Tullow Oil Regulatory News (TLW)

Tullow oil PLC - 2022 Half Year Results

14 September 2022 - Tullow Oil (Tullow) announces its Half Year results for the six months ended 30 June 2022. Tullow will host a webcast presentation at 9am this morning, details of which can be found on the last page of this announcement and online at www.tullowoil.com

Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented today:

"The turnaround of Tullow has gained momentum in the first half of 2022, with solid production from our West African portfolio driving stronger financial performance. We added material, unhedged production in Ghana through the pre-emption of the Kosmos-Oxy deal and took over the Operations & Maintenance (O&M) of the Jubilee FPSO to ensure that we can sustain the good operating performance and deliver further operating cost improvements. Our drilling programme has been very efficient and at current performance levels we will be able to deliver our planned programme of wells through next year with just one rig.

The Board of Tullow remains fully committed to the merger with Capricorn which continues to be recommended by both the Tullow and Capricorn Boards on the current terms. We firmly believe that the proposed merger has the potential for material value creation by implementing a combined business plan which accelerates investment in key projects and delivers very significant synergies.

We have a high quality, opportunity rich portfolio, a clear and disciplined growth strategy and an improving balance sheet. The Board looks to the future with confidence, and I look forward to sharing further details at a capital markets day."

2022 First half results summary

· Group working interest production for the first half of 2022 averaged 60.9 kboepd, in line with expectations.

· Ghanaian drilling programme ahead of schedule, having completed two previously drilled wells and drilled and completed another three wells. A further six wells are expected to be drilled and two of these completed by year-end.

· Operational delivery: continued strong FPSO uptime (Jubilee c.95% and TEN c.99%), gas export (averaging c.90 mmscfd) and water injection (Jubilee c.170 kbwpd and TEN c.65 kbwpd).

· Reserves of 242 million barrels as of 30 June, valued at c.$4.7 billion after hedging (c.$5.3 billion before hedging)[1].

· Revenue of $846 million with realised oil price of $87/bbl after hedging; gross profit of $620 million; profit after tax of $264 million; underlying operating cash flow of $165 million.

· First half free cash flow of $(205) million (negative), which includes an arbitration payment of $76 million (outflow), Uganda FID payment of $75 million (inflow) and Ghana pre-emption consideration of $126 million (outflow), but excludes the benefit of over $200 million revenue relating to two Ghana liftings, which took place in early June but for which cash was received shortly after 30 June 2022, on 1 and 5 July respectively.

· Capital investment in the first half of 2022 was c.$156 million plus decommissioning costs of c.$29 million.

· Net debt at 30 June 2022 of c.$2.3 billion; Gearing reduced to 1.9x net debt/EBITDAX; liquidity headroom and free cash of $0.6 billion.

· Pre-emption of Deep Water Tano component of Kosmos Energy/Occidental Petroleum Ghana transaction successfully completed.

· Announcement of recommended all-share combination of Tullow Oil plc and Capricorn Energy plc.

[1] Note: The NPV10 valuation is calculated in accordance with the terms of the indenture for the issuance of 10.25% Senior Secured Notes due 2026 by Tullow Oil plc ("Tullow") dated 17 May 2021 (the "Indenture"). Tullow has agreed with the Takeover Panel that an independent valuation report prepared in accordance with Rule 29 of the City Code on Takeovers and Mergers (the "Takeover Code") will be included in the scheme document when published by Capricorn Energy plc in connection with its recommended merger with Tullow (the "Merger"). The publication of this independent reserves report in connection with the Merger, or any other independent reserves report required by the Takeover Code, should not be construed as a commitment to publish any such report in the future.

Key financial results

1 Excludes the benefit of over $200 million revenue relating to two Ghana liftings which took place in early June but for which cash was received shortly after 30 June 2022, on 1 and 5 July respectively.

2022 Guidance

· Group working interest production narrowed to 60-64 kboepd.

· Full year capital investment and decommissioning spend of c.$380 million and c.$100 million, respectively. Increase of $30 million associated with additional equity following pre-emption in Ghana.

· Full year underlying operating cashflow expected to be c.$950 million, assuming an average oil price of $95/bbl. Post all costs, Tullow forecasts full year free cash flow of c.$200 million and gearing of

· Free cash flow guidance includes the c.$75 million contingent consideration in relation to Tullow's sale of its assets in Uganda to TotalEnergies, a payment of c.$76 million in relation to the arbitration award in favour of HiTec Vision regarding the purchase of Spring Energy in 2013 and a c.$126 million payment for the completion of the pre-emption related to the sale of Occidental Petroleum's interests in the Jubilee and TEN fields in Ghana to Kosmos Energy.

