REG - Tullow Oil PLC - 2025 Half Year Results
Wed 07:00
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RNS Number : 1253U Tullow Oil PLC 06 August 2025
Tullow oil PLC - 2025 Half Year Results
First 2025 Jubilee well onstream with better net pay than expected
Strong strategic momentum with realisation of $300 million Gabon proceeds
Focused on delivering our key strategic priority of refinancing our capital structure
6 August 2025 - Tullow Oil plc ("Tullow"), the independent oil and gas
exploration and production group ("Group"), announces its Half Year Results
for the six months ended 30 June 2025. Details of a management presentation
and webcast that will be held at 9:00 BST today are available on the last page
of this announcement or visit the Group's website: www.tullowoil.com
(http://www.tullowoil.com)
Richard Miller, Chief Financial Officer and Interim Chief Executive Officer,
Tullow Oil plc, commented:
"Our 2025 strategic priorities remain clear: refinancing our capital
structure, optimising production, increasing reserves, and completing the sale
of our Kenyan assets, having already realised $300 million proceeds from the
sale of our portfolio of assets in Gabon.
"In Ghana we have already taken actions to address the recent underperformance
at Jubilee, with further optimisation potential identified. We have
recommenced drilling and have successfully completed and brought onstream the
first of two planned 2025 production wells at Jubilee, with better than
expected net pay during drilling. The high quality 4D seismic data acquired at
the start of the year is now being used to generate improved models that will
directly inform the well-planning process and will be further supported with
the capture of an Ocean Bottom Node (OBN) seismic survey in the fourth quarter
this year.
"We achieved a key milestone by signing a MoU in Ghana to extend our
production licences for both Jubilee and TEN to 2040, which is expected to
increase reserves and unlock significant value from these fields.
"In the second half of the year we are focussed on refinancing our capital
structure, production optimisation activities and continuing to optimise our
cost base, which combined with the progress in the first half of the year will
help unlock Tullow's intrinsic value."
2025 FIRST HALF RESULTS
· First half Group working interest oil and gas production 50.0
kboepd (1H24: 63.7 kboepd). Excluding Gabon, 40.6 kboepd (1H24: 53.5 kboepd).
· Revenue of $524 million (1H24: $759 million); realised oil price of
$69.0/bbl after hedging (1H24: $77.7/bbl), gross profit of $218 million (1H24:
$460 million); loss after tax of $(61) million (1H24: profit after tax of $196
million). Excluding Gabon, revenue of $411 million (1H24: $666 million);
realised oil price of $69.7/bbl after hedging (1H24: $77.0/bbl), gross profit
of $165 million (1H2024: $387 million); loss after tax of $(80) million (1H24:
profit after tax of $106 million).
· Net G&A of $23 million (1H24: $31 million).
· Capital expenditure of $103 million (1H24: $157 million) and
decommissioning spend of $13 million (1H24: $9 million). Excluding Gabon of
$78 million (1H 2024: $130 million)
· Free cash flow(1) of $(188) million in 1H25 (1H24: $(126) million),
in line with expectations based on timing of tax payments, lifting schedule
and costs associated with Jubilee maintenance in 1H25.
· Net debt(1) at 30 June 2025 of $1.6 billion (30 June 2024: $1.7
billion); cash gearing of 1.9x net debt/EBITDAX(1) (30 June 2024: 1.4x);
liquidity headroom of $0.2 billion (30 June 2024: $0.7 billion). Excluding
Gabon, cash gearing of 2.1x net debt/EBITDAX (30 June 2024: 1.6x).
strategic priorities
· The first half of 2025 has seen significant progress towards
delivery of our strategic priorities for the year to realise Tullow's
potential, including:
- On 29 July, Tullow completed the sale of Tullow Oil Gabon SA for a total
cash consideration of $300 million net of tax.
- On 21 July, Tullow entered into a sale and purchase agreement for the sale
of Tullow Kenya BV for a cash consideration of at least $120 million.
Completion and receipt of the first two milestone payments, totalling $80
million, are expected during 2025.
- On 4 June, Tullow and its JV partners announced a Memorandum of
Understanding (MoU) with the Government of Ghana to extend the West Cape Three
Points (WCTP) and Deep Water Tano (DWT) licences to 2040; the MoU includes a
commitment to work to increase gas supply to c.130 mmscf/d and a guaranteed
reimbursement mechanism for gas sales. As a result of the licence extensions
the JV partners expect to realise a material increase in gross 2P reserves.
- In January the International Chamber of Commerce Tribunal determined that
Branch Profit Remittance Tax (BPRT) in Ghana is not appliable to Tullow Ghana
and therefore it is not liable to pay the $320 million assessment.
2025 FULL YEAR OUTLOOK
· 2025 Group working interest production guidance is expected to
average 40-45 kboepd, including c.6 kboepd of gas, reflecting the sale of the
Gabonese assets effective from the start of the year.
· Full year capex and decommissioning guidance, both updated to
reflect the Gabonese sale, of c.$185 million and c.$20 million, respectively.
· Ghana drilling campaign recommenced with the J72-P well, the first
of two Jubilee production wells in 2025, which was brought onstream at the end
of July having encountered better than expected net pay during drilling
operations.
· Interpretation of the 4D seismic data acquired in the first quarter
continues, with a further four firm Jubilee wells planned for 2026.
· Cost base optimisation savings of c.$10 million expected to reduce
2025 annual net G&A to $40 million, with Group targeted savings of c.$50
million over the next three years compared to 2024.
· Full year free cash flow guidance is adjusted to $300 million at
$65/bbl, reflecting 1H25 Jubilee production performance resulting in one
lifting moving into 2026. Guidance is inclusive of $380 million of disposal
proceeds, $35 million of 2024 Gabonese cash taxes paid in 1H25 which are not
reimbursed through the transaction and c.$50 million of overdue gas payments
in Ghana.
· Year-end net debt guidance is unchanged at c.$1.1 billion with
gearing of c.1.3x (net debt/EBITDAX(1)).
· Following completion of the sale of Tullow Oil Gabon SA, Tullow
applied part of the proceeds to repay in full and simultaneously cancel the
$150 million Revolving Credit Facility (RCF).
· Tullow remains focused on further deleveraging and reaching net
debt of less than $1 billion and cash gearing of less than 1x in the near
term.
1. Alternative performance measures are reconciled on pages 38 to 40
Operational update
Production
In the first six months of 2025, Group production averaged 50.0 kboepd (40.6
kboepd excluding Gabon), including 7.1 kboepd of gas. 2025 Group production
guidance is expected to be at the lower end of the 40-45 kboepd range
(previously 50-55 kboepd), reflecting the removal of Gabonese production from
the start of the year and including c.6 kboepd of gas.
Ghana
During the first six months of the year, operational efficiency remained high,
with average facility uptime across the Ghana FPSOs at 97% and a combined
average oil production rate of c.32.8 kbopd net and an average gas production
rate of 6.2 kboepd net.
Gross oil production from the Jubilee field averaged 60.9 kbopd (net: 23.7
kbopd) in the first half of the year, inclusive of a 15 day planned
maintenance shutdown conducted safely and on budget. During the first half of
2025, Jubilee has been affected by higher than expected water cut from certain
wells, which has impacted riser stability on the eastern side of Jubilee.
Riser base gas lift has now been introduced on the east side of the field,
which restored and stabilised production in June. Riser base gas lift for the
western side of Jubilee, which will provide further uplift to production and
reserves, has been sanctioned and will be implemented in the coming years.
Voidage replacement was greater than 100% in the first half of the year, but
water injection levels were lower than expected due to planned maintenance
taking longer than expected and a fault with the sea water lift system. Tullow
anticipates being able to restore water injection rates closer to capacity of
300 kbw/d in the second half of 2025 to provide increased pressure support and
reduce declines. Additionally, we expect a further uplift in production from
the J72-P well, which encountered better than expected net pay and was brought
onstream in July.
When the rig recommences drilling in the fourth quarter of the year, after a
break for maintenance, the next well is planned to be a Jubilee producer
(J73-P), to come onstream around the end of the year. A further four firm
Jubilee wells are then planned for 2026. Processing of the 4D seismic, shot in
the first quarter, is currently ongoing and will help validate the locations
for the later wells in the campaign. Tullow will further enhance this data set
with the capture of an Ocean Bottom Node (OBN) seismic survey in the fourth
quarter of 2025, which will underpin infill drilling across Jubilee and TEN.
Gross oil production from the TEN fields averaged 16.4 kbopd (net: 9.0 kbopd)
in the first half of the year. This was above expectations supported by
opening a previously shut-in production interval in Enyenra and water
injection optimisation activities. The TEN FPSO flare tip was replaced in May,
which has allowed a further c.50% reduction in routine flaring from July 2025
onwards.
As part of the Memorandum of Understanding (MoU) relating to the extension of
the WCTP and DWT licences in Ghana, a number of principles are included that
underpin the continued development of both TEN and Jubilee. These include a
commitment to work to increase the supply of gas to c.130 mmscf/d (from
current level of c.100 mmscf/d), a reduced gas price for Jubilee associated
gas, and a guaranteed reimbursement mechanism for gas sales. The MoU describes
the intended further development plans for Jubilee, which includes the right
to drill up to 20 additional wells in the Jubilee field, representing
investment of up to $2 billion in Ghana over the life of the licences. As a
result of the licence extensions to 2040 the JV partnership expects to realise
a material increase in gross 2P reserves.
Non-operated and exploration portfolios
Tullow completed the $300 million sale of its non-core Gabon assets to the
Gabon Oil Company on 29 July 2025.
In Côte d'Ivoire, Tullow continues to work with the operator of the Espoir
field to optimise the strategy for the asset point forwards.
As part of continued portfolio rationalisation, the Group has taken the
decision to exit exploration licences in Cote d'Ivoire (CI-524 and CI-803) and
the MLO 114 and MLO 119 licences in Argentina. Tullow continues to focus
efforts on infrastructure-led exploration activities in Ghana.
Kenya
Tullow entered into a sale and purchase agreement for the sale of its Kenya
assets to Auron Energy E&P Limited, an affiliate of Gulf Energy Limited on
21 July 2025 for a total consideration of at least $120 million. In addition,
Tullow will be entitled to royalty payments subject to certain conditions and
retains a no-cost back-in right for a 30% participation in future development
phases. The company expects completion with receipt of the first two payments,
totalling $80 million, during 2025.
Reserves and resources
Tullow will publish its 1H25 reserves report in September and expects a
reduction based on the incorporation of first half production data and field
underperformance at Jubilee. The recent sanction of riser base gas lift, the
potential uplift associated with new incremental drilling targets and licence
extensions are expected to offset the reduction in due course.
Sustainability
Our sustainability approach focuses on three core themes - People, Climate and
Nature - which are aligned with the issues that are most significant to our
business, our stakeholders and the relevant broader UN Sustainable Development
Goals (SDGs). These sustainability themes are underpinned by robust corporate
governance and responsible business conduct, both of which continued to be
deemed material from an impact and financial standpoint.
Care for people
Tullow continues to prioritise safe operations and finished the first half
2025 with four medical treatment cases.
Tullow continues to work closely with local suppliers to drive local content
and strengthen human rights due diligence through increased engagement,
support, and training.
Achieve Net Zero
Tullow continued to make progress on its Net Zero by 2030 (Scope 1 and 2)
target during the first half of 2025. Tullow completed engineering works in
the first six months of 2025 to progress workstreams to eliminate routine
flaring. To address hard-to-abate residual emissions, Tullow is progressing
its nature based carbon offset project with the Ghana Forestry Commission (FC)
that is expected to deliver first offsets by the end of 2026. The FC has
conducted extensive community engagement, begun tree planting and initiated an
environmental and social impact assessment in the first half of 2025.
Respect the environment
In April 2025, Tullow published its inaugural nature disclosure which aligns
with the recommendations of the Taskforce on Nature-related Financial
Disclosures (TNFD). The report is based on the outcomes of the assessment of
the biodiversity baseline completed in 2024 and focused on Ghana.
Governance
As previously announced, Sheila Khama, Independent Non-Executive Director has
stepped down from the Board with effect from 1 August 2025, to focus on her
other professional commitments and roles outside of Tullow.
