2024 Half Year Results

Ghana drilling programme completed safely and ahead of schedule

2024 guidance reiterated

7 August 2024 - 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 2024. 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

Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented today: "During the first half of 2024, Tullow has continued to deliver strong operational and financial performance. We are pleased to report improved results across key financial metrics compared to the first half of 2023; with higher production and oil price realisations combined with lower expenditure. The Ghana drilling programme was also completed safely, and ahead of schedule. "We were delighted to reach a major milestone by taking final investment decision (FID) of our nature-based carbon offset initiative, in partnership with the Ghana Forestry Commission. The project will deliver certified carbon offsets in line with Tullow's 2030 Net Zero target, while bringing broader positive impacts to the local community. "We now progress into a period of lower capex in the second half of the year and beyond. We will continue to reduce debt through sustainable free cash flow generation, strengthening our balance sheet and providing optionality for investment, growth and future returns."

2024 FIRST HALF RESULTS

• First half Group working interest oil and gas production 63.7 kboepd (1H23: 60.8 kboepd).
• Revenue of $759 million (1H23: $777 million); realised oil price of $77.7/bbl after hedging (1H23: $73.3/bbl), gross profit of $460 million (1H23: $351 million); profit after tax of $196 million (1H23: $70 million).
• Capital expenditure of $157 million (1H23: $187 million) and decommissioning spend of $9 million (1H23: $44 million).
• Free cash flow1 of $(126) million (1H23: $(142) million), in line with expectations based on timing of tax payments and capital expenditure weighted toward the first half of the year.
• Net debt1 at 30 June 2024 of $1.7 billion (30 June 2023: $1.9 billion); cash gearing of 1.4x net debt/EBITDAX1 (30 June 2023: 1.7x); liquidity headroom of $0.7 billion (30 June 2023: $0.7 billion).

2024 FULL YEAR OUTLOOK

• 2024 Group working interest production is expected to be at the lower end of the Group's 62-68 kboepd range, as previously guided; driven primarily by underperformance of a single Jubilee well, which came onstream in February 2024.
• Full year capex and decommissioning guidance of c.$230 million and c.$70 million, respectively. This represents a c.$20 million capex decrease (versus previous guidance of c.$250 million) in both Ghana and Gabon.
• A significant free cash flow uplift is expected in the second half of 2024. Full year free cash flow guidance remains unchanged at $200-300 million at $80/bbl.
• Increased access to oil price upside as legacy hedges fully rolled off in May 2024; 2H 2024 average floor of $60/bbl and capped upside of $112/bbl.
• Year-end net debt guidance is unchanged at less than $1.4 billion with gearing of c.1x (net debt/EBITDAX1).
• Tullow has no uncovered debt maturities until May 2026 and continues to consider options to manage its debt maturities and optimise its capital structure.
• Outcome of arbitration in respect of Ghana Branch Profits Remittance Tax expected in the second half of 2024.
• Tullow remains focused on deleveraging and reaching net debt of less than $1 billion and cash gearing of less than 1x in the near term.
• Alternative performance measures are reconciled on pages 36 to 38

Operational update

Production

In the first six months of 2024, Group production averaged 63.7 kboepd, including 7.0 kboepd of gas. As previously disclosed, Group 2024 production is expected to be at lower end of the 62 to 68 kboepd range.

Ghana

During the first six months of the year, operational efficiency remained high, with average facility uptime across the Ghana FPSOs at 97%.

Gross oil production from the Jubilee field averaged 90.1 kbopd (net: 35.1 kbopd) in the first half of the year. This was below expectations, primarily attributable to poor performance from to the J69 producer well, which was brought onstream in February 2024. The J69 well is producing significantly less than expected due to a lack of pressure communication from water injection in this specific area. This is not being experienced elsewhere and across the field, water injection has averaged a record c.225 kbwpd. This improved rate of water injection, together with the new J70 water injection well brought onstream in June, is resulting in a good uplift in reservoir pressure which is already increasing production levels and offsetting decline. As a result, Jubilee oil production is expected to remain at similar levels to the first half and average c.90 kbopd (net: c.34 kbopd) for the full year.

Five new Jubilee wells (three producers and two water injectors) were brought onstream during the first half of 2024, bringing the current drilling programme to an end, approximately six months ahead of schedule and with no recordable safety incidents. A 4D seismic survey will be completed in early 2025 to update the view of the sub-surface, support drill candidate selection and optimise well placement ahead of a 2025/26 drilling programme.

During the drill break, work will focus on integrating the results of the previous drilling programme and optimising pressure support across the field to maximise production and minimise decline. Tullow will continue to prioritise safe and reliable operations, with a focus on cost and capital efficiency to optimise cash flow delivery.

Gross oil production from the TEN fields averaged 19.0 kbopd (net: 10.4 kbopd) in the first half of the year. The fields have exceeded expectations, with Enyenra and Ntomme wells responding positively to both injection and production optimisation. Consequently, full year gross TEN oil production guidance has been increased to c.18 kbopd (net: c.10 kbopd).

Net gas production in Ghana averaged 6.5 kboepd in the first half of the year. The interim Gas Sales Agreement remains in place until the fourth quarter of 2025 at $3.00/mmbtu with applicable indexation. Tullow is also in discussion in relation to potential third party off-take opportunities to create a significant longer-term revenue stream from gas production.

Non-operated and exploration portfolios

Production from our non-operated portfolio in Gabon and Côte d'Ivoire averaged 11.7 kboepd net in the first half of the year, in line with expectations. Full year net production remains unchanged at c.11.5 kboepd.