MERGER WITH CAPRICORN ENERGY

On 1 June 2022 Tullow announced that it had reached agreement with Capricorn Energy on the terms of an all-share merger to create a leading African energy company with a material and diversified asset base and a portfolio of investment opportunities delivering visible production growth. This recommended merger will enable the new company to develop and implement a new business plan that accelerates the development of new, material opportunities, realise meaningful cost synergies and deliver a combined group with robust cash generation and a resilient balance sheet. The combined group will also have a sustainable capital returns programme and a deep commitment to environmental stewardship, social investment, development of local content and its national workforces.

Tullow expects to host a Capital Markets Day for investors and issue a circular and prospectus in connection with the recommended merger in the fourth quarter, ahead of a shareholder vote, followed by completion of the transaction before the end of the year.

ESG

Net Zero 2030

Tullow is committed to becoming a Net Zero Company by 2030 on its Scope 1 and 2 emissions. This will be achieved through a number of decarbonising activities to eliminate flaring on its operated assets in Ghana, working closely with our partners to eliminate flaring on our non-operated assets, and pursuing a nature-based carbon removal programme to off-set hard to abate emissions.

Over the next few years, Tullow has defined plans to reduce its carbon emissions from its operations through an increase in the gas handling capacity on Jubilee and process modifications on TEN. These investments are included in the Group's Business Plan and will put the Group on track to eliminate routine flaring in Ghana by 2025. Project Oil Kenya will align with Tullow's Net Zero 2030 target through limiting carbon emissions and offsetting any hard to abate emissions. Through our Net Zero Task Force, Tullow also continues to track progress on initiatives being delivered, and funded, by non-operating partners.

To offset the residual hard-to-abate carbon emissions, progress continues to be made in identifying nature-based carbon removal projects. A Feasibility Study has been completed, identifying a significant scale opportunity covering the Western Transitional Zone in Ghana. Tullow is in the process of finalising a Letter of Intent with the Forestry Commission, detailing key activities and information requirements to inform a Final Investment Decision (FID).

Operational UPDATE

Production

Group working interest production averaged 60.9 kboepd in the first half of 2022, in line with expectations. Full year production guidance for 2022 has been narrowed from 59-65 kboepd to 60-64 kboepd.

Ghana

The ongoing drilling programme that started in April 2021 has delivered eight new wells, six at Jubilee and two at TEN, at an average cost of c.$50 million per well (more than 10% below the average expected cost for these wells) and ahead of schedule. In addition, two existing wells have been completed, one at Jubilee (J12-WI) and one at TEN (En16-WI).

The first of the two strategic riser base wells (Nt10-P) was drilled to define the extent of the Ntomme reservoir and found good quality reservoir sands, but was water bearing. The second well (Nt11-P) is planned to target a different objective later this year and will help define future drilling and infrastructure plans for the TEN Enhancement Project. The rig is currently drilling and completing a producer well on Enyenra (En21-P), before moving across to Nt11-P.

The drill programme is ahead of schedule. If the current pace of drilling continues, the next phase of drilling at Jubilee, which includes wells to be tied into Jubilee South East infrastructure, is expected to be accelerated into the fourth quarter of 2022. At current performance levels, we will be able to deliver the planned programme of wells through next year with one rig. Accordingly, the joint venture partners have agreed to defer a decision regarding a second rig in Ghana.

Gross production from the Jubilee field averaged c.82.4 kbopd (net: c.30.8 kbopd) in the first half of the year, representing an increase of more than 15% compared to the first half of 2021. This is due to good well and operational performance, which included the successful completion of the planned, biennial maintenance shutdown of the Jubilee FPSO in May. Full year net production guidance for Jubilee is 32kbopd. Gross production from the TEN field averaged c.24.3 kbopd (net: c.12.5 kbopd) in the first half of the year, in line with expectations. Full year net production guidance for TEN is 13kbopd, with the expectation of an increase in production rates when the En21-P well comes onstream in the fourth quarter.

On the Jubilee FPSO, a handover of Operations & Maintenance (O&M) from the O&M Contractor to Tullow was successfully completed at the end of June. This transition will allow Tullow to deliver sustained FPSO safety and reliability performance for the long term, as well as help deliver planned reductions in the operating cost base and emissions.