Finance review
Condensed consolidated income statement
Income Statement (key metrics) 1H 2025(2) 1H 2024(2)
Restated
Revenue ($m)
Sales volume (boepd) 30,200 45,300
Realised oil price ($/bbl) 69.7 77.0
Total revenue 411 666
Operating income/(costs) ($m)
Underlying cash operating costs(1) (108) (87)
Depreciation, Depletion and Amortisation (DDA) of oil and gas and leased (159) (186)
assets
DDA before impairment charges ($/bbl) 21.6 19.1
Underlift/(Overlift) and oil stock movements 18 (5)
Administrative expenses (23) (31)
Exploration costs written off (1) (3)
(Impairment)/Impairment reversal of property, plant and equipment, net (39) 2
Net financing costs (139) (140)
(Loss)/Profit before tax (50) 254
Income tax expense (30) (148)
(Loss)/Profit for the period (80) 106
Adjusted EBITDAX(1) 768 1,083
Basic (loss)/earnings per share (cents) (5.5) 7.3
1. Alternative performance measures are reconciled on pages 38 to 40.
2. Balances above are presented excluding discontinued operations in
Gabon. Refer to note 10.
Revenue
Sales oil volumes
During the period, there were 30,200 boepd (1H 2024: 45,300 boepd) of
liftings. The decrease is mainly due to fewer liftings in Ghana with 5 in
Jubilee (1H 2024: 7) and 1 in TEN (1H 2024: 2).
Realised oil price ($/bbl)
The Group's realised oil price after hedging for the period was $69.7/bbl (1H
2024: $77.0/bbl) and before hedging $71.4/bbl (1H 2024: $84.0/bbl). Lower oil
prices and lower hedged volumes compared to 1H 2024 have resulted in a lower
hedge loss which decreased total revenue by $10 million in 1H 2025 (1H 2024:
decrease of $58 million).
Gas sales
Included in Total Revenue of $411 million is gas sales of $30 million (1H
2024: $29 million) of which $27 million (1H 2024: $25 million) relates to
Ghana. During the period, Tullow exported 17,342 mmscf (gross) of gas at an
average price of $3.04/mmbtu in Ghana (1H 2024: 18,148 mmscf, $2.95/mmbtu).
Cost of Sales
Underlying cash operating costs
Underlying cash operating costs amounted to $108 million; $14.6/boe (1H 2024:
$87 million; $8.9/boe). This consists of Ghana $88 million ($12.4/boe), Cote
d'Ivoire $11 million ($48.1/boe) and Corporate $8 million. The increase is
primarily driven by Jubilee shutdown and FPSO Class related maintenance costs
in the current period. Routine operating costs are largely consistent with
prior period.
Depreciation, depletion, and amortisation
DD&A charges before impairment on production and development assets
amounted to $159 million; $21.6/boe (1H 2024: $186 million: $19.1/boe). This
decrease in DD&A is mainly attributable to lower Jubilee field production
compared to 1H 2024.
Underlift/Overlift and oil stock movements
The Group had an underlift compared to an overlift expense in the comparative
period. The change was due to fewer liftings in Ghana in the current period
resulting from lower oil production volumes.
Administrative expenses
Administrative expenses of $23 million (1H 2024: $31 million) have decreased
against the comparative period mainly due to reduction in employee related
expenses and professional fees, partially offset by an adverse movement in the
foreign exchange rate. Full year forecast administrative costs are expected to
be lower than prior year at c.$40 million. With continued focus on reducing
G&A costs and rationalisation of the organisation following the
simplification of the business, the Group is targeting savings of c.$50
million over the next three years compared to 2024.
Impairment of property, plant and equipment
The Group recognised a net impairment charge on PP&E of $39 million in the
first half of 2025 (1H 2024: Net impairment reversal of $2 million), mainly
driven by a $35 million impairment charge on TEN field from lower oil price
assumptions.
Net financing costs
Net financing costs for the period were $139 million (1H 2024: $140 million).
Lower net interest expense on obligations under leases was offset by debt
arrangement fees incurred in 2025 and a reduced interest income. Interest on
borrowings was in line with prior period as savings due to bond repayments
were offset by interest on additional drawdown of borrowings.
A reconciliation of net financing costs is included in note 9.
Taxation
The overall adjusted net tax expense of $30 million (1H 2024: $148 million)
primarily relates to tax charges in respect of the Group's production
activities in West Africa, reduced by deferred tax credits associated with UK
decommissioning assets, exploration write-offs and impairments.
Based on a loss before tax for the first half of the year of $50 million (1H
2024: profit before tax of $254 million), the effective tax rate (ETR) is
(60.9)% (1H 2024: 58.4%). After adjusting for non-recurring amounts related to
exploration write-offs, disposals and impairments, the Group's adjusted tax
rate is 7,088.6% (1H 2024: 58.8%). In the UK, there is net interest and
hedging expenses of $77 million (1H 2024: $123 million), however, there is no
UK tax benefit as in previous periods.
The Group has applied the exception to recognising and disclosing information
about deferred tax assets and liabilities relating to Pillar Two income taxes.
The Group has not recorded any exposure to Pillar Two income taxes in those
jurisdictions where the safe harbour thresholds are not met based on the
latest available forecast data.
Detailed analysis of ETR for underlying business - Continuing Operations
Analysis of adjusted effective tax rate ($m) Adjusted Profit/(loss) Tax Adjusted
before tax
(expense)/credit
Effective tax rate
Ghana 1H 2025 111.5 (41.4) 37.2%
1H 2024 411.5 (144.7) 35.2%
Corporate 1H 2025 (110.3) 0.2 0.2%
1H 2024 (164.9) (0.6) (0.4%)
Other non-operated & exploration 1H 2025 (0.6) (2.1) (347.0%)
1H 2024 4.9 (2.6) 52.6%
Total 1H 2025 0.6 (43.3) 7,088.6%
1H 2024 251.5 (147.9) 58.8%
Detailed analysis of ETR - Discontinued Operations
Analysis of adjusted effective tax rate ($m) Adjusted Profit/(loss) Tax Adjusted
before tax
(expense)/credit
Effective tax rate
Gabon 1H 2025 52.9 (27.4) 51.8%
1H 2024 80.0 (23.5) 29.3%
Adjusted EBITDAX
Adjusted EBITDAX for the year was $768 million (1H 2024: $1,083 million). The
decrease in the period was mainly driven by lower revenue.
(Loss)/Profit for the year from continuing activities and (loss)/earnings per share
The loss for the year after tax from continuing activities amounted to $80
million (1H 2024: $106 million profit). The loss after tax was driven mainly
by lower revenue, higher impairment charge and restructuring costs, offset by
lower income tax expense in the current year. Basic loss per share was 5.5
cents (1H 2024: 7.3 cents earnings per share).
Balance Sheet and Liquidity management
Key metrics 1H 2025 1H 2024
Capital investment ($m)(1) 103 157
Derivative financial instruments ($m) (4) (32)
Borrowings ($m) (1,808) (1,980)
Underlying operating cash flow ($m) (1) 34 169
Free cash flow ($m)(1) (188) (126)
Net debt ($m)(1) 1,640 1,735
Gearing (times)(1,2) 2.1 1.6
1. Alternative performance measures are reconciled on pages 38 to 40.
2. Gearing presented above excludes discontinued operations in Gabon.
Capital Investment
Capital expenditure amounted to $103 million (1H 2024: $157 million) out of
which $100 million was invested in production and development activities with
a $63 million spend in Ghana (1H 2024: $117 million), $24 million in Gabon (1H
2024: $25 million), $11 million in Cote d'Ivoire (1H 2024: $5 million) and $2
million in Kenya (1H 2024: $4 million). $53 million of capital investment
related to Jubilee (1H 2024: $108 million), mainly comprising $34 million of
drilling costs (1H 2024: $96 million). Investment in exploration and appraisal
activities was $3 million (1H 2024: $6 million).
The Group's 2025 capital expenditure guidance excluding Gabon is c.$185
million which will comprise Ghana of c.$160 million, Cote d'Ivoire of c.$15
million, Kenya and exploration spend of c.$10 million.
Decommissioning
Decommissioning expenditure was $1 million in the first half of 2025 (1H 2024:
$9 million), and $12 million of cash provisioning for future decommissioning
in Ghana (1H 2024: $nil). The Group's decommissioning guidance for 2025 is
revised to c.$20 million, with expenditure in the second half of the year
relating to the UK and Mauritania.
Derivative financial instruments
Tullow 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 30 June 2025, Tullow's hedge portfolio provides downside protection for
c.70% of forecast production entitlements in the second half of 2025 with
c.$60/bbl weighted average floors across all hedging instruments; for the same
period, c.20% of forecast production entitlements is capped at weighted
average sold calls of c.$89/bbl. A second tier of capped upside exists through
three-way collars on c.25% of the total hedged volume with weighted average
sold calls of $84/bbl, however, potential hedging losses on three-way collars
are limited to a $10/bbl range due to the presence of purchased calls,
allowing re-participation in the upside if oil prices rise above $94/bbl on a
weighted average basis. Hedging ratios reflect the portfolio post-Gabon asset
sale.
For 1H 2026, Tullow's hedge portfolio provides downside protection for c.15%
of forecast production entitlements with c.$57/bbl weighted average floors,
while c.10% is capped predominately with collars with weighted average sold
calls at c.$76/bbl.
No hedges were in place for 2H 2026 as at 30 June 2025. All financial
instruments that are initially recognised and subsequently measured at fair
value have been classified in accordance with the hierarchy described in IFRS
13 Fair Value Measurement. Fair value is the amount for which the asset or
liability could be exchanged in an arm's length transaction at the relevant
date. Where available, fair values are determined using quoted prices in
active markets (Level 1). To the extent that market prices are not available,
fair values are estimated by reference to market-based transactions or using
standard valuation techniques for the applicable instruments and commodities
involved (Level 2).
All of the Group's derivatives are Level 2 (2024: Level 2). There were no
transfers between fair value levels during the year.
At 30 June 2025, the Group's derivative instruments had a net negative fair
value of $4 million (1H 2024: net negative $32 million).
The following table demonstrates the timing, volumes and prices of the Group's
commodity hedge portfolio at 30 June 2025:
2H 2025 Portfolio Breakdown bopd Bought put Sold call Bought call
Straight puts 4,500 $59.94 - -
Collars 7,000 $60.00 $89.05 -
Three-way collars 12,500 $59.20 $83.64 $93.64
Total/Weighted Average 24,000 $59.57 $85.58 $93.64
1H 2026 Portfolio Breakdown bopd Bought put Sold call Bought call
Straight puts 250 $57.00 - -
Collars 3,000 $57.17 $75.67 -
Three-way collars 174 $57.85 $76.30 $86.30
Total/Weighted Average 3,424 $57.19 $75.70 $86.30
Borrowings
On 1 March 2025, the Group repaid in full its Senior Notes. The principal
repayment of $493 million and accrued interest to maturity were funded from a
combination of drawing down the remaining balance of $270 million under the
Glencore Facility and cash on balance sheet.
On 29 April 2025, the Group made a drawdown under its Revolving Credit
Facility (RCF) to manage near-term working capital.
On 15 May 2025, the Group made the annual prepayment of $100 million of the
Senior Secured Notes due 2026.
On 21 May 2025, the Group entered into an extension of its RCF to 31 October
2025 at reduced commitments of $150 million. On 29 July 2025, the Group repaid
and cancelled in full the $150 million RCF, see note 24.
As at 30 June 2025, the Group's total drawn debt reduced to $1,835 million,
consisting of $1,285 million nominal value Senior Secured Notes due in May
2026, $400 million outstanding under the Glencore facility and $150 million
outstanding under the RCF.
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).
On 17 April 2025, S&P revised the Group's corporate credit rating and the
rating of the 2026 Notes to CCC+ with negative outlook from B-.
On 13 May 2025, Moody's revised the Group's corporate credit rating and the
rating of the 2026 Notes to Caa2 with negative outlook from Caa1.
Underlying Operating Cash Flow and Free Cash Flow
Underlying operating cash flow amounted to $34 million (1H 2024: $169
million). This decrease was primarily driven by a $263 million decline in cash
revenue due to lower sales volumes and reduced oil prices, and higher cash
operating costs and working capital of $78 million. This was offset by $201
million lower cash taxes in the current period.
Free cash flow has decreased to $(188) million (1H 2024: $(126) million)
primarily due to the decrease in underlying operating cash flow of $136
million as explained above. There was also contribution to decommissioning
escrow fund of $12 million in the current period. The decrease was partially
offset by a reduction in net cash used in investing activities of $62 million
and reduced lease payments related to capital activities of $22 million.
Net Debt and Gearing
Reconciliation of net debt $m
FY 2024 net debt 1,452
Sales revenue (524)
Operating costs 142
Other operating and administrative expenses 43
Operating cash flow before working capital movements (339)
Movement in working capital 151
Tax paid 103
Purchases of intangible exploration and evaluation assets and property, plant 96
and equipment
Other investing activities (7)
Other financing activities 176
Debt arrangement fees 2
Foreign exchange loss on cash 6
1H 2025 net debt 1,640
1. Balances above are presented including discontinued operations in
Gabon.
