Half year Results

Tullow oil PLC - 2020 Half Year Results

9 September 2020 - Tullow Oil (Tullow) announces its Half Year results for the six months ended 30 June 2020. 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:

"Despite the very tough conditions in the first half of this year, we have successfully delivered reliable production and major, sustainable reductions to our cost base. We are also close to completing the important sale of our interests in Uganda. The quality of Tullow's assets remains robust. Since my arrival as CEO, we have been developing new plans for our business, with the support of our Joint Venture Partners and expert advisors. These plans will deliver enhanced value from our assets to benefit all our stakeholders including our host countries and investors. We will host a Capital Markets Day towards the end of 2020 at which we will update the market on these plans to deliver on Tullow's true potential."

2020 FIRST Half results Summary

·    Group working interest production for the first half of 2020 averaged 77,700 bopd, in line with expectations

·    Revenue of $731 million; gross profit of $164 million; loss after tax of $1.3 billion

·    Loss after tax driven by exploration write-offs and impairments totalling $1.4 billion pre-tax

·    Capital investment of $192 million; decommissioning costs of $38 million

·    Negative free cash flow in 1H due to weighting of cash taxes, cash capex, differentials, redundancy costs and working capital

·    Net debt at 30 June 2020 of $3.0 billion; Gearing of 3.0x net debt/EBITDAX; liquidity headroom and free cash of $0.5 billion

·    Strong operational performance in Ghana; both FPSOs delivering in excess of 95 per cent uptime

·    Approval from shareholders for sale of Ugandan assets for $500 million in cash on completion and $75 million in cash at FID

·    Rahul Dhir appointed Chief Executive Officer as of 1 July 2020; as of 9 September 2020, Dorothy Thompson returns to non-Executive Chair and Mitchell Ingram appointed as new Non-executive Director of Tullow (see separate announcement)

key financial results

	1H 2020	1H 2019
Sales revenue ($m)	731	872
Gross profit ($m)	164	527
Underlying cash operating cost per barrel ($/bbl)	11.0	9.0
Profit / (loss) after tax ($m)	(1,327)	103
Free cash flow ($m)	(213)	181
Net debt ($m)	3,019	2,948
Gearing	3.0	1.8

 

2020 Capital markets day

Since December 2019, Tullow has taken significant steps to re-base its business through a major restructuring of its organisation and cost base which has led to substantial savings. This work has continued with the arrival of Rahul Dhir as CEO in July 2020 who has commissioned a comprehensive review of Tullow's portfolio, growth prospects and capital structure. Once this review is complete, and its conclusions have been fully validated, the Group will hold a Capital Markets Day (CMD) before the end of the year. At this CMD, Rahul Dhir and other senior leaders will lay out their plans for Tullow's business and assets and demonstrate how they will unlock material value from the portfolio. 

2020 SECOND HALF OUTLOOK

·    Group production has been strong going into the second half and full year guidance has been narrowed to 73-77,000 bopd following good well performance in Ghana offset by the negative impact from OPEC+ quotas in Gabon

·    Maximising Jubilee/TEN gas offtake nominations; focus on continuous improvement to maintain FPSO uptime in excess of 95%

·    Ntomme-09 production well came on stream in August and is incrementally adding c.5,000 bopd gross to TEN oil production

·    In Kenya, the JV has withdrawn its Force Majeure (FM) notice; the JV has received a 15-month licence extension; the farm-down process has been suspended pending a comprehensive review of the development concept and strategic alternatives

·    Capital and decommissioning expenditure full year guidance of c.$300 million and c.$65 million remains unchanged

·    60 per cent of 2H 2020 sales revenue hedged with a floor of $57/bbl; 48 per cent of 2021 hedged with a floor of $51/bbl

·    2020 free cash flow forecast to break even at the current forward curve subject to year-end working capital movements

·    Proceeds of $500 million from Uganda transaction completion expected before year-end; portfolio sales still targeted to deliver proceeds of over $1 billion in aggregate albeit in a challenging external environment for asset sales and farm downs   

·    Organisational restructuring well advanced and forecast to deliver cash savings of over $350 million over three years, significantly in excess of the previous target of $200 million. This will deliver annual sustainable cash savings of over $125 million from 2021.

·    Semi-annual RBL debt capacity redetermination expected to complete in early October 2020; at Tullow's request, the next redetermination will be in January 2021 following the CMD later this year to incorporate the outcome of revised business plans

·    Evaluation of various refinancing alternatives with respect to the Group's capital structure is ongoing in parallel

·    New exploration acreage awarded in Peru; data reprocessing and evaluation continues in Guyana; drilling of Goliathberg-Voltzberg North well in Block 47, Suriname, planned for first quarter of 2021.

