TULLOW OIL PLC - 2023 HALF YEAR RESULTS
Tullow oil PLC - 2023 Half Year Results
First half revenue of $777 million, gross profit of $351 million and profit after tax of $70 million
Start-up of Jubilee South East marks major step up in production and free cash flow
Business plan on track to deliver c.$800 million free cash flow between 2023-2025
13 September 2023 - Tullow announces its Half Year results for the six months ended 30 June 2023. Tullow will host a webcast presentation at 9am this morning, details of which can be found below and online at www.tullowoil.com.
Rahul Dhir, Tullow Chief Executive Officer, commented today:
"We are at an important inflection point in the evolution of our business plan. For the last two and a half years we have relentlessly focused on capital discipline, operational performance and appropriate investment in our assets. This has resulted in a much-improved business, material debt reduction and most recently, the delivery of Jubilee South East which has substantially increased production. We now switch to harvesting mode as our business is set to generate c.$800 million of free cash flow between 2023 and 2025, whilst we will continue to run our business with the same discipline. This will enable us to further reduce our debt, put in place a sustainable capital structure and grow our business to create value for our investors, host nations and employees."
Delivering strategic priorities
· First half working interest production of 53.5 kboepd; additional 7.3 kboepd net gas production from Ghana.
· Start-up of Jubilee South East project, with gross production from the Jubilee field surpassing 100 kbopd.
· Commercialisation of Ghana gas through interim gas sales agreement; represents a new revenue stream for Tullow.
· Strong operational and safety performance; 97% average uptime at Jubilee and TEN FPSOs; four new Jubilee wells online year to date.
· Gabon portfolio optimisation through cashless asset swap agreement with Perenco and licence extensions.
· Unlocked value from sale of Tullow Guyana B.V., including the Orinduik licence, to Eco Atlantic for cash and contingent consideration.
· Accelerated deleveraging through purchase of c.$166 million of 2025 Notes for c.$100 million cash consideration.
First Half financial Results
· Revenue of $777 million; realised oil price of $73.3/bbl after hedging; gross profit of $351 million; profit after tax of $70 million.
· Underlying operating cash flow of $188 million1; free cash flow of $(142) million1.
· Capital investment of $187 million and decommissioning costs of $44 million.
· Net debt at 30 June 2023 of $1.9 billion1; Gearing of 1.7x net debt/EBITDAX1; liquidity headroom of $0.7 billion.
Full Year Outlook
· Full year oil production guidance narrowed to 58 to 60 kbopd (from 58 to 64 kbopd); additional c.7 kboepd gas production expected from Ghana.
· Unchanged full year capex guidance of c.$400 million and decommissioning spend of c.$70 million.
· Significant free cash flow reversal in the second half with c.$200 million1 generated at $80/bbl. Unchanged full year free cash flow guidance of c.$100 million1 at $80/bbl.
· Year-end net debt expected to be c.$1.7 billion1 and gearing expected to be c.1.5x (net debt/EBITDAX)1.
· Continued delivery of business plan to generate c.$800 million of free cash flow1 from 2023 to 2025, supported by strong production outlook and capex flexibility.
· Progressing a range of options to address debt maturities and position the business for a successful refinancing.
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Webcast - 9:00 BST
Access the webcast using the following link and follow the instructions provided: https://web.lumiconnect.com/156469303
Contacts |
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Tullow Investor Relations Nicola Rogers |
Camarco (Media) (+44 20 3781 9244) Billy Clegg Andrew Turner Rebecca Waterworth |
1Alternative performance measures are reconciled on pages 36 to 39.
Operational UPDATE
Production
Group working interest production averaged 53.5 kboepd in the first half of 2023. In addition, 7.3 kboepd of gas was sold under the Ghana Interim Gas Sales Agreement. Full year oil production guidance has been narrowed to 58-60 kbopd (previously 58 to 64 kbopd), driven by Jubilee first half performance slightly below expectations and the timing of the Jubilee South East start up in the second half of the year. Full year gas production in Ghana is expected to average c.7 kboepd.
