two-year forward curve of $5/bbl,
based on the approximate range of annualised average oil price over recent
history, and a reduction or increase in the medium and long-term price
assumptions of $5/bbl, based on the range of annualised average historical
prices, are considered to be reasonably possible changes for the purposes of
sensitivity analysis. Decreases to oil prices specified above would result in
an impairment charge for TEN of $41.4 million, reducing the remaining carrying
value of the CGU to $nil, whilst increases to oil prices specified above would
lead to an impairment reversal of $43.6 million. A 1% increase in the post-tax
discount rate would result in an impairment charge of $8.5 million. The Group
believes a 1% increase in the post-tax discount rate to be a reasonable
possibility based on historical analysis of the Group's and peer group of
companies' impairments. The above scenarios would not have an impact on the
carrying value of Jubilee.
10. Property, plant and equipment continued
Trigger for 2024 Pre-tax discount rate assumption 2024 Remaining recoverable amount(e)
Impairment/ (reversal)
2024 Impairment/ (reversal)
$m $m
Espoir (Cote D'Ivoire) a 2.5 14% -
Mauritania b (19.7) n/a -
UK CGU c,d 5.4 n/a -
Impairment reversal (11.8)
a. Change to decommissioning discount rate.
b. Impairment reversal driven by operational efficiencies and scope revision.
c. Change to decommissioning estimate.
d. The fields in the UK are grouped into one CGU as all fields share
critical gas infrastructure.
e. The remaining recoverable amount of the asset is its value in use.
11. Other assets
$m 2025 2024
Non-current
Amounts due from joint venture partners 269.7 333.1
VAT recoverable - 7.7
Deferred consideration 30.5 -
300.2 340.8
Current
Amounts due from joint venture partners 404.7 350.2
Underlifts - 20.9
Prepayments 20.1 17.1
Deferred consideration 40.0 -
Other current assets 8.1 3.7
472.9 391.9
773.1 732.7
Non-current receivables from joint venture partners include the Ghana
decommissioning fund, which relates to the requirement for joint venture
partners of the Unitisation and Unit Operating Agreement (UUOA) to establish a
trust fund in which the estimated cost of decommissioning and abandonment are
accrued to cover decommissioning obligations in respect of the Jubilee Field
Unit when the trigger date occurs. As at 31 December 2025, Tullow has
contributed $23.2 million (2024: $11.6 million) into the decommissioning trust
fund.
The increase in current receivables from joint venture partners compared to 31
December 2024 relates to net increase in GNPC (Ghana National Petroleum
Corporation) receivable and other working capital movements.
GNPC receivables as at 31 December 2025 were $223.1 million net to Tullow
(2024: $110.8 million), with $64.9 million related to cash calls (2024: $6.7
million), $107.8 million related to gas receivable (2024: $56.2 million) and
$50.4 million related to TEN development debt (2024: $47.9 million). Tullow is
working with the Government of Ghana and its agencies to resolve these
outstanding balances.
Deferred consideration relates to Tranche B and C, adjusted for time value of
money, from disposal of assets in Kenya (refer to note 8).
12. Business combination
On 29 February 2024, the Group completed the asset swap agreement (ASA)
transaction with Perenco Oil and Gas Gabon S.A (Perenco). The rationale for
the transaction was the simplification of the Group's equity ownership across
key fields in Gabon, creating better alignment between the participating
interest partners and streamlining processes such as budgeting, cost
management and capital allocation. The revised portfolio of assets has enabled
Tullow to leverage its technical skills and focus on more material positions
in key fields.
The transaction was an asset swap achieved through the exchange of
participating interests held by both parties in certain licences in Gabon. The
exchange represented the acquisition of an additional interest in a joint
operation that constitutes a business, and therefore IFRS 11 Joint
Arrangements required the application of the principles in IFRS 3 Business
Combinations.
In line with the requirements of IFRS 3, the interests transferred as part of
the consideration, which comprised mainly of property, plant, and equipment of
$54.4 million, were remeasured to the acquisition date fair value of $93.3
million. This resulted in an asset revaluation gain of $38.9 million
recognised in the income statement at 31 December 2024.