Operational Review

Production

Group working interest production averaged 77,700 bopd in the first half of 2020, in line with expectations. Full year guidance has been updated to reflect recent strong performance in Ghana, offset by production curtailments in Gabon due to OPEC+ quotas being applied. Overall, guidance for the full year is narrowed from 71-78,000 bopd to 73-77,000 bopd, with the mid-point forecast of 75,000 bopd maintained.

Group average working interest production	H1 2020 actual (bopd)	FY 2020 forecast (bopd)
Ghana	54,000	53,000
Jubilee	30,000	30,000
TEN	24,000	23,000
Equatorial Guinea	5,000	4,700
Gabon	16,800	15,200
Côte d'Ivoire	1,900	2,100
Oil production	77,700	75,000

Ghana

The impact of COVID-19 has been managed safely across the business with no adverse impact on Ghana production. This has been achieved in close cooperation with the Government of Ghana.

Production across both fields in Ghana has been strong in the first half of 2020 with the Jubilee field averaging 84,700 bopd gross (net: 30,000 bopd) and the TEN field averaging 50,900 bopd gross (net: 24,000 bopd). This performance is a result of increased gas offtake nominations from the Ghana National Gas Company as well as approval from the Ministry of Energy to temporarily increase flaring, higher than forecast facility uptime of over 95% at both FPSOs and greater reliability and redundancy in the water injection facilities on the Jubilee FPSO.

At TEN, the Ntomme-09 production well came onstream at the start of August 2020 and is contributing an incremental c.5,000 bopd gross oil production. The Maersk Venturer drillship has now been released. Tenders are ongoing to contract a rig to recommence activity in Ghana in 2021.

The strong production performance has continued in the second half of the year with Jubilee and TEN averaging 90,000 bopd and 50,000 bopd gross respectively through July and August. This has been driven by continued high facility uptimes and strong well performance across both fields including the Ntomme-09 well that came onstream in early August.

The final phase of the Jubilee Turret Remediation Project is the installation of a Catenary Anchor Leg Mooring (CALM) buoy to assist with offloading. The CALM buoy arrived in Ghana in January 2020 however full installation works were delayed until September 2020. Once the installation works are complete, commissioning is expected to be completed in the fourth quarter of 2020.

A comprehensive review of the investment and production optimisation plans for Jubilee and TEN, which are designed to realise the full potential of both assets and to maximise value for all stakeholders, is currently under way. This review is being conducted in consultation with the Joint Venture Partners and is supported by expert advisors.

Non-operated portfolio

Production from Tullow's non-operated portfolio in the first half has been stable with working interest production averaging      23,700 bopd, in line with expectations.

Production performance across the non-operated portfolio is expected to remain stable in the second half of 2020. However, in August, Tullow received notification from the operator of the Simba field that as part of Gabon's requirement to comply with the OPEC+ quota, the field would be shut in until the end of the year. This is expected to have a net negative impact on average annual Group production of approximately 1,500 bopd which is incorporated in the revised production guidance. The final outcome is subject to change depending on how the Government of Gabon implement the quotas. Tullow are working closely with Joint Venture Partners to ensure any production curtailments are equitably shared.  

Decommissioning

Decommissioning in Tullow-operated licences in the UK North Sea continues to progress as planned with final removal and seabed clearance activities scheduled from September 2020. In Mauritania, decommissioning of the wells in the Chinguetti field was suspended following the Government's decision to close the borders due to COVID-19 in March 2020.

Kenya

Tullow has been working with its Joint Venture Partners to progress the full field development plan. In May 2020 Tullow and its Joint Venture Partners declared FM on the Kenya licences. Following productive discussions with the Government, an improvement in the COVID-19 situation and assurances from Government that the tax incentives granted to the phased project will continue to apply, the FM notices were withdrawn in August 2020. Whilst these issues have resulted in a delay to the Final Investment Decision (FID) on the project, it has allowed time for both Tullow and its Joint Venture Partners to collaboratively work on realising the full potential of the assets. This has resulted in the Government of Kenya agreeing to an initial extension to the Second Additional Exploration Period for the 10BB and 13T licence blocks until 31 December 2020 with a final extension until 31 December 2021, contingent on an agreed work programme and budgets. Separately, the farm down process has been suspended while the Joint Venture Partners complete a comprehensive review of the development concept to ensure it continues to be robust at low oil prices, and also consider the strategic alternatives for the asset.

Uganda

Following the announcement on 23 April 2020 that Tullow had agreed the sale of its assets in Uganda to Total for $500 million in cash on completion, $75 million in cash following FID, plus post first oil contingent payments, the transaction is progressing as planned with completion expected before the year-end.