Ghana
Jubilee
Gross oil production from the Jubilee field averaged 72.4 kbopd (net: 28.2 kbopd) in the first half of the year. This was slightly below expectations largely due to reduced water injection in late 2022 and into the first quarter of 2023, which has since been rectified in February 2023. In addition, Jubilee South East starting up in July has shifted the tie in and contribution of new wells to slightly later than planned. While this timing impacts the full year forecast, the anticipated ramp up remains unchanged and the field is expected to exit the year over 100 kbopd, as initially forecast at the start of 2023. Full year 2023 gross oil production from Jubilee is expected to average c.90 kbopd (net: c.35 kbopd), reduced from c.95 kbopd gross (net: c.37 kbopd).
Four wells have been brought on stream year to date - a Jubilee main producer in May, two JSE producers in July and another JSE producer this month. Two further wells - both water injectors - are scheduled to be brought on stream before year end. The wells are performing in line with expectations and the start-up of JSE has quickly increased gross production rates, with the field currently producing over 100,000 bopd. The start-up of JSE marks a significant milestone that underpins future growth and cash flow delivery, and the Group looks forward to continued project delivery.
Tullow and its partners aim to maintain the increased level of production at Jubilee through an ongoing infill drilling programme. The partnership has identified multiple future drilling locations and further opportunities to extend the plateau towards the end of the decade and realise the full potential of the significant Jubilee resource base.
TEN
Production from the TEN fields averaged 20 kbopd (net: 11 kbopd) during the first half of 2023, with improved pressure support from injection wells put online during 2021-22 resulting in negligible decline. Full year gross production remains c.20 kbopd gross (net: c.11kbopd). A planned shutdown was carried out in July and work was completed to improve asset integrity, enhance production through increased gas injection and higher liquids recovery, and reduce flaring in line with our Net Zero commitment. The TEN flare has reduced by around 50% compared to before the shutdown and with a plan to further reduce flaring at TEN into 2024.
Gas commercialisation
Net gas production in Ghana averaged 7.3 kboepd in the first half of the year. The Interim Gas Sales Agreement, initially valued at $0.50/mmbtu, was amended in July 2023 to a price of $2.90/mmbtu until the end of the third quarter of 2023. The commercialisation of Jubilee gas represents a new revenue stream for Tullow of c.$4 million per month, while commercial discussions continue for the long-term gas sales agreement. Full year net gas production in Ghana is expected to average c.7 kboepd.
Non-operated portfolio
Net production from the non-operated portfolio averaged 14.3 kboepd in the first half of 2023, in line with expectations, and full year net production forecast remains c.14 kboepd.
Production from Gabon averaged 12.8 kbopd net in the first half of 2023. In April 2023, a cashless asset swap was agreed with Perenco Oil and Gas Gabon S.A. to optimise Tullow's equity ownership across key fields in Gabon. The deal delivers a more balanced portfolio of discovered resources, appraisal and exploration assets, with the Tchatamba facilities placed as a core hub for Tullow.
Tullow announced in August that it had gained Government approval for the extension of several of its Gabon licences to 2046 reflecting the future potential of these Gabon fields and the longevity of the Tchatamba facilities. The extension is expected to add c.5mmbbls net 2P reserves, which would deliver c.100% 2P reserves replacement in Gabon this year.
Production from Tullow's fields in Gabon remains unaffected by the ongoing political activity in the country and the Group continues to work closely with the operators of its fields to ensure the safe continuation of operations.
ILX drilling continued in Gabon with the Akoum B appraisal well which was plugged and abandoned in the second quarter of 2023 after encountering insufficient resources to justify development. Within the Simba and DE8 licences, several low-risk and compelling investment options are being high-graded for near term drilling programmes.
Production from Espoir in Côte d'Ivoire averaged c.1.5 kboepd net in the first half of 2023. Tullow and its Joint Venture (JV) Partners exercised the option to purchase the Espoir FPSO for a gross consideration of c.$20 million (c.$5 million net). Tullow continues to work with the operator to establish the best way forward for the asset.
