Half-year Report

Tullow oil PLC - 2021 Half Year Results

15 September 2021 - Tullow Oil (Tullow) announces its Half Year results for the six months ended 30 June 2021. Details of the presentation (virtual) and conference call are available on the last page of this announcement and online at www.tullowoil.com.

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

"Strong operational performance in the first half of the year and a transformational debt refinancing have put Tullow on a firm footing to deliver our Business Plan. Our West Africa production assets have performed well, and we are narrowing production guidance for 2021 to the upper end of the range. In Kenya, the revised development plan creates a robust project that has the potential to deliver material value to the Government of Kenya and other stakeholders. Through our operations, Tullow continues to deliver Shared Prosperity and to be an engine for economic and social change in the developing economies in which we work. Furthermore, by targeting Net Zero by 2030 and an emphasis on responsible operations, we are ensuring that the oil and gas resources of our host countries are developed efficiently and safely, whilst minimising our environmental impact."

2021 First half results summary

·    Group working interest production for the first half of 2021 averaged 61,230 boepd, in line with expectations.

·    Good operational progress in Ghana; FPSOs delivering over 98% uptime; sustained increased water injection and gas offtake rates; first new well in drilling programme, J56 producer, came on stream delivering production rates ahead of expectations.

·    Progress made on the delivery of Business Plan set out in November 2020, including target to become Net Zero by 2030.

·    Revenue of $727 million; gross profit of $321 million; profit after tax of $93 million; underlying operating cash flow of
$218 million and free cash flow of $86 million.

·    Continued focus on costs results in reduced administrative expenses of $23 million in 1H21, down c.50% year-on-year. 

·    Capital investment of $101 million; decommissioning costs of $37 million. 1H21 operating costs averaged $12.9/bbl, a year-on-year increase primarily due to lower production and increased costs related to extended COVID-19 operating procedures.

·    Net debt at 30 June 2021 of c.$2.3 billion; Gearing of 2.6x net debt/EBITDAX; liquidity headroom and free cash of $0.7 billion.

·    Completion of comprehensive debt refinancing with $1.8 billion of five-year Senior Secured Notes issued and a new $500 million revolving credit facility.

·    Completion of Equatorial Guinea and Dussafu Marin permit sales in March and June respectively, receiving $133 million.

Key financial results

2021 Guidance

·    Group working interest production narrowed upwards to 58,000-61,000 boepd following deferral of a Jubilee shut-down into 2022 and an increase in production from Simba in Gabon following acceleration of work into 2H21.

·    Full year capital investment and decommissioning spend of c.$260 million and c.$90 million respectively.

·    Full year underlying operating cashflow expected to be c.$0.6 billion assuming $60/bbl for the remainder of the year. Post all costs, Tullow forecasts full year free cash flow of c.$0.1 billion. If the oil price averages $70/bbl in 2H21, this would increase by c.$50 million.

·    Tullow's free cash flow guidance includes an expected payment of $75 million from Total which would be triggered if a Final Investment Decision (FID) for the Lake Albert Development in Uganda occurs before the end of the year. Public announcements suggest good progress is being made in Uganda, with agreements recently in place to launch the Upstream and Pipeline projects, but if FID does not occur in 2021, the $75 million payment is expected in 2022.

STRATEGY & BUSINESS PLAN

2021 is a transition year for Tullow as the Group begins to deliver the 10-year Business Plan presented at its Capital Markets Day last November. Much has been achieved in the first half of the year and while the start of drilling in Ghana is one of the most tangible examples, the Group has also maintained cost discipline, allocated capital carefully to accelerate high-return projects such as Simba in Gabon and recently submitted a revised draft development plan for Kenya, the culmination of over a year's in-depth work. The issuance of $1.8 billion of Senior Secured Notes with a $500 million revolving credit facility in May 2021 placed Tullow on a much firmer financial footing and the Group now has a clear runway to invest appropriately in its assets to maximise their value and deliver its cash generative plan.  