On 28 May 2020 CNOOC Uganda Limited informed both Tullow and Total that it had elected not to exercise its pre-emption rights.

On 18 June 2020 Tullow published the shareholder circular relating to the transaction and on 15 July 2020 a General Meeting was held, at which the transaction received approval with over 99 per cent of the 56 per cent votes cast in favour.

On 6 August 2020 the Government of Uganda provided their consent to the transfer of operatorship from Tullow to Total.

Completion of the transaction remains subject to the Government of Uganda and the Uganda Revenue Authority entering into a binding Tax Agreement with Tullow Uganda and Total Uganda that reflects the pre-agreed principles on the tax treatment of the transaction, and the Government of Uganda approving the transfer of Tullow's interests to Total. Good progress is being made in satisfying these conditions to completion.

Exploration

Tullow retains a high-quality exploration portfolio in both Africa and South America with high-potential opportunities. However, in light of the challenging external environment Tullow will be minimising exploration spend in the short term and looking at ways to rebalance the portfolio whilst maintaining opportunities to realise value and preserve longer term options for growth.  

South America

In Suriname, the Goliathberg-Voltzberg North well in Block 47 is now planned to be drilled in the first quarter of 2021, testing dual targets in the Cretaceous turbidite play in approximately 1,900 metres of water. The well will be drilled by the Stena Forth drillship.

Data reprocessing and evaluation continues in Guyana to support future drilling activity. In Peru, Tullow has been awarded blocks Z67 and Z68 in the Trujillo basin, targeting a completely new petroleum system and new plays.

Seismic acquisition in Argentina commenced in the fourth quarter of 2019 and was able to continue until May 2020 before being put on hold due to the impact of the COVID-19 pandemic. Recommencement is targeted for the fourth quarter of 2020.

Tullow has now exited the Walton-Morant licence in Jamaica which expired on 31 July 2020.

Africa

Seismic acquisition in Côte d'Ivoire commenced in February 2020 but was suspended in April 2020 due to the impact of the COVID-19 pandemic. The data collected during the early stages of the project is now being evaluated to decide on the next steps for the basin.

In Namibia, Tullow is awaiting the outcome of the Venus-1 well which is expected to be drilled by Total in the fourth quarter of 2020 on a block to the south of Tullow's PEL-90 acreage before deciding next steps.

Shareholder engagement

At the AGM on 23 April 2020, a significant number (33%) of votes were cast against Resolution 13. The Resolution sought the authority for Directors to make allotments of shares in accordance with routine practice in the UK and complied with the guidance published by the Investment Association and the Pre-Emption Group. Being an Ordinary Resolution, it was passed but the vote against was a clear statement from a few of our shareholders. Following the AGM, our Chair of the Board has engaged with our major shareholders who voted against the resolution and now has an understanding of the concerns raised by them. The concerns relate to the potential dilution of their existing shareholdings and the Board has noted these concerns.

Finance review

Financial summary	1H 2020	1H 2019
Working interest production volume (boepd)	77,700	86,300
Sales volume (boepd)	77,100	75,200
Realised oil price ($/bbl)	51.8	64.3
Total revenue ($m)	731	872
Gross profit ($m)	164	527
Underlying cash operating costs per boe ($/boe) 1	11.0	9.0
Exploration costs written off ($m)	941	81
Impairment of property, plant and equipment, net ($m)	418	12
Operating (loss) / profit ($m)	(1,306)	388
(Loss) / profit before tax ($m)	(1,436)	268
(Loss) / profit after tax ($m)	(1,327)	103
Basic (loss)/ earnings per share (cents)	(94.2)	7.4
Capital investment ($m) 1	192	248
Last 12 months adjusted EBITDAX ($m) 1	1,013	1,623
Net debt ($m) 1	3,019	2,948
Gearing (times) 1	3.0	1.8
Free cash flow ($m) 1	(213)	181

¹ Underlying cash operating costs per boe, capital investment, adjusted EBITDAX, net debt, gearing and free cash flow are non-IFRS measures and are explained later in this section.

Production and commodity prices

Total Group working interest production averaged 77,700 boepd (1H 2019: 86,300 boepd), a decrease of 10% for the period. The realised oil price after hedging for the period was $51.8/bbl (1H 2019: $64.3/bbl) and before hedging $42.5/bbl (1H 2019: $66.7/bbl). The impact of COVID-19 pandemic on global oil demand resulted in significant discounts to the Dated Brent benchmark oil price for the cargoes sold during April and May 2020. Low oil prices led to a gain on the realisation of commodity hedges, increasing total revenue by $130.8 million (1H 2019: loss of $32.6 million).