Exploration
In August, Tullow announced the sale of Tullow Guyana B.V, including the 60% operated Orinduik licence, to Eco Atlantic. The sale consists of $0.7 million cash payment upon completion and contingent considerations of $4 million on commercial discovery and $10 million on issuance of a production licence. Furthermore, royalty payments on potential future production of 1.75% of the working interest entitlement revenue net of capital expenditure and lifting costs will be due to Tullow. This transaction is in line with Tullow's strategy to optimise its portfolio and unlock value from its positions in emerging basins. Tullow and Eco Atlantic are working to secure the required approvals before the end of the year.
Decommissioning
Decommissioning expenditure in the UK and Mauritania was $44 million during the first half of the year and full year guidance was lowered to c.$70 million, following the deferral of certain activities into 2024. 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 2024-26 is c.$70 million. A further c.$10 million will be paid into escrow in 2023 for future decommissioning obligations in Ghana.
Kenya
Following the withdrawal of its minority partners from Project Oil Kenya in the first half of 2023, Tullow is now the sole partner in the project (refer to Note 11 for more detail). This has created a more flexible proposition for a strategic partnership and discussions continue with several interested parties. The Kenyan energy regulator (EPRA) has recently engaged third party consultants to assist with the review of the Field Development Plan (FDP) and Tullow continues to work with the Government of Kenya and EPRA on the approval of the FDP.
Environment, Social and GOVERNANCE (ESG)
As part of Tullow's decarbonisation programme towards Net Zero in 2030, good progress is being made to eliminate routine flaring on Tullow's FPSOs in Ghana. Increased gas handling capacity work is underway on Jubilee, whilst the TEN flare has reduced by around 50% compared to before the shutdown, with a plan to further reduce flaring at TEN into 2024.
Tullow is progressing its carbon offset project with the Ghana Forestry Commission. The project is set to mitigate Tullow's hard to abate, residual, emissions whilst also supporting Ghana in meeting its Nationally Determined Contributions under the Paris Agreement. The Forestry Commission has started to engage initial stakeholders involved with the project.
Tullow continues to support education and skills development in our local communities. So far this year under Phase III of the Senior High Schools programme construction has been completed on facilities that will enable c.1000 students to access accommodation and senior high school education, and Phase IV construction is underway that will support over 1,000 additional students.
On local content, a focus area this year has been on developing Ghanaian supplier community awareness; in July, 73 indigenous Ghanaian companies and 11 officials of the Petroleum Commission graduated from the "Tullow Supply Chain Academy Programme" run in partnership with Accenture. Tullow continues to focus on increasing procurement spend with indigenous and JV companies in Ghana. In the first half of 2023, 95% of total procurement spend was with indigenous and JV companies compared to 88% over the same period last year.
At Tullow's Annual General Meeting on 24 May 2023, c.27% of votes were cast against Resolution 19. The Resolution sought the authority for the Company to purchase its own shares, pursuant to section 701 of the Companies Act 2006 (the Act) (within the meaning of section 693(4) of the Act) on such terms and in such manner as the Board of Directors of the Company may from time to time determine. As a special resolution it therefore did not pass. The Board has continued its dialogue with our major shareholders who voted against the resolution and has an understanding of the concerns raised, which relate to the potential impact on their existing shareholdings.
Mike Daly stepped down from the Board following the 2023 AGM, having served nine years as an independent non-executive Director.
Rebecca Wiles was appointed as an independent non-executive Director in June 2023, bringing deep technical subsurface and geoscience expertise as well as emerging markets experience in Africa to the Tullow Board, following a 33-year career at BP plc.