Over the past few months, Tullow has focused on further refining the plan for the 2021-2025 period with a base case capital expenditure of c.$1.3 to c.$1.5 billion during this period. This expenditure is self-funded and requires no additional borrowing. Revenues are protected by Tullow's comprehensive prudent hedging programme and the Group has flexibility to reduce expenditure in the event of a sustained oil price fall to $55/bbl or below.

Overall, from 2021-2025, Tullow's Business Plan will deliver growth in production, reserves and underlying value, along with material cash flow to support deleveraging which will see the Group reduce its gearing to below 1.5x by 2025.

Maximising value from producing assets

The Jubilee field has c.2 billion barrels of oil initially in place and to date, Tullow has produced less than half of the expected ultimate recovery. Accordingly, given the quality of the field, Jubilee provides a highly profitable investment opportunity over the 2021-2025 period through a combination of infill drilling, facilities expansion, and two sanctioned projects in the eastern part of the field - Jubilee North East and Jubilee South East.

The TEN fields have over 1 billion barrels of oil initially in place and to date, Tullow has produced less than a third of the expected ultimate recovery through the Enyenra and Ntomme fields. Since the 2020 Capital Markets Day, Tullow and its Partners have had the opportunity to deepen their understanding of the TEN area, and now have an improved view of the remaining potential. Accordingly, the JV Partners have evolved their forward strategy on TEN to concentrate on the biggest and most cost-effective "pools", particularly in the Greater Ntomme and Tweneboa ("GNT") area. Two strategically-positioned wells to be drilled in the near-term will help better define the overall resource base at TEN, with options to accelerate future development. The Group is also seeking to commercialise the significant non-associated gas resource in the TEN fields.

Tullow's non-operated production in Gabon and Cote d'Ivoire continue to provide positive cash flow through existing production, infrastructure-led exploration (ILX) and a number of diverse low-risk investment options and projects.

Value opportunities

In Kenya, the revised development plan has been commercially, technically and environmentally enhanced. Tullow and its Kenya Joint Venture (JV) Partners are actively seeking a strategic partner(s) for the next stage of the project to develop this discovered resource which has the potential to deliver material value to the Government of Kenya and the JV Partnership, as well as other stakeholders.

Tullow is focusing its exploration expertise on unlocking additional value from our asset base. In Ghana and Côte d'Ivoire, Tullow's team is maturing prospects around the TEN FPSO and subsea infrastructure as well as in the adjacent block, CI-524. In the emerging basins of Guyana and Argentina, Tullow is focused on limiting its capital exposure while also seeking to capitalise on its significant positions in both countries.

Tullow's purpose

The oil & gas industry is in flux as many companies allocate capital away from the upstream and divest assets.  However, as long as global hydrocarbon demand exists, it is imperative that Africa's oil & gas assets are managed responsibly, efficiently and transparently and that oil & gas production in developing economies creates long-lasting economic and social benefits.  Notwithstanding the focus on reducing the use of fossil fuels by society and through legislation, the oil & gas industry can be an engine of development in many developing economies, particularly in Africa. Tullow has a long and proud history in Africa and is well positioned to continue as a leader in the continent's oil & gas industry. With a target to achieve Net Zero by 2030 and an emphasis on responsible operations, Tullow will ensure that the oil & gas resources of its host countries are developed efficiently and safely while minimising the environmental impact. Through its work, Tullow will deliver Shared Prosperity and create value for our investors, staff, host nations and communities.

ESG

Net Zero 2030

Tullow is committed to becoming a Net Zero Company by 2030 on its Scope 1 and 2 emissions. Over the period, this will be achieved through a combination of decarbonising its operated assets in Ghana and pursuing a nature-based carbon removal programme.

Over the next three years, Tullow has defined plans to reduce its CO2/GHG 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.

To offset the residual difficult-to-abate carbon emissions, progress is being made in identifying nature-based carbon removal projects such as reforestation, afforestation and conservation projects in Ghana. Ongoing work includes project screening, feasibility and investment readiness assessments ahead of selecting projects that deliver carbon offsets and community benefits. Tullow has appointed Terra Global to carry out feasibility studies in Ghana to identify projects for future investment.

