REG - Tullow Oil PLC - Full Year Results
25/03/2025 07:15
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RNS Number : 9622B Tullow Oil PLC 25 March 2025
Tullow oil PLC - 2024 FULL Year Results
Continued strategic and operational delivery
On track to address upcoming debt maturities
Production optimisation activities underway
25 March 2025 - 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 2024. 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)
Richard Miller, Interim Chief Executive Officer and Chief Financial Officer,
Tullow Oil plc, commented:
"In 2024 we had a number of succeses but also some operational challenges,
most notably with Jubilee production and a reserves revision, however there is
now strong momentum within the business with a return to drilling at Jubilee,
and the commencement of production optimisation and reserves maturation
activities in Ghana. In addition a number of key achievements have recently
been realised, including the resolution of the Ghana Branch Profits Remittance
Tax arbitration which eliminated a material overhang, the repayment of our
2025 senior notes and as announced on 24 March, the signed binding heads of
terms for the sale of our Gabonese assets for a cash consideration of $300
million. This will accelerate our deleveraging progress this year.
"I am clear on the levers required to unlock Tullow's full potential. The team
remains fully focused on our near-term priorities; advancing our refinancing
plan, reducing costs, optimising production activities at Jubilee and TEN, and
driving reserve growth. We will continue to maintain our financial discipline
and prioritise investments that add value and deliver high returns.
"Tullow's core strength as a trusted partner with a cash generative business
and attractive assets with reserves growth opportunities positions us well as
we lay the foundations for value creation."
2024 FULL YEAR RESULTS
· Group working interest oil and gas production averaged 61.2
kboepd (2023: 62.7 kboepd).
· Revenue of $1,535 million (2023: $1,634 million), including $74
million hedge costs (2023: $139 million).
· Capital expenditure(1) of $231 million (2023: $380 million) and
decommissioning expenditure including cash provisioning for future
decommissioning of $60 million (2023: $67 million).
· Adjusted EBITDAX(1) of $1,152 million (2023: $1,151 million);
gross profit of $754 million (2023: $765 million); profit after tax of $55
million (2023: loss of $110 million), including exploration costs writen off
of $213 million (2023: $27 million).
· Free cash flow(1) (FCF) of $156 million (2023: $170 million).
· Net debt(1) at year end reduced to $1,452 million (2023: $1,608
million); cash gearing of net debt(1) to adjusted EBITDAX(1) of 1.3 times
(2023: 1.4 times); liquidity headroom of $715 million (2023: $1,000 million).
· Audited 2P reserves at year end 2024 of 164.5 mmboe (2023:
212.2 mmboe), valued at $2.5 billion (NPV10), with the reserves reduction
including 22.4 mmboe of Group production.
· Successful extension of the $250 million Revolving Credit
Facility (RCF) to 30 June 2025.
· Successful resolution of the Ghana Branch Profits Remittance Tax
(BPRT) arbitration, which removed a potential $320 million liability and
endorses the sanctity of our Petroleum Agreements.
· Five new Jubilee wells (three producers and two water injectors)
brought onstream, bringing the drill programme to an end approximately six
months ahead of schedule with no recordable safety incidents, and saving over
$88 million (gross) compared to the initial budget.
· Average FPSO uptime at Jubilee and TEN of 97%.
· Decommissioning activities in Mauritania accelerated and
completed in 2024, ahead of schedule and below budget.
· Significant milestone reached with the Ghana Forestry Commission
to implement a nature-based carbon offset programme.
2025 OUTLOOK and GUIDANCE
· Tullow has signed a binding heads of terms agreement with Gabon
Oil Company for the sale of Tullow Oil Gabon SA, for a cash consideration of
$300 million net of tax. Entering into the full sale and purchase agreement is
targeted for the second quarter of 2025, with completion of the transaction
expected around the middle of the year, subject to relevant governmental and
regulatory approvals. See separate release: LINK
(https://www.tullowoil.com/media/press-releases/tullow-agrees-binding-heads-terms-300-million-net-tax-sale-gabon-assets-gabon-oil-company/)
· Group working interest production expected to average 50 to 55
kboepd as previously announced, including c.6 kboepd of gas.
· Ghana drilling programme with Noble Venturer to commence in May
2025, with two Jubilee wells (one producer and one water injector) expected to
come onstream in the third quarter of 2025.
· Completed 4D seismic survey in first quarter of 2025 to support
future well locations and drive reserves growth.
· Capital expenditure of c.$250 million, allocated as follows:
c.$160 million in Ghana, c.$70 million across the west African non-operated
portfolio, c.$5 million in Kenya and c.$15 million of exploration expenditure.
· Decommissioning spend of c.$15 million for UK; c.$15 million
cash provisioning for Ghana and Gabon.
· Further cost base optimisation underway, with expected c.$10
million saving reducing annual cash net G&A to c.$40 million.
· Cash taxes expected to be c.$150-200 million at $70-80/bbl with
payments weighted c.60% to the first half of the year.
· Forecast free cash flow of c.$100-200 million at $70-80/bbl,
including c.$50 million of overdue gas receipts in Ghana from 2024.
· Refinancing of the Group's capital structure targeted during
2025, following repayment of the 2025 Notes in early March 2025.
1. Alternative performance measures are reconciled on pages 34 to 37
Management Presentation - WEBCAST - 09:00
To access the webcast please use the following link and follow the
instructions provided:
https://meetings.lumiconnect.com/100-695-362-491
(https://meetings.lumiconnect.com/100-695-362-491)
A replay will be available on the website from midday on 25 March 2025:
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
Rob Hayward Georgia Edmonds
Rebecca Waterworth
Notes to editors
Tullow is an independent energy company that is building a better future
through responsible oil and gas development in Africa. The Company's
operations are focused on its West-African producing assets in Ghana, Gabon
and Côte d'Ivoire, alongside a material discovered resource base in Kenya.
Tullow is committed to becoming Net Zero on its Scope 1 and 2 emissions by
2030 and has a Shared Prosperity strategy that delivers lasting socio-economic
benefits for its host nations. The Group is quoted on the London and Ghana
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
It is a privilege to be appointed Interim Chief Executive Officer (CEO). I
have been a part of Tullow since 2011 and I care deeply about the business.
I would like to thank Rahul for his leadership over the past four years.
During his tenure operational performance has improved significantly and, due
to a reduced cost base and rigorous capital allocation process, net debt(1)
has reduced from $2.81 billion to $1.45 billion. I look forward to building on
the strong foundations that have been laid by continuing to focus on
delivering our transformative plans for the business in 2025 and beyond.
Key to our plans this year is the refinancing of upcoming debt maturities to
strengthen our balance sheet. The process to further accelerate our
deleveraging pathway continues with the strong progress towards realising the
accretive cash sale of our Gabonese assets which is expected to close around
the middle of the year.
In January 2025 we successfully resolved our claim in relation to the
assessment of Ghana Branch Profits Remittance Tax (BPRT). This outcome, which
determined that Tullow Ghana was not liable to pay the $320 million BPRT
assessment previously issued by the Ghana Revenue Authority (GRA) and will
have no future exposure to BPRT in respect of its operations under its
Petroleum Agreements (PAs), affirmed our long held assessment and confidence
in the PAs and removed a material overhang from our business. We continue to
engage with the Government of Ghana on two further disputed tax claims, which
were referred to the International Chamber of Commerce (ICC) in February 2023,
with the aim of resolving these disputes on a mutually acceptable basis.
We have a clear plan to unlock material value from Tullow's unique pan-African
platform. Tullow is a cash generative business and we are laying the
foundations to grow our reserves base, accelerate our deleveraging pathway and
deliver significant value accretion.
Operational performance
Our commitment to operational delivery is enabling us to manage our assets
effectively. In the first half of 2024 the Ghana drilling programme was
completed safely and ahead of schedule and resulted in 18 new Jubilee wells
coming onstream since 2021.
2024 was a mixed year from a production perspective. Lower than anticipated
production at Jubilee in the second half of 2024 was partially offset by
strong performance at TEN. To address decline rates at Jubilee we have
introduced a number of operational process improvements including power supply
upgrades on the FPSO and measures to improve water injection reliability and
increase capacity to 300 kbwpd.
Group working interest production for 2025 is expected to be 50-55 kboepd,
including c.6 kboepd of gas production and inclusive of a two-week planned
maintenance shutdown on the Jubilee field in the first half of the year, which
will have a c.4% impact on Jubilee annual production. Two new Jubilee wells
(one producer and one water injector) will be drilled, starting in May 2025,
and are expected to come onstream in the third quarter of the year.
Ghana
Ghana continues to be the cornerstone of our operations. During the year,
operational efficiency remained high with average facility uptime across the
FPSOs averaging 97% and a combined average production rate of c.44.1 kbopd
net. Five new Jubilee wells (three producers and two water injectors) were
brought onstream during the first half of 2024, completing the Ghana drilling
programme safely, and approximately six months ahead of schedule.
Gross oil production from the Jubilee field averaged c.87 kbopd (c.33.9 kbopd
net). Production was impacted primarily by the performance of the J69 producer
well, a lack of pressure communication from water injection, water injection
performance and increased water cut in certain wells. The FPSO will undergo
planned maintenance in the first quarter of 2025, during which we plan to
implement upgrades to improve the reliability of the power supply and water
injection consistency. Stable water injection combined with production
optimisation activities is expected to reduce the rate of decline experienced
in the second half of 2024.
Gross oil production from the TEN fields exceeded expectations, averaging
c.18.5 kbopd (c.10.2 kbopd net) during the year, with Enyenra and Ntomme wells
responding positively to both injection and production optimisation. We
continue to explore options to maximise long term value from TEN, including a
focus on the cost base to improve economics, and maturing further infill
potential.
