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2025 Half Year Results

6th Aug 2025 07:00

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

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 flow1 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 debt1 at 30 June 2025 of $1.6 billion (30 June 2024: $1.7 billion); cash gearing of 1.9x net debt/EBITDAX1 (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/EBITDAX1).

· 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 20252

1H 20242

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 costs1

(108)

(87)

Depreciation, Depletion and Amortisation (DDA) of oil and gas and leased assets

(159)

(186)

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 EBITDAX1

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)before tax

Tax(expense)/credit

Adjusted

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)before tax

Tax(expense)/credit

Adjusted

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 and equipment

96

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 30.06.25Unaudited

Six months ended 30.06.24Unaudited Restated1

Year ended 31.12.24Audited Restated1

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 Unaudited

Six months ended 30.06.24 Unaudited

Year ended 31.12.24Audited

(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 value

9.7

14.7

26.1

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 30.06.25Unaudited

Six months ended 30.06.24Unaudited

Year ended 31.12.24Audited

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

Sharecapital

Sharepremium

Foreign currency translation reserve¹

Hedgereserve²

Hedgereserve - timevalue²

Merger reserves3

Retained earnings

Total

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 30.06.24Unaudited

Year ended31.12.24Audited

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 period1

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-Operated4

Kenya5

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 result1

145.2

(4.0)

-

(2.4)

(13.7)

125.1

Unallocated corporate expenses2

 

 

(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 liabilities3

(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-Operated4

Kenya

Exploration

Corporate

Total

 

Six months ended 30 June 2024

Sales revenue by origin

703.0

20.4

-

-

(57.9)

665.5

Segment result1

446.2

7.6

-

(2.3)

(65.8)

385.7

Other provisions

 

 

39.4

Unallocated corporate expenses2

 

 

(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 liabilities3

(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-Operated4

Kenya

Exploration

Corporate

Total

 

Year ended 31 December 2024

Sales revenue by origin

1,325.4

35.4

-

-

(73.6)

1,287.2

Segment result1

722.6

14.5

(145.4)

(55.9)

(91.6)

444.2

Provisions reversal

 

 

70.4

Unallocated corporate expenses2

 

 

(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 liabilities3

(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 Restated2

Sales revenue Year ended 31.12.24 Restated2

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

Kenya1

-

-

-

-

254.4

110.9

Total Kenya

-

-

-

-

254.4

110.9

Argentina

-

-

-

-

37.8

-

Côte d'Ivoire

-

-

-

-

7.3

-

Total Exploration

-

-

-

-

45.1

-

Gabon1

-

-

-

-

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 Restated1

Year ended 31.12.24 Audited Restated1

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 Restated5 

Year ended 31.12.24 Audited Restated5

Cost of sales

Operating costs

107.8

87.0

197.8

Depletion and amortisation of oil and gas and leased assets1

159.1

186.0

412.1

(Underlift), overlift and oil stock movements2

(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 assets1

2.0

1.7

6.5

Other administrative costs

17.5

26.8

39.2

Total administrative expenses3

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 Restated1

Year ended 31.12.24 Audited Restated1

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 ended30.06.25

Six months ended30.06.24

Yearended31.12.24

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 ended30.06.25

Six months ended30.06.24

Year ended31.12.24

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 ended30.06.25

Six months ended30.06.24

Year ended31.12.24

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 sale1

(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/(back)six months ended 30.06.25

Write-off/(back) 30.06.25 Unaudited $m

Remaining recoverable amount 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-offyear ended 31.12.24

Write-off 31.12.24 Audited $m

Remaining recoverable amount 31.12.24Audited $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 andgas assetssix months ended

30.06.25

Unaudited

Other fixed assetssix months

ended

30.06.25

Unaudited

Right of useassetssix months

ended

30.06.25

Unaudited

Totalsix months ended

30.06.25

Unaudited

Oil and gas assetssix months

ended

30.06.24

Unaudited

Other fixed assetssix months

ended

30.06.24

Unaudited

Right of useassetssix months

ended

30.06.24

Unaudited

Totalsix months

ended

30.06.24

Unaudited

Oil and gas assets

Year

 ended

 31.12.24

Audited

Other fixed assets

Year

 ended

31.12.24

Audited

Right of useassetsYear

ended

31.12.24

Audited

Total

Year

 ended 31.12.24

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)

 six months ended 30.06.25

Impairment/ (reversal) 30.06.25

Unaudited

$m

30.06.25 Remaining recoverable amounte

Unaudited

$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)

 six months ended 30.06.24

Impairment/ (reversal) 30.06.24

Unaudited

$m

30.06.24 Remaining recoverable amount

Unaudited

$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

Audited

$m

 

Pre-tax discount rate assumption

31.12.24 Remaining recoverable amount

Audited

$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 liabilities1

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

Decommissioning30.06.25 Unaudited

Other provisions 30.06.25 Unaudited

Total30.06.25 Unaudited

Decommissioning30.06.24 Unaudited

Other provisions 30.06.24 Unaudited

Total 30.06.24 Unaudited

Decommissioning31.12.24 Audited

Other provisions 31.12.24 Audited

Total 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)

Acquisitions1

-

-

-

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 guarantees1

25.9

28.1

24.1

Other contingent liabilities2

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 investments1

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 adjustments1

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 Restated2

Adjusted EBITDAX1,3

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 Restated5

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 assets1

 

159.1

186.0

(Underlift), overlift and oil stock movements2

(17.7)

5.4

Other cost of sales3

6.3

6.6

Underlying cash operating costs

 

107.9

87.0

Non-recurring costs4

(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

A replay will be available on the website from midday on 7 August 2025:

https://www.tullowoil.com/investors/results-reports-and-presentations/

Contacts

Tullow Oil plc

(London)

[email protected]

Matthew Evans

Rob Hayward

Camarco

(London)

(+44 20 3781 9244)

Billy Clegg

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

X: www.x.com/TullowOilplc

 

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