The fair values of the identifiable assets and liabilities acquired were:
Fair value recognised on
acquisition
$m
Intangible assets 1.0
Property, plant and equipment 97.4
Other current assets 0.7
Goodwill 44.9
Total assets acquired 144.0
Provisions (5.8)
Deferred tax liabilities (44.9)
Total liabilities assumed (50.7)
Net identifiable assets acquired 93.3
Total purchase consideration (93.3)
Consideration satisfied by exchange of assets (85.2)
Consideration satisfied by cash (8.1)
Purchase of additional interest in joint operation per the cash flow statement (8.1)
The fair value of the purchase consideration of $93.3 million reflected the
discounted future cash flows of the assets and liabilities exchanged as part
of the swap as the transaction was intended to be value neutral. However, as
the transaction completed more than a year later, the ASA included provisions
to ensure the neutrality of the transaction via cash adjustments for the
period between the economic date and the completion date, the agreed
adjustment upon completion was $8.1 million, which has been included in
investing activities in the cash flow statement.
IAS 12 Income Taxes requires recognition of a deferred tax asset or liability
for the difference between the fair value of the assets acquired and
liabilities assumed, and their respective tax bases. Goodwill of $44.9 million
was recognised as a direct result of the recognition of the deferred tax
liability.
The assets and liabilities acquired from the transaction, including the
goodwill, were part of the disposal group in the sale of Tullow Oil Gabon SA
in the year ending 31 December 2025. Refer to note 8.
13. Trade and other payables
$m 2025 2024
Current
Trade payables 92.7 75.7
Other payables 63.3 96.8
Overlifts 15.3 38.3
Accruals 305.4 373.8
Current portion of leases 161.7 151.9
638.4 736.5
Non-current
Other non-current liabilities(1) 56.1 84.9
Non-current portion of leases 436.9 581.0
493.0 665.9
1. Other non-current liabilities include balances related to joint venture
partners.
Accruals relate to operating and administrative expenditure of $147.1 million
(2024: $196.3 million), capital expenditure of $124.1 million (2024: $119.6
million), interest expense on bonds of $24.0 million (2024: $35.3 million) and
staff-related expenses of $10.2 million (2024: $22.6 million). The movement in
the operating and administrative expenditure is driven by efficiencies in cost
management and optimised contractual arrangements with suppliers.
Trade and other payables are non-interest bearing except for leases (note 14).
The change in trade payables and in other payables represents timing
differences and levels of work activity, particularly the ongoing drilling
campaign in Jubilee which commenced in late 2025.
Payables related to operated joint ventures (primarily in Ghana) are recorded
gross with the amount representing the partners' share recognised in amounts
due from joint venture partners (note 11).
The movement in current and non-current lease liabilities is mainly driven by
the level of drilling activity in Ghana (note 14).
14. Leases
This note provides information for leases where the Group is a lessee. The
Group did not enter into any material contracts acting as a lessor.
i) Amounts recognised in the balance sheet
Right-of-use assets Lease liabilities
$m 2025 2024 2025 2024
Right-of-use assets (included within property, plant and equipment) and lease
liabilities
Property leases 15.9 18.2 21.4 26.1
Oil and gas production and support equipment leases 400.5 466.4 541.4 661.9
Transportation equipment leases 14.5 19.8 35.8 44.9
Total 430.9 504.4 598.6 732.9
Current provisions 161.7 151.9
Non-current 436.9 581.0
Total 598.6 732.9
There were no additions and disposals of right-of-use assets during the 2025
financial year (2024: $1.4 million and $145.3 million). Refer to note 10.
14. Leases continued
TEN FPSO
The Group's leases balance includes the TEN FPSO. As at 31 December 2025, the
present value of the TEN FPSO right-of-use asset was $398.3 million (2024:
$466.3 million).
The present value of the TEN FPSO gross lease liability was $534.4 million
(2024: $650.0 million).
A receivable from the joint venture partners of $200.5 million (2024: $244.9
million) was recognised in other assets (note 11) to reflect the value of
future payments that will be met by cash calls from partners relating to the
TEN FPSO lease. The present value of the receivable from the joint venture
partners unwinds over the expected life of the lease and the unwinding of the
discount is reported in the finance income.
On 19 February 2026, Tullow announced that it signed a Sale and Purchase
Agreement to acquire the TEN FPSO on behalf of the joint venture.