Governance - Board changes

In June, Tullow announced that Dorothy Thompson CBE, Non-Executive Chair, had decided to step down from Tullow's Board. An executive search firm was appointed soon after and the process to find Dorothy's replacement is progressing well. Tullow expects to announce its new Chair in the autumn.

Tullow has also announced today in a separate press release that Les Wood, Chief Financial Officer, has mutually agreed with the Board that he will step down from Tullow at the end of the first quarter of 2022.

Operational Review

Production

Group working interest production averaged 61,230 boepd in the first half of 2021, in line with expectations. Full year guidance has been narrowed to 58,000-61,000 boepd, towards the upper end of the range.

Ghana

Jubilee

Gross production from the Jubilee field averaged c.70,600 bopd (net: c.25,100 bopd) in the first half of the year, slightly ahead of expectations due to good facility uptime and well performance. Full year guidance for Jubilee has been slightly adjusted upwards to c.74,300 bopd (net: c.26,400 bopd) following the decision to move the planned maintenance shut-down into the first half of 2022. Shifting the shutdown by approximately six months is expected to maximise the amount of work achievable as gas enhancement works planned for 2023 can be brought forward and an expected easing in COVID-19 restrictions will allow for a more efficient work programme to be carried out in the planned shutdown period.

The 2021 drilling programme continues and the first well of the programme, the J-56 producer, came onstream in July 2021 delivering rates ahead of expectations. The second well, the J-55 water injector, is expected to be online in the next few weeks and will be paired with an existing production well. During August, the rig drilled the top hole of the next Jubilee producer well, J-57-P, which is expected to be completed and brought online in early 2022. As a result of the new wells, average production from Jubilee is expected to increase in the second half of the year before growing further in 2022 as the drilling campaign continues.

TEN

Gross production from the TEN fields averaged c.37,000 bopd (net: c.17,400 bopd) in the first half of the year. This is broadly in line with expectations. Full year gross production from TEN is expected to be c.33,200 bopd (net: c.15,700 bopd) reflecting the underlying decline in the field during the year. Drilling of the Ntomme gas injector well (Nt-06) reached total depth this month with completion expected to be finished in October. When tied in later this year, the well is expected to mitigate against further decline and keep production broadly flat into 2022.

Operational improvement plan

The operational improvement plan in Ghana is an important part of our strategy to optimise reservoir performance, address production decline and support long term stable production. The plan is delivering good results across the key areas of facility uptime, gas offtake and water injection. The two FPSOs averaged 98% uptime in the first half of 2021, gas offtake from the Government of Ghana is averaging c.110 mmscfd and improved Jubilee water injection rates continue to be in excess of 200 kbwpd.

Non-operated portfolio

Net production from the non-operated portfolio averaged c.18,700 boepd in the first half of 2021, with contributions from Gabon, Equatorial Guinea and Côte d'Ivoire. Following the sale of assets in Equatorial Guinea and the Dussafu Marin permit in Gabon net production from the portfolio for the full year is expected to be c.17,900 boepd.

Fields in Gabon continue to offer high-return and fast payback opportunities. As such, capital expenditure has been re-allocated to accelerate the Simba expansion and an appraisal well at Tchatamba, into 2021. As part of the Simba expansion, the Simba-3 production well was brought onstream in early September and is performing in line with expectations. The Tchatamba south appraisal well, brought forward from 2022, is currently being drilled, and subject to results, will enable the Tchatamba south east development to commence in 2022, a year earlier than initially planned.

As previously announced in Tullow's 2020 Full Year Results, following a major incident onboard the FPSO in the CNR International (CNR) operated Espoir field in mid-January 2021, production was shut in for approximately four weeks in the first half of the year. A further shut down of approximately two months is currently under way to carry out remediation work identified by BW Offshore, the FPSO operator, required for vessel class certification. The loss of production resulting from these shut-down periods is factored into the Group's 2021 production guidance. CNR and Tullow are working together with BW Offshore on the optimum remediation plan, with work expected to commence in 2022. A further update will be provided in due course once remediation plans are finalised.