Net gas production in Ghana averaged 6.0 kboepd in 2024. The Jubilee interim
Gas Sales Agreement (GSA) remains in place until the fourth quarter of 2025 at
$3.00/mmbtu. We are planning to supply TEN gas during the Jubilee shutdown and
continue to progress options to create a significant long-term revenue stream
from the gas production and discussions continue regarding third party
off-take opportunities.
Discussions with the Government of Ghana are ongoing in relation to
receivables for the exported gas and we look forward to working with the new
administration to settle the payments.
In 2025 we will undertake a short drilling programme in Ghana, with a primary
focus on reducing natural decline. Furthermore, the state-of-the-art 4D
seismic survey at the Jubilee and TEN fields will improve our understanding of
the pressure and fluid movement in the reservoirs and is expected to support
at least two further drilling campaigns on Jubilee within the current licence
period, which will ultimately enable us to book more wells as reserves.
Combined with the upward revision of TEN reserves related to substantial
progress towards a material reduction in fixed costs, including in relation to
the FPSO, and further 4D seismic assisted development drilling, there is a
material opportunity ahead to sustain long-term production beyond the current
life of field.
Non-operated and exploration portfolios
Production from the non-operated portfolio in 2024 was 10.6kbopd net. The
production loss resulting from an incident at Simba was largely offset by
improved production from the field when it came back onstream, as well as good
performance from other onshore and offshore fields in the portfolio.
The Simba field in Gabon was shut down following an incident in March 2024 at
the Perenco operated Becuna Platform, which tragically resulted in fatalities.
The operator resumed operations in August 2024 after putting in place the
necessary operational and engineering controls and obtaining the necessary
regulatory approvals.
In Gabon, the Falcon NE infrastructure led exploration (ILX) prospect on the
DE8 licence will be drilled during the first half of 2025. The Sarafina ILX
well, drilled in 2024, found hydrocarbons and work is ongoing with the
operator to evaluate the commercial potential.
In Côte d'Ivoire, options to realise value and mitigate capital exposure at
the Espoir field are being explored ahead of licence expiry in 2026. We
continue to assess options on the way forward for exploration licences CI-524
and CI-803.
In Argentina, we continue to assess options for these licences whilst
mitigating capital exposure.
Decommissioning activities in the Banda/Tiof fields in Mauritania were
accelerated in 2024 and have been completed ahead of schedule and below
budget.
Kenya
Despite the delays associated with securing governmental approval and a
strategic partner, Kenya remains a material option to drive value and growth
and we are continuing to work with the Kenyan government to seek support for a
Field Development Plan (FDP) and identify a long-term strategic partner, which
is a key milestone to achieve a Final Investment Decision (FID).
Reserves and resources
At the end of 2024, audited 2P reserves were 164.5 mmboe (2023: 212.2 mmboe).
The reserves reduction includes 22.4 mmboe of Group production during 2024 and
a downward revision in Jubilee. Although recent Jubilee drilling results have
encountered reservoir thicknesses close to prognosis, water has broken through
in certain producing wells earlier than previously expected. This suggests
that there still remain significant volumes of bypassed oil, which will be
optimally targeted utilising the data produced by the 2025 4D seismic
campaign. TEN reserves have been revised upwards as we progress a material
reduction in fixed operating costs, especially on the FPSO, which extends the
economic lifetime of the asset and facilitates further potential development
through infill drilling.
Our asset base continues to have significant value, and as at 31 December
2024, the Group's audited 2P NPV10 was $2.5 billion.
The Group's audited 2C resources of 708.6 mmboe at the end of 2024 (2023:
745.0 mmboe) reflect the material opportunity we have to mature resources into
reserves to realise sustained long-term production. In 2025, part of the
Group's material 2C resources are expected to mature into 2P reserves with the
support of the ongoing 4D seismic survey in Ghana and resulting identification
of robust infill targets.
Sustainability
We are committed to building a better future through responsible oil and gas
development. We recognise the ongoing need for oil and gas in Africa over the
coming decades and we will continue to support our host countries to develop
their natural resources whilst taking actions to minimise our environmental
footprint and create value for all stakeholders including the communities
where we operate.
As part of the double materiality assessment we conducted in 2024, we engaged
a wide group of stakeholders to ensure we are focussed on the material
economic, social and environmental impacts and issues that are most relevant
to our business. We also refreshed how we communicate our sustainability
approach to ensure it is clear for our stakeholders.
Our Net Zero by 2030 commitment is a core aspect of our strategy. During the
year we implemented process improvements and modifications on our FPSOs in
Ghana, and after all engineering works are complete, we expect routine flaring
to be eliminated by the end of 2025.
As announced in July 2024, we have formed a strategic partnership with the
Ghana Forestry Commission to begin full scale implementation of a nature-based
carbon offset programme. This initiative aims to generate up to one million
tonnes of certified carbon offsets per year to mitigate our residual, hard to
abate emissions. The capability we have developed in addressing our emissions
can also be applied to other carbon intensive assets across the continent to
support low emission resource extraction.
Our community development programmes focused on improving education and
employability in our host communities and creating opportunities for local
employment and entrepreneurship. In February 2024, as part of our new
'Accelerating Progress Through Partnerships' community strategy, we announced
the first multi-year Agriventures partnership with Innohub Foundation in
Ghana. This two-year agriculture-focused programme will find and support
entrepreneurs to set up and grow businesses capable of providing sustainable
livelihoods.
To build on our existing commitment to minimise our environmental impact and
protect biodiversity, in 2024 we set a "No Net Loss" nature ambition and
completed a nature baseline assessment of our operated and non-operated assets
to identify our nature-related impacts, risks and opportunities. In addition,
we have also published our inaugural Taskforce on Nature-related Financial
Disclosures (TNFD) report.
Outlook
In the year ahead our priorities are to progress our refinancing plan,
optimise our production activities at Jubilee and TEN, and grow our reserve
base. In particular we are leveraging advanced technologies and innovative
approaches to minimise decline and extend the life of these fields and we have
absolute confidence in the Jubilee field to deliver material cash flows and
provide the business with optionality for returns and growth, once our net
debt target of below $1 billion is reached.
The repayment of the 2025 Notes combined with our ongoing work to address our
upcoming debt maturities will continue to strengthen our balance sheet.
In the near term we will maintain our focus on costs and financial discipline,
prioritising high returns and focusing on investments that add value. As we
continue to reduce our debt and optimise our capital structure, our balance
sheet will grow stronger and we will be well-positioned to create lasting
economic and social value for all stakeholders.
I would like to thank the whole Tullow team for all their hard work and
dedication, they are the driving force behind the progress we have made in
2024 and they have shown tremendous resilience in recent months as we have
embarked on additional cost optimisation, including redundancies associated
with streamlining our cost base.
I would also like to thank our shareholders for their continued support, as we
realise the potential of the business and generate value for all stakeholders.
1. Alternative performance measures are reconciled on pages 34 to 37
Finance review
Income Statement
Income Statement (key metrics) 2024 2023
Revenue ($m)
Sales volume (boepd) 52,421 55,754
Realised oil price ($/bbl) 76.4 77.5
Total revenue 1,535 1,634
Operating income/(costs) ($m)
Underlying cash operating costs (1) (272) (293)
Depreciation, Depletion and Amortisation (DDA) of oil and gas and leased (438) (431)
assets
DDA before impairment charges ($/bbl) 19.6 18.8
Overlift and oil stock movements (43) (109)
Administrative expenses (53) (56)
Asset revaluation 39 -
Exploration costs written off (213) (27)
Impairment reversal/(Impairment) of property, plant and equipment, net 12 (408)
Gain on bond buyback - 86
Net financing costs (274) (286)
Profit from continuing activities before tax 322 96
Income tax expense (267) (206)
Profit/(loss) for the year 55 (110)
Adjusted EBITDAX (1) 1,152 1,151
Basic earnings/(loss) per share (cents) 3.7 (7.6)
1. Alternative performance measures are reconciled on pages 34 to 37.
Revenue
Sales oil volumes
During the year, there were 52,421 boepd (2023: 55,754 boepd) of liftings. The
decrease was primarily driven by a reduction of two liftings in Gabon offset
by an additional 650 kbbls lifted in Ghana, with 13 cargos lifted in Jubilee
(2023: 13) and 4.5 in TEN (2023: 4).
Realised oil price ($/bbl)
The Group's realised oil price after hedging for the period was $76.4/bbl
(2023: $77.5/bbl) and before hedging $80.2/bbl (2023: $84.3/bbl). Lower oil
prices and lower hedged volumes subject to price caps compared to 2023 have
resulted in a lower hedge loss which decreased total revenue by $74 million
(2023: $139 million).
Gas sales
Included in Total Revenue of $1,535 million are gas sales of $54 million of
which $48 million relates to Ghana. During the year, Tullow exported 33,660
mmscf (gross) of gas at an average price of $2.97/mmbtu in Ghana.
Cost of sales
Underlying cash operating costs
Underlying cash operating costs amounted to $272 million; $12.2/boe (2023:
$293 million; $12.8/boe). Routine operating costs remain largely consistent
with prior year. The decrease is primarily driven by non-recurring expenditure
incurred in prior year, which included costs related to TEN shutdown and
Jubilee riser remediation.
Depreciation, depletion and amortisation
DDA charges before impairment on production and development assets amounted to
$438 million; $19.6/boe (2023: $431 million; $18.8/boe). The increase in DDA
per boe was primarily driven by the reduction in Jubilee field 2P reserves
during the current year offset by the impact of TEN field impairment recorded
in 2023.
Overlift and oil stock movements
The Group recognised an overlift expense of $43 million (2023: overlift
expense $109 million). The decrease in overlift expense is primarily due to
lower liftings in Gabon in the current year, resulting from reduced oil
production volumes compared to the prior year.
Administrative expenses
Administrative expenses of $53 million (2023: $56 million) have decreased in
the current year despite the inflationary environment. This is largely due to
reduction in one-off corporate project expenditures in the current year.
Further cost base optimisation is underway for 2025, with expected c.$10
million saving reducing annual net G&A to c.$40 million.