Net debt increased by $188 million during the period to $1,640 million as at
30 June 2025 (FY 2024: $1,452 million), consisting of $1,285 million Senior
Secured Notes due 2026, $150 million Super Senior Revolving Credit Facility
and $400 million Secured Notes Facility, less cash and cash equivalents.
The Gearing ratio has increased to 2.1 times (1H 2024: 1.6 times) due to a
decrease in Adjusted EBITDAX from lower revenue in the current period as
explained above.
Ghana tax assessments
Tullow has two ongoing disputed tax assessments that relate to the
disallowance of loan interest deductions for the fiscal years 2010 - 2020 and
proceeds received by Tullow Oil plc under Tullow's corporate Business
Interruption Insurance policy. Both were referred to international arbitration
in 2023, with first hearings scheduled for 2025. The parties have agreed a
procedural timetable for the loan interest arbitration under which the first
Tribunal hearing was due to have been held in the week commencing 30th June
2025. This was postponed to allow more time to continue settlement
negotiations. The hearing on the Business Interruption Insurance proceeds
remains scheduled for November 2025. Tullow continues 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 consider the going concern assessment period to be up to 30
September 2026. The Group closely monitors and manages its liquidity headroom.
Cash forecasts are regularly produced, and sensitivities run for different
scenarios covering key judgements and assumptions including, but not limited
to, changes in commodity prices, different production rates from the Group's
producing assets and different outcomes on ongoing disputes or litigations and
the timing of any associated cash outflows.
Management has applied the following oil price assumptions for the going
concern assessment based on forward prices and market forecasts:
Base Case: $66/bbl for 2025; $65/bbl for 2026.
Low Case: $60/bbl for 2025; $60/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 tested by including a 10%
production decrease and a 5% increase in operating costs compared to the Base
Case. Management has also considered additional outflows in respect of all
ongoing disputes and litigations within the Low Case, with an additional $68
million outflow included for the cases expected to progress in the going
concern period. Based on the legal opinions received by management, the
remaining disputes and litigations are not expected to conclude within the
going concern period or have remote outcomes, therefore no outflows have been
included in that respect in the Low Case. In the event of negative outcomes
after the going concern period, management would use all available court
processes to appeal such rulings which, based on observable court timelines,
would likely take in excess of a further year.
The Group is reliant on the continued provision of external financing. The
c.$1.3 billion 2026 Notes fall due within the going concern period in May 2026
and 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, consisting of c.$1.3
billion 2026 Notes and a $400m Secured Notes Facility, in advance of this
date. The $150 million RCF facility was repaid and cancelled in full on 29
July 2025.
A fundamental assumption in concluding that the Group is a going concern is a
successful execution of a holistic refinancing in advance of the 2026 Notes
falling due for payment. Management is evaluating a range of refinancing
options and is in ongoing discussions with banks, commodity traders and other
private sources of funding to secure financial commitments towards the
refinancing, supported by the underlying value of the Group's assets and cash
generation from the Group's producing fields to support future debt service
and repayment. Completion of the Gabon sale transaction and associated receipt
of $307 million proceeds on 29 July 2025 has materially reduced the Group's
net debt and reduced the risk associated with the holistic debt refinancing.
The successful execution of a holistic refinancing is subject to agreement of
terms with a range of stakeholders including bondholders and 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 sale and purchase agreement for the sale of Tullow Kenya BV,
which holds Tullow's entire working interests in Kenya, for a total
consideration of at least $120 million has been entered into with Auron Energy
E&P Limited, an affiliate of Gulf Energy Limited. Completion of the
transaction, which is subject to regulatory approvals, and receipt of a $40
million completion payment are assumed in Q3 2025, with a further $40 million
payment due on approval of a field development plan assumed in Q4 2025 in the
Base Case; in the Low Case, receipt of the second $40 million instalment
payment is assumed in June 2026. Completion of this transaction and associated
payments due on completion and field development plan approval will further
reduce the Group's net debt and are therefore expected to reduce the risk
associated with the holistic debt refinancing.
Implications and material uncertainty
The Base Case and the Low Case scenarios forecast a liquidity shortfall in May
2026 when the c.$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. The completion of the sale of Tullow Oil Gabon SA has
removed the material uncertainty in relation to obtaining sufficient liquidity
to cover the expiration of the RCF at the end of June 2025 which had been
identified at year-end 2024.
The Directors have initiated a process to execute a holistic refinancing
following discussions with banks, commodity traders and other private sources
of funding. The Directors believe this is achievable before May 2026, noting
the risks associated with wider market conditions and agreement on terms with
a range of stakeholders including bondholders.
The Directors note that despite expressions of interest from private as well
as public parties for participation in the holistic refinancing, executing a
holistic refinancing is outside the control of the Group. If the Directors
were unable to execute a holistic refinancing, 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 executing a holistic refinancing of the
Group's debt capital structure by May 2026 at the latest is outside the
control of the Group. This is therefore a material uncertainty that may cast
significant doubt over the Group's ability to continue as a going concern.
Notwithstanding this material uncertainty, the Board has confidence in the
Group's ability to execute a holistic refinancing by May 2026. This is based
on the plans in place to execute a holistic refinancing and ongoing
discussions with banks, traders, and other private sources of funding which
are supported by the underlying value of the Group's assets and cash
generation from 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 was unable to continue as a going
concern.
2025 principal risks and uncertainties
The Company risk profile has been closely monitored throughout the year, with
consideration given to the risks to delivering the Business Plan, as well as
whether external factors such as geo-political factors, global pandemics and
oil price volatility have resulted in any new risks or changes to existing
risks. The impact of these factors has been considered and managed across all
principal risks. The Directors have reviewed the principal risks and
uncertainties facing the Company and concluded that for the remaining six
months of the financial year are substantially unchanged from those disclosed
in the 2024 Annual Report and are listed below.
1. Business plan not delivered
2. Asset integrity breach
3. Value not unlocked
4. Geopolitical risk
5. Climate change
6. Major accident event
7. Insufficient liquidity and funding capacity to sustain business
8. Capability cannot be attracted, developed or retained
9. Compliance or regulatory breach
10. Major cyber-disruption
The detailed descriptions of the principal risks and how they are being
managed can be found on pages 54 to 58 in the 2024 Annual Report and Accounts.
Events since 30 June 2025
On 21 July 2025, Tullow announced that it had signed a sale and purchase
agreement with Auron Energy E&P Limited, an affiliate of Gulf Energy
Limited, for the sale and purchase of 100% of the shares in Tullow Kenya BV
(refer to note 10 for the details of the transaction).
On 29 July 2025, following satisfaction of all conditions precedent under the
sale and purchase agreement, Tullow completed the sale of its 100% interest in
Tullow Oil Gabon SA, which holds all of Tullow's non-operated working
interests in Gabon (discussed in note 10 Held for sale and discontinued
operations), to the Gabon Oil Company for a total cash consideration of $307
million, net of tax and customary adjustments. This is a non-adjusting event
as at 30 June 2025 under IAS 10 Events after the Reporting Period. The
financial impact of the disposal cannot be disclosed in the 2025 half-year
results as completion accounting is still underway, and the relevant
disclosures will be made in the Group's 2025 annual financial statements. The
transaction is subject to a capital gains tax of $52 million as agreed with
the Gabon Tax Authority, which will be paid by Gabon Oil Company. On
completion, this will be recorded as an income tax expense with a
corresponding pre-tax gain on disposal and no deferred tax recognised.
On 29 July 2025, the RCF of $150 million was repaid and cancelled in full.
There have not been any other events since 30 June 2025 that have resulted in
a material impact on the half-year results.
Responsibility statement
(DTR 4.2 and the Transparency (Directive 2004/109/EC) Regulations (as amended))
The Directors confirm that to the best of their knowledge:
a. the condensed set of financial statements has been prepared in
accordance with IAS 34 Interim Financial Reporting as adopted by the UK and EU
and IAS 34 Interim Financial Reporting as adopted by the EU, the Disclosure
Guidance and Transparency Rules of the United Kingdom's Financial Conduct
Authority (DTR) and the Transparency (Directive 2004/109/EC) Regulations 2007
as amended
b. the interim management report includes a fair review of the
information required by DTR 4.2.7R and Regulation 8(2) (indication of
important events during the first six months and description of principal
risks and uncertainties for the remaining six months of the year); and
c. the interim management report includes a true and fair review of
the information required by DTR 4.2.8R and Regulation 8(3) (disclosure of
related parties' transactions and changes therein).
A list of the current Directors is maintained on the Tullow Oil plc website:
www.tullowoil.com.
By order of the Board,
Phuthuma Nhleko
Richard Miller
Chair
Chief Financial Officer and Interim Chief Executive Officer
5 August 2025
5 August 2025
Disclaimer
This statement contains certain forward-looking statements that are subject to
the usual risk factors and uncertainties associated with the oil and gas
exploration and production business. Whilst the Group believes the
expectations reflected herein to be reasonable in light of the information
available to them at this time, the actual outcome may be materially different
owing to factors beyond the Group's control or within the Group's control
where, for example, the Group decides on a change of plan or strategy.
Accordingly, no reliance may be placed on the figures contained in such
forward-looking statements.
Independent review report to Tullow Oil plc
Conclusion
We have been engaged by the Company to review the condensed set of financial
statements in the half-yearly financial report for the six months ended 30
June 2025 which comprises the Condensed consolidated income statement,
Condensed consolidated statement of comprehensive income and expense,
Condensed consolidated balance sheet, Condensed consolidated statement of
changes in equity, Condensed consolidated cash flow statement and the related
notes 1 to 25. We have read the other information contained in the half yearly
financial report and considered whether it contains any apparent misstatements
or material inconsistencies with the information in the condensed set of
financial statements.
Based on our review, nothing has come to our attention that causes us to
believe that the condensed set of financial statements in the half-yearly
financial report for the six months ended 30 June 2025 is not prepared, in all
material respects, in accordance with UK adopted International Accounting
Standard 34 and the Disclosure Guidance and Transparency Rules of the United
Kingdom's Financial Conduct Authority.
Basis for Conclusion
We conducted our review in accordance with the International Standard on
Review Engagements 2410 (UK) "Review of Interim Financial Information
Performed by the Independent Auditor of the Entity" (ISRE) issued by the
Financial Reporting Council. A review of interim financial information
consists of making enquiries, primarily of persons responsible for financial
and accounting matters, and applying analytical and other review procedures. A
review is substantially less in scope than an audit conducted in accordance
with International Standards on Auditing (UK) and consequently does not enable
us to obtain assurance that we would become aware of all significant matters
that might be identified in an audit. Accordingly, we do not express an audit
opinion.
As disclosed in note 2, the annual financial statements of the Group are
prepared in accordance with UK adopted international accounting standards. The
condensed set of financial statements included in this half-yearly financial
report has been prepared in accordance with UK adopted International
Accounting Standard 34, "Interim Financial Reporting".
Material Uncertainty Related to Going Concern
Based on our review procedures, which are less extensive than those performed
in an audit as described in the Basis for Conclusion section of this report,
we draw attention to note 2 in the condensed set of financial statements,
which indicates that the Group is forecasting a liquidity shortfall in May
2026 when the $1.3 billion 2026 Notes become due for payment, and that the
implementation of a holistic refinancing of the Group's debt capital structure
in advance of this date is outside the control of the Group.
As stated in note 2, these events or conditions, along with the other matters
as set forth in note 2, indicate that a material uncertainty exists that may
cast significant doubt on the Group's ability to continue as a going concern.
Our conclusion is not modified in respect of this matter.
The responsibilities of the directors with respect to going concern are
described in the relevant section of this report.
Responsibilities of the directors
The directors are responsible for preparing the half-yearly financial report
in accordance with the Disclosure Guidance and Transparency Rules of the
United Kingdom's Financial Conduct Authority.
In preparing the half-yearly financial report, the directors are responsible
for assessing the company's ability to continue as a going concern,
disclosing, as applicable, matters related to going concern (including the
Material Uncertainty set out in note 2) and using the going concern basis of
accounting unless the directors either intend to liquidate the company or to
cease operations, or have no realistic alternative but to do so.
Auditor's Responsibilities for the review of the financial information
In reviewing the half-yearly report, we are responsible for expressing to the
Company a conclusion on the condensed set of financial statements in the
half-yearly financial report. Our conclusion, including the Material
Uncertainty related to going concern, are based on procedures that are less
extensive than audit procedures, as described in the Basis for Conclusion
paragraph of this report.
Use of our report
This report is made solely to the company in accordance with guidance
contained in International Standard on Review Engagements 2410 (UK) "Review of
Interim Financial Information Performed by the Independent Auditor of the
Entity" issued by the Financial Reporting Council. To the fullest extent
permitted by law, we do not accept or assume responsibility to anyone other
than the company, for our work, for this report, or for the conclusions we
have formed.