FINANCE REVIEw
|
Income Statement (key metrics) |
1H 2023 |
1H 2022 Restated1 |
|
Revenue ($m) |
|
|
|
Sales volume (boepd) |
56,900 |
53,500 |
|
Realised oil price ($/bbl) |
73.3 |
86.3 |
|
Total revenue |
777 |
859 |
|
Operating costs ($m) |
|
|
|
Underlying cash operating costs2 |
136 |
143 |
|
Depreciation, Depletion and Amortisation (DD&A) of oil and gas and leased assets |
163 |
177 |
|
DD&A before impairment charges ($/bbl) |
14.8 |
15.6 |
|
Overlift, (underlift) and oil stock movements |
109 |
(120) |
|
Administrative expenses |
19 |
23 |
|
Gain on bargain purchase |
- |
197 |
|
Gain on bond buyback |
65 |
- |
|
Exploration costs written off |
(10) |
(87) |
|
Impairment of property, plant and equipment, net |
(33) |
(7) |
|
Net financing costs |
(135) |
(149) |
|
Profit from continuing activities before tax |
217 |
561 |
|
Income tax expense |
(147) |
(297) |
|
Profit for the year from continuing activities |
70 |
264 |
|
Adjusted EBITDAX 2 |
1,171 |
1,276 |
|
Basic earnings per share (cents) |
4.9 |
18.4 |
1Refer to note 2 for details on prior year restatement.
2Alternative performance measures are reconciled on pages 36 to 39.
Revenue
Sales volumes
During the period, there were 56,900 boepd (1H2022: 53,500 boepd) of liftings. The increase is mainly due to an additional lifting in 1H 2023 in Gabon compared to 1H 2022 where an incident at the Cap Lopez terminal had delayed a lifting. The total number of liftings in Ghana is comparable to the previous period with 6 in Jubilee (1H 2022: 5) and 2 in TEN (1H 2022: 3).
Realised oil price ($/bbl)
The Group's realised oil price after hedging for the period was $73.3/bbl (1H 2022: $86.3/bbl) and before hedging $79.7/bbl (1H 2022: $106.9/bbl). Lower oil prices compared to 1H 2022 have resulted in a lower hedge loss decreasing total revenue by $65.9 million in 1H 2023 (1H 2022: decrease of $189.6 million).
Cost of Sales
Underlying cash operating costs amounted to $136 million; $12.4/boe (1H 2022: $143 million; $13.0/boe). The cash unit operating costs have decreased against the comparative period due to a decrease in total operating costs in Ghana following the O&M transition in the second half of 2022 and in Gabon due to a change in the cost allocation for the Perenco-operated fields.
Depreciation, depletion and amortisation (DD&A)
DD&A charges before impairment on production and development assets amounted to $163 million; $14.8 /boe (1H 2022: $177 million: $16.1/boe). This decrease in DD&A is mainly attributable to 2022 impairments relating to TEN.
Overlift, underlift and oil stock movements
The Group had an overlift expense compared to an underlift in the comparative period. The change was due to timing of liftings specifically in Gabon in 1H 2022 where an incident at the Cap Lopez terminal delayed a lifting.
Administrative expenses
Administrative expenses of $19 million (1H 2022: $23 million) have decreased against the comparative period mainly due to decrease in depreciation of administrative assets. Tullow achieved in excess of $360 million in net cash savings for the 3-year period since mid-2020 to date thereby significantly exceeding the target of $200 million cash savings for 3-year period that had been set.
Gain on bond buyback - refer to Borrowings section below.
Exploration costs written off
During the first half of 2023, the Group has written off exploration costs of $10 million (1H 2022: $87 million) which was predominantly driven by Kenya where withdrawal of the JV Partners led to a re-assessment of risks associated to reaching FID resulting in a $9 million impairment.
Impairment of property, plant and equipment (PP&E)
The Group recognised a net impairment charge on PP&E of $33 million in respect of the first half 2023 (1H 2022: $7 million) due to changes to estimates on the cost of decommissioning for certain UK and Mauritania assets.
Net financing costs
Net financing costs for the period were $135 million (1H 2022: $149 million). This decrease is mainly due to lower interest on obligations under finance leases of $6 million as well as an increase in interest income of $8 million primarily due to higher interest rates. A reconciliation of net financing costs is included in Note 9.