Operating costs, depreciation and expenses

Underlying cash operating costs amounted to $155 million; $11.0/boe (1H 2019: $145 million; $9.0/boe). The increase in cash unit operating costs is principally due to both the ending of the Business Interruption coverage in May 2019, which offset exceptional operating costs for Jubilee such as shuttle tanker operation which will continue until completion of the CALM buoy offloading system as well as lower production for the period.

DD&A charges before impairment on production and development assets amounted to $267million; $18.9/boe (1H 2019: $287 million; $17.9/boe). This increase in DD&A per barrel is mainly attributable to decreased production.

Administrative expenses of $51 million (1H 2019: $55 million) were in line with the comparative period. In February 2020, Tullow concluded its Business Review - which included a review of the Group's organisation structure and resources. Implementation of the new organisation structure will result in a significant reduction in headcount, with an associated restructuring cost of $59 million provided for in the first half of 2020 for redundancy and onerous office lease payments.

 

Impairment of property, plant and equipment (PP&E)	1H 2020	1H 2019
Pre-tax impairment of PP&E, net ($m)	418	12
Associated deferred tax credit ($m)	107	-
Post-tax impairment of PP&E, net ($m)	311	12

 

The Group recognised a net impairment charge on property, plant and equipment of $418 million in respect of first half 2020 (1H 2019: $12million). Impairments were primarily associated with a $5/bbl reduction in the Group's long-term accounting oil price assumption to $60/bbl and lower near- term oil price forecasts.

Exploration costs written off	1H 2020	1H 2019
Exploration cost written off ($m)	941	81

 

During the first half of 2020 the Group recorded exploration write-off costs of $941 million which are predominantly driven by a write-down of the value of the Ugandan assets to the value of the disposal consideration as well as a write down to the value of the Kenya assets, principally associated with the reduction of the Group's long-term oil price assumption and anticipated delay in FID. The remaining write-offs include Marina-1 well costs in Peru and the write-off of licence level costs associated with Peru, Comoros, Côte d'Ivoire and Namibia due to lower levels of planned activity and licence exits.

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 2020, the Group's derivative instruments had a net positive fair value of $197 million (30 June 2019: negative $2.4 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 2019: Level 2). There were no transfers between fair value levels during the year.

2H 2020 hedge position at 30 June 2020	Bopd	Bought put (floor)	Sold call	Bought call
Collars	35,200	$57.72	$79.32	-
Three-way collars (call spread)	12,000	$56.42	$77.82	$87.68
Total/weighted average	44,500	$57.37	$78.91	$87.68

The 2021 and 2022 hedging position at 30 June 2020 was c.24,000 bopd and c.2,000 bopd hedged with an average floor price protected of $52.60/bbl and $50.63/bbl respectively.

Net financing costs

Net financing costs for the period were $131 million (1H 2019: $120 million). The increase in financing costs during the period is mainly driven by the Group ceasing to capitalise interest expenses on qualifying assets during 2019. 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, offset by interest earned on cash deposits and capitalised borrowing costs. A reconciliation of net financing costs is included in Note 8.

Taxation

The overall net tax credit of $109 million (1H 2019: expense of $165 million) primarily relates to expenses in respect of Ghana and West Africa non-operated assets and non-recurring deferred tax credits associated with exploration write-offs, impairments and onerous lease provisions.

The Group's statutory effective tax rate is 7.6%. After adjusting for the non-recurring amounts related to exploration write-offs, impairments, restructuring costs and disposals and their associated tax benefit, the Group's adjusted tax rate is -57.7% (1H 2019: 49.0%). The adjusted tax rate has decreased due to changes in the geographical mix of profits largely generated in production territories of Ghana, Gabon and Equatorial Guinea, prior year adjustments and increased losses with no tax benefit.

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

The loss after tax for the period amounted to $1,326.8 million (1H 2019: $103.2 million profit). Basic loss per share was 94.2 cents (1H 2019: basic earnings per share of 7.4 cents).

 

Reconciliation of net debt	$m
Year-end 2019 net debt	2,805.5
Sales revenue	(731.0)
Operating costs	155.3
Other operating and administrative expenses	247.5
Cash flow from operations	(328.2)
Movement in working capital	32.5
Tax paid	93.1
Purchases of intangible exploration and evaluation assets and property, plant and equipment	222.2
Other investing activities	(1.2)
Other financing activities	191.3
Foreign exchange loss on cash	4.3
1H 2020 net debt	3,019.5

Capital investment

Capital expenditure amounted to $192 million (1H 2019: $248 million) with $158 million invested in production and development activities and $34 million invested in exploration and appraisal activities. More than 70 per cent of the total was invested in Ghana and Kenya.