Non-operated portfolio

Net production from the non-operated portfolio averaged c.17.6 kboepd in the first half of 2022, in line with expectations. Full year net production guidance for the non-operated portfolio is c.17 kboepd.

Production from Gabon averaged c.15.5 kbopd in the first half of 2022, with Simba being the highest contributor. A long-term appraisal well test at the Tchatamba field is underway and expected to see first oil in September 2022. Infill drilling campaigns continue at the Ezanga Complex and Oba field.

Production from Côte d'Ivoire averaged c.2.1 kboepd in the first half of 2022. A 45 day shutdown of the Espoir FPSO is now planned from October 2022, in which cargo tank maintenance and remediation work, which is required for vessel class certification, will be carried out. Tullow continues to engage with the operator, CNR International, to define the appropriate longer-term course of action for the FPSO.

Decommissioning

The Group's operated and non-operated decommissioning programmes in the UK and Mauritania are ongoing. The majority of operational work is expected to be completed by the end of 2025, with environmental and monitoring surveys to continue from 2026. The expected remaining UK and Mauritania decommissioning exposure over 2022-26 is c.$145 million, with c.$100 million forecasted in 2022. The final exposure may vary depending on the final required scope and work programmes agreed across the various projects.

Tullow expects to pay c.$30 million per annum for the decommissioning of producing assets in Ghana and parts of the non-operated producing portfolio.

Kenya

A process to secure a strategic partner for the development project in Kenya is ongoing and Tullow is confident that substantial progress will be made before the end of the year. Following the recent elections, Tullow and its joint venture partners will work with the new government to progress the project which has the potential to make a significant contribution to the Kenyan economy through taxation, revenue sharing, employment and local content.

Exploration

All of the Group's exploration activity is guided by an overlay of rigorous cost discipline. In Tullow's core area of West Africa, the exploration team is focused on maturing near-field and infrastructure-led exploration (ILX) opportunities around existing producing fields, to unlock additional value from the Group's asset base.

In Côte d'Ivoire, Tullow, together with its JV Partner PetroCi, has elected to proceed into the second exploration phase in Block CI-524. This block presents a unique opportunity to realise operational synergies during the exploration phase and in the event of discoveries due to Tullow's deep understanding of the area and its proximity to the Group's producing fields.

In Gabon, focus is on strengthening the prospective resource base within the Simba licence where several low-risk and compelling investment options adjacent to infrastructure have been identified and will be considered for future drilling programmes.

Tullow also continues to focus on unlocking value from its prospective resource base in the emerging basins of Guyana and Argentina, while seeking to mitigate capital exposure from historical work commitments in Argentina of c.$25 million through farm-down. In Argentina a two year extension has been granted in Block MLO-122.

Operational activity in the first half of 2022 included the drilling of the Beebei-Potaro exploration well in the Repsol operated Kanuku Block offshore Guyana. This commitment well encountered good quality reservoir in the primary and secondary targets, but both targets were water bearing and the well has been plugged and abandoned. Tullow is integrating the well results into its regional subsurface models and is working with its joint venture partners before deciding on next steps.

During the first half of 2022, the Group has written off exploration costs of $87 million (1H 2021: $49 million) which are predominantly driven by write-offs resulting from the Beebei Potaro well.

FINANCE REVIEW

1Underlying cash operating costs per boe, capital investment, adjusted EBITDAX, net debt, gearing, free cash flow, underlying operating cash flow and pre-financing free cash flow are alternative performance measures (APM) and are explained and reconciled on pages 39 to 42.

Production and commodity prices

Total Group working interest production averaged 60,856 boepd (1H 2021: 61,230 boepd). The marginal decrease in production primarily resulted from the 15 day maintenance shutdown of the Jubilee facility, the natural decline in TEN and the sale of Equatorial Guinea and the Dussafu asset in Gabon in 1H21, offset by increased Jubilee production outside the maintenance shutdown period.

The realised oil price after hedging for the period was $86.5/bbl (1H 2021: $60.8/bbl) and before hedging $106.9/bbl (1H 2021: $65.2/bbl). The higher realised oil prices have been sustained during 2H21 and 1H22 offset by hedge losses, decreasing total revenue by $189.6 million (1H 2021: decrease of $52.4 million).

The underlift in the income statement was mainly due to the increase in oil prices and stock positions in Gabon and Ghana as well as the delay in lifting due the Cap Lopez terminal spillage in Gabon.

Higher oil prices combined with oil entitlements have led to a 93% increase in gross profit for the period.