Carrying amounts of the lease liabilities and joint venture leases receivables
and the movements during the period:
$m Lease liabilities Joint venture lease receivables Total
At 1 January 2024 (906.7) 349.5 (557.2)
Additions and changes in lease estimates 1.6 1.2 2.8
Payments/(receipts) 291.6 (122.6) 169.0
Interest (expense)/income (119.7) 48.1 (71.6)
Currency translation adjustments 0.3 - 0.3
At 1 January 2025 (732.9) 276.2 (456.7)
Payments/(receipts) 232.3 (90.2) 142.1
Interest (expense)/income (97.0) 37.9 (59.1)
Currency translation adjustments (1.0) - (1.0)
At 31 December 2025 (598.6) 223.9 (374.7)
ii) Amounts recognised in the statement of profit or loss
$m 2025 2024
Depreciation charge of right-of-use assets
Property leases 4.4 8.5
Oil and gas production and support equipment leases 63.3 82.9
Total 67.7 91.4
Interest expense on lease liabilities (included in finance costs) 97.0 119.7
Interest income on amounts due from joint venture partners (37.9) (48.1)
Expense relating to short-term leases 57.2 0.8
Expense relating to leases of low-value assets 0.6 0.6
Total 184.6 164.4
The total net cash outflow for leases in 2025 was $142.1 million (2024: $169.0
million).
15. Provisions
$m Decommissioning Other provisions Total Decommissioning 2024 Other provisions Total
2025
2025
2025
2024
2024
At 1 January 306.4 39.4 345.8 377.9 93.7 471.6
New provisions - 16.5 16.5 - 22.4 22.4
Changes in estimate (32.1) (2.1) (34.2) (39.3) (75.9) (115.2)
Acquisitions - - - 5.8 - 5.8
Disposal of subsidiaries (31.6) (4.3) (35.9) - - -
Payments (5.9) (37.9) (43.8) (49.0) (0.7) (49.7)
Unwinding of discount 12.2 - 12.2 11.4 - 11.4
Currency translation adjustment 1.9 0.3 2.2 (0.4) (0.1) (0.5)
At 31 December 250.9 11.9 262.8 306.4 39.4 345.8
Current provisions 3.3 2.2 5.5 9.8 14.5 24.3
Non-current provisions 247.6 9.7 257.3 296.6 24.9 321.5
Other provisions include non-income tax provisions of $5.7 million (2024: $7.1
million) and $6.2 million (2024: $32.3 million) of disputed cases and claims.
Management estimates non-current other provisions would fall due between two
and five years.
New other provisions of $16.5 million mainly relate to redundancy and
restructuring costs incurred during the year.
The decommissioning provision represents the present value of decommissioning
costs relating to the UK and African oil and gas interests. The Group has
assumed cessation of production as the estimated timing for outflow of
expenditure. However, expenditure could be incurred prior to cessation of
production or after and actual timing will depend on a number of factors,
including underlying cost environment, availability of equipment and services,
and allocation of capital.
Decommissioning provisions Inflation assumption(1) Discount rate assumption Cessation of production assumption Total Discount rate assumption Cessation of production assumption Total
2025
2025
2025
2024
2024
2024
$m $m
Côte d'Ivoire n/a n/a 2026 54.8 4.5% 2026 50.0
Gabon n/a n/a n/a - 4.5-5.0% 2030-2047 30.7
Ghana 2.0% 4.0% 2035-2036 177.0 4.5% 2033-2036 195.6
Mauritania n/a n/a 2018 0.8 n/a 2018 1.1
UK n/a 3.5% 2018 18.3 n/a 2018 29.0
250.9 306.4
1. Short-term inflation rate assumption has increased from 2.5% to 3%
in 2026. Long-term rates of 2% remained unchanged from 31 December 2024.
The Group is in discussions with the regulator in respect of the impact of the
intended transfer of operatorship to the PetroCi (upon expiry of the license
effective July 2026) on the decommissioning obligation for the Espoir field in
Côte d'Ivoire. Inflation and discounting adjustments have not been applied to
the decommissioning estimate.
The Group's decommissioning activities are ongoing in the UK and Mauritania,
with $3.3 million of the future costs expected to be incurred in 2026. The
remaining activities are planned to continue through to 2030, with an
associated expenditure of $15.8 million, mostly in the UK.