Capital investment will continue to be carefully controlled in the second half of 2020 and is expected to total c.$300 million. The capital investment total is expected to comprise Ghana capex of c.$120 million, West African non-operated capex of c.$60 million and Kenya pre-development expenditure of c.$20 million and exploration and appraisal expenditure of c.$85 million. The capital investment total excludes Ugandan expenditure of c.$15 million which is due to be reimbursed by Total when the transaction completes.

Going concern

The Group closely monitors and carefully manages its liquidity risk. Cash flow forecasts are regularly updated and sensitivities run for different scenarios, including, but not limited to, changes in commodity price and different forecasts for the Group's producing assets. The Group continues to pursue further rationalisation of its cost base through a further reduction of general & administrative (G&A) and operating costs, cuts to discretionary capital investment (for example by directing capital towards producing fields to optimise value and near-term cash flow, and substantially reducing investment in exploration and appraisal activities) and deferring decommissioning expenditure. Management has engaged a specialist consultancy firm to support the identification of further cost reduction opportunities.

The Group has performed a cash flow assessment under a Base Case and a Low Case until 30 September 2022, aligning the assessment period with the 18-month liquidity forecast test required for the Reserve Based Lending ("RBL") re-determination in March 2021, the last such re-determination which falls within the 12-month Going Concern assessment period.

Cash flow forecasts have been regularly updated in light of the oil price volatility seen in the first half of 2020, caused by the COVID-19 pandemic (further discussed on page 10).

Management has applied the following oil price assumptions for the Going Concern assessment:

•      Base Case: $40/bbl for 2020, $45/bbl for 2021 and $50/bbl for 2022, and

•      Low Case: $30/bbl for 2020, $35/bbl for 2021 and $40/bbl for 2022.

The Low Case includes, amongst other downside assumptions, an 8% production decrease compared to the Base Case. As described on page 7, the Group benefits from its hedging policy, meaning that the impact of low oil prices in the Going Concern period is partially mitigated. Both the Base Case and the Low Case assume that the Uganda transaction will complete and that all debt is repaid in full at its contractual maturity date.

Liquidity

The Group's Base Case and Low Case scenarios forecast sufficient financial headroom for the 12 months from approval of its 2020 Half Year Results on 8 September 2020.

Management has also performed a reverse stress test and concluded that for the Group to reach zero liquidity at the end of the Going Concern period, the oil price would need to average ca. $10/bbl between 1 September 2020 and 30 September 2021, assuming successful RBL re-determinations in September 2020, January 2021 and March 2021. This is deemed to be significantly below reasonable worst-case oil price assumptions for that period.

In the unlikely event that the Uganda transaction does not complete, and the Group therefore does not receive $500 million proceeds on completion, the Base Case scenario forecasts that the Group reaches zero liquidity in July 2021 as a result of the forecast repayment of the Convertible Bond. This would result in an increased projected liquidity shortfall in respect of the 18-month Liquidity Forecast Test at the January 2021 and the March 2021 RBL re-determination (see below).

Gearing covenant

The RBL Facility contains a gearing covenant, which is tested for each 12-month period ending on 30 June and 31 December each year, and which requires that net debt of the Group as defined in the RBL Facility agreement is lower than 3.5 times consolidated EBITDAX for each relevant 12-month period. Under both the Base Case and the Low Case scenarios prepared by Management, the Group's gearing is forecast to be in excess of the RBL gearing covenant when calculated at 31 December 2020 and 30 June 2021.

In order to address the forecast breach of the RBL Gearing covenant, Management will seek an amendment of the covenant in advance of the relevant assessment, or a waiver, such that the covenant will not be breached. The Directors believe that the Group would be able to secure such an amendment or waiver, which would be both consistent with past practice, most recently in June 2020 when a relaxation to 4.5 times net debt to consolidated EBITDAX was agreed ahead of the 30 June 2020 covenant test, and the Directors' reasonable expectation of the commercial interests of the Group and its lenders.

Liquidity Forecast Test

As part of each RBL re-determination process the Group is required to demonstrate to the reasonable satisfaction of the relevant majority of its lenders under the RBL Facility that it has, or will have, sufficient funds available to meet the Group's financial commitments for a period of 18 months starting from the first month immediately following the relevant RBL re-determination. In addition to the scheduled RBL re-determinations each year in March and September, the Company has requested an RBL re-determination following the Capital Markets Day later this year, with that re-determination expected to conclude in January 2021. Based on liquidity projections under the Base Case and Low Case scenarios, which assume that the Uganda transaction will complete and, as required under the terms of the RBL Facility, that all debt is repaid in full at its contractual maturity date, the Group is expected to have sufficient liquidity for the 18-month period ending in March 2022, and as such the Group is expected to pass the Liquidity Forecast Test in respect of the September 2020 RBL re-determination.