Tullow was deeply saddened to learn of the incident at the Perenco-operated Simba field in Gabon in March 2024, which resulted in fatalities. Production has been shut in while investigations and remediations are taking place. Production is expected to resume on the Simba field before the end of the year. Production forecasts for Gabon remain unchanged with lower Simba production being offset by improvement in other fields, including Ezanga and Echira.

In Côte d'Ivoire, Tullow continues to work with the operator of the Espoir field to establish the best way forward for the asset. Tullow continues to mature prospects on its exploration licences in Côte d'Ivoire and Argentina alongside seeking potential farm-down Partners.

Kenya

Tullow continues to work collaboratively with the Government of Kenya as they evaluate the amended Field Development Plan (FDP). The Energy and Petroleum Regulatory Authority (EPRA) has provided useful feedback and the FDP review period has been extended for a further six months to 31 December 2024. Tullow is continuing its cooperation and collaboration with the Government to reach final approval of the FDP. Discussions continue with prospective strategic partners for this project.

Reserves and resources

Tullow's review of its reserves and resources position is ongoing, incorporating 1H production as well as results and performance from the recent Ghana drill programme. Tullow will publish its 1H24 reserves report in September, in line with prior years.

Environmental, Safety and Governance (ESG)

Tullow continues to progress along its pathway to Net Zero by 2030 (Scope 1 and 2). The primary focus of the Group's Net Zero strategy is on decarbonising its operated production facilities in Ghana and Tullow continues to progress workstreams to eliminate routine flaring by the end of 2025. To address hard-to-abate residual emissions, in May 2024 Tullow took a final investment decision (FID) with the Ghana Forestry Commission to invest $90 million over 10 years, implementing a high integrity, jurisdictional based Reduced Emissions from Deforestation and Degradation (REDD+) programme that will deliver certified carbon offsets in line with Tullow's 2030 Net Zero roadmap. The programme is expected to generate up to 1 million tonnes per annum of certified carbon offsets from c.2 million hectares of land across the Bono and Bono East regions of Ghana.

Tullow is committed to being a responsible steward of the environment and ensuring robust systems are in place to manage environmental risks. These systems were deployed during two losses of primary containments in the first half of 2024 that resulted in a release of oil to the sea. These were dealt with quickly, with no major impacts, and a thorough investigation has been undertaken with actions taken to prevent any recurrence.

In June 2024, Tullow released the Noble Venturer drill ship from its contract in Ghana, which marked 1,171 days of operations, drilling 21 deep-water wells without any recordable EHS incidents.

The Group's Shared Prosperity strategy continues to focus on supporting enterprise, especially agribusiness, enhancing employability and job creation, strengthening local economies and improving living standards, through our different partnerships. In February 2024, Tullow launched the Tullow AgriVentures Programme (TAP) in partnership with Innohub Ghana. TAP has an ambition to generate approximately 600 new agriculturally linked ventures and support 30 existing businesses to grow and create more than 1,500 jobs. Tullow continues to work closely with local suppliers to drive local content and strengthen human rights due diligence through increased engagement, support, and training. In the first half of the year, Tullow received three awards at the Ghana Shippers' Authority Awards 2024, recognising the Group's commitment to local content, imports and transparency in the energy sector.

Finance review

Income Statement

• Alternative performance measures are reconciled on pages 36 to 38.

Revenue

Sales Oil Volumes

During the period, there were 51,200 boepd (1H2023: 56,900 boepd) of liftings. The decrease is mainly due to the reduction of two liftings in Gabon offset by an increase of one lifting in Ghana with 7 in Jubilee (1H 2023: 6) and 2 in TEN (1H 2023: 2).

Realised oil price ($/bbl)

The Group's realised oil price after hedging for the period was $77.7/bbl (1H 2023: $73.3/bbl) and before hedging $83.9/bbl (1H 2023: $79.7/bbl). Lower hedged volumes subject to price caps compared to 1H 2023 have resulted in a lower hedge loss despite higher oil prices, decreasing total revenue by $57.9 million in 1H 2024 (1H 2023: decrease of $65.9 million).

Gas sales

Included in Total Revenue of $759 million is gas sales of $29 million of which $25 million relates to Ghana. During the period, Jubilee exported 18,148 mmscf (gross) of gas at an average price of $2.95/mmbtu.

Cost of Sales

Underlying cash operating costs

Underlying cash operating costs amounted to $125 million; $10.8/boe (1H 2023: $136 million; $12.4/boe). The cash unit operating costs have decreased against the comparative period driven by reprioritisation and rephasing of Jubilee O&M activities in the current period and TEN shutdown preparatory costs in 1H 2023.

Depreciation, depletion, and amortisation

DD&A charges before impairment on production and development assets amounted to $198 million; $17.1 /boe (1H 2023: $163 million: $14.8/boe). This increase in DD&A is mainly attributable to increased Jubilee production and gas commercialisation offset by the impact of 2023 impairments relating to TEN.

Overlift and oil stock movements

The Group had an underlift compared to an overlift expense in the comparative period. The change was due to timing of liftings specifically in Gabon resulting in a higher oil stock position compared to the comparative period. Jubilee has had one lifting higher in the current period with oil stock position comparable to prior period as a result of increased production.

Administrative expenses

Administrative expenses of $31 million (1H 2023: $19 million) have increased against the comparative period due to prior year adjustments and accrual release in 1H 2023 of $6 million, one-off redundancy costs in 1H 2024 of $1.4 million, increase in payroll costs and phasing of spend in 1H 2024. Full year forecast administrative costs are expected to be in line with prior year despite the inflationary environment.

Asset revaluation

The asset revaluation of $39 million relates to assets disposed of as part of the swap with Perenco (refer to Note 13 for further information).