Taxation
The overall net tax expense of $147 million (1H 2022: $297 million) primarily relates to tax charges in respect of the Group's production activities in West Africa, reduced by tax credits associated with UK decommissioning, exploration write-offs and impairments. The tax charge has been calculated by applying the effective tax rate which is expected to apply to each jurisdiction for the year ending 31 December 2023.
Based on a profit before tax for the first half of the year of $217 million (1H 2022: $561 million), the effective tax rate is 67.7% (1H 2022: 52.9%). After adjusting for the non-recurring amounts related to exploration write-offs, impairments, onerous lease provisions and their associated tax benefit, the Group's underlying effective tax rate is 56.2% (1H 2022: 63.0%). The underlying effective tax rate has decreased primarily due to there being no UK tax benefit from net interest and hedging expenses, representing a smaller proportion of the Group's overall profits in 1H 2023 than in 1H 2022. Non-deductible expenditure in Ghana and Gabon and prior year adjustments are additional contributing factors.
The Group's future statutory effective tax rate is sensitive to the geographic mix in which pre-tax profits arise. There is no UK tax benefit from net interest and hedging expenses, whereas net interest income and hedging profits would be taxable in the UK. Consequently, the Group's tax charge will continue to vary according to the jurisdictions in which pre-tax profits occur.
|
Analysis of adjusted effective tax rate ($'m) |
Adjusted profit/(loss) before tax |
Adjusted tax (expense)/credit |
Adjusted effective tax rate |
|
Ghana - 1H 2023 |
266.0 |
(97.7) |
36.7% |
|
1H 2022 |
543.8 |
(192.8) |
35.5% |
|
Gabon - 1H 2023 |
105.0 |
(49.7) |
47.3% |
|
1H 20221 |
199.3 |
(93.0) |
46.6% |
|
Corporate - 1H 2023 |
(114.3) |
1.7 |
1.5% |
|
1H 2022 |
(299.7) |
0.2 |
0.1% |
|
Other non-operated & exploration - 1H 2023 |
5.2 |
(1.5) |
28.7% |
|
1H 20221 |
17.9 |
(5.2) |
29.2% |
|
Total - 1H 2023 |
261.9 |
(147.2) |
56.2% |
|
1H 20221 |
461.3 |
(290.8) |
63.0% |
1The prior year has been restated to include the notional tax on the profit oil within current tax expense in accordance with the terms of the respective Production Sharing Contracts (PSCs). Refer to note 2.
Adjusted EBITDAX
Adjusted EBITDAX for the year was $1,171 million (1H 2022 restated: $1,276 million). The decrease in the period was mainly driven by lower revenues as a result of lower oil prices.
Profit for the year from continuing activities and earnings per share
The profit after tax for the period amounted to $70 million (1H 2022: profit of $264 million). Basic earnings per share was 4.9 cents (1H 2022: 18.4 cents).
Balance Sheet and Liquidity management
|
Balance Sheet and Liquidity management (key metrics) |
1H 2023 |
1H 2022 |
|
Capital investment ($m)1 |
187 |
156 |
|
Derivative financial instruments ($m) |
(79) |
(573) |
|
Borrowings ($m) |
(2,211) |
(2,471) |
|
Underlying operating cash flow ($m) 1 |
188 |
165 |
|
Free cash flow ($m)1 |
(142) |
(205) |
|
Net debt ($m)1 |
1,938 |
2,336 |
|
Gearing (times)1, 2 |
1.7 |
1.8 |
1Alternative performance measures are reconciled on pages 36 to 39.
2 Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the period ended 30 June 2023 of $8.0 million (1H 2022: $12.9 million; FY 2022: $21.4 million), and a corresponding increase to income tax expense.
The restatement impacted Adjusted EBITDAX and Gearing as at 30 June 2022, increasing Adjusted EBITDAX from $1,262.6 million to $1,275.5 million, and reducing gearing from 1.9 to 1.8. Refer to Note 2.
Capital investment
Capital expenditure amounted to $187 million (1H 2022: $156 million) with $177 million invested in production and development activities and $10 million invested in exploration and appraisal activities.