16. Commercial reserves and contingent resources summary working interest
basis
Ghana Other Total
Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Petroleum
bcf
bcf
bcf
mmboe(6)
COMMERCIAL
RESERVES(1)
1 January 2025 104.8 138.4 36.4 1.1 141.2 139.5 164.5
Revisions(3) (14.7) 7.8 - - (14.7) 7.8 (13.4)
Production (11.9) (14.8) (0.3) (0.8) (12.2) (15.6) (14.8)
Acquisitions - - - - - - -
Disposals(4,5) - - (36.0) - (36.0) - (36.0)
31 December 2025 78.2 131.4 0.1 0.3 78.3 131.7 100.3
CONTINGENT RESOURCES(2)
1 January 2025 126.4 438.8 509.2 13.9 635.6 452.7 711.0
Revisions(3) (11.2) (8.9) - - (11.2) (8.9) (12.7)
Acquisitions - - - - - - -
Disposals(4,5) - - (494.7) - (494.7) - (494.7)
31 December 2025 115.2 429.9 14.5 13.9 129.7 443.8 203.6
TOTAL
31 December 2025 193.4 561.3 14.6 14.2 208.0 575.5 303.9
1. Reserves presented are 'proven and probable'. They are as audited and
reported by the independent third-party reserves auditor as at year end 2025.
2. Contingent resources are 'best estimate'. For Ghana, they are as audited
and reported by the independent third-party reserves auditor as at year end
2025.
3. Reserves and resources revisions in Ghana are primarily related to a
technical re-evaluation based on Jubilee production performance during 2025.
4. Reserve and resource changes in the non-operated portfolio primarily
reflect the disposal of the Gabon assets at the start of 2025, with only the
Espoir asset remaining at the end of 2025.
5. The sale of S.Lokichar assets in Kenya have contributed the most
significant reduction in contingent resources.
6. A gas conversion factor of 6 mscf/boe is used to calculate the total
petroleum mmboe.
The Group provides for depletion and amortisation of tangible fixed assets on
a net entitlements basis, which reflects the terms of the Production Sharing
Contracts related to each field. Total working interest reserves were 100.4
mmboe at 31 December 2025 (31 December 2024: 161.5 mmboe).
Contingent resources are discovered resources for which development plans are
either in the course of preparation, on hold or further evaluation is under
way with a view to future development.
Alternative performance measures
The Group uses certain measures of performance that are not specifically
defined under IFRS or other generally accepted accounting principles. These
non-IFRS measures include capital investment, net debt, gearing, adjusted
EBITDAX, underlying cash operating costs, free cash flow, underlying operating
cash flow and pre-financing cash flow.
Capital investment
Capital investment is defined as additions to property, plant and equipment
and intangible exploration and evaluation assets less decommissioning asset
additions, right-of-use asset additions, lease payments related to capital
activities, additions to administrative assets, and certain other adjustments.
The Directors believe that capital investment is a useful indicator of the
Group's organic expenditure on exploration and evaluation assets and oil and
gas assets incurred during a period because it eliminates certain accounting
adjustments such as decommissioning and administrative asset additions.
$m 2025 2024
Additions to property, plant and equipment 153.1 249.0
Additions to intangible exploration and evaluation assets 6.8 34.7
Less
Changes to decommissioning asset estimates (32.1) (39.3)
Right-of-use asset additions - 1.4
Lease payments related to capital activities - (21.9)
Additions to administrative assets 0.3 3.1
Other non-cash capital movements(1) (3.7) 109.3
Capital investment 195.4 231.1
Movement in working capital (0.1) (1.6)
Additions to administrative assets 0.3 3.1
Cash capital expenditure per the cash flow statement 195.6 232.6
1. In 2024, Other Non-cash capital movements includes $95 million of additions
in relation to asset swap with Perenco in Gabon.
Net debt
Net debt is a useful indicator of the Group's indebtedness, financial
flexibility and capital structure because it indicates the level of cash
borrowings after taking account of cash and cash equivalents in the Group's
business that could be utilised to pay down the outstanding cash borrowings.
Net debt is defined as current and non-current borrowings plus non-cash
adjustments, less cash and cash equivalents. Non-cash adjustments include
unamortised arrangement fees and other adjustments. The Group's definition of
net debt does not include the Group's leases as the Group's focus is the
management of cash borrowings and a lease is viewed as deferred capital
investment. The value of the Group's lease liabilities as at 31 December 2025
was $161.7 million current and $436.9 million non-current; it should be noted
that these balances are recorded gross for operated assets and are therefore
not representative of the Group's net exposure under these contracts.