Decommissioning

Decommissioning activities continue in the UK and Mauritania. In Tullow-operated licences in the UK, final surveys are being planned to close out the decommissioning programme this year. The Group's non-operated decommissioning activities are ongoing and are expected to continue through to 2025.

In Mauritania, preparation is under way to commence the Group's operated decommissioning programme of the Banda and Tiof fields with operations now expected to commence in early 2022, subject to Government approval. Non-operated decommissioning of the Chinguetti field is ongoing. The full abandonment of the wells was completed in August ahead of preparing to clear infrastructure from the seabed in 2022.

Due to a delayed start in some of the activities in Mauritania and the UK, decommissioning expenditure in 2021 is now expected to be c. $90 million (down from c.$100 million).

Kenya

Over the past year, Tullow and its Joint Venture (JV) Partners (Africa Oil and Total Energies) have completed the redesign of the Kenya development project (Blocks 10BB and 13T licences) to ensure it is a technically, commercially and environmentally robust project. A higher production plateau of 120,000 bopd is now planned, with expected gross oil recovery of 585 mmbo over the full life of the field. This resource position is supported by external international auditors Gaffney Cline Associates (GCA) who have issued a Competent Persons Report (CPR) and confirmed the life of field resource position of 585 mmbo.  

The key changes to the development concept have been driven by:

1.     Incorporating the production data from the Early Oil Pilot Scheme (EOPS) where 450,000 bbls was produced from Amosing and Ngamia fields. These two fields account for over 50% of the resource distribution, leading to greater confidence in achieving the higher end of the resource distribution range. 

2.     Optimising the number of wells to be drilled with drilling initially at the crest of the fields to achieve First Oil. Changing the producer to injector ratio from 2:1 to 1:1 leading to improved pressure support and higher resources recovered from the reservoir.

3.     Adding the Ekales field into the first phase of production. Ekales is geographically straddled between the Twiga and Amosing fields and ongoing technical work has helped mature our understanding. As such, the first phase will now include the Ngamia, Ekales, Amosing and Twiga (NEAT) fields and will target 390 mmbo of the overall 585 mmbo. 

4.     Optimising the overall development cost with a facility design capacity of 130,000 bopd and an increase to the pipeline size from 18" to 20" to handle the increased flow rates. 

Total gross capital expenditure (capex), which covers both the upstream and the pipeline to First Oil, is expected to be c.$3.4 billion. The increase in capex from the previous design is due to a bigger facility processing capacity, additional wells to be drilled and larger diameter crude oil export pipeline, which delivers 30% increase in resources whilst lowering the unit cost to $22/bbl (previously c.$31/bbl). The revised concept also allows greater flexibility in adding additional fields into production without significant modifications to the project's infrastructure.   

Tullow and its JV Partners have taken the opportunity of this review to improve the environmental and social aspects of the project. Carbon emissions will be limited through a combination of heat conservation, use of associated gas for power and reinjection of excess gas into the reservoir. Further, there are opportunities to use the Kenyan national grid that is substantially powered by renewables and options to offset remaining emissions. As per the previous development plan, the 825-kilometres long pipeline that will transport the crude oil from Turkana to the port of Lamu will be heated and buried to avoid long-term disruption. The project will also require water for reservoir pressure which will be abstracted through a pipeline from the Turkwell Dam and will also be used to provide water to local communities. This project would also be Kenya's first oil and gas development and would represent a stable, long-term source of income for the Government of Kenya.

Simultaneously to the development, an exploration and appraisal plan will be put in place to ensure the remaining five discoveries are efficiently developed. This will extend and sustain initial plateau rates while keeping costs low by using the rigs used for development drilling. Future phases will also focus on additional exploration potential within the Blocks 10BB and 13T licences and also exploring the wider Blocks 10BA and 12B licence acreage. 