Exploration costs written off

During the first half of 2024, the Group has written off exploration costs of $3 million (1H 2023: $10 million) driven by exploration costs in Cote D'Ivoire and New Venture activities.

Impairment of property, plant and equipment

The Group recognised a net impairment reversal on PP&E of $2 million in respect of the first half of 2024 (1H 2023: Net impairment $33 million) which is mainly driven by change in decommissioning discount rates offset by changes to estimates on the cost of decommissioning for certain UK assets.

Net financing costs

Net financing costs for the period were $138 million (1H 2023: $135 million). This increase is mainly due to higher interest on obligations under leases of $17m, offset by lower interest on borrowings of $15 million due to bond buybacks in 2H 2023 and a prepayment in May 2024 resulting in a lower amount of outstanding bonds.

A reconciliation of net financing costs is included in Note 9.

Taxation

The overall adjusted net tax expense of $171 million (1H 2023: $147 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 2024.

Based on a profit before tax for the first half of the year of $368 million (1H 2023: $217 million), the effective tax rate is 46.7% (1H 2023: 67.7%). After adjusting for non-recurring amounts related to exploration write-offs, disposals, impairments and their associated deferred tax benefit, the Group's adjusted tax rate is 51.7% (1H 2023: 56.2%). In the UK there is net interest and hedging expenses of $123 million (1H 2023: $80 million), however there is no UK tax benefit as in previous periods.

The Group's future statutory effective tax rate is sensitive to the geographic mix in which pre-tax profits arise. There is no UK tax benefit from net interest and hedging expenses, whereas net interest income and hedging profits would be taxable in the UK. Consequently, the Group's tax charge will continue to vary according to the jurisdictions in which pre-tax profits occur. 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's effective tax rate is more than 15% for this period and the group is not expecting profit to be taxed at less than 15%.

Adjusted EBITDAX

Adjusted EBITDAX for the year was $1,282 million (1H 2023: $1,171 million). The increase in the period was mainly driven by the oil stock movements in the current period as explained in Cost of Sales section above.

Profit for the year from continuing activities and earnings per share

The profit for the year from continuing activities amounted to $196 million (1H 2023: $70 million profit). The increase in profit after tax was driven mainly by a reduction in impairments, asset revaluation gains and provision releases. Basic earnings per share was 13.5 cents (1H 2023: 4.9 cents earnings per share).

Balance Sheet and Liquidity management

• Alternative performance measures are reconciled on pages 36 to 38.

Capital Investment

Capital expenditure amounted to $157 million (1H 2023: $187 million) with $151 million invested in production and development activities of which $108 million was invested in Jubilee mainly comprising of $96 million on drilling costs and $6 million invested in exploration and appraisal activities.

The Group's 2024 capital expenditure guidance is revised to c.$230 million which will comprise Ghana of c.$150 million, West African Non-Operated of c.$50 million, Kenya of c.$10 million and exploration spend of c.$20 million.

Decommissioning

Decommissioning expenditure was $9 million in the first half of 2024 (1H 2023: $44 million). The Group's decommissioning expenditure guidance related to decommissioning liabilities in the UK and Mauritania in 2024 is revised to $65 million as the Mauritania operated decommissioning campaign is expected to commence earlier than previously planned. This increase is offset by deferrals in Gabon, resulting in decommissioning expenditure guidance for 2024 remaining unchanged at c.$70 million net to Tullow.

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 2024, Tullow's hedge portfolio provides downside protection for c.60% of forecast production entitlements in the second half of 2024 with c.$60/bbl weighted average floors across all hedging instruments; for the same period, c.24% of forecast production entitlements is capped at weighted average sold calls of c.$112/bbl. A second tier of capped upside exists through three-way collars on 15% of the total hedged volume with weighted average sold calls of $83/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 $93/bbl on a weighted average basis.

For the period from January 2025 to June 2025, Tullow's hedge portfolio provides downside protection for c.45% of forecast production entitlements with c.$59/bbl weighted average floors, while c.27% is capped though three-way collars with weighted average sold calls at c.$92/bbl and re-participation in the upside above c.$102/bbl on a weighted average basis. For the period from July 2025 to December 2025, three-way collars provide downside protection for c.10% of forecast production entitlements with c.$60/bbl weighted average floors and c.$89-$99/bbl call spreads on a weighted average basis.

All financial instruments that are initially recognised and subsequently measured at fair value have been classified in accordance with the hierarchy described in IFRS 13 Fair Value Measurement. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets (Level 1). To the extent that market prices are not available, fair values are estimated by reference to market-based transactions or using standard valuation techniques for the applicable instruments and commodities involved (Level 2).

All of the Group's derivatives are Level 2 (2023: Level 2). There were no transfers between fair value levels during the year.

At 30 June 2024, the Group's derivative instruments had a net negative fair value of $32 million (1H23: net negative $79 million).

The following table demonstrates the timing, volumes and prices of the Group's commodity hedge portfolio at 30 June 2024:

Borrowings

On 15 May 2024, the Group made the annual prepayment of $100 million of the 2026 Notes.

The Group's total drawn debt reduced to $2.0 billion, consisting of $0.5 billion nominal value 2025 Notes, $1.4 billion nominal value 2026 Notes and $0.1 billion outstanding under a Secured Notes Facility.

Management regularly reviews options for optimising the Group's capital structure and may seek to refinance, retire or purchase any or all of its outstanding debt from time to time through new debt financings and/or cash purchases in open market purchases, privately negotiated transactions or otherwise.

Credit Ratings

Tullow maintains credit ratings with Standard & Poor's (S&P's) and Moody's Investors Service (Moody's).