Operating costs, depreciation and expenses

Underlying cash operating costs amounted to $143 million; $13.0/boe (1H 2021: $143 million; $12.9/boe). The cash unit operating costs has remained unchanged against the comparative period. However this is due to disposal of Equatorial Guinea and Dussafu asset in Gabon in 1H21 offset by the shutdown in Jubilee in Ghana and the Simba expansion project costs in Gabon.

Normalised cash operating costs which exclude COVID-19 operating procedures, shuttle tanker operations, CSV campaign and shutdown costs were $11.6/boe (1H 2021: $12.5/boe). Refer to page 41 for the reconciliation as an APM.

Higher equities in Jubilee and TEN following the pre-emption in 1H22 also contributed to the increase in total operating costs.

DD&A charges before impairment on production and development assets amounted to $177 million; $16.1 /boe (1H 2021: $170 million:$15.3/boe). This increase in DD&A per barrel is mainly attributable to Ghana pre-emption which was effective 1Q22, offset by 2021 impairments.

Administrative expenses of $23 million (1H 2021: $23 million) has remained unchanged against the comparative period mainly due to an increase in professional fees offset by a favourable GBP:USD FX variance in 2022 and a decrease to the administrative assets' depreciation. Tullow delivered $238 million in net cash costs savings since mid-2020 to date.

The Group recognised a net impairment charge on PP&E of $7 million in respect of first half 2022 (1H 2021: $8million) due to changes to estimates on the cost of decommissioning for certain UK and Mauritania assets.

During the first half of 2022, the Group has written off exploration costs of $87 million (1H 2021: $49 million) which are predominantly driven by write-offs the Beebei Potaro commitment well in Guyana which has been plugged and abandoned following the completion of the well.

Gain on bargain purchase

On 17 March 2022 the Group completed the pre-emption related to the sale of Occidental Petroleum's interests in the Jubilee and TEN fields in Ghana to Kosmos Energy. As a result of this acquisition, the Group's interest in the TEN fields increased from 47.18% to 54.84%, and from 35.48% to 39.0% in the Jubilee field. The difference between the fair value of net assets acquired and consideration paid was recognised within the income statement as gain on bargain purchase of $197 million. Refer to note 18. Business combination.

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 2022, Tullow's hedge portfolio provides downside protection for 66% of forecast production entitlements (after pre-emption) through to May 2023 and 41% for a further 12 months to May 2024 with $51/bbl floors and weighted average sold calls of $78/bbl for the remainder of 2022, and $55/bbl floors and weighted average sold calls of c.$75/bbl in 2023 and 2024.

At 30 June 2022, the Group's derivative instruments had a net negative fair value of negative $573 million (30 June 2021: negative $148 million).

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. 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.

All of the Group's derivatives are Level 2 (1H 2021: Level 2). There were no transfers between fair value levels during the year.

Borrowings

In May, the Group made a mandatory prepayment of $100 million of the Senior Secured Notes due 2026, which reduced total debt to $2.5 billion. As at 30 June 2022 net debt was $2,336 million (30 June 2021: $2,290 million). Management regularly reviews options for optimising the Group's capital structure and may purchase outstanding debt securities or repay debt from time to time in open-market purchases and/or privately negotiated transactions, and upon such terms and at such prices as it may determine.

Net financing costs

Net financing costs for the period were $149 million (1H 2021: $157 million). The decrease in financing costs is mainly due to $19 million fees incurred in 1H 2021 in relation to the refinancing of the RBL facility, a decrease of $5 million in interest on obligations under finance leases due to a decrease in lease liability position, offset by a $14 million increase in interest on borrowings.

Net financing costs include interest incurred on the Group's debt facilities, foreign exchange gains/losses, the unwinding of discount on decommissioning provisions, and the net financing costs associated with lease assets. These costs are offset by interest earned on cash deposits. A reconciliation of net financing costs is included in Note 9.

Taxation

The overall net tax expense of $284 million (1H 2021: $120 million) primarily relates to expenses in respect of Ghana and West Africa non-operated assets net of non-recurring deferred tax credits associated with exploration write-offs, impairments and onerous lease provisions. 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 2022. 

The Group's statutory effective tax rate is 51.8% (1H 2021: 56.4%). After adjusting for the non-recurring amounts related to exploration write-offs, impairments, restructuring costs, disposals and onerous lease provisions and their associated tax benefit, the Group's underlying effective tax rate is 62.0% (1H 2021: (83.1%)). The change in effective tax rate from 1H21 to 1H22 is due primarily to there being no tax benefit from net interest and hedging expenses, representing a smaller proportion of the Group's overall profits in 1H22 than in 1H21. Non-deductible expenditure in Ghana and a change to the mix of taxable and non-taxable profits in Gabon are additional contributing factors.