Tullow and its JV Partners have submitted a draft FDP to the Ministry of Energy & Petroleum for their review. The JV Partners are now working collaboratively with them and will incorporate their feedback and plan to submit a final FDP by the end of 2021, in line with licence extension requirements provided by the Government of Kenya in December 2020. At the same time Tullow and its JV Partners are actively seeking strategic partners for the project. Based on the revised plan, Tullow believes that this project is an attractive commercial prospect for investors looking to access the East Africa oil and gas sector in both the upstream and midstream. It is intended that a strategic partner will be secured ahead of a Final Investment Decision. 

Exploration

In Tullow's core area of West Africa, the exploration team is focused on maturing near-field and infrastructure-led exploration opportunities around existing producing fields, to unlock additional value from the Group's asset base. Tullow also continues to focus on unlocking value from the substantial prospective resource base in the emerging basins of Guyana and Argentina, while seeking to mitigate capital exposure from historical work commitments of c.$50 million in 2022, through farm-downs. These include the Beebei-Potaro exploration well on the Kanuku Block in Guyana which will target the prolific Cretaceous light oil play of the Guyana-Suriname Basin, as well as a seismic acquisition over Block MLO 122 in Argentina.

Operational activity in the first half of 2021 included the drilling of the Goliathberg-Voltzberg North well in Suriname Block 47, which encountered minor oil shows. Tullow is considering next steps for Blocks 47 and 54. The Group has notified the Government of Suriname of its decision to relinquish Block 62, and Tullow will exit the licence in October 2021. In Argentina, a multi-client 3D seismic acquisition was completed on Tullow-operated licences MLO114 and MLO119 during the first quarter of 2021. In Côte d'Ivoire seismic activities have now been fully demobilised from onshore block CI-520 and Tullow has now exited the licence. Tullow has now exited all onshore blocks in Côte d'Ivoire but retains its 90% interest in the offshore Block CI-524, adjacent to the TEN field. The Group continues to optimise its portfolio and has exited Blocks Z38 and Z64 in Peru and PEL 0037 in Namibia. Refer to note 11 for details of the Group exploration write-off assessment.

FINANCE REVIEW
 

¹ Underlying 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 and are explained and reconciled on pages 36 to 39.

Production and commodity prices

Total Group working interest production averaged 61,230 boepd (1H 2020: 77,700 boepd), a decrease of 21% for the period. The decrease in production primarily resulted from the natural decline in Jubilee and TEN and the sale of Equatorial Guinea and Dussafu asset in Gabon in 1H21. The drilling of new wells in Ghana to offset the production decline commenced in 1H21. However, the first well drilled and completed, J-56, came onstream in July 2021 and as such did not contribute to 1H21 production. 

The realised oil price after hedging for the period was $60.8/bbl (1H 2020: $51.8/bbl) and before hedging $65.2/bbl (1H 2020: $42.5/bbl). There has been a recovery in oil markets in 2H20 and 1H21, which has led to higher realised prices partially offset by hedge losses, decreasing total revenue by $52.4 million (1H 2020: increase of $130.8 million).

The overlift expense was primarily caused by the timing of liftings with seven cargos across Ghana, Gabon and Cote d'Ivoire lifted in June 2021.

Operating costs, depreciation and expenses

Underlying cash operating costs amounted to $143 million; $12.9/boe (1H 2020: $155 million; $11.0/boe). The increase in cash unit operating costs is principally due to lower production and increased costs associated with COVID-19 operating procedures, partially offset by reduced operating costs mainly associated with Jubilee and the cessation of shuttle tanker operations in the Jubilee field in 1Q21 following commissioning of a Catenary Anchor Leg Mooring buoy. Cash operating costs excluding COVID-19 operating procedures and shuttle tanker operations were $11.6/boe (1H 2020: $9.6/boe). The sale of Equatorial Guinea and the Dussafu asset in Gabon in 1H21 also contributed to the decrease in total operating costs.

DD&A charges before impairment on production and development assets amounted to $170 million; $15.3/boe (1H 2020: $267 million; $18.9/boe). This decrease in DD&A per barrel is mainly attributable to 2020 impairments and increases to 2020 year end reserves partially offset by decreased production.