Since December 2023, S&P has maintained Tullow's corporate credit rating at B- with negative outlook, and the rating of the 2026 Notes at B- and the rating of the 2025 Notes at CCC+. Similarly, Moody's has maintained Tullow's corporate credit rating at Caa1 with negative outlook, and the rating of 2026 Notes at Caa1 and the rating of the 2025 Notes at Caa2.

Underlying Operating Cash Flow and Free Cash Flow

Underlying operating cash flow amounted to $169 million (1H 2023: $188 million). Cash revenue of $97 million higher due to an additional cash lifting in the current period and impact of higher oil price, offset by $137 million higher cash taxes in the current period.

Free cash flow has increased to $(126) million (1H 2023: $(142) million) primarily due to a decrease in decommissioning spend in current period of $30 million and lower finance costs of $9 million. This is offset by the decrease in underlying operating cashflow of $19m as explained above.

Net Debt and Gearing

Net debt increased by $127 million during the period to $1,735 million at 30 June 2024 (FY 2023: $1,608 million), consisting of $493 million Senior Notes due 2025, $1,385 million Senior Secured Notes due 2026 and $130 million outstanding under a Secured Notes Facility less cash and cash equivalents.

The Gearing ratio has decreased to 1.4 times (1H 2023:1.7 times) due to an increase in Adjusted EBITDAX as explained above primarily due to movements in oil stock in the current period.

Ghana tax assessments

A further arbitration hearing was conducted in June 2024 in respect of the assessment for Branch Profits Remittance Tax (BPRT). This claim relates to the Ghana Revenue Authority (GRA) seeking to apply BPRT under a law which the Group considers is not applicable to Tullow Ghana Limited, since it falls outside the tax regime provided for in the Petroleum Agreements and relevant double tax treaties. Tullow referred this case to international arbitration in October 2021 and a decision from the panel is expected in the second half of the year. Tullow has two further ongoing disputed tax assessments that relate to the disallowance of loan interest deductions for the fiscal years 2010 - 2020 and proceeds received by Tullow Oil plc under Tullow's corporate Business Interruption Insurance policy. Both were referred to international arbitration in 2023, with first hearings scheduled for 2025, however 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 31 August 2025. The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group's producing assets and different outcomes on ongoing disputes or litigation.

Management has applied the following oil price assumptions for the going concern assessment:

• Base Case: $82/bbl for 2024, $78/bbl for 2025; and
• Low Case: $70/bbl for 2024, $70/bbl for 2025.

The Low Case includes, amongst other downside assumptions, a 10% production decrease and 10% increased operating costs compared to the Base Case. Management has also considered additional outflows in respect of all ongoing litigations/arbitrations within the Low Case, with an additional $111 million outflow being included for the cases expected to progress in the period under assessment. The Low Case does not include the outflow for the full exposure on Ghana BPRT arbitration of $320 million (refer to note 10 Ghana tax assessments for details). The remaining arbitration cases are not expected to conclude within the going concern period and no outflows have been included in that respect.

At 30 June 2024, the Group had $0.7 billion liquidity headroom consisting of $0.2 billion free cash and $0.5 billion available under the revolving credit facility, maturing in December 2024.

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 financings 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.

The Group's forecasts show that the Group will be able to operate within its current debt facilities and have sufficient financial headroom for the going concern assessment period under its Base Case and Low Case. The Directors have also performed a reverse stress test to establish the average oil price throughout the going concern period required to reduce headroom to zero, that price was determined to be $20/bbl. Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Thus, they have adopted the going concern basis of accounting in preparing the half year results.

2024 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 2023 Annual Report and are listed below.

• Business plan not delivered
• Asset integrity breach
• Value not unlocked
• Geopolitical risk
• Climate change
• Major accident event
• Insufficient liquidity and funding capacity to sustain business
• Capability cannot be attracted, developed or retained
• Compliance or regulatory breach
• Major cyber-disruption

The detailed descriptions of the principal risks and how they are being managed can be found on pages 52 to 56 in the 2023 Annual Report and Accounts.

Events since 30 June 2024

There have not been any events since 30 June 2024 that have resulted in a material impact on the interim results.

Rahul Dhir Richard Miller

Chief Executive Officer Chief Financial Officer

6 August 2024 6 August 2024

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 2024 which comprises of Condensed consolidated income statement, Condensed consolidated statement of comprehensive income and expense, Condensed consolidated balance sheet, Condensed statement of changes in equity, Condensed consolidated cash flow statement and the related notes 1 to 24. 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 2024 is not prepared, in all material respects, 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.

Basis for Conclusion

As disclosed in note 2, the annual financial statements of the group are 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 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.

Conclusions Relating to Going Concern

Responsibilities of the directors

Auditor's Responsibilities for the review of the financial information

Use of our report

Ernst & Young LLP

London

Condensed consolidated income statement

Six months ended 30 June 2024

Items that may be reclassified to the income statement in subsequent periods

Cash flow hedges

• 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.
• The hedge reserve represents gains and losses on derivatives classified as effective cash flow hedges.

Condensed consolidated cash flow statement

Six months ended 30 June 2024

Notes to the financial statements

Six months ended 30 June 2024

General information

The condensed financial statements for the six-month period ended 30 June 2024 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 2023, 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 2023 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 2023, a copy of which has been delivered to the Registrar of Companies. The auditor's report on these accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of an emphasis of matter and did not contain a statement under sections 498 (2) or (3) of the Companies Act 2006.

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 Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority (DTR) and the Transparency (Directive 2004/109/EC) Regulations 2007 as amended.