$m 2025 2024
Current borrowings 1,277.9 589.4
Non-current borrowings 381.0 1,386.4
Non-cash adjustments(1) 26.3 31.6
Less cash and cash equivalents(2) (332.2) (555.1)
Net debt 1,353.0 1,452.3
1. Non-cash adjustments include unamortised arrangement fees which are
incurred on creation or amendment of borrowing facilities.
2. Cash and cash equivalents include an amount of $6.8 million (2024: $83.5
million) which the Group holds as operator in joint venture bank accounts.
Included in cash at bank is $3.0 million (2024: $6.5 million) held in
restricted bank accounts. This mainly consists of $2.3 million pledged as
collateral for a Letter of Credit Facility. In the prior year, $6.5 million
was held as security for performance bonds relating to work commitments on
exploration licences.
Gearing and Adjusted EBITDAX
Gearing is a useful indicator of the Group's indebtedness, financial
flexibility and capital structure and can assist securities analysts,
investors and other parties to evaluate the Group. Gearing is defined as net
debt divided by adjusted EBITDAX. Adjusted EBITDAX is defined as profit/(loss)
from continuing activities adjusted for income tax expense, finance costs,
finance revenue, loss on disposal, depreciation, depletion and amortisation,
share-based payment charge, provision reversal, exploration costs written off,
impairment reversal of property, plant and equipment net, expected credit loss
(reversal)/charge on trade receivables and restructuring provision.
$m 2025 2024 Restated(1)
Loss for the year from continuing activities (129.2) (55.0)
Adjusted for
Income tax expense 66.5 228.7
Finance costs 326.0 344.2
Finance revenue (63.4) (69.2)
Loss on disposal 4.5 -
Depreciation, depletion and amortisation 376.0 418.7
Share-based payment charge 7.7 6.9
Provision reversal - (70.4)
Exploration costs written off 2.1 202.3
Impairment reversal of property, plant and equipment, net (4.8) (11.8)
Expected credit loss (reversal)/charge on trade receivables (6.6) 6.6
Restructuring provision 7.2 7.1
Adjusted EBITDAX(3) 586.0 1,008.1
Net debt 1,353.0 1,452.3
Gearing (times) 2.3 1.4
1. Comparative adjusted EBITDAX and gearing have been restated to present
Gabon as a discontinued operation. Refer to note 8.
Balances above are presented excluding discontinued operations in Gabon.
Adjusted EBITDAX including results from discontinued operations in Gabon is
$648.1 million (2024: $1,151.9 million).
Underlying cash operating costs
Underlying cash operating costs is a useful indicator of the Group's costs
incurred to produce oil and gas. Underlying cash operating costs eliminates
certain non-cash accounting adjustments to the Group's cost of sales to
produce oil and gas. Underlying cash operating costs is defined as cost of
sales less operating lease expense, depletion and amortisation of oil and gas
assets, underlift, overlift and oil stock movements, share-based payment
charge included in cost of sales, royalties and certain other cost of sales.
Underlying cash operating costs are divided by production to determine
underlying cash operating costs per boe.
In 2024 and 2025, Tullow incurred abnormal non-recurring costs, which are
presented separately below. The adjusted normalised cash operating costs are a
helpful indicator to the forward underlying costs of the business.
$m 2025 2024 Restated(5)
Cost of sales 603.9 652.5
Add
Lease payments related to operating activity 11.6 11.6
Less
Depletion and amortisation of oil and gas and leased assets(1) 371.4 412.1
Underlift, overlift and oil stock movements(2) 28.3 42.1
Share-based payment charge included in cost of sales 0.5 0.4
Other cost of sales(3) 12.4 11.7
Underlying cash operating costs 202.9 197.8
Non-recurring costs(4) (24.4) (8.3)
Total normalised cash operating costs 178.5 189.5
Production (MMboe) 14.7 18.9
Underlying cash operating costs per boe ($/boe) 13.8 10.5
Normalised cash operating costs per boe ($/boe) 12.1 10.0
1.Depletion and amortisation of oil and gas assets is the depreciation and
amortisation of the Group's oil and gas assets over the life of an asset on a
unit of production basis.
2.Under lifting or offtake arrangements for oil and gas produced in certain
operations in which the Group has interests with other commercial partners,
each participant may not receive and sell its precise share of the overall
production in each period. The resulting imbalance between cumulative
entitlement and cumulative production less stock constitutes "underlift" or
"overlift". Underlift and overlift are valued at market value and included
within other current assets and other current payables on the Group's balance
sheet, respectively. Movements during an accounting period are charged to cost
of sales rather than charged through revenue, and as a result gross profit is
recognised on an entitlements basis.