Administrative expenses of $23 million (1H 2020: $51 million) significantly decreased against the comparative period. In February 2020, Tullow concluded its Business Review, which included a review of the Group's organisation structure and resources and resulted in a significant headcount reduction. Furthermore, the Group has focused on reducing non-payroll G&A costs including outsourcing, information systems expenses, professional fees and office rent. However, this is partially offset by the adverse GBP:USD FX variance in 2021. Tullow is still on target to deliver sustainable cash savings of over $125 million per annum.

The Group recognised a net impairment charge on PP&E of $8 million in respect of first half 2021 (1H 2020: $418 million) due to changes to estimates on the cost of decommissioning for certain UK assets.

During the first half of 2021, the Group has written off exploration costs of $49 million (1H 2020: $941 million) which are predominantly driven by write-offs of the GVN-1 well costs in Block 47 in Suriname and subsequently all associated licence costs for all blocks in Suriname. The remaining write-offs comprise of licence level costs associated with Peru, Comoros, Côte d'Ivoire and Namibia due to no planned activity and licence exits. This is offset by a release of an indirect tax provision following settlement in Uganda relating to its disposal in 2020.

Disposals

On 9 February 2021, Tullow announced that it signed two separate sale and purchase agreements with Panoro Energy ASA for all of Tullow's assets in Equatorial Guinea and the Dussafu Marin permit asset in Gabon for a total consideration of $180 million, inclusive of contingent payments.

In March 2021, the Group completed the sale of its assets in Equatorial Guinea and $89 million was received in cash following completion adjustments. The net gain on disposal on this transaction is $123 million.

In June 2021, the Group completed the sale of its Dussafu Marin permit asset in Gabon and $39 million was received in cash following completion adjustments. An additional $5 million was received for completion of both transactions. The net gain on disposal on this transaction is $5 million.

Derivative financial instruments

Tullow continues to undertake hedging activities as part of the ongoing management of its business risk 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 2021, Tullow's hedge portfolio provides downside protection for 51% of forecast production entitlements through to May 2023 and 29% for a further 12 months to May 2024. Since completion of the comprehensive debt refinancing in May, new hedges have been placed with $55/bbl floors and weighted average sold calls of c.$70/bbl.

At 30 June 2021, the Group's derivative instruments had a net negative fair value of $148 million (30 June 2020: positive $197 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 2020: Level 2). There were no transfers between fair value levels during the year.

The 2022, 2023 and 2024 hedging position at 30 June 2021 was c.23,400 bopd, c.20,000 bopd and c.6,800 bopd hedged with an average protected floor price of $48/bbl, $55/bbl and $55/bbl respectively.

Net financing costs

Net financing costs for the period were $157 million (1H 2020: $131 million). The increase in financing costs during the period is mainly driven by finance fees, such as legal and advisor fees related to the assessment of alternative refinancing options of the extinguished RBL Facility directly expensed to the income statement ($18 million), as well as increased average cost of debt following completion of the refinancing transactions in May 2021, offset by the net gain on early settlement and derecognition of the RBL Facility and the 2022 Notes ($8 million credit).

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 8.

Taxation

The overall net tax expense of $120 million (1H 2020: credit of $109 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 2021. 

The Group's statutory effective tax rate is 56.4% (1H 2020: 7.6%). 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 83.1% (1H 2020: (57.7%)). The change in effective tax rate from 1H20 to 1H21 is due primarily to there being no UK tax benefit from net interest and hedging expenses in 1H21, compared to net profits in 1H20. Non-deductible expenditure in Ghana and a change to the mix of taxable and non-taxable profits in Gabon are additional contributing factors.

Profit/ (Loss) after tax from continuing activities and earnings /(loss) per share

The profit after tax for the period amounted to $93 million (1H 2020: $1,327 million loss). Basic earnings per share was 6.5 cents (1H 2020: basic loss per share of 94.2 cents).

Capital investment

Capital expenditure amounted to $101 million (1H 2020: $192 million) with $65 million invested in production and development activities and $36 million invested in exploration and appraisal activities.