The Group's cash flow projections forecast a potential liquidity shortfall during the 18-month period relevant to the Liquidity Forecast Test in respect of the January 2021 RBL re-determination due to the maturity of the $650m Senior Notes due in April 2022. If the Group is unable to demonstrate to the reasonable satisfaction of the relevant majority of its lenders under the RBL Facility that it has, or will have, sufficient funds available to meet the Group's financial commitments for the 18-month testing period from February 2021 to July 2022 inclusive, and the Group is unable to cure the forecast liquidity shortfall within 90 days following the date on which it becomes aware that it has not passed the Liquidity Forecast Test, there will be an event of default under the RBL Facility by the end of April 2021.

Management is undertaking a comprehensive review of each of the Group's assets to maximise their value. These plans will be laid out at a Capital Markets Day before the end of the year, following which Management expects to take one or more of the following actions which it believes would be progressed sufficiently by the end of January 2021 to address the forecasted liquidity shortfall in April 2022:

·    Evaluate refinancing options for either or both of the Convertible Bonds due in July 2021 and the Senior Notes due in April 2022.

·    Seek to agree more beneficial technical and/or economic assumptions with its lenders or to amend the commercial terms of the RBL Facility in order to maintain or increase debt capacity.

·    Seek to secure new liquidity from banks or capital markets investors.

In parallel, the Directors continue to evaluate strategic opportunities and engage in discussions with third parties with a view to raising material proceeds from portfolio management, in addition to the proceeds expected to be received from the Uganda transaction.

If in the opinion of the Directors the above initiatives cannot be sufficiently progressed by January 2021 to address the forecasted liquidity shortfall in April 2022, and in the unlikely event that the Uganda transaction does not complete, the Group will initiate discussions with its creditors with a view to agreeing a financial restructuring proposal.

Implications

The Directors note that the results of some of the actions mentioned above are outside the control of the Group. If a breach of the RBL Gearing covenant in respect of either of the 12-month testing periods ending on 31 December 2020 and 30 June 2021 were to occur or the Group were not to pass the 18 months Liquidity Forecast Test at the September 2020, the January 2021 or the March 2021 RBL re-determination, and the Group were unable to negotiate amendments or waivers to its covenants, the ability of the Group to continue trading would depend upon the Group being able to negotiate a financial restructuring proposal with its creditors and, if necessary, that proposal being approved by shareholders. Whilst the Board would seek to negotiate such a financial restructuring proposal with its creditors, there is no certainty that the creditors would engage with the Board in those circumstances. There would therefore be a significant risk of the Group entering into insolvency proceedings, which the Directors consider would likely result in limited or no value being returned to shareholders.

The Directors have concluded that the uncertainties associated with 1) securing amendments or waivers for the forecasted non-compliance with the RBL Gearing covenant as at 31 December 2020 and 30 June 2021 and 2) progressing sufficiently one or more of the actions outlined above, in order to pass the 18 months Liquidity Forecast Test at the January 2021 or the March 2021 RBL re-determination, are material uncertainties that may cast significant doubt that the Group will be able to continue as a Going Concern. Notwithstanding these material uncertainties, the Board's confidence in the Group's ability to obtain amendments or waivers for the forecasted non-compliance with the RBL Gearing covenant and to pass the Liquidity Forecast Test at the January 2021 and the March 2021 RBL re-determination supports the preparation of the financial statements on a Going Concern basis. The financial statements do not include the adjustments that would result if the Group were unable to continue as a Going Concern.

COVID-19 (Coronavirus)

The Company continues to monitor the ongoing COVID-19 outbreak. The key impact has been in respect of short- term oil demand and price volatility as noted in the Going Concern section above.

The Group has experience of managing infectious diseases of this nature following the significant contingency planning put in place during the West African Ebola outbreak in 2015. The Group actively monitors advice from the World Health Organisation and Public Health England, as well as participates in weekly calls with the International Oil and Gas Producers' Health Committee relating to the COVID-19 outbreak to ensure best practice precautions are being applied.

At present the threat level in the Group's countries of operation remains low, as per our Infectious Disease Health Management Guidelines, however we continue to closely monitor this as the situation develops. Clear information and health precautions on how employees should protect themselves and reduce exposure to, and transmission of, a range of illnesses along with general advice has been communicated across the organisation. In both Ghana and Kenya, the Group's in-country teams have set up their EID (Emerging Infectious Disease) Management committees in response to the current COVID-19 outbreak.