Ernst & Young LLP
London
5 August 2025
Condensed consolidated income statement
Six months ended 30 June 2025
$m Notes Six months ended 30.06.25 Six months ended 30.06.24 Year ended 31.12.24
Unaudited
Unaudited Restated(1)
Audited Restated(1)
Continuing operations
Revenue 7 410.6 665.5 1,287.2
Other operating income - insurance proceeds 4.2 - -
Cost of sales 8 (249.6) (278.4) (652.5)
Gross profit 165.2 387.1 634.7
Administrative expenses 8 (23.2) (30.5) (52.2)
Restructuring provisions 8 (10.6) - (7.1)
Expected credit loss charge on trade receivables 15 (1.9) - (6.6)
Exploration costs written off 12 (1.0) (3.1) (202.3)
(Impairment)/Impairment reversal of property, plant and equipment, net 13 (39.1) 1.7 11.8
Provisions reversal 8 - 39.4 70.4
Operating profit 89.4 394.6 448.7
Finance income 9 29.1 36.6 69.2
Finance costs 9 (168.4) (176.9) (344.2)
(Loss)/profit from continuing operations before tax (49.9) 254.3 173.7
Income tax expense 11 (30.5) (148.1) (228.7)
(Loss)/profit for the period from continuing operations (80.4) 106.2 (55.0)
Discontinued operations
Profit after tax from discontinued operations 10 19.7 89.8 109.6
(Loss)/profit for the period (60.7) 196.0 54.6
Attributable to
Owners of the Company (60.7) 196.0 54.6
(Loss)/earnings per ordinary share ¢ ¢ ¢
Basic (4.2) 13.5 3.7
Diluted (4.2) 12.9 3.6
(Loss)/earnings per ordinary share from continuing operations ¢ ¢ ¢
Basic (5.5) 7.3 (3.8)
Diluted (5.5) 7.0 (3.8)
1. Comparative balances have been restated to present
Gabon as a discontinued operation. Refer to note 10.
2.
Condensed consolidated statement of comprehensive income and expense
Six months ended 30 June 2025
$m Six months ended 30.06.25 Six months ended 30.06.24 Unaudited Year ended 31.12.24
Unaudited
Audited
(Loss)/profit for the period (60.7) 196.0 54.6
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
Losses arising in the period - (33.0) (28.5)
Losses arising in the period - time value (1.7) (24.5) (21.9)
Reclassification adjustments for items included in profit on realisation - 45.6 47.5
Reclassification adjustments for items included in loss on realisation - time 9.7 14.7 26.1
value
Exchange differences on translation of foreign operations (8.0) 1.6 2.0
Net other comprehensive income for the period - 4.4 25.2
Total comprehensive (expense)/income for the period (60.7) 200.4 79.8
Attributable to
Owners of the Company (60.7) 200.4 79.8
Condensed consolidated balance sheet
As at 30 June 2025
$m Notes Six months ended 30.06.25 Six months ended 30.06.24 Year ended 31.12.24
Unaudited
Unaudited
Audited
Assets
Non-current asset
Goodwill 14 - 44.9 44.9
Intangible exploration and evaluation assets 12 0.3 295.6 109.1
Property, plant and equipment 13 2,018.2 2,515.1 2,324.1
Other non-current assets 16 303.7 303.5 340.8
Deferred tax assets 2.7 17.0 8.3
2,324.9 3,176.1 2,827.2
Current assets
Inventories 17 107.2 178.1 132.4
Trade receivables 15 106.1 91.6 137.9
Other current assets 16 454.3 476.1 391.9
Current tax assets 8.1 16.9 6.9
Derivative financial instruments - - 0.1
Cash and cash equivalents 18 194.1 272.6 555.1
Assets classified as held for sale 10 410.4 - -
1,280.2 1,035.3 1,224.3
Total assets 3,605.1 4,211.4 4,051.5
Liabilities
Current liabilities
Trade and other payables 19 (597.5) (667.0) (736.5)
Borrowings 20 (1,426.4) (589.2) (589.4)
Provisions 21 (40.5) (82.3) (24.3)
Current tax liabilities (109.8) (107.4) (175.3)
Derivative financial instruments (3.8) (29.9) (11.9)
Liabilities associated with assets classified as held for sale 10 (133.1) - -
(2,311.1) (1,475.8) (1,537.4)
Non-current liabilities
Trade and other payables 19 (598.1) (712.9) (665.9)
Borrowings 20 (381.9) (1,390.3) (1,386.4)
Provisions 21 (287.1) (328.2) (321.5)
Deferred tax liabilities (356.6) (458.4) (413.0)
Derivative financial instruments - (2.4) -
(1,623.7) (2,892.2) (2,786.8)
Total liabilities (3,934.8) (4,368.0) (4,324.2)
Net liabilities (329.7) (156.6) (272.7)
Equity
Called-up share capital 22 217.9 217.4 217.5
Share premium 22 1,294.7 1,294.7 1,294.7
Foreign currency translation reserve (250.4) (242.8) (242.4)
Hedge reserve 0.1 (6.3) 0.1
Hedge reserve - time value (4.1) (26.1) (12.1)
Merger reserve 755.2 755.2 755.2
Retained earnings (2,343.1) (2,148.7) (2,285.7)
Equity attributable to equity holders of the Company (329.7) (156.6) (272.7)
Total equity (329.7) (156.6) (272.7)
Condensed consolidated statement of changes in equity
Six months ended 30 June 2025
$m Share Share Foreign currency translation reserve¹ Hedge Hedge Merger reserves(3) Retained earnings Total
capital
premium
reserve²
reserve - time
value²
At 1 January 2024 216.7 1,294.7 (244.4) (18.9) (16.3) 755.2 (2,346.4) (359.4)
Profit for the period - - - - - - 196.0 196.0
Hedges, net of tax - - - 12.6 (9.8) - - 2.8
Currency translation adjustments - - 1.6 - - - - 1.6
Total comprehensive income - - 1.6 12.6 (9.8) - 196.0 200.4
Exercise of employee share options 0.7 - - - - - (0.7) -
Share-based payment charges - - - - - - 2.4 2.4
At 30 June 2024 217.4 1,294.7 (242.8) (6.3) (26.1) 755.2 (2,148.7) (156.6)
Loss for the period - - - - - - (141.4) (141.4)
Hedges, net of tax - - - 6.4 14.0 - - 20.4
Currency translation adjustments - - 0.4 - - - - 0.4
Total comprehensive income - - 0.4 6.4 14.0 - (141.4) (120.6)
Exercise of employee share options 0.1 - - - - - (0.1) -
Share-based payment charges - - - - - - 4.5 4.5
At 1 January 2025 217.5 1,294.7 (242.4) 0.1 (12.1) 755.2 (2,285.7) (272.7)
Loss for the period - - - - - - (60.7) (60.7)
Hedges, net of tax - - - - 8.0 - - 8.0
Currency translation adjustments - - (8.0) - - - - (8.0)
Total comprehensive income - - - - - - (60.7) (60.7)
Exercise of employee share options 0.4 - - - - - (0.4) -
Share-based payment charges - - - - - - 3.7 3.7
At 30 June 2025 217.9 1,294.7 (250.4) 0.1 (4.1) 755.2 (2,343.1) (329.7)
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.
Condensed consolidated cash flow statement
Six months ended 30 June 2025
$m Notes Six months ended 30.06.25 Unaudited Six months ended 30.06.24 Year ended
Unaudited
31.12.24
Audited
Cash flows from operating activities
(Loss)/profit before tax from continuing operations (49.9) 254.3 173.7
Profit before tax from discontinued operations 10 47.1 113.3 147.8
(Loss)/profit before tax (2.8) 367.6 321.5
Adjustments for:
Depreciation, depletion and amortisation 13 161.1 199.7 444.2
Asset revaluation 14 - (38.9) (38.9)
Taxes paid in kind 11 (3.8) (5.9) (6.3)
Exploration costs written off 12 6.7 3.1 212.6
Impairment/impairment (reversal) of property, plant and equipment, net 13 39.1 (1.7) (11.8)
Provisions expense/(reversal), net 10.6 (39.4) (63.3)
Payment for provisions 21 (4.3) (0.6) (0.7)
Decommissioning expenditure (9.7) (9.9) (45.0)
Share-based payment charge 3.7 2.4 6.9
Finance income 9,10 (30.4) (39.7) (71.5)
Finance costs 9,10 169.2 177.7 345.6
Operating cash flow before working capital movements 339.4 614.4 1,093.3
(Increase)/decrease in trade and other receivables (51.0) 33.0 0.7
Decrease/(increase) in inventories 7.2 (70.9) (25.1)
(Decrease)/increase in trade payables (107.5) (37.6) 49.9
Cash generated from operating activities 188.1 538.9 1,118.8
Income taxes paid (103.1) (307.5) (360.3)
Net cash from operating activities 85.0 231.4 758.5
Cash flows from investing activities
Purchase of additional interests in a joint operation 14 - (8.1) (8.1)
Purchase of intangible exploration and evaluation assets (5.6) (12.8) (27.8)
Purchase of property, plant and equipment (90.1) (139.5) (196.7)
Interest received 7.2 10.2 19.5
Net cash used in investing activities (88.5) (150.2) (213.1)
Cash flows from financing activities
Debt arrangement fees (2.3) - -
Repayment of borrowings 25 (592.5) (100.0) (100.0)
Drawdown of borrowings 25 420.3 - -
Payment of obligations under leases (72.5) (93.9) (169.0)
Finance costs paid (103.1) (116.3) (223.2)
Net cash used in financing activities (350.1) (310.2) (492.2)
Net (decrease)/increase in cash and cash equivalents (353.6) (229.0) 53.2
Cash and cash equivalents at beginning of period 555.1 499.0 499.0
Foreign exchange (loss)/gain (6.2) 2.6 2.9
Cash and cash equivalents at end of period(1) 195.3 272.6 555.1
1. $1.2 million of cash balances at 30 June 2025 is included in assets held
for sale (refer to note 10).
Notes to the financial statements
Six months ended 30 June 2025
1. General information
The condensed financial statements for the six-month period ended 30 June 2025
have been prepared in accordance with International Accounting Standard (IAS)
34 Interim Financial Reporting as adopted by UK and EU and the requirements of
the Disclosure and Transparency Rules (DTR) of the Financial Conduct Authority
(FCA) in the United Kingdom as applicable to interim financial reporting.
The Condensed financial statements represent a 'condensed set of financial
statements' as referred to in the DTR issued by the FCA. Accordingly, they do
not include all the information required for a full annual financial report
and are to be read in conjunction with the Group's financial statements for
the year ended 31 December 2024, which were prepared in accordance with
UK-adopted international accounting standards (IFRSs) and International
Financial Reporting Standards (IFRSs) adopted pursuant to Regulation (EC) No
1606/2002 as it applies in the European Union (EU). The Condensed financial
statements are unaudited and do not constitute statutory accounts as defined
in section 434 of the Companies Act 2006. The financial information for the
year ended 31 December 2024 does not constitute statutory accounts as defined
in section 434 of the Companies Act 2006. This information was derived from
the statutory accounts for the year ended 31 December 2024, a copy of which
has been delivered to the Registrar of Companies. The Independent auditor's
report on these accounts was unqualified, with emphasis of matter relating to
material uncertainties with regards to going concern and did not contain a
statement under sections 498 (2) or (3) of the Companies Act 2006.
2. Accounting policies
The annual financial statements of Tullow Oil plc will be 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 condensed set of financial statements included in this
half-yearly financial report has been prepared in accordance with
International Accounting Standard (IAS) 34 Interim Financial Reporting as
adopted by UK and EU, the Disclosure and Transparency Rules of the Financial
Conduct Authority and the Transparency (Directive 2004/109/EC) Regulations
2007 as amended.
The significant accounting policies adopted in the 2025 half-yearly financial
report are the same as those adopted in the Group's Annual Report and Accounts
as at 31 December 2024.
Liquidity risk management and going concern
The Directors consider the going concern assessment period to be up to 30
September 2026. The Group closely monitors and manages its liquidity headroom.
Cash forecasts are regularly produced, and sensitivities run for different
scenarios covering key judgements and assumptions including, but not limited
to, changes in commodity prices, different production rates from the Group's
producing assets and different outcomes on ongoing disputes or litigations and
the timing of any associated cash outflows.
Management has applied the following oil price assumptions for the going
concern assessment based on forward prices and market forecasts:
Base Case: $66/bbl for 2025; $65/bbl for 2026.
Low Case: $60/bbl for 2025; $60/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 tested by including a 10%
production decrease and a 5% increase in operating costs compared to the Base
Case. Management has also considered additional outflows in respect of all
ongoing disputes and litigations within the Low Case, with an additional $68
million outflow included for the cases expected to progress in the going
concern period. Based on the legal opinions received by management, the
remaining disputes and litigations are not expected to conclude within the
going concern period or have remote outcomes, therefore no outflows have been
included in that respect in the Low Case. In the event of negative outcomes
after the going concern period, management would use all available court
processes to appeal such rulings which, based on observable court timelines,
would likely take in excess of a further year.