Asset revaluation
Asset revaluation of $39 million relates to assets disposal as part of the
assets swap with Perenco in Gabon (refer to Note 11 for further information).
Exploration costs written off
During 2024, the Group wrote off exploration costs of $213 million (2023: $27
million) primarily driven by Kenya where an extension of the Field Development
Plan review date to June 2025 led to a reassessment of the risks associated
with reaching Final Investment Decision and resulted in a $145 million
impairment (refer to Note 8 for further details). Additionally, the carrying
values of assets in Argentina and Cote d'Ivoire were written off by $39
million and $16 million, respectively, due to lack of planned expenditure on
licences prior to expiry. Furthermore, $10 million was written off in relation
to the Sarafina well at Simba, in Gabon.
Impairment of property, plant and equipment
The Group recognised a net impairment reversal on PP&E of $12 million in
the current year (2023: Net impairment of $408 million) largely driven by cost
savings from operational efficiencies and scope revision in the operated
Mauritania decommissioning campaign.
Net financing costs
Net financing costs for the period were $274 million (2023: $286 million).
This decrease is mainly attributable to lower interest on bonds due to a
reduction in the outstanding balance, partially offset by higher interest on
obligations under leases.
A reconciliation of net financing costs is included in Note 6.
Taxation
The overall net tax expense of $267 million (2023: $206 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 expenditure, exploration write-offs and impairments.
Based on a profit before tax for the period of $322 million (2023: $96
million), the effective tax rate is 83.0% (2023: 214.3%). 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 60.1% (2023: 70.2%). The effective tax rate is in line
with the prior year, with the impact of non-deductible expenditure in Ghana
and Gabon and no UK tax benefit arising from net interest and hedging expense
of $206 million (2023: $167 million) being partially offset by deferred tax
credits related to non-operated assets undergoing decommissioning and prior
year adjustments.
The Group's future statutory effective tax rate is sensitive to the geographic
mix in which pre-tax profits arise. There is no UK tax benefit from net
interest and hedging expenses, whereas net interest and hedging profits would
be taxable in the UK. Consequently, the Group's tax charge will continue to
vary according to the jurisdictions in which pre-tax profits occur.
Analysis of adjusted effective tax rate ($m) Adjusted profit/(loss) Tax Adjusted
before tax
(expense)/credit
effective tax rate
Ghana 2024 580.3 (208.6) 35.9%
2023 584.4 (210.1) 35.9%
Gabon 2024 130.6 (38.2) 29.3%
2023 216.0 (101.2) 46.8%
Corporate 2024 (281.6) (5.7) (2.0%)
2023 (379.4) 9.6 2.5%
Other non-operated & exploration 2024 (7.8) (0.7) (8.7%)
2023 1.5 4.7 (324.2%)
Total 2024 421.5 (253.2) 60.1%
2023 422.5 (296.9) 70.2%
Adjusted EBITDAX
Adjusted EBITDAX for the year was $1,152 million (2023: $1,151 million) with a
reduction in operating costs of $21 million, decrease in administrative
expenses of $5 million, lower royalty taxes of $6 million and a decrease in
overlift expense of $67 million, offset by lower revenue of $99 million.
Profit/(loss) for the year from continuing activities and earnings per share
The profit for the year from continuing activities amounted to $55 million
(2023: $110 million loss). The increase in profit after tax was mainly driven
by a reduction in impairments, recognition of asset revaluation gains and
provision releases in the current year. Basic earnings per share was 3.7 cents
(2023: 7.6 cents loss per share).
Balance sheet and liquidity management
Key metrics 2024 2023
Capital investment ($m)(1) 231 380
Derivative financial instruments ($m) (12) (35)
Borrowings ($m) (1,976) (2,085)
Underlying operating cash flow ($m)(1) 668 813
Free cash flow ($m)(1) 156 170
Net debt ($m)(1) 1,452 1,608
Gearing (times)(1) 1.3 1.4
1. Alternative performance measures are reconciled on pages 34 to 37.
Capital investment
Capital expenditure amounted to $231 million (2023: $380 million) with $206
million invested in production and development activities of which $134
million invested in Jubilee mainly comprising of $103 million spend on
drilling costs. Investments in exploration and appraisal activities are $25
million.
The Group's 2025 capital expenditure is expected to be c.$250 million and is
expected to comprise Ghana capex of c.$160 million, West African Non-Operated
capex of c.$70 million, Kenya capex of c.$5 million and exploration spend of
c.$15 million.
Decommissioning
Decommissioning expenditure was $49 million in 2024 (2023: $67 million). The
Group's decommissioning budget in 2025 is c.$30 million of which c.$15 million
is cash provisioning for future decommissioning in Ghana and Gabon. Subject to
programme scheduling, at the end of 2025 it is expected that c.$15 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.
At 31 December 2024, the Group's hedge portfolio provides downside protection
for c.60% of forecast production entitlements in the first half of 2025 with
c.$59/bbl weighted average floors across all structures; while retaining
strategic upside participation across for the same period, with only c.5% of
forecast production entitlements capped with collars at a weighted average
sold call of c.$92/bbl, and c.40% of forecast production entitlements secured
with three-way collars with $92-$102/bbl call spreads. Similarly in the second
half of 2025, the Group's hedge portfolio provides downside protection for
c.55% of forecast production entitlements with c.$60/bbl weighted average
floors across all structures; for the same period, c.15% of forecast
production entitlements is capped at weighted average sold calls of c.$89/bbl
while c.30% of forecast production entitlements is secured with three-way
collars.
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 (2023: Level 2). There were no
transfers between fair value levels during the year.
At 31 December 2024, the Group's derivative instruments had a net negative
fair value of $12 million (2023: net negative $35 million).
The following table demonstrates the timing, volumes and prices of the Group's
commodity hedge portfolio at year end:
1H25 hedge portfolio at 31 December 2024 bopd Bought put Sold Bought
(floor) call call
Straight puts 9,500 $58.47 - -
Collars 2,000 $60.00 $91.94 -
Three- way collars (call spread) 16,500 $59.05 $92.02 $102.02
Total/Weighted Average 28,000 $58.92 $92.01 $102.02
2H25 hedge portfolio at 31 December 2024 bopd Bought put Sold Bought
(floor) call call
Straight puts 4,500 $59.94 - -
Collars 7,000 $60.00 $89.05 -
Three- way collars (call spread) 12,500 $59.20 $83.64 $93.64
Total/Weighted Average 24,000 $59.57 $85.58 $93.64
Borrowings
On 15 May 2024, the Group made the annual prepayment of $100 million of the
Senior Secured Notes due 2026.
The Group's total drawn debt reduced to $2,007.4 million, consisting of $492.5
million nominal value Senior Notes due in March 2025, $1,385.2 million nominal
value Senior Secured Notes due in May 2026 and $129.7 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 of its outstanding
debt from time to time through new debt financings 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).
Since December 2023, S&P has maintained the Group's corporate credit
rating at B- with negative outlook, and the rating of the 2026 Notes at B- and
the rating of the 2025 Notes at CCC+. Similarly, Moody's has maintained the
Group's corporate credit rating at Caa1 with negative outlook, and the rating
of 2026 Notes at Caa1 and the rating of the 2025 Notes at Caa2.
Underlying operating cash flow and free cash flow
Underlying operating cash flow for the year was $668 million (2023: $813
million), reflecting a decrease of $145 million. This was primarily driven by
$148 million decline in cash revenue due to lower sales volumes, impact of
reduced oil prices and timing of revenue payments. Additionally, cash taxes
increased by $76 million compared to the prior year. These factors were
partially offset by an $25 million reduction in cash operating costs, royalty
taxes and administrative expenses and $26 million decrease in lease obligation
repayments.
Free cash flow for the year decreased to $156 million (2023: $170 million).
Underlying operating cashflow has reduced by $145 million, as outlined above.
This decrease was largely offset by lower net cash used in investing
activities, as well as reduced lease payments related to capital activities
and decommissioning costs, which decreased by $55 million, $32 million, and
$22 million, respectively. These reductions were due to the completion of the
JSE campaign in Ghana and Chinguetti decommissioning campaign in Mauritania in
2023. Additionally, finance costs paid were $17 million lower in the current
period.
Net debt and gearing
Reconciliation of net debt $m
FY 2023 net debt 1,608.4
Sales revenue (1,534.9)
Operating costs 272.4
Other operating and administrative expenses 169.2
Operating cash flow before working capital movements (1,093.3)
Movement in working capital (25.5)
Tax paid 360.3
Purchases of intangible exploration and evaluation assets and property, plant 232.6
and equipment
Other investing activities (19.5)
Other financing activities 392.2
Foreign exchange loss on cash (2.9)
FY 2024 net debt 1,452.3
Net debt reduced by $156.1 million during the year to $1,452.3 million on 31
December 2024 (2023: $1,608.4 million), due to generation of free cash flow of
$156.1 million (as explained above).
The Gearing ratio has decreased to 1.3 times (2023: 1.4 times) due to the
reduction in net debt compared to prior year.
Ghana tax assessments
On 24 December 2024, the BPRT Tribunal issued its ruling to the International
Chamber of Commerce (ICC) which delivered its award on 2 January 2025 with
regards to the BPRT arbitration with the Government of Ghana. The Tribunal
determined that BPRT is not applicable to Tullow Ghana since it falls outside
of the tax regime provided for in the Petroleum Agreements. This will mean
that Tullow Ghana is not liable to pay the US$320 million BPRT assessment
issued by the Ghana Revenue Authority and Tullow will have no future exposure
to BPRT in respect of its operations under the Petroleum Agreements. Tullow
has two further 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, however we continue to engage
with the Government of Ghana, including the GRA, with the aim of resolving the
assessments on a mutually acceptable basis.