Capital investment will continue to be carefully controlled in the second half of 2023 and total 2023 capital expenditure is expected to be c.$400 million. The capital investment total is expected to comprise Ghana capex of c.$300 million, West African Non-Operated capex of c.$60 million, Kenya capex of c.$10 million and exploration spend of c.$30 million.
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.
Tullow's commodity hedging policy aims to ensure that 60% of the forecast sales entitlement volumes benefit from downside protection for the first year ahead, and 30% for the second year ahead. In addition, through appropriate instrument selection, Tullow is committed to maintaining full access to upside for no less than 60% of sales volumes. Tullow has recently started the implementation of new hedges and now has downside protection in place for c.60% of forecast sales volumes through to the end of 2023, with legacy uncapped upside exposure for c.45% for the same period.
At 30 June 2023, the Group's derivative instruments had a net negative fair value of $79 million (30 June 2022: negative $573 million).
All financial instruments that are initially recognised and subsequently measured at fair value have been classified in accordance with the hierarchy described in IFRS 13 Fair Value Measurement. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions or using standard valuation techniques for the applicable instruments and commodities involved.
All of the Group's derivatives are Level 2 (1H 2022: Level 2). There were no transfers between fair value levels during the year.
|
Hedge position at 30 June 2023 |
2H 20231 |
1H 20242 |
2H 20243 |
|
|
Hedged Volume (kbopd) |
34,513 |
22,734 |
- |
|
|
Weighted average bought put (floor) ($/bbl) |
$56/bbl |
$56/bbl |
- |
|
|
Weighted average sold call ($/bbl) |
$75/bbl |
$76/bbl |
- |
|
From 30 June to date, Tullow has added further hedge volumes in the following periods:
1Aug-Dec 23: 5 kbopd $60/bbl straight puts;
21H 2024: c.9 kbopd $60/bbl straight puts,
32H 2024: 3.5 kbopd of collar structures with $60/bbl floors and weighted average sold upside (ceiling) of $115/bbl.
Borrowings
On 15 May 2023, the Group made a mandatory prepayment of $100 million of the Senior Secured Notes due 2026, which reduced total drawn debt to $2.4 billion. On 20 June 2023, the Group repurchased $167 million nominal value of Senior Notes due 2025 for $100 million cash consideration through an Unmodified Dutch Auction. This further reduced total debt to $2.2 billion. A gain on early bond redemption of $65 million is recognised as other income in the income statement. The remaining outstanding Senior Notes due 2025, amounting to $633 million nominal value, are due in March 2025.
Management regularly reviews options for optimising the Group's capital structure and may seek to retire or purchase outstanding debt from time to time through cash purchases or exchanges in the open market or otherwise. Refer to Note 18 - Borrowings for further detail.
Credit Ratings
Tullow maintains credit ratings with Standard & Poor's (S&P) and Moody's Investors Service (Moody's).
On 21 June 2023, S&P's downgraded Tullow's corporate credit rating to CCC+, stable outlook, from B- with negative outlook, and the rating of the $1.6 billion Senior Secured Notes due 2026 to CCC+ from B- and the rating of the $633m Senior Notes due 2025 to CCC from CCC+. S&P's rating action follows Tullow's repurchase of $166.5 million of its $800 million Senior Notes due 2025 and reflects S&P's view that there may be a risk of further bond buybacks below par, which S&P's may see as distressed, and Tullow's dependence, in S&P's view on favourable financial markets to refinance its debt maturities.
On 21 June 2023, Moody's appended a limited default (LD) designation to Tullow's Caa1-PD Probability of Default rating following Tullow's repurchase of $166.5 million of its $800 million Senior Notes due 2025. The LD designation reflects Moody's view that Tullow's debt repurchase constitutes a 'distressed exchange' under Moody's definition, which encompasses events whereby issuers fail to fulfil debt service obligations outlined in their original debt agreements, including buying back outstanding debt at a substantial discount to par. As per Moody's methodology, the LD designation was removed after 3 business days. The LD designation does not constitute a rating action. Consequently, Tullow's ratings remain unchanged at Caa1, negative outlook for the corporate credit rating, Caa1 for the $1.6 billion Senior Secured Notes due 2026, and Caa2 for the $633 million Senior Notes due 2025.