The accounting policies adopted in the 2024 half-yearly financial report other than for Goodwill, described below, are the same as those adopted in the Group's Annual Report and Accounts as at 31 December 2023.

Goodwill

The Group allocates goodwill to cash-generating units (CGUs) that represent the assets acquired as part of the business combination. Goodwill is tested for impairment annually as at 31 December and when circumstances indicate that the carrying value may be impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU (or group of CGUs) to which goodwill relates. When the recoverable amount of the CGU is less than it's carrying amount, an impairment loss is recognised. Impairment losses relating to goodwill cannot be reversed in future periods.

Going Concern

The Directors consider the going concern assessment period to be up to 31 August 2025. The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group's producing assets and different outcomes on ongoing disputes or litigation.

Management has applied the following oil price assumptions for the going concern assessment:

Base Case: $82/bbl for 2024, $78/bbl for 2025; and

Low Case: $70/bbl for 2024, $70/bbl for 2025.

The Low Case includes, amongst other downside assumptions, a 10% production decrease and 10% increased operating costs compared to the Base Case. Management has also considered additional outflows in respect of all ongoing litigations/arbitrations within the Low Case, with an additional $111 million outflow being included for the cases expected to progress in the period under assessment. The Low Case does not include the outflow for the full exposure on Ghana BPRT arbitration of $320 million (refer to note 10 Ghana tax assessments for details). The remaining arbitration cases are not expected to conclude within the going concern period and no outflows have been included in that respect.

At 30 June 2024, the Group had $0.7 billion liquidity headroom consisting of c.$0.2 billion free cash and $0.5 billion available under the revolving credit facility, maturing in December 2024.

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 financings and/or cash purchases, in open-market purchases, privately negotiated transactions or otherwise. Such refinancing 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.

Accounting policies continued

Going concern continued

The Group's forecasts show that the Group will be able to operate within its current debt facilities and have sufficient financial headroom for the going concern assessment period under its Base Case and Low Case. The Directors have also performed a reverse stress test to establish the average oil price throughout the going concern period required to reduce headroom to zero, that price was determined to be $20/bbl. Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Thus, they have adopted the going concern basis of accounting in preparing the half year results.

Earnings per share

The calculation of basic earnings per share is based on the profit for the period after taxation attributable to equity holders of the parent of $196.0 million (1H 2023: profit of $70.1 million) and a weighted average number of shares in issue of 1,455.5 million (1H 2023: 1,444.0 million).

The calculation of diluted earnings per share is based on the profit for the period after taxation as for basic 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 66.1 million resulting in a diluted weighted average number of shares of 1,521.6 million (1H 2023: 1,492.4 million).

Dividends

The Directors intend to recommend that no 2024 interim dividend be paid.

Approval of Accounts

These unaudited half year results were approved by the Board of Directors on 6 August 2024.

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, profit and certain asset and liability information regarding the Group's reportable business segments for the period ended 30 June 2024, 30 June 2023 and 31 December 2023.

• Segment result is a non IFRS measure which includes gross profit, exploration costs written off, impairment of property, plant and equipment. See reconciliation below.
• Unallocated expenditure and includes amounts of a corporate nature and not specifically attributable to a geographic area.
• Total liabilities - Corporate comprise the Group's external debt and other non-attributable liabilities.
• Segmental reporting continued

Reconciliation of segment result

• Segment result is a non IFRS measure which includes gross profit, exploration costs written off, impairment of property, plant and equipment. See reconciliation above.
• Unallocated expenditure includes amounts of a corporate nature and not specifically attributable to a geographic area.
• Total liabilities - Corporate comprise the Group's external debt and other non-attributable liabilities.

4.

Segmental reporting continued

• 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.
• Unallocated expenditure includes amounts of a corporate nature and not specifically attributable to a geographic area.
• Total liabilities - Corporate comprise of the Group's external debt, derivative financial instruments and other non-attributable liabilities.

4.

Segmental reporting continued

• Excludes derivative financial instruments and deferred tax assets.
• Total revenue

Finance income has been presented as part of net financing costs (refer to note 9).

Other costs

• Depreciation expense on leased assets of $42.4 million as per note 12 includes a charge of $0.7 million on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $41.7 million relates to other leased assets and is included within cost of sales.
• Refer to Page 5 of Finance Review and Note 16 for detailed explanations.
• The increase in other administrative costs is mainly due to one-off redundancy costs, payroll costs and phasing of costs.
• A previously recognised provision of $39.4 million relating to a potential claim arising out of historical contractual agreements has been released in the current period as no claim was raised.
• Net financing costs

Taxation on profit on continuing activities

The overall net tax expense of $171.3 million (1H 2023: $147 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 2024.

Based on a profit before tax for the first half of the year of $368 million (1H 2023: $217 million), the effective tax rate is 46.7% (1H 2023: 67.7%). 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 51.7% (1H 2023: 56.2%). In the UK there is net interest and hedging expenses of $123million (1H 2023: $80 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 $1,037.7 million (1H 2023: $989.4 million; FY23: $1,030.3 million) which includes $6.4 million of interest and penalties (1H 2023: $11.5million; FY23: $6.9million).

Provisions of $86.2million (1H 2023: $99.4 million; FY23: $85.0 million) are included in income tax payable ($78.7 million (1H 2023: $71.0 million; FY23: $78.3million)) and provisions $7.5million (1H 2023: $28.4 million; FY23: $6.7million)). 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 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 2023, giving rise to an overall increase in provision of $1.2 million and increase in contingent liability of $7.4million from 31 December 2023.