Liquidity risk management and going concern
The Directors have extended the going concern assessment period to 31 May
2026, aligning with the maturity date of the 2026 senior secured bonds (2026
Notes). 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 litigation and
the timing of any associated cash outflows. This assessment covers both the
Group and the Company.
Management has applied the following oil price assumptions for the going
concern assessment based on forward prices and market forecasts:
Base Case: $70/bbl for 2025; $70/bbl for 2026.
Low Case: $65/bbl for 2025; $65/bbl for 2026.
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 stress tested by including a 10%
production decrease and 5% increased operating costs compared to the Base
Case. Management has also considered additional outflows in respect of all
ongoing litigations/arbitrations within the Low Case, with an additional $67
million outflow being included for the cases expected to progress in the going
concern period. Based on the legal opinions received by management, the
remaining arbitration cases 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.
The Group is reliant on the continued provision of external financing. The
undrawn $250 million revolving credit facility (RCF) and the $1.3 billion 2026
Notes fall due within the going concern period and both will require
refinancing to ensure the Group has sufficient liquidity to meet its financial
obligations. The Directors intend to complete a holistic refinancing of the
existing debt capital structure during 2025. Discussions with banks and
commodity traders to secure the refinancing are underway. A fundamental
assumption in concluding that the Group is a going concern is a successful
execution of a holistic refinancing. The successful execution of a holistic
refinancing is subject to favourable macroeconomic and market conditions
including but not limited to oil price, credit ratings and accessibility of
High Yield Bond markets and is therefore outside the control of management.
In addition, a binding heads of terms agreement for the sale of Tullow Oil
Gabon SA which holds 100% of Tullow's working interest in Gabon for cash
consideration of $300 million net of tax has been entered into with Gabon Oil
Company. Signing of a sale and purchase agreement is targeted for the second
quarter of 2025. Completion of the transaction, which will be subject to
relevant governmental and regulatory approvals, and receipt of the associated
cash proceeds are assumed in June 2025 in the Base Case, with a three month
delay assumed in the Low Case. Completion of this transaction will materially
reduce the Group's net debt and is therefore expected to reduce the risk
associated with the holistic debt refinancing. However, completion and timing
of completion of this transaction are outside the control of management.
Implications and material uncertainties
The Base Case and the Low Case scenarios forecast a liquidity shortfall in May
2026 when the $1.3 billion 2026 Notes become due for payment, unless the
Directors execute a holistic refinancing of the Group's debt capital structure
in advance of that date. In addition, the Low Case scenario forecasts a
liquidity shortfall at the end of June 2025, following expiry of the RCF and
due to the assumed delay to the receipt of proceeds from the sale of Tullow
Oil Gabon SA.
The Directors have initiated a process to execute a holistic refinancing based
on proposals received from banks. The Directors believe this is achievable
before the end of June 2025, noting the risks associated with wider market
conditions. If this were not achieved by the end of June 2025 the Directors
would continue to pursue such a refinancing in the second half of 2025 to
alleviate the projected liquidity shortfall in May 2026 and believe this is
achievable, again subject to market conditions.
In addition, if a holistic refinancing was not executed by the of June 2025
and receipt of proceeds from the sale of Tullow Oil Gabon SA was delayed (as
assumed in the Low Case scenario), the Directors plan to enter into
discussions with the lenders under the RCF to extend the maturity of the
facility to align with the timing of completion of the holistic refinancing or
the receipt of proceeds from the sale of Tullow Oil Gabon SA. Should this not
be possible, the Directors will pursue alternative bridge financing from
commodity traders or secure an alternative source of financing from private
credit markets ahead of the projected shortfall at the end of June 2025. The
Directors have received unsolicited offers of credit from such counterparties
in excess of the need to alleviate the projected shortfall and would seek to
engage with them and progress such offers, if required.
The Directors note that despite expressions of interest from private as well
as public parties for participation in the holistic debt refinancing,
implementing a holistic refinancing is outside the control of the Group. If
the Directors were unable to implement a refinancing proposal, the ability of
the Group to continue trading would depend upon the Group being able to
negotiate a financial restructuring proposal with its creditors and, if
necessary, that proposal being approved by shareholders. Whilst the Board
would seek to negotiate such a financial restructuring proposal with its
creditors, it is possible that the creditors would not engage with the Board
in those circumstances. There would therefore be a possible risk of the Group
entering into insolvency proceedings, which the Directors consider would
likely result in limited or no value being returned to shareholders.
The Directors have concluded that 1) implementing a holistic refinancing by
the end June 2025 or by May 2026 at the latest and 2) obtaining sufficient
liquidity to cover the expiration of the RCF at the end of June 2025, if a
holistic refinancing is not implemented by that date, by extending the
maturity of the facility or by completing the sale of Tullow Oil Gabon SA and
receipt of proceeds from the transaction or with alternative bridge financing,
are outside the control of the Group. These are therefore material
uncertainties that may cast significant doubt over the Group and the Company's
ability to continue as a going concern. Notwithstanding these material
uncertainties, the Board has confidence in the Group's ability to implement a
holistic refinancing or extend the RCF or either complete the sale of Tullow
Oil Gabon SA including receipt of proceeds or seek an alternative source of
financing before the end of June 2025. This is based on the plans in place on
the holistic refinancing, the ongoing support of existing lenders under the
RCF, the binding heads of terms agreement signed with Gabon Oil Company for
the sale of Tullow Oil Gabon SA and the unsolicited offers of liquidity
received from other sources of finance and credit providers. This is in the
context of the underlying value and cash generation of the Group's producing
fields to support future debt service and repayment. On this basis the Board
have prepared the Financial Statements on a going concern basis. The Financial
Statements do not include the adjustments that would result if the Group and
the Company were unable to continue as a going concern.
Events since 31 December 2024
On 14 February 2025, Richard Miller was appointed as Interim Chief Executive
Officer (CEO). Rahul Dhir stepped down as Director from the Board of Tullow
Oil plc.
On 3 March 2025, the Group settled the 2025 Notes upon maturity with a payment
of $510 million, comprising a $493 million principal repayment and $17 million
final coupon. This payment was partially funded through a $270 million
drawdown from the Secured Notes Facility, with the remainder sourced from cash
at bank. Following the $270 million drawdown, the Secured Notes Facility was
fully drawn at $400 million.
On 24 March 2025, Tullow announced that it had signed a binding heads of terms
agreement with Gabon Oil Company for the sale of Tullow Oil Gabon SA, which
holds 100% of Tullow's working interests in Gabon for a total cash
consideration of $300 million net of tax. Signing of a sale and purchase
agreement is targeted for the second quarter of 2025, with completion of the
transaction and receipt of funds expected around the middle of the year,
subject to receipt of relevant governmental and regulatory approvals.
The transaction is a corporate sale of Tullow's entire Gabonese portfolio of
assets, representing c.10 kbopd of 2025 production guidance and c.36 million
barrels of 2P reserves. Conditions precedent for the completion of the
Transaction include all necessary approvals (including from government
ministries), CEMAC Competition Commission approval and Tullow's processing of
the 2024 dividend in compliance with Gabonese requirements.
This is a non adjusting event as at 31 December 2024 as defined by IAS 10
'Events after the Reporting Period'.
There have not been any other events since 31 December 2024 that have resulted
in a material impact on the year end results.