Profit after tax from continuing activities and earnings per share

The profit after tax for the period amounted to $264 million (1H 2021: $93 million). Basic earnings per share was 18.4 cents (1H 2021: basic earnings per share of 6.5 cents).

Capital investment

Capital expenditure amounted to $156 million (1H 2021: $101 million) with $135 million invested in production and development activities and $21 million invested in exploration and appraisal activities.

Capital investment will continue to be carefully controlled in the second half of 2022 and total 2022 capital expenditure is expected to be c.$380 million. The capital investment total is expected to comprise Ghana capex of c.$300 million, including an increase of $30 million associated with additional equity following pre-emption in Ghana, West African non-operated capex of c.$30 million, Kenya capex of c.$5 million and exploration spend of c.$45 million.

Going concern

The Directors consider the going concern assessment period to be up to 30 September 2023. 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. For the assessment, management has excluded the liquidity enhancing impact of the recommended merger with Capricorn Energy PLC within its base case as it provides a more conservative assessment.

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

Base Case: $100/bbl for 2022, $90/bbl for 2023; and

Low Case: $80/bbl for 2022, $70/bbl for 2023.

The Low Case includes, amongst other downside assumptions, a 5 per cent production decrease compared to the Base Case as well as increased outflows associated with an ongoing dispute.

The Group had $0.6 billion liquidity headroom of unutilised debt capacity and free cash as at 30 June 2022. 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. 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.

2022 principal risks and uncertainties

The Company risk profile has been closely monitored throughout the year, with consideration given to the risks to delivering the revised 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 principal risks and uncertainties facing the Group at half year remain unchanged from those disclosed in the 2021 Annual Report as listed below.

1.  Risk of failure to deliver production targets

2.  Risk of a major EHS incident

3.  Risk of failure to unlock value

4.  Risk of failure to manage geopolitical risks

5.  Risk of failure to manage climate change risks

6.  Risk of insufficient liquidity and funding capacity

7.  Risk of failure to develop, retain and attract capability

8.  Risk of compliance or regulatory breach

9.  Risk of major cyber attack

Events since 30 June 2022

Tullow Ghana Limited has awarded a 5-year contract to Petrofac Ghana (Petrofac) to support Operations and Maintenance activities on the FPSO Kwame Nkrumah (KNK) following the expiry of Tullow's contract with MODEC Production Services Ghana JV Ltd (MODEC) which ended on 30 June 2022. Tullow and MODEC worked on a smooth transition of O&M services and achieved a seamless transition on 1 July 2022.

On 5 August 2022, it was announced that the Beebei Potaro well, offshore Guyana has been plugged and abandoned after encountering good quality reservoir in the primary and secondary targets, but both targets were water bearing.

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,

Rahul Dhir

Chief Executive Officer

13 September 2022

Richard Miller

Interim Chief Financial Officer

13 September 2022

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

We conducted our review in accordance with 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 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 UK adopted International Accounting Standard 34, "Interim Financial Reporting".

Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis of Conclusion section of this report, nothing has come to our attention to suggest that management have inappropriately adopted the going concern basis of accounting or that management have identified material uncertainties relating to going concern that are not appropriately disclosed.

This conclusion is based on the review procedures performed in accordance with this ISRE, however future events or conditions may cause the entity to cease to continue as a going concern.

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 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 our Conclusions Relating 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.

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

13 September 2022

Condensed consolidated income statement

Six months ended 30 June 2022

Condensed consolidated statement of comprehensive income and expense

Six months ended 30 June 2022

Condensed consolidated balance sheet

As at 30 June 2022

1Refer to note 19 for details on prior period restatement.

Condensed statement of changes in equity

As at 30 June 2022

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, and exchange gains or losses arising on long-term foreign currency borrowings which are a hedge against the Group's overseas investments.

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

3 On 12 July 2021 Tullow repaid the $300 million Convertible Bond due 2021 (note 20). As the conversion option was not exercised, the equity component of $48.4 million has been transferred from the separate reserve to retained earnings.

Condensed consolidated cash flow statement

Six months ended 30 June 2022

1 On 17 May 2021, as part of the refinancing transaction $309.8 million was agreed to be put into a trustee account for settlement of principal and accrued interest of the convertible loan notes on due date. On 12 July 2021 the convertible loan notes were settled by the trustees by utilising the amount kept in the trust account. This this has been disclosed as a financing activity within the cash flow statement.