Capital investment will continue to be carefully controlled in the second half of 2021 and total 2021 capital expenditure is expected to be c.$260 million. The capital investment total is expected to comprise Ghana capex of c.$160 million, West African non-operated capex of c.$46 million and Kenya pre-development expenditure of c.$4 million and exploration and appraisal expenditure of c.$50 million. This reflects the reduction in capex following the sales of the Equatorial Guinea assets and the Dussafu Marin permit in Gabon, offset in part by the acceleration of the Simba expansion development in Gabon and incremental increases across Ghana, Gabon and Kenya.

Going concern

The Directors consider the going concern assessment period to be up to 30 September 2022. 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: $60/bbl for 2021, $60/bbl for 2022; and

Low Case: $45/bbl for 2021, $45/bbl for 2022.

The Low Case includes, amongst other downside assumptions, a 6 per cent production decrease compared to the Base Case as well as increased outflows associated with an ongoing dispute.

On 17 May 2021, the Group announced the completion of its offering of $1.8 billion Senior Secured Notes due 2026. The net proceeds, together with cash on balance sheet, have been used to (i) repay all amounts outstanding under, and cancel all commitments made available pursuant to, the Company's RBL Facility, (ii) redeem in full the Company's senior notes due 2022, (iii) at maturity, repay in full and cancel the Company's convertible bonds due 2021 and (iv) pay fees and expenses incurred in connection with the transactions. The Group also entered into a $500 million Super Senior Revolving Credit Facility (SSRCF) which is undrawn and will be primarily used for working capital purposes. The 2026 Senior Notes and the SSRCF do not have any maintenance covenants (disclosure of key covenants and the determination of availability under the SSRCF are provided in note 18). Following completion of these transactions the Directors have concluded that the material uncertainties noted in the 2020 Annual Report and Accounts, associated with implementing a Refinancing Proposal and obtaining amendments or waivers in respect of covenant breaches or, in the event a Refinancing Proposal is implemented, the revised covenants are subsequently breached, no longer exist.

The Group had $0.7 billion liquidity headroom of unutilised debt capacity and free cash as at 30 June 2021. 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. These forecasts show full availability of the $500 million SSRCF, which under the Base Case remains undrawn. Furthermore Management have performed a reverse stress test and the average oil price throughout the going concern period required to reduce headroom to zero during the assessment period is $42/bbl. Based on the analysis above, the Directors have a reasonable expectation that the Company 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.

2021 principal risks and uncertainties

The Board determines the key risks for the Group and monitors mitigation plans and performance on a monthly basis. An exercise was performed in June 2021 to assess whether the principal risks and uncertainties disclosed in the 2020 Annual Report continue to be appropriate given the change in external risk landscape. Although there has been some change to sub-risks, the principal risks and uncertainties facing the Group at half year remain unchanged from those disclosed in the 2020 Annual Report as listed below. Whilst the Group has successfully refinanced its debt facilities in 1H 2021 it still believes that the sustainability of its capital structure may be a risk in the medium to long term. The company risk profile continues to be assessed on an ongoing basis including considering if the pandemic or oil price volatility results in any new risks or changes to existing risks. Risks associated with COVID-19 have been considered and managed across all principal risk categories.

1.   Risk of failure to deliver operations, development and subsurface objectives

2.   Risk of failure to deliver commercially attractive and timely development projects

3.   Risk of disruption to business due to inability to manage stakeholder relations

4.   Risk of failure to manage impact of climate change

5.   Risk of asset integrity breach or major production failure

6.   Risk of insufficient liquidity and funding capacity

7.   Risk that we fail to deliver a sustainable capital structure

8.   Risk that the transformation plan fails to support the strategy and deliver cost savings

9.   Risk that the people strategy and culture do not support the strategy

10. Risk of major compliance breach

11. Risk of major cyber attack

Events since 30 June 2021

There have not been any adjusting events since 30 June 2021 that have resulted in a material impact on the half year results.

Non-Adjusting event

On 17 May 2021, as part of the refinancing transaction $310 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.

Responsibility statement

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';

b.   the interim management report includes a fair review of the information required by DTR 4.2.7R (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 (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,