Group income statement
Year ended 31 December 2024
$m Notes 2024 2023
Revenue 1,534.9 1,634.1
Cost of sales 5 (780.9) (869.2)
Gross profit 754.0 764.9
Administrative expenses 5 (53.2) (56.1)
Restructuring provisions 5 (7.1) -
Expected credit loss charge on trade receivables (6.6) -
Other gains - 0.2
Asset revaluation 11 38.9 -
Exploration costs written off 8 (212.6) (27.0)
Impairment reversal/(impairment) of property, plant and equipment, net 9 11.8 (408.1)
Provisions reversal 5 70.4 22.0
Operating profit 595.6 295.9
Loss on hedging instruments - (0.4)
Gain on bond buyback - 86.0
Finance income 6 71.5 44.0
Finance costs 6 (345.6) (329.6)
Profit from continuing activities before tax 321.5 95.9
Income tax expense 7 (266.9) (205.5)
Profit/(loss) for the year from continuing activities 54.6 (109.6)
Attributable to
Owners of the Company 54.6 (109.6)
Earnings/(loss) per ordinary share from continuing activities ¢ ¢
Basic 3.7 (7.6)
Diluted 3.6 (7.6)
Group statement of comprehensive income and expense
Year ended 31 December 2024
$m 2024 2023
Profit/(loss) for the year 54.6 (109.6)
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
(Losses)/gains arising in the year (28.5) 20.1
(Losses)/gains arising in the year - time value (21.9) 50.3
Reclassification adjustments for items included in profit on realisation 47.5 111.3
Reclassification adjustments for items included in loss on realisation - time 26.1 27.8
value
Exchange differences on translation of foreign operations 2.0 (5.8)
Net other comprehensive income for the year 25.2 203.7
Total comprehensive income for the year 79.8 94.1
Attributable to
Owners of the Company 79.8 94.1
Group balance sheet
As at 31 December 2024
$m Notes 2024 2023
Assets
Non-current asset
Goodwill 11 44.9 -
Intangible exploration and evaluation assets 8 109.1 287.0
Property, plant and equipment 9 2,324.1 2,532.8
Other non-current assets 10 340.8 338.6
Deferred tax assets 8.3 19.6
2,827.2 3,178.0
Current assets
Inventories 132.4 107.3
Trade receivables 137.9 43.5
Other current assets 10 391.9 571.2
Current tax assets 6.9 3.8
Derivative financial instruments 0.1 -
Cash and cash equivalents 555.1 499.0
Assets classified as held for sale 11 - 55.8
1,224.3 1,280.6
Total assets 4,051.5 4,458.6
Liabilities
Current liabilities
Trade and other payables 12 (736.5) (775.0)
Borrowings (589.4) (100.0)
Provisions 14 (24.3) (67.9)
Current tax liabilities (175.3) (230.5)
Derivative financial instruments (11.9) (35.0)
Liabilities associated with assets classified as held for sale 11 - (17.6)
(1,537.4) (1,226.0)
Non-current liabilities
Trade and other payables 12 (665.9) (783.2)
Borrowings (1,386.4) (1,984.6)
Provisions 14 (321.5) (403.7)
Deferred tax liabilities (413.0) (420.5)
(2,786.8) (3,592.0)
Total liabilities (4,324.2) (4,818.0)
Net liabilities (272.7) (359.4)
Equity
Called-up share capital 217.5 216.7
Share premium 1,294.7 1,294.7
Foreign currency translation reserve (242.4) (244.4)
Hedge reserve 0.1 (18.9)
Hedge reserve - time value (12.1) (16.3)
Merger reserve 755.2 755.2
Retained earnings (2,285.7) (2,346.4)
Equity attributable to equity holders of the Company (272.7) (359.4)
Total equity (272.7) (359.4)
Group statement of changes in equity
Year ended 31 December 2024
$m Share Share Foreign currency translation reserve¹ Hedge Hedge Merger reserve(3) Retained earnings Total
capital
premium
reserve²
reserve - time
value²
At 1 January 2023 215.2 1,294.7 (238.6) (150.3) (94.4) 755.2 (2,241.3) (459.5)
Profit for the period - - - - - - (109.6) (109.6)
Hedges, net of tax - - - 131.4 78.1 - - 209.5
Currency translation adjustments - - (5.8) - - - - (5.8)
Total comprehensive income - - (5.8) 131.4 78.1 - (109.6) 94.1
Exercise of employee share options 1.5 - - - - - (1.5) -
Share-based payment charges - - - - - - 6.0 6.0
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 31 December 2024 217.5 1,294.7 (242.4) 0.1 (12.1) 755.2 (2,285.7) (272.7)
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 2024
$m Notes 2024 2023
Cash flows from operating activities
Profit from continuing activities before tax 321.5 95.9
Adjustments for:
Depreciation, depletion and amortisation 9 444.2 436.6
Asset revaluation 11 (38.9) -
Other gains - (0.2)
Taxes paid in kind 7 (6.3) (11.0)
Exploration costs written off 8 212.6 27.0
Impairment (reversal)/impairment of property, plant and equipment, net 9 (11.8) 408.1
Provisions reversal (63.3) (22.0)
Payment for provisions 14 (0.7) (0.6)
Decommissioning expenditure 14 (45.0) (78.1)
Share-based payment charge 6.9 6.0
Loss on hedging instruments - 0.4
Gain on bond buyback - (86.0)
Finance income 6 (71.5) (44.0)
Finance costs 6 345.6 329.6
Operating cash flow before working capital movements 1,093.3 1,061.7
Decrease/(increase) in trade and other receivables 0.7 (36.3)
(Increase)/decrease in inventories (25.1) 66.6
Increase in trade payables 49.9 58.7
Cash generated from operating activities 1,118.8 1,150.7
Income taxes paid (360.3) (274.5)
Net cash from operating activities 758.5 876.2
Cash flows from investing activities
Proceeds from disposals - 0.7
Purchase of additional interests in a joint operation (8.1) -
Purchase of intangible exploration and evaluation assets (27.8) (30.2)
Purchase of property, plant and equipment (196.7) (262.3)
Interest received 19.5 23.3
Net cash used in investing activities (213.1) (268.5)
Cash flows from financing activities
Debt arrangement fees - (5.0)
Repayment of borrowings (100.0) (432.2)
Drawdown of borrowings - 129.7
Payment of obligations under leases 13 (169.0) (195.0)
Finance costs paid (223.2) (240.0)
Net cash used in financing activities (492.2) (742.5)
Net increase/(decrease) in cash and cash equivalents 53.2 (134.8)
Cash and cash equivalents at beginning of year 499.0 636.3
Foreign exchange gain/(loss) 2.9 (2.5)
Cash and cash equivalents at end of year 555.1 499.0
Notes to the financial statements
Year ended 31 December 2024
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 2024 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 2023
have been delivered to the Registrar of Companies and those for 2024 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
2023. 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 2024, 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 2024 Annual Report and Accounts.
Certain new accounting standards and interpretations have been published that
are not mandatory for 31 December 2024 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. 2024 Annual Report and Accounts
The 2024 Annual Report and Accounts will be mailed in April 2025 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
The information reported to the Group's Interim Chief Executive Officer for
the purposes of resource allocation and assessment of segment performance is
focused on four Business Units: Ghana, non-operated producing assets and
decommissioning assets, Kenya and Exploration. Therefore, the Group's
reportable segments under IFRS 8 are Ghana, Non-Operated, Kenya and
Exploration.
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 2024 and 31 December 2023.
$m Ghana Non-Operated Kenya Exploration Corporate Total
2024
Sales revenue by origin 1,325.4 283.1 - - (73.6) 1,534.9
Segment result(1) 722.6 123.5 (145.4) (55.9) (91.6) 553.2
Provisions reversal 70.4
Asset revaluation 38.9
Unallocated corporate expenses(2) (66.9)
Operating profit 595.6
Finance income 71.5
Finance costs (345.6)
Profit before tax 321.5
Income tax expense (266.9)
Profit after tax 54.6
Total assets 3,164.3 305.0 112.2 4.9 465.1 4,051.5
Total liabilities(3) (1,978.4) (254.2) (5.8) (6.2) (2,079.6) (4,324.2)
Other segment information
Capital expenditure:
Property, plant and equipment 126.4 122.3 2.2 - 2.6 253.5
Intangible exploration and evaluation assets 0.2 14.3 6.4 13.8 - 34.7
Depletion, depreciation and amortization (401.4) (37.0) (2.7) - (3.1) (444.2)
Impairment reversal of property, plant and equipment, net - 11.8 - - - 11.8
Exploration costs written off - (11.2) (145.4) (56.0) - (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 below.
2. Unallocated expenditure includes amounts of a corporate nature and not
specifically attributable to a geographic area.
3. Total liabilities - Corporate comprise the Group's external debt and other
non-attributable liabilities.
Reconciliation of segment result
$m 2024 2023
Segment result 553.2 329.8
Add back
Exploration costs written off 212.6 27.0
Impairment (reversal)/Impairment of property, plant and equipment (11.8) 408.1
Gross profit 754.0 764.9
4. Segmental reporting continued
$m Ghana Non-Operated Kenya Exploration Corporate Total
2023
Sales revenue by origin 1,311.4 461.8 - - (139.1) 1,634.1
Segment result(1) 408.2 114.0 (17.9) (9.9) (164.6) 329.8
Other provisions 22.0
Other gains 0.2
Unallocated corporate expenses(2) (56.1)
Operating profit 295.9
Loss on hedging instruments (0.4)
Gain on bond buyback 86.0
Finance income 44.0
Finance costs (329.6)
Profit before tax 95.9
Income tax expense (205.5)
Profit after tax (109.6)
Total assets 3,529.7 200.9 253.3 48.5 426.2 4,458.6
Total liabilities(3) (2,231.6) (355.1) (10.3) (2.9) (2,218.1) (4,818.0)
Other segment information
Capital expenditure:
Property, plant and equipment 413.7 85.9 (2.2) - 2.1 499.5
Intangible exploration and evaluation assets 0.2 1.6 7.5 16.1 - 25.4
Depletion, depreciation and amortisation (387.7) (44.1) 0.6 - (5.4) (436.6)
Impairment of property, plant and equipment, net (301.2) (97.9) - - (9.0) (408.1)
Exploration costs written off (0.2) 0.9 (17.9) (9.8) - (27.0)
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 includes amounts of a corporate nature and 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.
5. Other costs
$m 2024 2023
Cost of sales
Operating costs 272.4 292.9
Depletion and amortisation of oil and gas and leased assets(1) 437.6 430.8
Overlift, underlift and oil stock movements 42.5 109.3
Royalties 27.9 33.9
Share-based payment charge included in cost of sales 0.4 0.4
Other cost of sales 0.1 1.9
Total cost of sales 780.9 869.2
Administrative expenses
Share-based payment charge included in administrative expenses 6.5 5.6
Depreciation of other fixed assets 6.6 5.8
Other administrative costs 40.1 44.7
Total administrative expenses 53.2 56.1
Provisions reversal(2) (63.3) (22.0)
1. Depreciation expense on leased assets of $91.4 million (2023: $81.4
million) as per Note 9 includes a charge of $4.1 million (2023: $2.2 million)
on leased administrative assets, which is presented in administrative expenses
in the income statement. The remaining balance of $87.3 million (2023: $79.2
million) relates to other leased assets and is included in cost of sales.
2. This includes reduction in other provisions of $70.4 million (2023: $22.0
million) as well as provision for restructuring and redundancy costs of $7.1
million (2023: $nil).
The decrease in other administrative costs is mainly due to a reduction in
one-off corporate project expenditure and lower insurance premiums partly
offset by higher payroll costs in the current year.