3.Other cost of sales includes purchases of gas from third parties to fulfil
gas sales contracts and royalties paid in cash.
4. Non-recurring costs include vessel Class maintenance related works and
shutdown preparation costs.
5. Comparative balances have been restated to present Gabon as a discontinued
operation. Refer to note 8.
6. Balances above are presented excluding discontinued operations in Gabon.
Free cash flow
Free cash flow is a useful indicator of the Group's ability to generate cash
flow to fund the business and strategic acquisitions, reduce borrowings and
provide returns to shareholders through dividends. Free cash flow is defined
as net cash from operating activities, and net cash from/ (used in) investing
activities, repayment of obligations under leases, finance costs and debt
arrangement fees paid and foreign exchange (loss)/ gain.
$m 2025 2024
Net cash from operating activities 334.3 758.5
Net cash from/ (used in)investing activities 149.5 (213.1)
Repayment of obligations under leases (142.1) (169.0)
Finance costs paid (216.2) (223.2)
Debt arrangement fees (19.7) -
Foreign exchange (loss)/gain (6.5) 2.9
Free cash flow 99.3 156.1
Underlying operating cash flow
This is a useful indicator of the Group's assets' ability to generate cash
flow to fund further investment in the business, reduce borrowings and provide
returns to shareholders. Underlying operating cash flow is defined as net cash
from operating activities less repayment of obligations under leases plus
decommissioning expenditure.
Pre-financing cash flow
This is a useful indicator of the Group's ability to generate cash flow to
reduce borrowings and provide returns to shareholders through dividends.
Pre-financing free cash flow is defined as net cash from operating activities,
and net cash used in investing activities, less repayment of obligations under
leases and foreign exchange gain.
$m 2025 2024
Net cash from operating activities 334.3 758.5
Add
Decommissioning expenditure 17.6 45.0
Lease payments related to capital activities - 21.9
Payments to decommissioning escrow fund 11.6 11.6
Less
Repayment of obligations under leases (142.1) (169.0)
Underlying operating cash flow 221.4 668.0
Net cash used in investing activities 149.5 (213.1)
Decommissioning expenditure (17.6) (45.0)
Lease payments related to capital activities - (21.9)
Payments to decommissioning escrow fund (11.6) (11.6)
Pre-financing cash flow 341.7 376.4
Management Presentation - WEBCAST - 09:00 BST 28 April 2026
To access the webcast please use the following link and follow the
instructions provided:XXX
https://meetings.lumiconnect.com/100-007-059-118
(https://eur01.safelinks.protection.outlook.com/?url=https%3A%2F%2Fmeetings.lumiconnect.com%2F100-007-059-118&data=05%7C02%7Cmatthew.evans%40tullowoil.com%7Ccc88f849681c4d95a51508de80e8da2a%7C9d5a858ee6c746a7a63cda2023c57cf8%7C1%7C0%7C639089934646392008%7CUnknown%7CTWFpbGZsb3d8eyJFbXB0eU1hcGkiOnRydWUsIlYiOiIwLjAuMDAwMCIsIlAiOiJXaW4zMiIsIkFOIjoiTWFpbCIsIldUIjoyfQ%3D%3D%7C0%7C%7C%7C&sdata=FN5DAbAvCg4Xvpg9QZVU8XSvgETMXkFdHfYLIkM8o5s%3D&reserved=0)
A replay will be available on the website from midday on 28 April 2026:
https://www.tullowoil.com/investors/results-reports-and-presentations/
(https://www.tullowoil.com/investors/results-reports-and-presentations/)
CONTACTS
Tullow Oil plc Camarco
(London) (London)
ir@tullowoil.com (+44 20 3757 4980)
Matthew Evans Billy Clegg
Georgia Edmonds
Rebecca Waterworth
Notes to editors
Tullow is an independent energy company committed to building a better future
through the responsible oil and gas development of its core producing assets
in Ghana. The Group is quoted on the London and Ghanaian stock exchanges
(symbol: TLW). For further information, please refer to: www.tullowoil.com.
Follow Tullow on:
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(http://www.linkedin.com/company/Tullow-Oil)
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