Underlying Operating Cash Flow and Free Cash Flow
Underlying operating cash flow amounted to $188 million (1H 2022: $165 million.) This increase mainly relates to a payment in 1H 2022 of $77 million relating to a historic dispute that has now been settled, lower Gabon royalty payments of $18m and lower operating costs of $11 million offset by a decrease in cash revenue of $81 million in the current period.
Free cash flow has increased to $(142) million (1H 2022: $(205) million) primarily due to an increase in underlying operating cash flow of $23 million as explained above. There has been a decrease in net cash used in investing activities of $58 million due to the one- off Ghana pre-emption payment and Uganda FID consideration receipt in 1H 2022 but this has been offset by an increase in capex of $15 million and decommissioning spend of $11 million in the current period.
Net Debt and Gearing
Reconciliation of net debt |
$m |
|
FY 2022 net debt |
1,864 |
|
Sales revenue |
(777) |
|
Operating costs |
136 |
|
Other operating and administrative expenses |
189 |
|
Operating cash flow before working capital movements |
(452) |
|
Movement in working capital |
78 |
|
Tax paid |
165 |
|
Purchases of intangible exploration and evaluation assets and property, plant and equipment |
149 |
|
Other investing activities |
(13) |
|
Other financing activities |
215 |
|
Gain on bond buyback |
(65) |
|
Foreign exchange loss on cash |
(3) |
|
1H 2023 net debt |
1,938 |
Liquidity Risk Management and Going concern
The Directors consider the going concern assessment period to be up to 30 September 2024. 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: $76/bbl for 2023, $74/bbl for 2024; and
Low Case: $70/bbl for 2023, $70/bbl for 2024.
The Low Case includes, amongst other downside assumptions, a 10% production decrease and 12% increased operating costs compared to the Base Case as well as increased outflows associated with ongoing disputes. It also assumes that the TEN FPSO remains leased and not purchased during the assessment period as Tullow has control over the timing of the purchase under the contract.
At 30 June 2023, the Group had $0.7 billion liquidity headroom consisting of c.$0.2 billion free cash and $0.5 billion available under the revolving credit facility.
The Group or its affiliates may, at any time and from time to time, seek to retire or purchase outstanding debt through cash purchases and/or exchanges, in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will be upon such terms and at such prices as management may determine, and will depend on prevailing market conditions, liquidity requirements, contractual restrictions, and other factors. The amounts involved may be material.
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.
2023 principal risks and uncertainties
The Company risk profile has been closely monitored throughout the year, with consideration given to the risks to delivering the Business Plan, as well as whether external factors such as geo-political factors, global pandemics and oil price volatility have resulted in any new risks or changes to existing risks. The impact of these factors has been considered and managed across all principal risks. The directors have reviewed the principal risks and uncertainties facing the Company and concluded that for the remaining six months of the financial year are substantially unchanged from those disclosed in the 2022 Annual Report and are listed below.
1. Risk of failure to deliver business plan
2. Risk of an asset integrity breach
3. Risk of a major accident event
4. Risk of failure to unlock value
5. Risk of failure to manage geopolitical risks
6. Risk of failure to meet climate change targets
7. Risk of insufficient liquidity and funding capacity to sustain and grow the business or risk of failure to deliver a highly cash-generative business
8. Risk of failure to develop, retain and attract capability
9. Risk of a compliance or regulatory breach
10. Risk of major cyber disruption
The detailed descriptions of the principal risks and how they are being managed can be found on pages 42 to 45 in the 2022 Annual Report and Accounts.