The Group is reliant on the continued provision of external financing. The
c.$1.3 billion 2026 Notes fall due within the going concern period in May 2026
and 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, consisting of c.$1.3
billion 2026 Notes and a $400m Secured Notes Facility, in advance of this
date. The $150 million RCF facility was repaid and cancelled in full on 29
July 2025.
A fundamental assumption in concluding that the Group is a going concern is a
successful execution of a holistic refinancing in advance of the 2026 Notes
falling due for payment. Management is evaluating a range of refinancing
options and is in ongoing discussions with banks, commodity traders and other
private sources of funding to secure financial commitments towards the
refinancing, supported by the underlying value of group's assets and cash
generation from the Group's producing fields to support future debt service
and repayment. Completion of the Gabon sale transaction and associated receipt
of $307 million proceeds on 29 July 2025 has materially reduced the Group's
net debt and reduced the risk associated with the holistic debt refinancing.
The successful execution of a holistic refinancing is subject to agreement of
terms with a range of stakeholders including bondholders and 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 sale and purchase agreement for the sale of Tullow Kenya BV,
which holds Tullow's entire working interests in Kenya, for a total
consideration of at least $120 million has been entered into with Auron Energy
E&P Limited, an affiliate of Gulf Energy Limited. Completion of the
transaction, which is subject to regulatory approvals, and receipt of a $40
million completion payment are assumed in Q3 2025, with a further $40 million
payment due on approval of a field development plan assumed in Q4 2025 in the
Base Case; in the Low Case, receipt of the second $40 million instalment
payment is assumed in June 2026. Completion of this transaction and associated
payments due on completion and field development plan approval will further
reduce the Group's net debt and are therefore expected to reduce the risk
associated with the holistic debt refinancing.
Implications and material uncertainty
The Base Case and the Low Case scenarios forecast a liquidity shortfall in May
2026 when the c.$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. The completion of the sale of Tullow Oil Gabon SA has
removed the material uncertainty in relation to obtaining sufficient liquidity
to cover the expiration of the RCF at the end of June 2025 which had been
identified at year-end 2024.
The Directors have initiated a process to execute a holistic refinancing
following discussions with banks, commodity traders and other private sources
of funding. The Directors believe this is achievable before May 2026, noting
the risks associated with wider market conditions and agreement on terms with
a range of stakeholders including bondholders.
The Directors note that despite expressions of interest from private as well
as public parties for participation in the holistic refinancing, executing a
holistic refinancing is outside the control of the Group. If the Directors
were unable to execute a holistic refinancing, 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 executing a holistic refinancing of the
Group's debt capital structure by May 2026 at the latest is outside the
control of the Group. This is therefore a material uncertainty that may cast
significant doubt over the Group's ability to continue as a going concern.
Notwithstanding this material uncertainty, the Board has confidence in the
Group's ability to execute a holistic refinancing by May 2026. This is based
on the plans in place to execute a holistic refinancing and ongoing
discussions with banks, traders, and other private sources of funding which
are supported by the underlying value of the Group's assets and cash
generation from 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 was unable to continue as a going
concern.
3. (Loss)/earnings per share
The calculation of basic (loss)/earnings per share is based on the loss for
the period after taxation attributable to equity holders of the parent of
$60.7 million (1H 2024: profit of $196.0 million) and a weighted average
number of shares in issue of 1,460.2 million (1H 2024: 1,455.5 million).
The calculation of diluted (loss)/earnings per share is based on the
(loss)/profit for the period after taxation as for basic (loss)/earnings per
share. The number of shares outstanding, however, is adjusted to show the
potential dilution if employee share options are converted into ordinary
shares. The weighted average number of ordinary shares is increased by 77.5
million resulting in a diluted weighted average number of shares of 1,537.7
million (1H 2024: 1,521.6 million).
4. Dividends
The Directors intend to recommend that no 2025 interim dividend be paid.
5. Approval of Accounts
These unaudited half year results were approved by the Board of Directors on 5
August 2025.
6. Segmental Reporting
The information reported to the Group's 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 and profit information regarding the
Group's reportable business segments for the period ended 30 June 2025, 30
June 2024 and 31 December 2024.
$m Ghana Non-Operated(4) Kenya(5) Exploration Corporate Total
Six months ended 30 June 2025
Sales revenue by origin 402.8 17.5 - - (9.7) 410.6
Other operating income - - - - 4.2 4.2
Segment result(1) 145.2 (4.0) - (2.4) (13.7) 125.1
Unallocated corporate expenses(2) (35.7)
Operating profit 89.4
Finance income 29.1
Finance costs (168.4)
Loss before tax (49.9)
Income tax expense (30.5)
Loss after tax (80.4)
Total assets 2,989.4 321.4 115.0 4.6 174.7 3,605.1
Total liabilities(3) (1,808.9) (212.8) (6.0) (5.3) (1,901.8) (3,934.8)
Other segment information
Capital expenditure:
Property, plant and equipment 66.1 32.1 - - 0.1 98.3
Intangible exploration and evaluation assets - 0.4 3.1 1.0 - 4.5
Depletion, depreciation and amortization (155.4) (4.0) - - (1.7) (161.1)
Impairment of property, plant and equipment, net (35.0) (4.1) - - - (39.1)
Exploration costs written off - - - (1.0) - (1.0)
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 below.
2. Unallocated expenditure and 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.
4. Non-Operated excludes results attributable to
Gabon, which is classified as discontinued operations (refer to note 10).
5. Kenya has been classified as asset held for sale
(refer to note 10).
6. Segmental reporting continued
Reconciliation of segment result
$m Six months ended 30.06.25 Unaudited Six months ended 30.06.24 Unaudited Year ended 31.12.24 Audited
Segment result 125.1 385.7 444.2
Add back
Exploration costs written off 1.0 3.1 202.3
Impairment/(Impairment reversal) of property, plant and equipment, net 39.1 (1.7) (11.8)
Gross profit 165.2 387.1 634.7
$m Ghana Non-Operated(4) Kenya Exploration Corporate Total
Six months ended 30 June 2024
Sales revenue by origin 703.0 20.4 - - (57.9) 665.5
Segment result(1) 446.2 7.6 - (2.3) (65.8) 385.7
Other provisions 39.4
Unallocated corporate expenses(2) (30.6)
Operating profit 394.5
Finance income 36.6
Finance costs (176.9)
Profit before tax 254.2
Income tax expense (148.1)
Profit after tax 106.1
Total assets 3,346.3 341.7 255.8 50.7 216.9 4,211.4
Total liabilities(3) (1,981.8) (287.2) (7.2) (1.8) (2,090.0) (4,368.0)
Other segment information
Capital expenditure:
Property, plant and equipment 90.0 113.7 (0.4) - 2.4 205.7
Intangible exploration and evaluation assets 0.1 2.4 3.9 5.3 - 11.7
Depletion, depreciation and amortization (181.0) (17.4) - - (1.3) (199.7)
Impairment reversal of property, plant and equipment, net - 1.7 - - - 1.7
Exploration costs written off - (0.8) - (2.3) - (3.1)
1.Segment result is a non-IFRS measure which includes gross profit,
exploration costs written off and impairment of property, plant and equipment.
See reconciliation above.
2. Unallocated expenditure and 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.
4. Non-Operated balances have been restated to exclude results attributable to
Gabon, which is classified as discontinued operations (refer to note 10).
6. Segmental reporting continued
$m Ghana Non-Operated(4) Kenya Exploration Corporate Total
Year ended 31 December 2024
Sales revenue by origin 1,325.4 35.4 - - (73.6) 1,287.2
Segment result(1) 722.6 14.5 (145.4) (55.9) (91.6) 444.2
Provisions reversal 70.4
Unallocated corporate expenses(2) (65.9)
Operating profit 448.7
Finance income 69.2
Finance costs (344.2)
Profit before tax 173.7
Income tax expense (228.7)
Loss after tax (55.0)
Total assets 3,164.3 305.0 112.2 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 above.
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.
4. Non-Operated balances have been restated to exclude results attributable to
Gabon, which is classified as discontinued operations (refer to note 10).
6. Segmental reporting continued
$m Sales revenue six months ended 30.06.25 Sales revenue six months ended 30.06.24 Restated(2 ) Sales revenue Year ended 31.12.24 Restated(2) Non-current assets 30.06.25 Non-current assets 30.06.24 Non-current assets 31.12.24
Ghana 402.8 703.0 1,325.4 2,310.3 2,618.9 2,468.3
Total Ghana 402.8 703.0 1,325.4 2,310.3 2,618.9 2,468.3
Kenya(1) - - - - 254.4 110.9
Total Kenya - - - - 254.4 110.9
Argentina - - - - 37.8 -
Côte d'Ivoire - - - - 7.3 -
Total Exploration - - - - 45.1 -
Gabon(1) - - - - 227.7 228.4
Côte d'Ivoire 17.4 20.3 35.4 - - -
Total Non-Operated 17.4 20.3 35.4 - 227.7 228.4
Corporate (9.6) (57.8) (73.6) 11.9 13.0 11.3
Total 410.6 665.5 1,287.2 2,322.2 3,159.1 2,818.9
1. Non-current assets relating to Kenya and Gabon were
transferred to assets held for sale. Sales revenue generated in Gabon is
presented within discontinued operations (refer to note 10).
2. Sales revenue balances have been restated to
present Gabon as a discontinued operation. Refer to note 10.
Non-current assets exclude derivative financial instruments and deferred tax
assets.
7. Total revenue
$m Six months ended 30.06.25 Unaudited Six months ended 30.06.24 Unaudited Restated(1) Year ended 31.12.24 Audited Restated(1)
Revenue from contracts with customers
Revenue from crude oil sales 390.4 694.9 1,306.8
Revenue from gas sales 29.9 28.6 54.0
Total revenue from contracts with customers 420.3 723.5 1,360.8
Loss on realisation of cash flow hedges (9.7) (58.0) (73.6)
Total revenue 410.6 665.5 1,287.2
1. Revenue balances have been restated to present
Gabon as a discontinued operation. Refer to note 10.
Finance income has been presented as part of net financing costs (refer to
note 9).
8. Other costs
$m Six months ended 30.06.25 Unaudited Six months ended 30.06.24 Unaudited Restated(5) Year ended 31.12.24 Audited Restated(5)
Cost of sales
Operating costs 107.8 87.0 197.8
Depletion and amortisation of oil and gas and leased assets(1) 159.1 186.0 412.1
(Underlift), overlift and oil stock movements(2) (17.7) 5.4 42.1
Share-based payment charge included in cost of sales - - 0.4
Other cost of sales 0.4 - 0.1
Total cost of sales 249.6 278.4 652.5
Administrative expenses
Share-based payment charge included in administrative expenses 3.7 2.0 6.5
Depreciation of other fixed assets(1) 2.0 1.7 6.5
Other administrative costs 17.5 26.8 39.2
Total administrative expenses(3) 23.2 30.5 52.2
Provisions expense/(reversal)(4) 10.6 (39.4) (63.3)
1. Depreciation expense on leased assets of $38.0
million (1H 2024: $42.4 million; FY 2024: $91.4 million) as per note 13
includes a charge of $0.7 million (1H 2024: $0.7 million; FY 2024: $4.1
million) on leased administrative assets, which is presented within
administrative expenses in the income statement. The remaining balance of
$37.3 million (1H 2024: $41.7 million; FY 2024: $87.3 million) relates to
other leased assets and is included within cost of sales.
2. The change from overlift expense to underlift is
due to fewer liftings in Ghana in the current period resulting from lower oil
production volumes.
3. The decrease in other administrative costs is
mainly due to reduced employee related expenses and professional fees.
4. This includes provision for restructuring and
redundancy costs of $10.6 million (1H 2024: $nil; FY 2024: $7.1 million).
Prior periods include reductions in other provisions (1H 2024: $39.4 million;
FY 2024: $70.4 million).
5. Comparative balances have been restated to present
Gabon as a discontinued operation. Refer to note 10.
9. Net financing costs
$m Six months ended 30.06.25 Unaudited Six months ended 30.06.24 Unaudited Restated(1) Year ended 31.12.24 Audited Restated(1)
Interest on borrowings 108.5 108.0 211.5
Interest on obligations for leases 50.6 62.0 119.7
Total borrowing costs 159.1 170.0 331.2
Finance and arrangement fees 2.5 0.6 3.0
Other interest expense 1.2 1.3 -
Unwinding of discount on decommissioning provisions 5.6 5.0 10.0
Total finance costs 168.4 176.9 344.2
Interest income on amounts due from Joint Venture partners for leases (19.8) (24.6) (48.1)
Other finance income (9.3) (12.0) (21.1)
Total finance income (29.1) (36.6) (69.2)
Net financing costs 139.3 140.3 275.0
1.Comparative balances have been restated to present Gabon as a discontinued
operation. Refer to note 10.