6. Net financing costs
$m 2024 2023
Interest on bank overdrafts and borrowings 211.5 237.0
Interest on obligations for leases 119.7 78.6
Total borrowing costs 331.2 315.6
Finance and arrangement fees 3.0 1.9
Other interest expense - 2.0
Unwinding of discount on decommissioning provisions 11.4 10.1
Total finance costs 345.6 329.6
Interest income on amounts due from Joint Venture partners for leases (48.1) (30.1)
Other finance income (23.4) (13.9)
Total finance income (71.5) (44.0)
Net financing costs 274.1 285.6
7. Taxation on profit on continuing activities
$m 2024 2023
Current tax on profits for the year
UK corporation tax - (1.9)
Foreign tax 307.6 322.2
Taxes paid in kind under Production Sharing Contracts 6.3 11.0
Adjustments in respect of prior periods (3.5) 10.8
Total corporate tax 310.4 342.1
UK petroleum revenue tax (2.4) (0.7)
Total current tax 308.0 341.4
Deferred tax
Origination and reversal of temporary differences
UK corporation tax (19.1) (22.9)
Foreign tax (27.0) (106.5)
Adjustments in respect of prior periods 1.1 (2.8)
Total deferred corporate tax (45.0) (132.2)
Deferred UK petroleum revenue tax 3.9 (3.7)
Total deferred tax (41.1) (135.9)
Total income tax expense 266.9 205.5
$m 2024 2023
Profit from continuing activities before tax 321.5 95.9
Tax on profit from continuing activities at the standard UK corporation 80.4 22.5
tax rate of 25% (2023: 23.5%)
Effects of:
Non-deductible exploration expenditure 50.3 3.4
Other non-deductible expenses 0.4 35.4
Net deferred tax asset not recognised 78.2 65.1
Utilisation of tax losses not previously recognised (0.6) (0.2)
Adjustment relating to prior years (2.4) (2.8)
Other tax rates applicable outside the UK 95.9 82.4
Other income not subject to corporation tax 0.3 (0.3)
Tax impact of acquisitions and disposals (35.6) -
Total income tax expense for the year 266.9 205.5
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 of $80.8 million (2023: $85.0 million) are included in income tax
payable of $79.0 million (2023: $78.3 million), deferred tax liability of $nil
(2023: $nil), and provisions of $1.8 million (2023: $6.7 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 $608.7 million
(2023: $1,030.3 million) excluding interest and penalties which in
management's view are remote.
7. Taxation on profit on continuing activities continued
The provisions and contingent liabilities relating to these disputes 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
2024, giving rise to an overall decrease in provision of $4.2 million and
decrease in contingent liability of $421.6 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 have agreed a
procedural timetable for the arbitration under which the first Tribunal
hearing will be held in July 2025.
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 parties have agreed a procedural
timetable for the arbitration under which the first Tribunal hearing will be
held in November 2025.
The Group continues to engage with the Government of Ghana with the aim of
resolving these tax disputes on a mutually acceptable basis.
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 (c$29.3 million) requesting payment by 15 March 2020.
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.
Other items
Other items totalling $192.3 million (2023: $294.0 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. Intangible exploration and evaluation assets
$m 2024 2023
At 1 January 287.0 288.6
Additions 34.7 25.4
Exploration costs written off (212.6) (27.0)
At 31 December 109.1 287.0
The below table provides a summary of the exploration costs written off on a
pre-tax basis by country.
Country CGU Rationale for 2024 write-off 2024 2024
Write-off
Remaining recoverable amount
$m
$m
Argentina MLO114, MLO119 and MLO122 a 38.8 -
Côte d'Ivoire Block 524 and Block 803 a 15.5 -
Gabon Simba b 10.3 -
Kenya Blocks 10BB and 13T c 145.4 103.2
New Ventures Various d 1.3 -
Uganda Exploration areas 1, 1A, 2 and 3A e 0.8 -
Other Various 0.5 -
Total write-off 212.6
a. No further activity planned following unsuccessful farm-down efforts.
b. Uncommercial well costs written off.
c. Delay in farm-down and extension of Field Development Plan review period.
d. New Ventures expenditure is written off as incurred.
e. Indirect tax movement on previously disposed or written-off assets.
Country CGU Rationale for 2023 write-off/(back) 2023 Write-off/(back)
$m
2023 Remaining recoverable amount
$m
Guyana Kanuku a 1.7 -
Guyana Orinduik a 0.7 -
Côte d'Ivoire Block 524 a 3.3 -
Kenya Blocks 10BB and 13T b,c 17.9 242.2
New Ventures Various d 4.1 -
Uganda Exploration areas 1, 1A, 2 and 3A e (4.3) -
Gabon DE8 f 3.4 -
Other Various 0.2 -
Total write-off 27.0
a. Current year expenditure on assets previously written off.
b. Following VIU assessment subsequent to withdrawal of JV Partners.
c. Revision of short-, medium- and long-term oil price assumptions.
d. New Ventures expenditure is written off as incurred.
e. Release of indirect tax provision following settlement.
f. Unsuccessful well costs written off.
8. Intangible exploration and evaluation assets continued
Kenya:
Discussions with the Government of Kenya (GoK) on approval of the Field
Development Plan (FDP) have been ongoing since its submission on 10 December
2021. An updated FDP was submitted on 3 March 2023 and is being reviewed by
the GoK before ratification by the Kenyan Parliament. Energy and Petroleum
Regulatory Authority (EPRA), the regulator, has engaged third-party
consultants to review the revised FDP and the current review period was
extended to 30 June 2025. The review of the FDP by EPRA is progressing, and
Tullow is in discussions to respond to commercial and technical queries raised
as part of the review. The Group expects a production licence to be granted
once the reviews are completed.
On 22 May 2023, Africa Oil Corporation (AOC) and Total Energies (TE) gave
notice of their respective withdrawal from the Blocks 10BA, 10BB and 13T
Production Sharing Contracts (PSCs) and the Joint Operating Agreements (JOAs),
effective 30 June 2023, quoting differing internal strategic objectives as
reasons. The withdrawal is ultimately subject to the GoK's consent, at which
stage the withdrawal will be considered completed and Tullow will have full
assignment of rights and liabilities under the JOA. Pending GoK approval, per
the terms of the agreement, the participating interest (PI) vests in trust for
the sole and exclusive benefit of Tullow, which is the only remaining Joint
Venture Partner.
In the Tullow management's view, in light of public statements and
announcements made by AOC and TE to this effect and in accordance with the
terms of the JOA, it is considered that the ownership of the 50% held by AOC
and TE was irrevocably passed to Tullow on 30 June 2023. From the date, Tullow
has the right to benefit from the PI and will also be liable for all costs
incurred going forward (except those for which the withdrawing parties remain
liable for). Tullow has also obtained an external legal opinion, which
substantiates the above position, however, subject to customary conditions of
Tullow having the financial and technical capacity as required under the
Petroleum Act. Tullow has submitted an application to GoK to obtain its
approval to execute the transfer of the 50% interest and is still in
discussions with EPRA/GoK to address certain commercial and technical points
raised in 2H 2024 as part of the approval process.
To achieve a Final Investment Decision (FID), securing a strategic partner who
will bring requisite commercial and technical abilities is a key milestone.
Considering the delay in securing a farm-down offer and time taken to secure
GoK approvals for transfer of the additional 50% interest, an impairment
trigger was identified for 31 December 2024 reporting.
In line with the accounting policy, recoverable value was determined using a
discount cash flow model. The long-term oil price assumptions remain
consistent with those used at the end of 2023, while discount rates have
increased by 1%. The cash flows were discounted using a pre-tax nominal
discount rate of 21% (2023: 20%). This resulted in a net present value (NPV)
significantly more than the carrying value of $248.6 million. However, the
Group has identified the following uncertainties in respect of its ability to
realise the NPV: receiving and subsequently finalising an acceptable offer
from a strategic partner thus enabling FDP approval; obtaining financing for
the project; and government deliverables in form of the provision of required
infrastructure and fiscal terms. These items require satisfactory resolution
before the Group can take an FID. The Group continues to progress with the
farm-down process.
Due to the binary nature of these uncertainties, the Group was unable to
either adjust the cash flows or discount rate appropriately. It has therefore
used its judgement and assessed a probability of achieving FID and therefore
the recognition of commercial reserves. This probability was applied to the
unrisked NPV to determine a risk-adjusted recoverable value, which was then
compared against the net book value of the asset. Certain risks have increased
since 31 December 2023, predominantly around achieving a farm-down and
receiving government approval for the FDP and the transfer of the additional
50% PI. Tullow continues to receive expressions of interest and non binding
offers from potential strategic partners and is in active discussions with
multiple interested parties. Hence the recoverable amount based on risked NPV
has been revised to $103.2 million and a further impairment of $145.4 million
has been recognised in the year ended 31 December 2024.
Management has compared the remaining net book value of the Kenya project with
the recoverable value under alternative development options, in case the
farm-down based on the FDP is unsuccessful. The alternative development
options support the recognition of the remaining net book value of the Kenya
project and will be pursued if the current project development plan could not
be progressed further.
Should the uncertainties around the project be resolved, there will be a
reversal from the previously recorded impairment charges of up to $1,075.2
million. However, in the case that an FID is not reached, there could be
potential changes in the carrying value in the next financial year due to
changes in facts and circumstances that influence the risk factors and thus
the overall probability weighting, which drives the recoverable value. This
can lead to the recognition of additional impairment of up to $103.2 million.
The sensitivity disclosure focuses on the binary nature of these uncertainties
leading to FID, this being the most relevant sensitivity disclosure, i.e.,
failure to achieve any one of the factors will result in failure to achieve
FID, which will result in the full impairment of the remaining carrying
amount.
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 increase the
impairment charge by $18.5 million, whilst increases to oil prices specified
above would result in a reduction in the impairment charge of $18.4 million. A
1% change in the pre-tax discount rate would result in an additional
impairment charge of $15.4 million. The Group believes a 1% change in the
pre-tax discount rate to be a reasonable possibility based on historical
analysis of the Group's and a peer group of companies' impairments.
Applying Net Zero emissions by 2050 to the current risking will result in an
additional impairment charge of $103.2 million.