Ghana tax assessments

In October 2021, Tullow Ghana Limited ("TGL") filed a Request for Arbitration with the International Chamber of Commerce ("ICC") disputing the US$320 million branch profits remittance tax ("BPRT") assessment issued as part of the direct tax audit for the financial years 2014 to 2016. The Ghana Revenue Authority ("GRA") is seeking to apply BPRT under a law which the Group considers is not applicable to TGL, since it falls outside the tax regime provided for in the Petroleum Agreements and relevant double tax treaties. The parties have agreed a procedural timetable for the arbitration under which the first Tribunal hearing was held in October 2023, with a second hearing held in June 2024 and a decision from the panel is expected in the second half of the year.

In December 2022, TGL received a $190.5m 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. The parties have agreed a procedural timetable for the arbitration under which the first Tribunal hearing will be held in July 2025.

In December 2022, TGL received a $196.5m corporate income tax assessment and payment demand from the GRA relating to proceeds received by Tullow during the financial years 2016 to 2019 under Tullow's corporate Business Interruption Insurance policy. The Group considers the assessment to breach TGL's rights under its Petroleum Agreements. In February 2023, TGL filed a Request for Arbitration to the ICC, disputing the assessment with the suspension of TGL's obligation to pay any amount in relation to the assessment until the dispute is formally resolved. The parties have agreed a procedural timetable for the arbitration under which the first Tribunal hearing will be held in November 2025.

The Group continues to engage with the Government of Ghana with the aim of resolving all tax disputes on a mutually acceptable basis.

Taxation on profit on continuing 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 3,094m (c$37 million) requesting payment by 15 March 2020. However, under the Production Sharing Contract ("PSC"), the Government is required to indemnify TBL against all taxes levied by any public authority, and the share of production paid to Petrobangla ("PB"), Bangladesh's national oil company, is deemed to include all taxes due which PB is then obliged to pay to the NBR. TBL sent the payment demand to PB and the Government requesting the payment or discharge of the payment demand under their respective PSC indemnities. On 14 June 2021 TBL issued a formal notice of dispute under the PSC to the Government and PB. A further request for payment was received from NBR on 28 October 2021 demanding settlement by 15 November 2021. Arbitration proceedings were initiated under the PSC on 29 December 2021 and a hearing of the merits of the case were heard by the Tribunal on 20 May 2024. Further written submissions are expected to be made to the Tribunal by both parties during 2024.

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.

Intangible exploration and evaluation assets

The below table provides a summary of the exploration costs written off on a pre-tax basis by country.

• Current year expenditure on assets previously written off
• New Ventures expenditure is written off as incurred
• Write-off of indirect tax receivable

Kenya:

Discussions with the Government of Kenya (GoK) on securing government deliverables and 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. Since 1 January 2024, the review period for the FDP was extended to 31 December 2024. The Group expects a production licence to be granted once government due process has been completed.

On 22 May 2023, Africa Oil Corporation (AOC) and Total Energies (TE) gave notice of their respective withdrawal from the Blocks 10BA, 10BB and 13T Production Sharing Contracts (PSCs) and the Joint Operating Agreements (JOAs), effective 30 June 2023, quoting differing internal strategic objectives as reasons. The withdrawal is ultimately subject to the GoK's consent, at which stage the transaction will be considered completed and Tullow will have full 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, who is the only remaining Joint Venture Partner.

Intangible exploration and evaluation assets continued

In management's view, in light of public statements and announcements made by AOC and TE to this effect, and in accordance with the terms of the Joint Operating Agreement, it is considered that the 50% ownership held by AOC and TE was passed on 30 June 2023, resulting in Tullow holding 100%. From that date, Tullow has the right to benefit from the PI and is liable for all costs incurred going forward (except those for which the withdrawing parties remain liable for). As the sole party, Tullow can control and direct the use of the asset from 30 June 2023. The position remained unchanged as at 30 June 2024. Tullow accounted for this as asset acquisition at nil cost. An impairment assessment was performed at 31 December 2023, following the withdrawal of the partners and upward revision of oil prices which were identified as impairment assessment triggers. This resulted in an NPV significantly in excess of the book value. However, the Group has identified the following uncertainties in respect of the Group's ability to realise the estimated Value in Use (VIU); receiving and subsequently finalising an acceptable offer from a strategic partner and securing governmental approvals relating thereto, obtaining financing for the project and government deliverables in form of provision of required infrastructure and fiscal terms. These items require satisfactory resolution before the Group can take a Final Investment Decision (FID).

Due to the binary nature of these uncertainties, the Group was unable to either adjust the cash flows or discount rate appropriately. It therefore used its judgement to determine a risk-adjusted VIU to compare against the net book value of the asset which resulted in an impairment of $17.9 million being recognised as at 31 December 2023. Should the uncertainties around the project be resolved, there will be a reversal of a previously recorded impairment. However, if the uncertainties are not resolved there will be an additional impairment of $246.7 million.

At 30 June 2024, the uncertainties outlined have remained largely unchanged and no material modifications have occurred in the development. Therefore, no trigger for impairment or impairment reversal was identified.

• Licence relinquishments, expiry, planned exit or reduced activity
• Current year expenditure on assets previously written off
• Following VIU assessment subsequent to withdrawal of JV partners
• New Ventures expenditure is written off as incurred

• Current year expenditure on assets previously written off
• Following VIU assessment subsequent to withdrawal of JV partners
• Revision of short, medium and long-term oil price assumptions
• New Ventures expenditure is written off as incurred
• Unsuccessful well costs written off
• Property, plant and equipment

• The fields in the UK are grouped into one CGU as all fields share critical gas infrastructure.
• Change to decommissioning discount rate.
• Change to decommissioning estimate

• The fields in the UK are grouped into one CGU as all fields share critical gas infrastructure.
• Change to decommissioning estimate.