10. Held for sale and discontinued operations
Gabon
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.
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. A sale and purchase agreement was signed on 13 May
2025. Completion of the transaction and receipt of funds occurred on 29 July
2025. Refer to note 24.
Management concluded that the disposal group met the IFRS 5 Held for Sale
criteria on 10 January 2025, when the Board of Directors approved the plan to
sell, and as such Tullow Oil Gabon SA has been classified as a disposal group
held for sale and as a discontinued operation for the period ended 30 June
2025. All assets and liabilities relating to the disposal group are presented
within the Non-Operated Business Unit for operating segment reporting.
The results of Tullow Oil Gabon SA for the period are presented below:
$m Six months ended Six months ended Year
30.06.25
30.06.24
ended
31.12.24
Discontinued operations
Revenue 113.1 93.3 247.7
Cost of sales (60.6) (20.8) (128.4)
Gross profit 52.5 72.5 119.3
Administrative expenses (0.2) (0.4) (1.0)
Asset revaluation - 38.9 38.9
Exploration costs written off (5.7) - (10.3)
Operating profit 46.6 111.0 146.9
Finance income 1.3 3.1 2.3
Finance costs (0.8) (0.8) (1.4)
Profit before tax from discontinued operations 47.1 113.3 147.8
Income tax expense (27.4) (23.5) (38.2)
Profit from discontinued operations 19.7 89.8 109.6
The major classes of assets and liabilities comprising the net assets
classified as held for sale as at 30 June 2025 are as follows:
$m 30.06.25
Assets
Goodwill 44.9
Intangible exploration and evaluation assets 6.0
Property, plant and equipment 200.8
Inventories 18.1
Trade receivables 24.3
Other current assets 0.6
Cash and cash equivalents 0.6
Assets classified as held for sale 295.3
Liabilities
Trade and other payables (29.9)
Current tax liabilities (16.3)
Provisions (33.6)
Deferred tax liabilities (47.3)
Liabilities directly associated with assets classified as held for sale (127.1)
Net assets directly associated with disposal group 168.2
10. Held for sale and discontinued operations continued
Gabon continued
The net cash flows generated/(incurred) by Tullow Oil Gabon SA are as follows:
$m Six months ended Six months ended Year
30.06.25
30.06.24
ended
31.12.24
Cash flows from operating activities (10.4) (61.3) 21.4
Cash flows from investing activities (25.2) (37.1) (45.7)
Cash flows from financing activities 38.1 99.8 22.2
Net cash inflow/(outflow) 2.5 1.4 (2.1)
Earnings per share from discontinued operations, ¢ Six months ended Six months ended Year
30.06.25
30.06.24
ended
31.12.24
Basic 1.3 6.2 7.5
Diluted 1.3 5.9 7.1
Kenya
On 15 April 2025, Tullow announced that it had signed a binding heads of terms
(HOTs) agreement with Gulf Energy Limited for the sale of Tullow Kenya BV,
which holds Tullow's entire working interest in Kenya, for a total
consideration of at least $120 million. The consideration will be split into a
$40 million payment due on completion (Tranche A), $40 million payable at the
earlier of Field Development Plan (FDP) approval or 30 June 2026 (Tranche B),
and $40 million payable over five years from the third quarter of 2028 onwards
(Tranche C). In addition, Tullow will be entitled to royalty payments subject
to certain conditions. Tullow also retains a back-in right for a 30%
participation in potential future development phases at no cost.
The sale and purchase agreement (SPA) was signed on 21 July 2025 and
completion of the transaction, satisfaction of conditions precedent and
receipt of funds from Tranche A and FDP approval (and consequent receipt of
funds from Tranche B) are expected in 2025. Management concluded that the
disposal group met the IFRS 5 Held for Sale criteria on 15 April 2025 when the
HOTs were signed. Tullow Kenya BV was not classified as a discontinued
operation for the period ended 30 June 2025 due to operations of the business
not being material to the Group.
The major classes of assets and liabilities comprising the net assets
classified as held for sale as at 30 June 2025 are as follows:
$m 30.06.25
Assets
Intangible exploration and evaluation assets 106.2
Other non-current assets 8.1
Other current assets 0.2
Cash and cash equivalents 0.6
Assets classified as held for sale 115.1
Liabilities
Trade and other payables (6.0)
Liabilities directly associated with assets classified as held for sale (6.0)
Net assets directly associated with disposal group 109.1
11. Taxation on profit on continuing activities
The overall net tax expense of $30 million (1H 2024: $148 million) primarily
relates to tax charges in respect of the Group's production activities in West
Africa, reduced by deferred tax credits associated with UK decommissioning
assets, exploration write-offs and impairments. The tax charge has been
calculated by applying the effective tax rate which is expected to apply to
each jurisdiction for the year ending 31 December 2025.
Based on a loss before tax for the first half of the year of $50 million (1H
2024: profit before tax of $254 million), the effective tax rate is (60.9)%
(1H 2024: 58.4%). After adjusting for the non-recurring amounts related to
exploration write-offs, impairments, disposals and their associated tax
benefit, the Group's underlying effective tax rate is 7,088.6% (1H 2024:
58.8%). In the UK, there is net interest and hedging expenses of $77 million
(1H 2024: $123 million), however there is no UK tax benefit as in previous
periods.
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 other 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 with significant updates described in more detail
below. 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.
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 unprovided liabilities of
$615.2 million (1H 2024: $1,037.7 million; FY 2024: $608.7 million) excluding
interest and penalties which in management's view are remote.
Provisions of $83.8 million (1H 2024: $86.2 million; FY 2024: $80.8 million)
are included in income tax payable of $79.3 million (1H 2024: $78.7 million;
FY 2024: $79.0 million) and provisions of $4.5 million (1H 2024: $7.5 million;
FY 2024: $1.8 million). Where these matters relate to expenditure which is
capitalised within Intangible Exploration and Evaluation Assets and Property,
Plant and Equipment, any difference between the amounts accrued and the
amounts settled is capitalised within 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's income statement.
The provisions and contingent liabilities relating to these disputes have
decreased following the conclusion of tax authority challenges and matters
lapsing under statutes of limitation, but have increased, following new claims
being initiated and extrapolation of exposures through to 30 June 2025, giving
rise to an overall increase in provision of $3.0 million and increase in
contingent liability of $6.5 million from 31 December 2024.
Ghana tax assessments
In December 2022, Tullow Ghana Limited (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 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.
Discussions between TGL and the GRA in respect of a negotiated settlement
continued throughout Q1 and Q2 2025. The parties have agreed a procedural
timetable for the loan interest arbitration under which the first Tribunal
hearing was due to have been held in the week commencing 30 June 2025. This
was postponed to allow more time to continue settlement negotiations. The
hearing on the Business Interruption Insurance proceeds remains scheduled for
November 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. Discussions between TGL and the GRA in
respect of a negotiated settlement continued throughout Q1 and Q2 2025. 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 all tax disputes on a mutually acceptable basis.
11. Taxation on profit on ordinary activities continued
Bangladesh litigation
The National Board of Revenue (NBR) is seeking to disallow $118 million of tax
relief in respect of development costs incurred by Tullow Bangladesh Limited
(TBL). The NBR subsequently issued a payment demand to TBL in February 2020
for Taka 3,094 million requesting payment by 15 March 2020. 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 is scheduled was heard by the Tribunal on 20 May 2024. Final written
submissions were made to the Tribunal in September 2024. There is currently no
certainty on timing of any decision from the Tribunal.
Timing of cash-flows
While it is not possible to estimate the timing 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
12. Intangible exploration and evaluation assets
$m Six months ended 30.06.25 Unaudited Six months ended 30.06.24 Unaudited Year ended 31.12.24 Audited
At 1 January 109.1 287.0 287.0
Additions 4.5 11.7 34.7
Exploration costs written off (1.0) (3.1) (212.6)
Transferred to assets classified as held for sale(1) (112.3) - -
At 30 June/31 December 0.3 295.6 109.1
1. This balance relates to assets in Gabon and Kenya.
Refer to note 10.
The below table provides a summary of the exploration costs written off on a
pre-tax basis by country.
Country CGU Rationale for write-off/ Write-off/ Remaining recoverable amount 30.06.25 Unaudited $m
(back)
(back)
six months ended 30.06.25
30.06.25 Unaudited $m
Argentina MLO114, MLO119 and MLO122 a 0.8 -
Côte d'Ivoire Block 524 and Block 803 a 0.3 -
Other Various (0.1) -
Total write-off 1.0
a. No further activity planned following unsuccessful
farm-down efforts.
b. In addition to the exploration costs written off
stated above, $5.7 million has been recognised in Gabon relating to
uncommercial well costs incurred in DE8 and Simba Cash Generating Units
(CGUs). These are presented as discontinued operations in note 10.
Country CGU Rationale for write-off six months ended 30.06.24 Write-off 30.06.24 Unaudited $m Remaining recoverable amount 30.06.24 Unaudited $m
Côte d'Ivoire Block 524 a 1.5 -
New Ventures Various b 0.8 -
Uganda Exploration areas 1, 1A, 2 and 3A c 0.8 -
Total write-off 3.1
a. Current year expenditure on assets previously
written off.
b. New Ventures expenditure is written off as
incurred.
c. Write-off of indirect tax receivable.
12. Intangible exploration and evaluation assets continued
Country CGU Rationale for write-off Write-off 31.12.24 Audited Remaining recoverable amount 31.12.24
year ended 31.12.24
$m
Audited
$m
Argentina MLO114, MLO119 and MLO122 a 38.8 -
Côte d'Ivoire Block 524 and Block 803 a 15.5 -
Kenya Blocks 10BB and 13T b 145.4 103.2
New Ventures Various c 1.3 -
Uganda Exploration areas 1, 1A, 2 and 3A d 0.8 -
Other Various 0.5 -
Total write-off 202.3
a. No further activity planned following unsuccessful
farm-down efforts.
b. Delay in farm-down and extension of Field
Development Plan review period.
c. New Ventures expenditure is written off as
incurred.
d. Indirect tax movement on previously disposed or
written-off assets.
e. In addition to the exploration costs written off
stated above, $10.3 million has been recognised in Gabon relating to
uncommercial well costs incurred in Simba CGU. This is presented as
discontinued operations in note 10.
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 has been
extended to 31 December 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.
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.
Tullow announced signing of Heads of Terms (HOTs) for sale of 100% of the
shares in Tullow Kenya BV (TKBV) to Auron Energy E&P Limited, an affiliate
of Gulf Energy Limited on 15 April 2025, and sale and purchase agreement
signed on 21 July 2025. TKBV consists of 100% undivided participating legal
and beneficial interest in the Block 10BA, Block 10BB and Block 13T PSCs
together with all related liabilities and obligations arising under or in
respect of such interest documents and together with all rights and
obligations attaching thereto.
Completion of the transaction, satisfaction of conditions precedent and
receipt of funds from Tranche A and FDP approval (and consequent receipt of
funds from Tranche B) are expected by Q4 2025 (refer to note 10). Management
has compared the remaining net book value of the Kenya Project with the
consideration as per the signed HOTs and has used its judgement to assess the
likelihood of completion of the farm-down process. Tullow management believes
that the value of proceeds per the signed HOTs is not materially different
from the current net book value and therefore does not see a trigger for
impairment or reversal.