Notes to the condensed financial statements

Six months ended 30 June 2022

1. General information

The condensed financial statements for the six-month period ended 30 June 2022 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 2021, 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 2021 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 2021, 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.

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 accounting policies adopted in the 2022 half-yearly financial report are the same as those adopted in the Group's Annual Report and Accounts as at 31 December 2021, except business combinations which is disclosed in Note 18. There was no business combination in the previous year. 

The Directors consider the going concern assessment period to be up to 30 September 2023. 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. For the assessment, management has excluded the liquidity enhancing impact of the recommended merger with Capricorn Energy PLC within its base case as it provides a more conservative assessment.

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

Base Case: $100/bbl for 2022, $90/bbl for 2023; and

Low Case: $80/bbl for 2022, $70/bbl for 2023.

The Low Case includes, amongst other downside assumptions, a 5 per cent production decrease compared to the Base Case as well as increased outflows associated with an ongoing dispute.

The Group had $0.6 billion liquidity headroom of unutilised debt capacity and free cash as at 30 June 2022. 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. 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.

3. Earnings per ordinary 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 $263.9 million (1H 2021: profit of $92.7 million) and a weighted average number of shares in issue of 1,435.3 million (1H 2021: 1,421.3 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 45.7 million resulting in a diluted weighted average number of shares of 1,481.0 million.

4. Dividends

The Directors intend to recommend that no 2022 interim dividend be paid.

5. Approval of accounts

These unaudited half year results were approved by the Board of Directors on 13 September 2022.

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 including Uganda 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 2022, 30 June 2021 and 31 December 2021.

1The basis of allocation of the loss on realisation of the cash flow hedges presented in the "Sales revenue by origin" line was incorrectly classified within Ghana and Non-Operated segment in the prior period. This has now been allocated to the Corporate reportable segment. For the comparative periods, the allocation for the year ended 31 December 2021 increased revenue for Ghana and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the hedging loss of $152.9 million was allocated to Corporate. For the six months ended 30 June 2021, revenue for Ghana and Non-Operated increased by $33.8 million, and $18.6 million, respectively, with the hedging loss of $52.4 million allocated to Corporate.

2Segment result is a non-IFRS measure which includes gross profit, exploration costs written off and impairment of property, plant and equipment. See reconciliation below.

3 This is included within the Restructuring costs and other provisions in the Group Income Statement.

4 Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area.

5 Total liabilities - Corporate comprise of the Group's external debt, derivative financial instruments and other non-attributable liabilities.

6. Segmental reporting continued

Reconciliation of segment result

1 Segment revenue and segment result allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classification of loss on realisation of the cash flow hedges within reportable segments. Total balances have remained unchanged.

The allocation for the six months ended 30 June 2021, revenue for Ghana and Non-Operated increased by $33.8 million, and $18.6 million, respectively, with the hedging loss of $52.4 million allocated to Corporate.

2 Total assets and total liabilities allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classification of tax assets and liabilities within reportable segments. The above balances have been restated by:

3 Non-operated segment includes release of $15.3 million indirect tax provision following settlement.

6. Segmental reporting continued

1 Segment revenue and segment result allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classification of loss on realisation of the cash flow hedges within reportable segments. Total balances have remained unchanged.

The allocation for the year ended 31 December 2021 increased revenue for Ghana and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the hedging loss of $152.9 million was allocated to Corporate.

2Total assets and total liabilities allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classification of tax assets and liabilities within reportable segments. The above balances have been restated by:

3 Non-operated segment includes release of $15.3 million indirect tax provision following settlement.

6. Segmental reporting continued

1 Segment revenue allocation between the reportable segments has been restated to correct a prior period error arising from incorrect classification of loss on realisation of the cash flow hedges within reportable segments. Total balances have remained unchanged.

For the comparative periods, the allocation for the year ended 31 December 2021 increased revenue for Ghana and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the hedging loss of $152.9 million was allocated to Corporate. For the six months ended 30 June 2021, revenue for Ghana and Non-Operated increased by $33.8 million, and $18.6 million, respectively, with the hedging loss of $52.4 million allocated to Corporate.

2 Excludes derivative financial instruments and deferred tax assets.

 7. Total revenue

8. Operating profit

1 Depreciation expense on leased assets of $23.2 million as per note 13 includes a charge of $2.0 million on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $21.2 million relates to other leased assets and is included within cost of sales.