• The fields in the UK are grouped into one CGU as all fields within those countries share critical gas infrastructure.
• The remaining recoverable amount of the asset is its value in use.
• Increase in production and development costs.
• Revision of value based on revisions to reserves.
• Revision of short, medium and long-term oil price assumptions.
• Change to decommissioning estimate.
• Fully impaired right-of-use asset relating to a vacant office space.

The Group applied the following nominal oil price assumption for impairment assessments:

*At 1H 2024 there were no impairment assessments carried out as no triggers were identified.

Business combination

On 29 February 2024 the Group completed the Asset Swap agreement (ASA) transaction with Perenco Oil and Gas Gabon S.A ("Perenco"). The rationale for the Transaction is the simplification of the Group's equity ownership across key fields in Gabon, creating better alignment between the participating interest partners and streamlining processes such as budgeting, cost management and capital allocation. The revised portfolio of assets will enable Tullow to leverage its technical skills and focus on more material positions in key fields.

The transaction is an asset swap achieved through the exchange of participating interests held by both parties in certain licences in Gabon. The exchange represents the acquisition of an additional interest in a joint operation that constitutes a business and therefore IFRS 11 requires the application of the principles in IFRS 3 relating to business combinations.

In line with the requirements of IFRS 3, the interests transferred as part of the consideration, which comprises mainly of Property, Plant, and Equipment of $54.4 million, have been remeasured to the acquisition date fair value of $93.3 million. This has resulted in an asset revaluation gain of $38.9 million recognised in the income statement at 30 June 2024.

The below table shows the pre completion and post completion equities in the licences subject to the transaction:

The exchange of the transferred interests between the parties was deemed for all purposes to be made with effect from the economic date of 1 February 2023 but completed on 29 February 2024 and this is therefore the acquisition date. The transaction was intended to be cash neutral on the economic date as the fair value of the assets exchanged were considered to be equal at that time and therefore no additional consideration would have been payable by either party at that time. However, as the transaction completed more than a year later, the ASA included provisions to ensure the neutrality of the transaction via cash adjustments for the period between the economic date and the completion date, the agreed adjustment upon completion was $8.1 million which has been included within investing activities in the cash flow statement.

The fair values of the identifiable assets and liabilities acquired were:

Fair value recognised on acquisition $m

Business combination continued

Valuation methodology and assumptions

The fair value of the purchase consideration of $93.3 million reflects the discounted future cash flows of the assets and liabilities exchanged as part of the swap as the transaction is intended to be value neutral. Provisions represent the present value of decommissioning costs which are expected to be incurred after the end of the licence in 2046.

Goodwill of $44.9 million was recognised upon acquisition due to the requirement of IAS 12 to recognise a deferred tax liability or asset for the difference between the fair value of the assets acquired and liabilities assumed, and their respective tax bases. Therefore, goodwill has arisen as a direct result of the recognition of the deferred tax liability. None of the goodwill is deductible for income tax purposes.

The disclosure requirement of IFRS 3 in relation to contributions to revenue and profit or loss have not been included as they are impracticable to obtain due to Tullow not being the operator of the assets.

No material acquisition-related costs were incurred in relation to the transaction.

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 2024 of $91.6 million (1H 2023: $164.0 million; FY 2023: $43.5 million) relates to June 2024 gross gas sales in Ghana ($75.4m) and oil liftings in Gabon ($11.7m) and Cote D'Ivoire ($4.5m).

Other assets

The movement between current and non-current amounts due from joint venture partners is mainly driven by the receivables relating to the TEN FPSO lease and loan balances in Ghana.

Underlifts of $11.1 million as at 30 June 2024 are due to the timing of liftings and are mainly attributable to the Jubilee field in Ghana.

Inventories

The increase in oil stock from 31 December 2023 is driven by an increase in Gabon of $39.0 million due to timing of liftings and a $32.1m stock increase in Ghana.

Cash and cash equivalents

Short- term deposits and other cash equivalents include an amount of $59.1 million (1H 2023: $53.1 million; FY 2023: $36.9 million) which the Group holds as operator in joint venture bank accounts. Included within cash at bank is $8.9 million (1H 2023: $4.5 million; FY 2023: $4.5 million) of restricted cash held as collateral for performance bonds issued in relation to exploration activities.

Trade and other payables

Accruals mainly relate to capital expenditure, interest expense on bonds and loans and staff related expenses.

Other non-current liabilities include balances related to JV Partners.

Trade and other payables are non-interest bearing except for leases.

The movement between current and non-current portion of leases is driven by TEN FPSO (Ghana). In 2H 2023, a decision was made to not exercise the option to purchase the TEN FPSO in April 2024, and the lease accounting assumptions were updated to reflect the best estimate view that the FPSO will continue to be leased until cessation of production in 2032.

Payables related to operated joint ventures (primarily related to Ghana and Kenya) are recorded gross with the debit representing the partners' share recognised in amounts due from joint venture partners (note 15). The change in trade payables and in other payables predominantly represents timing differences and levels of work activity.

Borrowings

The Group's capital structure includes $1.4 billion senior secured notes due in May 2026 (2026 Notes), $0.5 billion senior notes due in March 2025 (2025 Notes), a $0.4 billion Secured Notes Facility and an undrawn $500 million Super Senior Revolving Credit Facility (SSRCF) which will primarily be used for working capital purposes. 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 2024, the Group made the annual prepayment of $100 million of the 2026 Notes.

The 2025 Notes are due in a single payment in March 2025.