For details of the impairment recognised in the year ended 31 December 2024,
refer to note 8 Intangible exploration and evaluation assets in the Group's
2024 Annual Report and Accounts.
13. Property, plant and equipment
$m Oil and Other fixed assets Right of use Total Oil and gas assets Other fixed assets Right of use Total Oil and gas assets Other fixed assets Right of use Total
gas assets
six months
assets
six months ended
six months
six months
assets
six months
assets
six months ended
six months
six months
Year Year
Year Year
ended
30.06.25 ended ended
ended
30.06.25
ended
ended
ended ended ended ended 31.12.24
30.06.25
Unaudited 30.06.24 30.06.24
30.06.24
Unaudited
30.06.25
30.06.24
31.12.24 31.12.24 31.12.24 Audited
Unaudited
Unaudited Unaudited
Unaudited
Unaudited Unaudited Audited Audited Audited
Cost
At 1 January 11,513.8 23.4 1,124.4 12,661.6 11,282.1 21.9 1,268.8 12,572.8 11,282.1 21.9 1,268.8 12,572.8
Additions 98.2 0.1 - 98.3 104.5 2.6 1.2 108.3 151.6 3.1 1.4 156.1
Acquisition of additional interest in joint operation - - - - 97.4 - - 97.4 97.4 - - 97.4
Transfer to assets held for sale (714.4) (1.4) - (715.8) - - - - - - - -
Asset retirement - - - - - - (138.3) (138.3) - (1.3) (145.3) (146.6)
Currency translation adjustments 100.0 1.2 2.8 104.0 (7.9) (0.1) (0.2) (8.2) (17.3) (0.3) (0.5) (18.1)
At 30 June/31 December 10,997.6 23.3 1,127.2 12,148.1 11,476.1 24.4 1,131.5 12,632.0 11,513.8 23.4 1,124.4 12,661.6
Depreciation, depletion and amortization and impairment
At 1 January (9,698.9) (18.6) (620.0) (10,337.5) (9,377.7) (17.5) (644.8) (10,040.0) (9,377.7) (17.5) (644.8) (10,040.0)
Charge for the year (121.8) (1.3) (38.0) (161.1) (156.3) (1.0) (42.4) (199.7) (350.3) (2.5) (91.4) (444.2)
Impairment (loss)/reversal (39.1) - - (39.1) 1.7 - - 1.7 11.8 - - 11.8
Capitalised depreciation - - (4.2) (4.2) - - (25.4) (25.4) - - (29.5) (29.5)
Transfer to assets held for sale 513.6 1.4 - 515.0 - - - - - - - -
Asset retirement - - - - - - 138.3 138.3 - 1.3 145.3 146.6
Currency translation adjustments (100.0) (0.8) (2.2) (103.0) 7.9 0.1 0.2 8.2 17.3 0.1 0.4 17.8
At 30 June/31 December (9,446.2) (19.3) (664.4) (10,129.9) (9,524.4) (18.4) (574.1) (10,116.9) (9,698.9) (18.6) (620.0) (10,337.5)
Net book value at 30 June/31 December 1,551.4 4.0 462.8 2,018.2 1,951.7 6.0 557.4 2,515.1 1,814.9 4.8 504.4 2,324.1
The currency translation adjustments arose due to the movement against the
Group's presentational currency, USD, of the Group's UK assets, which have a
functional currency of GBP.
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
1H 2025 $66/bbl $65/bbl $70/bbl $70/bbl $70/bbl $70/bbl inflated at 2%
FY 2024 $74/bbl $71/bbl $75/bbl $75/bbl $75/bbl $75/bbl inflated at 2%
1H 2024 $82/bbl $78/bbl $75/bbl $75/bbl $75/bbl $75/bbl inflated at 2%
13. Property, plant and equipment continued
Trigger for impairment/(reversal) Impairment/ (reversal) 30.06.25 30.06.25 Remaining recoverable amount(e)
six months ended 30.06.25 Unaudited Unaudited
$m $m
TEN (Ghana) a 35.0 350.1
Espoir (Cote D'Ivoire) b 6.6 -
Mauritania c (1.0) -
UK CGU c,d (1.5) -
Impairment 39.1
a. Downward revision of medium- and long-term oil
price assumptions.
b. Impairment of capital expenditure in excess of
accumulated depreciation as the NPV of the asset is nil.
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.
Impairments identified in the TEN fields of $35.0 million were primarily due
to a reduction in medium- and long-term oil price assumptions from $75/bbl to
$70/bbl.
Oil prices stated above are benchmark prices to which an individual field
price differential is applied. All impairment assessments are prepared on a
VIU basis using discounted future cash flows based on 2P reserves profiles. A
reduction or increase in the two-year forward curve of $5/bbl, based on the
approximate range of annualised average oil price over recent history, and a
reduction or increase in the medium and long-term price assumptions of $5/bbl,
based on the range of annualised average historical prices, are considered to
be reasonably possible changes for the purposes of sensitivity analysis.
Decreases to oil prices specified above would increase the impairment charge
for TEN by $55.7 million, whilst increases to oil prices specified above would
lead to the current period impairment charge of $35.0 million being fully
reversed and a further reversal of previous impairments by $22.7 million. A 1%
increase in the pre-tax discount rate would increase the impairment by $10.2
million. The Group believes a 1% increase in the pre-tax discount rate to be a
reasonable possibility based on historical analysis of the Group's and peer
group of companies' impairments.
Trigger for impairment/(reversal) Impairment/ (reversal) 30.06.24 30.06.24 Remaining recoverable amount
six months ended 30.06.24 Unaudited Unaudited
$m $m
Espoir (Cote D'Ivoire) a (4.0) -
UK CGU b,c 2.3 -
Impairment (1.7)
a. Change to decommissioning discount rate.
b. Change to decommissioning estimate.
c. The fields in the UK are grouped into one CGU as
all fields share critical gas infrastructure.
Trigger for impairment/ (reversal) year ended 31.12.24 Impairment/ (reversal) 31.12.24 Remaining recoverable amount
31.12.24 Pre-tax discount rate assumption Audited
Audited $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.
14. Business combination
On 29 February 2024, the Group completed the asset swap agreement (ASA)
transaction with Perenco Oil and Gas Gabon S.A (Perenco). The rationale for
the transaction was the simplification of the Group's equity ownership across
key fields in Gabon, creating better alignment between the participating
interest partners and streamlining processes such as budgeting, cost
management and capital allocation. The revised portfolio of assets has enabled
Tullow to leverage its technical skills and focus on more material positions
in key fields.
The transaction was an asset swap achieved through the exchange of
participating interests held by both parties in certain licences in Gabon. The
exchange represented the acquisition of an additional interest in a joint
operation that constitutes a business, and therefore IFRS 11 Joint
Arrangements required the application of the principles in IFRS 3 Business
Combinations.
In line with the requirements of IFRS 3, the interests transferred as part of
the consideration, which comprised mainly of property, plant, and equipment of
$54.4 million, were remeasured to the acquisition date fair value of $93.3
million. This resulted in an asset revaluation gain of $38.9 million
recognised in the income statement at 30 June 2024.
Goodwill of $44.9 million recognised on acquisition is part of the Gabon
disposal group presented as Held for Sale. Refer to note 10.
For details of the transaction, refer to note 14 Business combination in the
Group's 2024 Annual Report and Accounts.
15. Trade receivables
Trade receivables comprise amounts due for the sale of oil and gas. They are
generally due for settlement within 30-60 days and are therefore all
classified as current. The Group holds the trade receivable with the objective
of collecting the contractual cash flows and therefore measures them
subsequently at amortised cost using the effective interest method.
The balance of trade receivables as of 30 June 2025 of $106.1 million (1H
2024: $91.6 million; FY 2024: $137.9 million) includes gross gas receivables
in Ghana of $111.1 million (1H 2024: $75.4 million; FY 2024: $124.4 million)
and oil liftings in Cote D'Ivoire of $2.5 million (1H 2024: $4.4 million; FY
2024: $6.9 million).
Expected credit loss charge on trade receivables
As at 30 June 2025, the allowance for expected credit losses (ECL) stood at
$8.5 million (1H 2024: $nil; FY 2024: $6.6 million) on the net gas receivable
balance in Ghana of $79.7 million (1H 2024: 31.7 million; FY 2024: $56.2
million). The amounts provided in 2025 reflect the increase in the net gas
balance receivable from 31 December 2024 due to delays in payments during the
period and changes in external credit ratings. No allowance for ECL has been
provided on balances receivable where mitigating contract clauses ensure that
amounts due will be fully recovered.
16. Other assets
$m 30.06.25 Unaudited 30.06.24 Unaudited 31.12.24 Audited
Non-current
Amounts due from joint venture partners 303.7 296.5 333.1
VAT recoverable - 7.0 7.7
303.7 303.5 340.8
Current
Amounts due from joint venture partners 408.3 440.7 350.2
Underlifts 17.3 11.1 20.9
Prepayments 18.3 21.4 17.1
Other current assets 10.4 2.9 3.7
454.3 476.1 391.9
758.0 779.6 732.7
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 30 June 2025, Tullow has contributed $23.2 million
(1H 2024: $nil; FY 2024: $11.6 million) into the decommissioning trust fund.
The increase in other current assets is mainly driven by $4.2 million
insurance proceeds related to lost production under the Business Interruption
insurance policy (1H 2024, FY 2024: $nil).
17. Inventories
$m 30.06.25 Unaudited 30.06.24 Unaudited 31.12.24 Audited
Warehouse stock and materials 65.3 67.3 78.2
Oil stock 41.9 110.8 54.2
107.2 178.1 132.4
The movement in inventories from 31 December 2024 is driven by a $9.6 million
oil stock decrease in Ghana and a transfer of $18.1 million of warehouse stock
and materials in Gabon to assets held for sale (refer to note 10).
18. Cash and cash equivalents
$m 30.06.25 Unaudited 30.06.24 Unaudited 31.12.24 Audited
Cash at bank 66.0 100.4 151.2
Short- term deposits and other cash equivalents 128.1 172.2 403.9
194.1 272.6 555.1
Cash and cash equivalents include an amount of $25.3 million (1H 2024: $59.1
million; FY 2024: $83.5 million) which the Group holds as operator in joint
venture bank accounts. Included in cash at bank is $6.6 million (1H 2024: $8.9
million; FY 2024: $6.5 million) of restricted cash held as collateral for
performance bonds issued in relation to decommissioning and exploration
activities.
19. Trade and other payables
$m 30.06.25 Unaudited 30.06.24 Unaudited 31.12.24 Audited
Current
Trade payables 72.2 58.2 75.7
Other payables 40.9 78.7 96.8
Overlifts - 3.3 38.3
Accruals 327.9 380.1 373.8
Current portion of leases 156.5 146.7 151.9
597.5 667.0 736.5
Non-current
Other non-current liabilities(1) 88.2 57.4 84.9
Non-current portion of leases 509.9 655.5 581.0
598.1 712.9 665.9
1. Other non-current liabilities include balances
related to JV Partners.
Accruals relate to operating and administrative expenditure of $155.4 million
(1H 2024: $148.1 million; FY 2024: $196.3 million), capital expenditure of
$125.6 million (1H 2024: $185.9 million; FY 2024: $119.6 million), interest
expense on bonds of $36.5 million (1H 2024: $31.9 million; FY 2024: $35.3
million) and staff-related expenses of $10.4 million (1H 2024: $14.2 million;
FY 2024: $22.6 million).
Trade and other payables are non-interest bearing except for leases. The
change in trade payables and in other payables represents timing differences
and levels of work activity.
As at 30 June 2025, $23.4 million of other payables and $12.2 million of
accruals were reclassified to liabilities directly associated with assets
classified as held for sale in Gabon and Kenya (refer to note 10).
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 (refer to note 16).
20. Borrowings
$m 30.06.25 Unaudited 30.06.24 Unaudited 31.12.24 Audited
Current
Borrowings - within one year
7.00% Senior Notes due 2025 - 489.2 489.4
10.25% Senior Notes due 2026 1,276.4 100.0 100.0
Super Senior Revolving Credit Facility 150.0 - -
Carrying value of total current borrowings 1,426.4 589.2 589.4
Non-current
Borrowings - after one year but within five years
10.25% Senior Notes due 2026 - 1,272.9 1,274.4
Secured Notes Facility due 2028 381.9 117.4 112.0
Carrying value of total non-current borrowings 381.9 1,390.3 1,386.4
Carrying value of total borrowings 1,808.3 1,979.5 1,975.8
The Group's capital structure includes $1,285 million Senior Secured Notes due
in May 2026 (2026 Notes), a $150 million Super Senior Revolving Credit
Facility (RCF) and a $400 million Secured Notes Facility.
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.
The 2026 Notes require an annual prepayment of $100 million, in May, of the
outstanding principal amount plus accrued and unpaid interest, with the
balance due on maturity. On 15 May 2025, the Group made the annual prepayment
of $100 million of the 2026 Notes.
During the first half of the year, the Group extended the maturity of the RCF
from 30 June 2025 to the earlier of (i) 31 October 2025, (ii) the 2026 Notes
refinancing date or (iii) within 3 business days of receipt of the Gabon sale
proceeds. The size of the facility also reduced from $250 million to $150
million to align with lower headroom needs.
The 2026 Notes, the Secured Notes Facility and the RCF are senior secured
obligations of Tullow Oil Plc and are guaranteed by certain subsidiaries of
the Group.
Capital management
The Group defines capital as the total equity and net debt of the Group.
Capital is managed in order to provide returns for shareholders and benefits
to stakeholders and to safeguard the Group's ability to continue as a going
concern. The Group is not subject to any externally imposed capital
requirements. To maintain or adjust the capital structure, management may put
in place new debt facilities, issue new shares for cash, repay debt, engage in
active portfolio management, or undertake such other restructuring activities
as appropriate. The Group monitors capital on the basis of the gearing, being
net debt divided by adjusted EBITDAX, and maintains a policy target of less
than 1x.