2Refer to page 6 of Finance Review and Note 19 for detailed explanations.

9. Net financing costs

10. Taxation on profit on ordinary activities

The overall net tax expense of $283.7 million (1H 2021: $120.4 million) primarily relates to expenses in respect of Ghana and West Africa non-operated assets net of non-recurring deferred tax credits associated with exploration write-offs, impairments and onerous lease provisions. 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 2022.

The Group's statutory effective tax rate is 51.8% (1H 2021: 56.4%). After adjusting for the non-recurring amounts related to exploration write-offs, impairments, restructuring costs, disposals and onerous lease provisions and their associated tax benefit, the Group's underlying effective tax rate is 62.0% (1H 2021: (83.1%)). The change in effective tax rate from 1H21 to 1H22 is primarily due to there being no UK tax benefit from net interest and hedging expenses, which represents a smaller proportion of the Group's overall profits in 1H22 than in 1H21. Non-deductible expenditure in Ghana and a change to the mix of taxable and non-taxable profits in Gabon are additional contributing factors.

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 of these claims, the result would be additional unprovided liabilities of $991.9 million (YE21: $1,025.5 million) which includes $33.0 million of interest and penalties (YE21: $34.1m).

Provisions of $106.5 million (YE21: $127.9 million) are included in income tax payable ($70.4 million (YE21: $34.1m)), deferred tax liability (nil (YE21: $41.0 million)) and provisions ($36.2 million (YE21: $52.4m)). Where these matters relate to expenditure which is capitalised within E&E and PP&E, 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 unprovided tax liabilities relating to these disputes have decreased following the conclusion of tax authority challenges, but have increased for the extrapolation of exposures, giving rise to an overall decrease in provision of $21.4m and decrease in unprovided tax liabilities of $33.6m. 

Ghana tax assessments

In August 2018, Tullow Ghana Limited (TGL) received a direct tax assessment from the Ghana Revenue Authority (GRA) for the financial years 2014 to 2016. After discussions, a final assessment was issued in December 2019 for $407.3 million requesting that $397.7 million be paid by 13 January 2020. The GRA is seeking to apply branch profits remittance tax under a law which the Group considers is not applicable to TGL, since it falls outside the tax regime set out in TGL's Petroleum Agreements and relevant double tax treaties. The GRA has additionally assessed TGL for unpaid withholding taxes and corporate income tax arising from the disallowance of loan interest. The Group considers that these assessments also breach TGL's rights under its petroleum agreements, applicable Ghanaian law and double taxation treaties, and, in some cases, have arisen as the result of the errors in the GRA's calculations. In January 2020, TGL issued a Notice of Dispute with the Ministry of Energy (MoE), disputing the issues and suspending TGL's obligation to pay any taxes until the disputed issues have been resolved. In April 2020, the GRA issued a Demand Notice for $365.0 million ($337.6 million branch profits remittance tax and withholding tax, and $27.4 million corporate income tax) which was put on hold by the MoE. In September 2021 TGL received a revised final tax audit report for $471.2 million ($325.0 million branch profits remittance tax and withholding tax, and $146.1 million corporate income tax).

In October 2021 TGL filed a Request for Arbitration with the International Chamber of Commerce (ICC) disputing the US$320 million branch profits remittance tax assessment and an additional Notice of Dispute objecting against the disallowance of certain expenditure in the revised tax audit report. The Parties have agreed a procedural timetable for the arbitration under which hearing will commence in October 2023. In December 2021, TGL paid US$3 million on account in respect of a revised withholding tax assessment of $3 million. TGL received a revised assessment in March 2022 assessing a tax liability of $102 million together with a Demand Notice requiring full settlement of the assessed tax liability within seven days. TGL disputes the basis for the revised assessment and the payment obligation is suspended in view of the Notices of Dispute previously issued. The March 2022 revised assessment results in assessments totalling US$422 million including BPRT. The Group disputes the validity of the assessments issued to date and the tax liability arising from the March 2022 assessment and continues to engage with the GRA to seek settlement of the issues raised (excluding BPRT) on a mutually acceptable basis outside of the ongoing dispute process.