The SSRCF, maturing in December 2024, comprises of (i) a $500 million revolving credit facility and (ii) a $100 million letter of credit facility. The revolving credit facility remains undrawn as at 30 June 2024. Letters of credit amounting to $4 million (FY 2023: $10 million) have been issued under the facility.

Unamortised debt arrangement fees for the 2026 Notes, 2025 Notes, Secured Notes Facility and the SSRCF are $12.3 million (FY 2023: $14.3 million), $3.3 million (FY 2023: $3.6 million), $12.2 million (FY 2023: $5.0) and $1.0 million (FY 2023: $2.3 million) respectively.

The 2026 Notes, the Secured Notes Facility and the SSRCF 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, adjust the dividend payment to shareholders, 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.

SSRCF covenants

The SSRCF does not have any financial maintenance covenants. Availability under the $500 million cash tranche of 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. SSRCF debt capacity is calculated as 2P NPV divided by 1.1x less senior secured debt outstanding.

Borrowings continued

2025 Notes and 2026 Notes covenants

The 2025 Notes and 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 2025 Notes and/or 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.

Tullow is permitted to incur debt to refinance the 2025 Notes on a like-for-like basis, i.e. subordinated to the 2026 Notes.

Tullow is permitted to make payments towards the 2025 Notes amounting to the greater of $100 million per year and 50% of the Consolidated Net Income of the Group for the period from 1 January 2021 to the end of the most recently completed fiscal half-year for which internal financial statements are available if, after giving pro forma effect to the payment(s), the 2P Reserves Coverage Ratio is equal to or greater than 1.5 times.

Tullow is permitted to make payments towards the 2025 Notes amounting to the greater of $100 million per year, 50% of the Consolidated Net Income of the Group for the period from 1 January 2021 to the end of the most recently completed fiscal half-year for which internal financial statements are available and 100% of Consolidated Cash Flow per year if, after giving pro forma effect to the payment(s), the 2P Reserves Coverage Ratio is equal to or greater than 2.0 times and the Consolidated Leverage Ratio is less than 1.5 times.

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 SSRCF and the 2026 Notes on a like-for-like basis.

Tullow is permitted to refinance the 2025 Notes with new indebtedness which is unsecured and ranks junior to the Secured Notes Facility.

Provisions

Other provisions include non-income tax provision and disputed cases and claims. 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, this provision has been released in the current period as no claim arose in respect of the agreement.

The decommissioning provision represents the present value of decommissioning costs relating to the European 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.

In 2024, the discount rate applied to the decommissioning provisions increased to 4.5% driven by an increase in the 10- and 20-year US Treasury Bills' rates. This resulted in an overall decrease in decommissioning provisions.

Called up share capital and share premium

As at 30 June 2024, the Group had in issue 1,458.0 million allotted and fully paid ordinary shares of GBP 10 pence each (1H 23: 1,448.3 million, FY 2023: 1,452.5million).

In the six months ended 30 June 2024, the Group issued 5.5 million shares in respect of employee share options (1H 23: 8.7 million; FY 2023: 12.9 million new shares in respect of employee share options).

Contingent Liabilities

• Performance guarantees are in respect of abandonment obligations, committed work programmes and certain financial obligations.
• 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.
• Events since 30 June 2024

There have not been any events since 30 June 2024 that have resulted in a material impact on the interim results.

Cash flow statement reconciliations

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, Norwegian tax refund 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.

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 2024 was $146.7 million current and $655.5 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.

• Non-cash adjustments include unamortised arrangement fees which are incurred on creation or amendment of borrowing facilities.
• Cash and cash equivalents include an amount of $59 million (1H 2023: $53.1 million) which the Group holds as operator in joint venture bank accounts. Included within cash at bank is $9 million (1H 2023: $4.5 million) of restricted cash held as collateral for performance bonds issued in relation to exploration activity.

Gearing and Adjusted EBITDAX

Gearing is a useful indicator of the Group's indebtedness, financial flexibility and capital structure and can assist securities analysts, investors and other parties to evaluate the Group. Gearing is defined as net debt divided by adjusted EBITDAX. 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)/credit, finance costs, finance revenue, gain on hedging instruments, depreciation, depletion and amortisation, share-based payment charge, restructuring costs, gain/(loss) on disposal, 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.

• Last 12 months (LTM). Refer to the 2023 Annual Report and Accounts and 2023 Half year results for a full reconciliation of 2023 and 1H 2023 Adjusted EBITDAX.

Underlying cash operating costs

Underlying cash operating costs is a useful indicator of the Group's costs incurred to produce oil and gas. Underlying cash operating costs eliminates certain non-cash accounting adjustments to the Group's cost of sales to produce oil and gas. Underlying cash operating costs is defined as cost of sales less operating lease expense, depletion and amortisation of oil and gas assets, underlift, overlift and oil stock movements, share-based payment charge included in cost of sales, royalties and certain other cost of sales. Underlying cash operating costs are divided by production to determine underlying cash operating costs per boe.

In 2024 and 2023, 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.

• 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.
• 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.
• Other cost of sales includes purchases of gas from third parties to fulfil gas sales contracts and royalties paid in cash.
• Non-recurring costs include O&M (Operations & Maintenance) costs, facility projects costs, oil spill response, and Refrigeration compressor motor repairs.

Free cash flow

Free cash flow is a useful indicator of the Group's ability to generate cash flow to fund the business and strategic acquisitions, reduce borrowings and provide returns to shareholders through dividends. Free cash flow is defined as net cash from operating activities, and net cash from/(used) in investing activities, repayment of obligations under leases, finance costs paid and foreign exchange gain/(loss).

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.

Management Presentation - WEBCAST - 9:00 BST

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