9. Property, plant and equipment
$m 2024 2024 2024 2024 2023 2023 2023 2023
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 11,282.1 21.9 1,268.8 12,572.8 11,182.6 30.0 1,196.8 12,409.4
Additions 151.6 3.1 1.4 156.1 416.1 2.3 81.1 499.5
Acquisitions 97.4 - - 97.4 - - - -
Transfer to assets held for sale - - - - (302.8) - - (302.8)
Asset retirement - (1.3) (145.3) (146.6) (67.7) (11.0) (10.6) (89.3)
Currency translation adjustments (17.3) (0.3) (0.5) (18.1) 53.9 0.6 1.5 56.0
At 31 December 11,513.8 23.4 1,124.4 12,661.6 11,282.1 21.9 1,268.8 12,572.8
Depreciation, depletion and amortization and impairment
At 1 January (9,377.7) (17.5) (644.8) (10,040.0) (8,888.4) (24.4) (515.2) (9,428.0)
Charge for the year (350.3) (2.5) (91.4) (444.2) (351.6) (3.6) (81.4) (436.6)
Impairment reversal/(Impairment) 11.8 - - 11.8 (399.1) - (9.0) (408.1)
Capitalised depreciation - - (29.5) (29.5) - - (49.3) (49.3)
Transfer to assets held for sale - - - - 247.6 - - 247.6
Asset retirement - 1.3 145.3 146.6 67.7 11.0 10.6 89.3
Currency translation adjustments 17.3 0.1 0.4 17.8 (53.9) (0.5) (0.5) (54.9)
At 31 December (9,698.9) (18.6) (620.0) (10,337.5) (9,377.7) (17.5) (644.8) (10,040.0)
Net book value at 31 December 1,814.9 4.8 504.4 2,324.1 1,904.4 4.4 624.0 2,532.8
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
2024 $74/bbl $71/bbl $75/bbl $75/bbl $75/bbl $75/bbl inflated at 2%
2023 $78/bbl $75/bbl $75/bbl $75/bbl $75/bbl $75/bbl inflated at 2%
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.
Trigger for 2023 impairment/ (reversal) 2023 Impairment/ (reversal) 2023 Remaining recoverable amount(g)
$m Pre-tax discount rate assumption $m
Espoir (Cote d'Ivoire) a,c 53.5 14% 0.4
TEN (Ghana) b,c 301.2 14% 528.3
Mauritania d 27.9 n/a -
UK CGU d,e 16.5 n/a -
UK Corporate f 9.0 n/a -
Impairment 408.1
a. Increase in production and development costs.
b. Revision of value based on revisions to reserves.
c. Revision of short, medium and long-term oil price assumptions.
d. Change to decommissioning estimate.
e. The fields in the UK are grouped into one CGU as all fields share critical
gas infrastructure.
f. Fully impaired right-of-use asset relating to a vacant office space.
g.The remaining recoverable amount of the asset is its value in use.
10. Other assets
$m 2024 2023
Non-current
Amounts due from joint venture partners 333.1 332.5
VAT recoverable 7.7 6.1
340.8 338.6
Current
Amounts due from joint venture partners 350.2 498.1
Underlifts 20.9 47.8
Prepayments 17.1 21.1
Other current assets 3.7 4.2
391.9 571.2
732.7 909.8
Non-current receivables from JV Partners include the Ghana decommissioning
fund, which relates to the requirement for JV 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 2024, Tullow has contributed $11.6
million (2023: $nil) into the decommissioning trust fund.
The decrease in current receivables from JV Partners compared to December 2023
mainly relates to partner's share of decreased accrual balances (note 12), net
decrease in GNPC (Ghana National Petroleum Corporation) receivables, lower
balance of current receivables relating to leases (note 13), and other working
capital movements.
11. 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 is 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 will enable
Tullow to leverage its technical skills and focus on more material positions
in key fields.
The transaction is an asset swap achieved through the exchange of
participating interests held by both parties in certain licences in Gabon. The
exchange represents the acquisition of an additional interest in a joint
operation that constitutes a business, and therefore IFRS 11 Joint
Arrangements requires 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 comprises mainly of property, plant, and equipment of
$54.4 million, have been remeasured to the acquisition date fair value of
$93.3 million. This has resulted in an asset revaluation gain of $38.9 million
recognised in the income statement at 31 December 2024.
The below table shows the pre-completion and post-completion equities in the
licences subject to the transaction:
Field Pre-completion Post-completion
Kowe (Tchatamba) Acquisition 25.0% 40.0%
DE8 Acquisition 20.0% 40.0%
Simba Disposal 57.5% 40.0%
Limande Disposal 40.0% 0%
Turnix Disposal 27.5% 0%
Moba Disposal 24.3% 0%
Oba Disposal 10.0% 0%
The exchange of the transferred interests between the parties was deemed for
all purposes to be made with effect from the economic date of 1 February 2023,
but completed on 29 February 2024 and this is therefore the acquisition date.
The transaction was intended to be cash neutral on the economic date as the
fair value of the assets exchanged were considered to be equal at that time,
and therefore no additional consideration would have been payable by either
party at that time. 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.
11. Business combination continued
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 disclosure requirement of IFRS 3 in relation to contributions to revenue
and profit or loss have not been included as they are impracticable to obtain
due to Tullow not being the operator of the assets.
No material acquisition-related costs were incurred in relation to the
transaction.
Valuation methodology and assumptions
The fair value of the purchase consideration of $93.3 million reflects the
discounted future cash flows of the assets and liabilities exchanged as part
of the swap as the transaction is intended to be value neutral. Provisions
represent the present value of decommissioning costs which are expected to be
incurred after the end of the licence in 2046.
Goodwill
Goodwill of $44.9 million was recognised from the asset swap. 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. Therefore, goodwill has arisen as a
direct result of the recognition of the deferred tax liability. None of the
goodwill is deductible for income tax purposes.
The goodwill acquired through the business combination is allocated fully to
the Tchatamba cash-generating unit (CGU), for the purposes of impairment
testing. Refer to Note 9 for full disclosure of the outcome of the impairment
test at 31 December 2024. Significant headroom remained between the net
present value (NPV) and the book value of the CGU and management did not
identify an impairment for this CGU.
Asset held for sale
As at 31 December 2024, the Group had no assets classified as held for sale
(2023: $55.8 million) and no liabilities associated with assets classified as
held for sale (2023: $17.6 million). The previously classified AHFS, relating
to the Gabon asset swap, was derecognised when the transaction was completed
during the year as disclosed above.
12. Trade and other payables
$m 2024 2023
Current
Trade payables 75.7 22.3
Other payables 96.8 65.3
Overlifts 38.3 3.1
Accruals 373.8 498.6
Current portion of leases 151.9 185.7
736.5 775.0
Non-current
Other non-current liabilities(1) 84.9 62.2
Non-current portion of leases 581.0 721.0
665.9 783.2
1. Other non-current liabilities include balances related to JV Partners.
Accruals relate to operating and administrative expenditure of $196.3 million
(2023: $209.2 million), capital expenditure of $119.6 million (2023: $225.6
million), interest expense on bonds of $35.3 million (2023: $40.9 million) and
staff-related expenses of $22.6 million (2023: $22.9 million). The movement in
the balance is predominantly driven by a decreased work programme in Ghana
during 2024 compared to 2023.
Trade and other payables are non-interest bearing except for leases (Note 13).
The change in trade payables and in other payables represents timing
differences and levels of work activity.
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 10).
The movement in current and non-current lease liabilities is mainly driven by
the level of drilling activity in Ghana (Note 13).
13. Leases
This note provides information for leases where the Group is a lessee. The
Group did not enter into any contracts acting as a lessor.
i) Amounts recognised in the balance sheet
Right-of-use assets Lease liabilities
$m 2024 2023 2024 2023
Right-of-use assets (included within property, plant and equipment) and lease
liabilities
Property leases 18.2 22.0 26.1 27.6
Oil and gas production and support equipment leases 466.4 576.9 661.9 826.4
Transportation equipment leases 19.8 25.1 44.9 52.7
Total 504.4 624.0 732.9 906.7
Current provisions 151.9 185.7
Non-current 581.0 721.0
Total 732.9 906.7
Additions and disposals of right-of-use assets during the 2024 financial year
were $1.4 million and $145.3 million, respectively. Refer to Note 9.
TEN FPSO
The Group's leases balance includes the TEN FPSO, classified as oil and gas
production and support equipment. During 2023, the assumption that the TEN
FPSO lease term would end in April 2024, when the purchase option was assumed
to be exercised, was updated to reflect the best estimate view that the FPSO
will continue to be leased until the cessation of production in 2032. It also
assumes an exercise of the extension option.
The resulting lease liability remeasurement had the following impact on the
balances:
$m 2023
Lease liability (39.2)
Right-of-use asset (included in property, plant and equipment) 25.6
Amounts due from Joint Venture Partners 13.6
13. Leases continued
As at 31 December 2024, the present value of the TEN FPSO right-of-use asset
was $466.3 million (2023: $549.0 million).
The present value of the TEN FPSO gross lease liability was $650.0 million
(2023: $763.5 million).
A receivable from the Joint Venture Partners of $244.9 million (2023: $288.8
million) was recognised in other assets (Note 10) 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.
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 2023 (984.1) 376.1 (608.0)
Additions and changes in lease estimates (174.1) 79.8 (94.3)
Payments/(receipts) 331.5 (136.5) 195.0
Interest (expense)/income (78.6) 30.1 (48.5)
Currency translation adjustments (1.4) - (1.4)
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 31 December 2024 (732.9) 276.2 (456.7)
ii) Amounts recognised in the statement of profit or loss
$m 2024 2023
Depreciation charge of right-of-use assets
Property leases 8.5 7.3
Oil and gas production and support equipment leases 82.9 74.1
Total 91.4 81.4
Interest expense on lease liabilities (included in finance costs) 119.7 78.6
Interest income on amounts due from Joint Venture Partners (48.1) (30.1)
Expense relating to short-term leases 0.8 1.0
Expense relating to leases of low-value assets 0.6 0.9
Total 164.4 131.8
The total net cash outflow for leases in 2024 was $169.0 million (2023: $195.0
million).