10. Taxation on profit on ordinary activities continued

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). In 2013, the High Court found in favour of Tullow such that the tax relief should be reinstated. However, in March 2017, the NBR won its appeal to the Supreme Court, which was not clear as to the position or liability of TBL. A review application against this judgment was filed in April 2018. The hearing took place in November 2019 and TBL was unsuccessful. 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. TBL secured an extension of the payment deadline to 15 June 2021 from the NBR to allow discussions with PB and the Government to take place. Such discussions have been delayed several times due to the COVID pandemic. 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 subsequently, no further enforcement action has been undertaken or threatened by NBR. The procedural hearing was held on 28 June 2022 which set the timetable for the process going forward. The first submissions are being made in October 2022 with the hearing date in May 2024.

While it is not possible to estimate the timing of tax cash flows in relation to possible outcomes with certainty. Management anticipate that there will not be material cash taxes paid in excess of the amounts provided for uncertain tax treatments in the next 12 months.

11. Disposals

There were no disposals in the six months ended 30 June 2022.

FID for the Tilenga Project in Uganda and the East African Crude Oil Pipeline (EACOP) as reported by Total Energies Ltd on 1 February 2022 triggered a contingent consideration of $75.0 million (offset by $7.1 million indemnity relating to tax audits) in relation to Tullow's sale of its assets in Uganda to Total in 2020 which was received on 16 February 2022.

On 31 March 2021, the Group completed the sale of its assets in Equatorial Guinea with a cash consideration received of $88.9 million. This transaction included contingent future payments of up to $16.0 million which are linked to asset performance and oil price. As per the SPA, a further $5.0 million of additional consideration was also received on completion of Dussafu Marin Permit in Gabon.

On 9 June 2021, the Group completed the asset sale of Dussafu Marin Permit in Gabon with a cash consideration received of $39.0 million. This transaction included contingent future payments of up to $24.0 million which are linked to asset performance and oil price.

11. Disposals continued

Given Tullow no longer holds interest in the above assets, based on publicly available information the Company has assessed that the asset performance condition is not met. Accordingly, no contingent consideration has been recognised as of 30 June 2022.

1 In addition to $127.8 million gain on disposal recognised following the Equatorial Guinea and Dussafu disposals, the Group recognised a loss of $5.0 million relating to its sale of Dutch assets to Hague and London Oil plc (HALO) in 2017, and a gain of $0.1 million relating to other transactions during the period (1H21: 122.9 million).

12. Intangible exploration and evaluation assets

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

a. Licence relinquishments, expiry, planned exit or reduced activity

b. Current year expenditure on assets previously written off

c. New Ventures expenditure is written off as incurred

d. Unsuccessful well costs written off

In Kenya, the Group had received a 15-month licence extension from September 2020 to December 2021 which was contingent on certain conditions, including submission of a technically and commercially compliant Field Development Plan (FDP). On 10 December 2021 Tullow and its Joint Venture Partners submitted an FDP to the Government of Kenya and fulfilled its licence obligations. The Group expects a production licence to be granted once due Government process has been completed. At 31 December 2021, in line with its accounting policy, the Group has performed a VIU assessment of Kenya asset following identification of triggers for impairment reversal. This resulted in an NPV significantly in excess of the book value of $255.2 million. However, the Group has identified the following uncertainties in respect to the Group's ability to realise the estimated 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. These items require satisfactory resolution before the Group can take FID.

Due to the binary nature of these uncertainties the Group was unable to either adjust the cash flows or discount rate appropriately. It has therefore used its judgement and assessed a probability of achieving FID and therefore the recognition of commercial reserves. This probability was applied to the VIU to determine a risk adjusted VIU and compared against the net book value of the asset. Based on this there was no impairment or impairment reversal as at 31 December 2021.

Since 1 Jan 2022, there have been ongoing discussions with Government of Kenya on the approval of FDP and securing government deliverables. The FDP is currently under review with Government of Kenya with review period extended to 6 November 2022. In addition, Company continues to progress with the farm down process with approvals being sought. However, as at 30 June 2022 the uncertainties are largely unchanged and hence, no trigger for impairment/impairment reversal was identified.

12. Intangible exploration and evaluation assets continued

a. Current year expenditure on assets previously written off

b. Licence relinquishments, expiry, planned exit or reduced activity

c. Unsuccessful well costs written off

d. Release of indirect tax provision following settlement

a. Current year expenditure on assets previously written off

b. Licence relinquishments, expiry, planned exit or reduced activity

c. Pre-licence exploration expenditure is written off as incurred

d. Unsuccessful well costs written off

e. Following VIU assessment as a result of reduction in long term oil price assumption, using a pre-tax discount rate of 18%

f. Written down to the value of the transaction consideration.

13. Property, plant and equipment