These EID Management committees steer the local management response to the outbreak, including ensuring that our contractors have implemented appropriate measures. The Company has also implemented 'self-declaration' forms for all personnel travelling to the Group's offshore assets in Ghana, that require people to sign-off that they have not been to the 'specified locations' as defined by the UK Foreign & Commonwealth Office in the last 30 days, as well as implementing business travel restrictions to and from these 'specified locations'. In the event of the COVID-19 outbreak escalating, country specific Business Continuity Plans set out how the Group proposes to continue to operate, recover quickly from, and effectively manage the response. In general, Covid-19 has had a minor impact on the Group's overall risk profile due to the controls and mitigations we have in place to manage these risks.

2020 principal financial 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 2020 to assess whether the principal risks and uncertainties disclosed in the 2019 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 2019 Annual Report as listed below. Consideration was given to whether a separate risk related to COVID-19 should be introduced, however it was concluded that the risks associated with COVID-19 are addressed and managed through the principal risks already in place. 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, as well as reviewing whether mitigating actions and controls remain valid as outlined in the COVID-19 section above.   

1.   Risk of major process safety, EHS incident or production failure in Ghana

2.   Risk of insufficient liquidity and funding capacity

3.   Risk of inability to make new significant oil discoveries and replenish exploration and subsurface portfolio

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

5.   Risk of disruption to business due to political/regulatory influence in Ghana

6.   Risk of failure to manage impact of climate change arising from evolving policy, regulation and carbon taxes

7.   Risk that the organisational model, people strategy and culture do not support strategy

8.   Risk of major breach of business conduct standards

9.   Risk of major cyber or information security incident

Events since 30 June 2020

There have not been any adjusting events since 30 June 2020 that have resulted in a material impact on the Half Year results.

However, there have been two non-adjusting events:

In Kenya, Tullow has been working with its Joint Venture Partners to progress the full field development plan. In May 2020 Tullow and its Joint Venture Partners declared FM on the Kenya licences. Following productive discussions with the Government, an improvement in the COVID-19 situation and assurances from Government that the tax incentives granted to the phased project will continue to apply, the FM notices were withdrawn in August 2020. Whilst these issues have resulted in a delay to the Final Investment Decision (FID) on the project, it has allowed time for both Tullow and its Joint Venture Partners to collaboratively work on realising the full potential of the assets. This has resulted in the Government of Kenya agreeing to an initial extension to the Second Additional Exploration Period for the 10BB and 13T licence blocks until 31 December 2020 with a final extension until 31 December 2021, contingent on an agreed work programme and budgets. Separately, the farm down process has been suspended while the Joint Venture Partners complete a comprehensive review of the development concept to ensure it continues to be robust at low oil prices, and also consider the strategic alternatives for the asset.

At a General Meeting on 15 July 2020, the Company announced that its request for approval of the proposed sale of its entire interests in Blocks 1, 1A, 2 and 3A in Uganda and the proposed East African Crude Oil Pipeline System to Total was passed by the requisite majority of its shareholders. Over 99% of the votes cast in the poll approved the transaction.

Non-IFRS measures

The Group uses certain measures of performance which are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include capital investment, net debt, gearing, adjusted EBITDAX, underlying cash operating costs and free cash flow.

Capital investment

Capital investment is defined as additions to property, plant and equipment and intangible exploration and evaluation assets less decommissioning asset additions, right-of-use additions, capitalised share-based payment charge, capitalised finance costs, additions to administrative assets, Norwegian tax refund and certain other adjustments. The Directors believe that capital investment is a useful indicator of the Group's organic expenditure on exploration and appraisal assets and oil and gas assets incurred during a period because it eliminates certain accounting adjustments such as capitalised finance costs and decommissioning asset additions.

	1H 2020	1H 2019
Additions to property, plant and equipment	162.1	317.7
Additions to intangible exploration and evaluation assets	114.6	112.2
Less
Decommissioning asset additions	27.2	22.7
Right-of-use asset additions	19.5	127.1
Lease payments related to capital activities	(2.2)	(1.4)
Capitalised share-based payment charge	0.6	0.6
Capitalised finance costs	-	12.1
Additions to administrative assets	4.8	5.2
Uganda capital investment	-	16.3
Other non-cash capital expenditure	34.5	(0.7)
Capital investment	192.3	248
Movement in working capital	25.1	(18.4)
Additions to administrative assets	4.8	5.2
Uganda capital investment	-	16.3
Cash capital expenditure per the cash flow statement	222.2	251.1

 

Net debt

Net debt is a useful indicator of the Group's indebtedness, financial flexibility and capital structure because it indicates the level of cash borrowings after taking account of cash and cash equivalents within the Group's business that could be utilised to pay down the outstanding cash borrowings. Net debt is defined as current and non-current borrowings plus non-cash adjustments, less cash and cash equivalents. Non-cash adjustments include unamortised arrangement fees, adjustment to convertible bonds, and other adjustments. The Group's definition of net debt does not include the Group's leases as the Group's focus is the management of cash borrowings and a lease is viewed as deferred capital investment. The value of the Group's lease liabilities as at 30 June 2020 was $263.5 million current and $1,063.4 million non-current; it should be noted that these balances are recorded gross for operated assets and are therefore not representative of the Group's net exposure under these contracts.