14. Provisions
$m Decommissioning Other provisions Total Decommissioning 2023 Other provisions Total
2024
2024
2024
2023
2023
At 1 January 377.9 93.7 471.6 398.1 116.3 514.4
New provisions - 22.4 22.4 - (10.4) 10.4
Changes in estimate (39.3) (75.9) (115.2) 47.8 (32.3) 15.5
Acquisitions(1) 5.8 - 5.8 - - -
Transfer to assets and liabilities held for sale - - - (14.2) - (14.2)
Payments (49.0) (0.7) (49.7) (66.4) (0.6) (67.0)
Unwinding of discount 11.4 - 11.4 10.1 - 10.1
Currency translation adjustment (0.4) (0.1) (0.5) 2.5 (0.1) 2.4
At 31 December 306.4 39.4 345.8 377.9 93.7 471.6
Current provisions(2) 9.8 14.5 24.3 53.4 14.5 67.9
Non-current provisions(2) 296.6 24.9 321.5 324.5 79.2 403.7
1. This relates to an acquisition through business combination
discussed in Note 11.
2. In 2024, provisions of $10.0 million were reclassified from current
provisions to non-current provisions as management expectations are that the
provision will not crystallise within the next 12 months.
Other provisions include non-income tax provisions of $7.1 million (2023:
$38.8 million) and $32.3 million (2023: $54.9 million) of disputed cases and
claims. Management estimates non-current other provisions would fall due
between two and five years.
New other provisions include $7.1 million for the restructuring programme that
commenced in December 2024. Changes in estimate of other provisions includes a
reduction of $31.1 million in relation to the BPRT arbitration ruling.
Non-current other provisions include a provision relating to a potential claim
arising out of historical contractual agreement. Further information is not
provided as it will be seriously prejudicial to the Group's interest.
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
2024
2024
2024
2023
2023
2023
$m $m
Côte d'Ivoire 2.0% 4.5% 2027 50.0 3.5% 2032 47.1
Gabon 2.0% 4.5-5.0% 2030-2047 30.7 3.5-4.0% 2034-2047 28.7
Ghana 2.0% 4.5% 2033-2036 195.6 3.5% 2032-2036 208.2
Mauritania n/a n/a 2018 1.1 n/a 2018 54.7
UK n/a n/a 2018 29.0 n/a 2018 39.2
306.4 377.9
1. Short-term inflation rate assumption has increased from 2.0% to
2.5% in 2025. Long-term rates of 2% remained unchanged from 31 December 2023.
The Group's decommissioning activities are ongoing in the UK and Mauritania,
with $10.0 million of the future costs expected to be incurred in 2025. The
remaining activities are planned to continue through to 2027, with an
associated expenditure of $20.0 million, mostly in the UK.
15. Commercial reserves and contingent resources summary working interest
basis
Ghana Non-Operated(7) Kenya Total
Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Petroleum
bcf
bcf
bcf
bcf
mmboe(6)
COMMERCIAL
RESERVES(1)
1 January 2024 143.8 151.7 41.9 6.8 - - 185.7 158.5 212.2
Revisions(3,4) (22.9) - (1.6) (4.5) - - (24.5) (4.5) (25.3)
Production (16.1) (13.3) (3.9) (1.2) - - (20.0) (14.5) (22.4)
Acquisitions(5) - - - - - - - - -
Disposals(5) - - - - - - - - -
31 December 2024 104.8 138.4 36.4 1.1 - - 141.2 139.5 164.5
CONTINGENT RESOURCES(2)
1 January 2024 152.8 511.0 35.1 9.7 470.4 - 658.3 520.7 745.0
Revisions(3,4) (26.4) (72.2) 10.9 4.2 (7.2) - (22.7) (68.0) (34.0)
Acquisitions(5) - - - - - - - - -
Disposals(5) - - - - - - - - -
31 December 2024 126.4 438.8 46.0 13.9 463.2 - 635.6 452.7 711.0
TOTAL
31 December 2024 231.2 577.2 82.4 15.0 463.2 - 776.8 592.2 875.5
1. Reserves presented are 'proven and probable'. They are as audited and
reported by the independent third-party reserves auditor as at year end 2024.
2. Contingent resources are 'best estimate'. They are as audited and reported
by the independent third-party reserves auditor as at year end 2024.
3. Reserves and resources revisions in Ghana are primarily related to
production performance during 2024 on Jubilee and include an upwards revision
of TEN reserves, supported by substantial progress towards a material
reduction in fixed costs, including in relation to the FPSO, which extends the
economic life to 2036.
4. Reserves revisions in the non-operated portfolio primarily reflect an
earlier assumed cessation of production on the Espoir field.
5. There have been no acquisitions or disposals in 2024. The asset swap in
Gabon, in which M'Oba, Oba, Limande, Turnix and a percentage of Simba were
exchanged for an increased working interest in Tchatamba and the DE8 licence,
was already accounted for in the 1 January 2024 reserve and resource
position.
6. A gas conversion factor of 6 mscf/boe is used to calculate the total
petroleum mmboe.
7. Non-Operated consists of assets located in Gabon and Cote d'Ivoire.
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 161.5
mmboe at 31 December 2024 (31 December 2023: 204.5 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, capitalised share-based payment
charge, capitalised finance costs, 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 capitalised finance costs
and decommissioning asset additions.
$m 2024 2023
Additions to property, plant and equipment 249.0 416.1
Additions to intangible exploration and evaluation assets 34.7 25.4
Less
Changes to decommissioning asset estimates (39.3) 47.8
Right-of-use asset additions 1.4 81.1
Lease payments related to capital activities (21.9) (53.6)
Additions to administrative assets 3.1 2.3
Other non-cash capital movements(1) 109.3 (16.0)
Capital investment 231.1 379.9
Movement in working capital (1.6) (89.7)
Additions to administrative assets 3.1 2.3
Cash capital expenditure per the cash flow statement 232.6 292.5
1. 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, adjustment to convertible bonds, 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 2024 was $151.9 million current and $581.0
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 2024 2023
Current borrowings 589.4 100.0
Non-current borrowings 1,386.4 1,984.6
Non-cash adjustments(1) 31.6 22.8
Less cash and cash equivalents(2) (555.1) (499.0)
Net debt 1,452.3 1,608.4
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 $83.5 million (2023: $36.9
million) which the Group holds as operator in joint venture bank accounts.
Included within cash at bank is $6.5 million (2023: $4.5 million) of
restricted cash held as collateral for performance bonds issued in relation to
exploration activity.
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 hedging instruments, asset revaluation, other gains,
depreciation, depletion and amortisation, share-based payment charge,
provision reversal, gain on bond buyback, exploration costs written off,
impairment (reversal)/impairment of property, plant and equipment net,
expected credit loss charge on trade receivables and restructuring provision.
$m 2024 2023
Profit/(Loss) from continuing activities 54.6 (109.6)
Adjusted for
Income tax expense 266.9 205.5
Finance costs 345.6 329.6
Finance revenue (71.5) (44.0)
Loss on hedging instruments - 0.4
Asset revaluation (38.9) -
Other gains - (0.2)
Depreciation, depletion and amortisation 444.2 436.6
Share-based payment charge 6.9 6.0
Provision reversal (70.4) (22.0)
Gain on bond buyback - (86.0)
Exploration costs written off 212.6 27.0
Impairment (reversal)/Impairment of property, plant and equipment, net (11.8) 408.1
Expected credit loss charge on trade receivables 6.6 -
Restructuring provision 7.1 -
Adjusted EBITDAX 1,151.9 1,151.4
Net debt 1,452.3 1,608.4
Gearing (times) 1.3 1.4
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 2023 and 2024, 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.
$m 2024 2023
Cost of sales 780.9 869.2
Add
Lease payments related to operating activity 11.6 7.2
Less
Depletion and amortisation of oil and gas and leased assets(1) 437.6 430.8
Underlift, overlift and oil stock movements(2) 42.5 109.3
Share-based payment charge included in cost of sales 0.4 0.4
Royalties 27.9 33.9
Other cost of sales(3) 11.7 9.1
Underlying cash operating costs 272.4 292.9
Non-recurring costs(4) (8.3) (25.9)
Total normalised cash operating costs 264.1 267.0
Production (MMboe) 22.4 22.9
Underlying cash operating costs per boe ($/boe) 12.2 12.8
Normalised cash operating costs per boe ($/boe) 11.8 11.7
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.
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 used in investing
activities, repayment of obligations under leases, finance costs paid and
foreign exchange gain/(loss).
$m 2024 2023
Net cash from operating activities 758.5 876.2
Net cash used in investing activities (213.1) (268.5)
Repayment of obligations under leases (169.0) (195.0)
Finance costs paid (223.2) (240.0)
Foreign exchange gain/(loss) 2.9 (2.5)
Free cash flow 156.1 170.2
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 2024 2023
Net cash from operating activities 758.5 876.2
Add
Decommissioning expenditure 45.0 78.1
Lease payments related to capital activities 21.9 53.6
Payments to decommissioning escrow fund 11.6 -
Less
Repayment of obligations under leases (169.0) (195.0)
Underlying operating cash flow 668.0 812.9
Net cash used in investing activities (213.1) (268.5)
Decommissioning expenditure (45.0) (78.1)
Lease payments related to capital activities (21.9) (53.6)
Payments to decommissioning escrow fund (11.6) -
Pre-financing cash flow 376.4 412.7
Management Presentation - WEBCAST - 09:00
To access the webcast please use the following link and follow the
instructions provided:
https://meetings.lumiconnect.com/100-695-362-491
(https://meetings.lumiconnect.com/100-695-362-491)
A replay will be available on the website from midday on 25 March 2025:
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
Rob Hayward Georgia Edmonds
Rebecca Waterworth
Notes to editors
Tullow is an independent energy company that is building a better future
through responsible oil and gas development in Africa. The Company's
operations are focused on its West-African producing assets in Ghana, Gabon
and Côte d'Ivoire, alongside a material discovered resource base in Kenya.
Tullow is committed to becoming Net Zero on its Scope 1 and 2 emissions by
2030 and has a Shared Prosperity strategy that delivers lasting socio-economic
benefits for its host nations. The Group is quoted on the London and Ghana
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)
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