RCF covenants
The RCF does not have any financial maintenance covenants. Availability under
the facility is determined on an annual basis with reference to the net
present value of the 2P reserves of the Group (2P NPV) at the end of the
preceding calendar year. RCF debt capacity is calculated as 2P NPV divided by
1.1 times less senior secured debt outstanding.
20. Borrowings continued
2026 Notes covenants
The 2026 Notes are subject to customary high-yield covenants including
limitations on debt incurrence, asset sales and restricted payments such as
prepayments of junior debt and dividends.
Key covenants in the current business cycle are considered to be those related
to debt incurrence and restricted payments. For definitions of the capitalised
terms used in the following paragraphs please refer to the offering memorandum
of the 2026 Notes.
Tullow is permitted to incur additional debt if the ratio of consolidated cash
flow to fixed charges for the previous 12 months is at least 2.25 times on a
pro forma basis.
Tullow is permitted to incur secured debt if the 2P Reserves Coverage Ratio is
at least 2.0 times on a pro forma basis.
The Group or its affiliates may, at any time and from time to time, seek to
refinance, retire or purchase any or all of its outstanding debt through new
debt refinancings and/or cash purchases, in open-market purchases, privately
negotiated transactions or otherwise. Such refinancings or repurchases, if
any, will be upon such terms and at such prices as management may determine,
and will depend on prevailing market conditions, liquidity requirements and
other factors.
Secured Notes Facility covenants
The Secured Notes Facility does not have any financial maintenance covenants.
The facility is subject to substantially the same covenants as the 2026 Notes,
with additional restrictions related to the use of proceeds from any
incurrence of new indebtedness ranking senior to the facility or sharing the
same collateral.
Tullow is permitted to refinance the RCF and the 2026 Notes on a like-for-like
basis.
21. Provisions
$m Decommissioning Other provisions 30.06.25 Unaudited Total Decommissioning Other provisions 30.06.24 Unaudited Total 30.06.24 Unaudited Decommissioning Other provisions 31.12.24 Audited Total 31.12.24 Audited
30.06.25 Unaudited
30.06.25 Unaudited
30.06.24 Unaudited
31.12.24
Audited
At 1 January 306.4 39.4 345.8 377.9 93.7 471.6 377.9 93.7 471.6
New provisions - 14.7 14.7 - 0.6 0.6 - 22.4 22.4
Changes in estimate (1.5) (2.1) (3.6) (23.0) (40.5) (63.5) (39.3) (75.9) (115.2)
Acquisitions(1) - - - 5.8 - 5.8 5.8 - 5.8
Transfer to liabilities held for sale (31.5) (2.1) (33.6) - - - - - -
Payments (1.2) (4.3) (5.5) (9.0) (0.6) (9.6) (49.0) (0.7) (49.7)
Unwinding of discount 6.4 - 6.4 5.8 - 5.8 11.4 - 11.4
Currency translation adjustment 2.4 1.0 3.4 (0.2) - (0.2) (0.4) (0.1) (0.5)
At 30 June/31 December 281.0 46.6 327.6 357.3 53.2 410.5 306.4 39.4 345.8
Current provisions 12.9 27.6 40.5 69.0 13.3 82.3 9.8 14.5 24.3
Non-current provisions 268.1 19.0 287.1 288.3 39.9 328.2 296.6 24.9 321.5
1. This relates to an acquisition through business
combination discussed in note 14.
Other provisions include non-income tax provisions of $7.1 million (1H 2024:
$38.1 million; FY 2024: $7.1 million) and disputed cases and claims of $39.4
million (1H 2024: $15.1 million; FY 2024: $32.3 million). Management estimates
non-current other provisions would fall due between two and five years.
Non-current other provisions included a provision relating to a potential
claim arising out of historical contractual agreements. 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.
22. Called up share capital and share premium
As at 30 June 2025, the Group had in issue 1,462.4 million allotted and fully
paid ordinary shares of GBP 10 pence each (1H 24: 1,458.0 million; FY 2024:
1,459.1million).
In the six months ended 30 June 2025, the Group issued 3.3 million shares in
respect of employee share options (1H 24: 5.5 million; FY 2024: 6.5 million
new shares in respect of employee share options).
23. Contingent Liabilities
$m 30.06.25 Unaudited 30.06.24 Unaudited 31.12.24 Audited
Contingent liabilities
Performance guarantees(1) 25.9 28.1 24.1
Other contingent liabilities(2) 35.6 83.1 37.8
61.5 111.2 61.9
1. Performance guarantees are in respect of
abandonment obligations, committed work programmes and certain financial
obligations.
2. Other contingent liabilities include amounts for
ongoing legal disputes with third parties where we consider the likelihood of
cash outflow to be higher than remote but not probable. The timing of any
economic outflow if it were to occur would likely range between one and five
years.
24. Events since 30 June 2025
On 21 July 2025, Tullow announced that it had signed a sale and purchase
agreement with Auron Energy E&P Limited, an affiliate of Gulf Energy
Limited, for the sale and purchase of 100% of the shares in Tullow Kenya BV
(refer to note 10 for the details of the transaction).
On 29 July 2025, following satisfaction of all conditions precedent under the
sale and purchase agreement, Tullow completed the sale of its 100% interest in
Tullow Oil Gabon SA, which holds all of Tullow's non-operated working
interests in Gabon (discussed in note 10 Held for sale and discontinued
operations), to the Gabon Oil Company for a total cash consideration of $307
million, net of tax and customary adjustments. This is a non-adjusting event
as at 30 June 2025 under IAS 10 Events after the Reporting Period. The
financial impact of the disposal cannot be disclosed in the 2025 Half-year
results as completion accounting is still underway, and the relevant
disclosures will be made in the Group's 2025 annual financial statements. The
transaction is subject to a capital gains tax of $52 million as agreed with
the Gabon Tax Authority, which will be paid by Gabon Oil Company. On
completion, this will be recorded as an income tax expense with a
corresponding pre-tax gain on disposal and no deferred tax recognised.
On 29 July 2025, the RCF of $150 million was repaid and cancelled in full.
There have not been any other events since 30 June 2025 that have resulted in
a material impact on the half-year results.
25. Cash flow statement reconciliations
Movement in borrowings ($m) 1H25 FY24 1H24 FY23 1H25 Movement 1H24 Movement 2024 Movement
Borrowings 1,808.3 1,975.8 1,979.5 2,084.6 (167.5) (105.1) (108.8)
Associated cash flows
Debt arrangement fees (2.3) - -
Repayment of borrowings (592.5) (100.0) (100.0)
Drawdown of borrowings 420.3 - -
Non-cash movements/presented in other cash flow lines
Amortisation of arrangement fees and accrued interest 7.0 (5.1) (8.8)
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 1H 2025 1H 2024
Additions to property, plant and equipment 98.2 201.9
Additions to intangible exploration and evaluation assets 4.5 11.7
Less
Decommissioning asset adjustments (1.5) (23.0)
Right-of-use asset additions - 1.2
Lease payments related to capital activities - (21.9)
Additions to administrative assets 0.1 2.6
Other non-cash capital expenditure 0.7 98.1
Capital investments(1) 103.4 156.6
Movement in working capital (7.8) 1.2
Additions to administrative assets 0.1 2.6
Cash capital expenditure per the cash flow statement 95.7 160.4
1. Capital investments include $25.6 million relating
to Gabon (1H 2024: $27.0 million)
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 within 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 30 June 2025 was $156.5 million current and $509.9 million
non-current; it should be noted that these balances are recorded gross for
operated assets and are therefore not representative of the Group's net
exposure under these contracts.
$m 1H 2025 1H 2024
Current borrowings 1,426.4 589.2
Non-current borrowings 381.9 1,390.3
Non-cash adjustments(1) 26.9 28.0
Less cash and cash equivalents (195.3) (272.6)
Net debt 1,639.9 1,734.9
1. Non-cash adjustments include unamortised
arrangement fees which are incurred on creation or amendment of borrowing
facilities.
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. This definition of gearing differs from the
one included in the RBL facility agreements. Adjusted EBITDAX is defined as
profit/(loss) from continuing activities adjusted for income tax expense,
finance costs, finance revenue, loss on hedging instruments, depreciation,
depletion and amortisation, share-based payment charge, restructuring costs,
asset revaluations, other gains and losses, gain on bond buyback, exploration
cost written off, impairment of property, plant and equipment net, and
provision for onerous contracts.
1H 2025 1H 2024 Restated(2)
Adjusted EBITDAX(1,3) 768.2 1,082.6
Net debt 1,639.9 1,734.9
Gearing (times) 2.1 1.6
1. Last 12 months (LTM). Refer to the 2024 Annual
Report and Accounts and 2024 Half year results for a full reconciliation of
2024 and 1H 2024 Adjusted EBITDAX.
2. Comparative adjusted EBITDAX and gearing have been
restated to present Gabon as a discontinued operation. Refer to note 10.
3. Adjusted EBITDAX including results from
discontinued operations in Gabon is $880.2 million (1H 2024: $1,281.8
million).
Underlying cash operating costs
Underlying cash operating costs is a useful indicator of the Group's costs
incurred to produce oil and gas. Underlying cash operating costs eliminates
certain non-cash accounting adjustments to the Group's cost of sales to
produce oil and gas. Underlying cash operating costs is defined as cost of
sales less operating lease expense, depletion and amortisation of oil and gas
assets, underlift, overlift and oil stock movements and certain other cost of
sales. Underlying cash operating costs are divided by production to determine
underlying cash operating costs per boe.
In 2025 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.
$m 1H 2025 1H 2024 Restated(5)
Cost of sales 249.6 278.4
Add
Lease payments related to operating activity 6.0 6.6
Less
Depletion and amortisation of oil and gas and leased assets(1) 159.1 186.0
(Underlift), overlift and oil stock movements(2) (17.7) 5.4
Other cost of sales(3) 6.3 6.6
Underlying cash operating costs 107.9 87.0
Non-recurring costs(4) (22.5) (4.8)
Total normalised cash operating costs 85.4 82.2
Production (MMboe) 7.4 9.7
Underlying cash operating costs per boe ($/boe) 14.6 8.9
Normalised cash operating costs per boe ($/boe) 11.6 8.4
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 in 1H 2025 include Jubilee
shutdown and FPSO Class related maintenance costs.
5. Comparative balances have been restated to present
Gabon as a discontinued operation. Refer to note 10.
6. Balances above are presented excluding discontinued
operations in Gabon.
Free cash flow
Free cash flow is a useful indicator of the Group's ability to generate cash
flow to fund the business and strategic acquisitions, reduce borrowings and
provide returns to shareholders through dividends. Free cash flow is defined
as net cash from operating activities, and net cash used in investing
activities, repayment of obligations under leases, finance costs paid, debt
arrangement fees and foreign exchange (loss)/gain.
$m 1H 2025 1H 2024
Net cash from operating activities 85.0 231.4
Net cash used in investing activities (88.5) (150.2)
Repayment of obligations under leases (72.5) (93.9)
Finance costs paid (103.1) (116.3)
Debt arrangement fees (2.3) -
Foreign exchange (loss)/gain (6.2) 2.6
Free cash flow (187.6) (126.4)
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 repayments 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 1H 2025 1H 2024
Net cash from operating activities 85.0 231.4
Add
Decommissioning expenditure 9.7 9.9
Lease payments related to capital activities - 21.9
Payments to decommissioning escrow fund 11.6 -
Less
Repayment of obligations under leases (72.5) (93.9)
Underlying operating cash flow 33.8 169.3
Net cash used in investing activities (88.5) (150.2)
Decommissioning expenditure (9.7) (9.9)
Lease payments related to capital activities - (21.9)
Payments to decommissioning escrow fund (11.6) -
Pre-financing free cash flow (76.0) (12.7)
Management Presentation - WEBCAST - 9:00 BST
To access the webcast please use the following link and follow the
instructions provided:
https://meetings.lumiconnect.com/100-984-014-243
(https://meetings.lumiconnect.com/100-984-014-243)
A replay will be available on the website from midday on 7 August 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 3781 9244)
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. Tullow's operations are
focused on its core producing assets in Ghana. Tullow is committed to becoming
Net Zero on its Scope 1 and 2 emissions by 2030, with a Shared Prosperity
strategy that delivers lasting socio-economic benefits for its host nations.
The Group is quoted on the London and Ghanaian stock exchanges (symbol: TLW).
For further information, please refer to: www.tullowoil.com.
Follow Tullow on:
LinkedIn: www.linkedin.com/company/Tullow-Oil
(http://www.linkedin.com/company/Tullow-Oil)
X: www.x.com/TullowOilplc (http://www.x.com/TullowOilplc)
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