	1H 2020	1H 2019
Non-current borrowings	3,239.2	3,285.4
Non-cash adjustments1	16.6	24.9
Less cash and cash equivalents2	(236.3)	(362.3)
Net debt	3,019.5	2,948.0

¹ Non-cash adjustments include unamortised arrangement fees which are incurred on creation or amendment of borrowing facilities as well as the Convertible Bonds which were measured at fair value. The difference between the fair value and the principal of the bond was included as a component of equity and a decrease to borrowings. Over the life of the Convertible Bond, the fair value reduces until the carrying value of the borrowings is equal to the principal outstanding for repayment on maturity.

² Cash and cash equivalents includes an amount of $32 million (1H 2019: $231 million) which the Group holds as operator in Joint Venture bank accounts. In addition to the cash held in joint venture bank accounts the Group had $67 million (1H 2019: $31 million) held in restricted bank accounts.

Gearing and Adjusted EBITDAX

Gearing is a useful indicator of the Group's indebtedness, financial flexibility and capital structure and can assist securities analysts, investors and other parties to evaluate the Group. Gearing is defined as net debt divided by adjusted EBITDAX. This definition of gearing differs from the one included in the RBL facility agreements. Adjusted EBITDAX is defined as profit/(loss) from continuing activities adjusted for income tax (expense)/credit, finance costs, finance revenue, gain on hedging instruments, depreciation, depletion and amortisation, share-based payment charge, restructuring costs, gain/(loss) on disposal, exploration cost written off, impairment of property, plant and equipment net, and provision for onerous service contracts.

	1H 2020	1H 2019
Adjusted EBITDAX1	1,012.9	1,623.2
Net debt	3,019.5	2,948.0
Gearing (times)	3.0	1.8

¹ Last 12 months (LTM). Refer to the 2019 Annual Report and Accounts for a full reconciliation of Adjusted EBITDAX.

Underlying cash operating costs

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

	1H 2020	1H 2019
Cost of sales	567.0	375.1
Add
Lease payments related to operating activity	1.2	0.9
Less
Depletion and amortisation of oil and gas and leased assets1	266.7	290.8
Underlift, overlift and oil stock movements2	128.9	(86.4)
Share-based payment charge included in cost of sales3	1.3	0.5
Other cost of sales4	16.0	26.1
Underlying cash operating costs	155.3	145.0
Working Interest Production (MMboe)	14.1	16.1
Underlying cash operating costs per boe ($/boe)	11.0	9.0

¹ Depletion and amortisation of oil and gas assets is the depreciation and amortisation of the Group's oil and gas assets over the life of an asset on a unit of production basis.

² Under lifting or offtake arrangements for oil and gas produced in certain operations in which the Group has interests with other commercial partners, each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative production less stock constitutes "underlift" or "overlift". Underlift and overlift are valued at market value and included within other current assets and other current payables on the Group's balance sheet, respectively. Movements during an accounting period are charged to cost of sales rather than charged through revenue, and as a result gross profit is recognised on an entitlements basis.

³ Share-based payment charge included in cost of sales relates to the portion of the non-cash share-based payment charge that relates to employees who work on operational projects.

⁴ Other cost of sales includes purchases of gas from third parties to fulfil gas sales contracts and royalties paid in cash.

Free cash flow

Free cash flow is a useful indicator of the Group's ability to generate cash flow to fund the business and strategic acquisitions, reduce borrowings and provide returns to shareholders through dividends. Free cash flow is defined as net cash from operating activities, and net cash used in investing activities, less debt arrangement fees, repayment of obligations under leases, finance costs paid, foreign exchange gain, and distribution to non-controlling interests.

	1H 2020	1H 2019
Net cash from operating activities	202.6	597.4
Net cash used in investing activities	(221.0)	(239.1)
Repayment of obligations under leases	(86.3)	(83)
Finance costs paid	(105.0)	(95.0)
Foreign exchange loss	(2.8)	-
Dividends paid	-	68.3
Free cash flow	(212.5)	180.8
Dividends paid	-	(68.3)
Free cash flow after dividend payment	(212.5)	112.5

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,