Events since 30 June 2023
Gabon
Approval of asset swap with Perenco
On 28 April 2023, Tullow announced that through its wholly owned subsidiary, Tullow Oil Gabon S.A., it had signed an asset swap agreement (ASA) with Perenco Oil and Gas Gabon S.A. (Perenco). Under the ASA, Tullow has agreed to assign and transfer certain of its existing participating interests in Limande, Turnix, M'oba, Oba and Simba assets to Perenco in return for the assignment and transfer by Perenco of 15% if its participating interests in Kowe (Tchatamba) and 20% of its participating interests in DE8 assets to Tullow.
The exchange of the transferred Interests between the parties will be deemed for all purposes to be made with effect from the economic date of 1 February 2023. Due to the agreed neutrality of the transaction, no additional consideration is payable by either party in respect thereof. The ASA includes provisions to ensure the neutrality of the transaction via cash adjustments for the period between signing and completion.
On completion, all assets and associated liabilities relating to the existing participating interests held in Limande, Turnix, M'Oba and Oba assets, together with 17.5% of Tullow's interest in Simba, will be disposed. All assets impacted by the transaction are included in the "Non-Operated" business unit applied for segment performance reporting.
The transaction is expected to complete by the end of 2023, subject to the fulfilment of certain conditional precedents, including the written approval of the relevant Governmental Authority of the Gabonese Republic of the amendment of the Tullow Protocol. (The "Tullow Protocol" is an investment convention that applies to certain Tullow licences.)
Management concluded that the assets did not meet the IFRS 5 Held for Sale(HFS) criteria as of 30 June 2023 because the approval of the Tullow Protocol was considered a substantive condition without which the transaction would be unlikely to proceed. Subsequent to the reporting date, the approval has been received and the HFS criteria was met on 19 July 2023.
Licence extensions
On 9 August 2023, Tullow announced that it had gained approval from the Government of Gabon for the extension of several of its Gabon licences operated by Perenco, from 2034 to 2046. In addition to fulfilling the conditional precedent to the swap transaction, the licence extension increases the value of Tullow's resource base through the addition of c.5mmbbls net 2P reserves that are expected to deliver c.100% 2P reserves replacement in Gabon this year.
Current political situation
Production from Tullow's fields in Gabon remains unaffected by the ongoing political activity in the country and the Group continues to work closely with the operators of its fields to ensure the safe continuation of operations.
Guyana
On 10 August 2023 Tullow announced that it had agreed to sell its total interest in Tullow Guyana B.V., which includes the Orinduik licence (60% operated equity) in Guyana, to Eco Guyana Oil and Gas (Barbados) Limited in exchange for an upfront cash consideration of $0.7 million and contingent consideration linked to a series of potential future milestones, triggered as follows:
· $4 million payment in the event of a commercial discovery;
· $10 million payment upon the issuance of a production licence from the Government of Guyana;
· Royalty payments on future production - 1.75% of the 60% working interest entitlement revenue net of capital expenditure and lifting costs.
The transaction is subject to customary government and other approvals and is expected to complete in the second half of 2023.
There have not been any other events since 30 June 2023 that have resulted in a material impact on the interim results.
Responsibility statement (DTR 4.2 and the Transparency (Directive 2004/109/EC) Regulations (as amended))
The Directors confirm that to the best of their knowledge:
a. the condensed set of financial statements has been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted by the UK and EU and IAS 34 'Interim Financial Reporting' as adopted by the EU, the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority (DTR) and the Transparency (Directive 2004/109/EC) Regulations 2007 as amended
b. the interim management report includes a fair review of the information required by DTR 4.2.7R and Regulation 8(2) (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and
c. the interim management report includes a true and fair review of the information required by DTR 4.2.8R and Regulation 8(3) (disclosure of related parties' transactions and changes therein).
A list of the current Directors is maintained on the Tullow Oil plc website: www.tullowoil.com.
By order of the Board,
Rahul Dhir
Chief Executive Officer
12 September 2023
Richard Miller
Chief Financial Officer
12 September 2023
Disclaimer
This statement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil and gas exploration and production business. Whilst the Group believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Group's control or within the Group's control where, for example, the Group decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward-looking statements.
Independent review report to Tullow Oil plc
Conclusion
We have been engaged by the Company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2023 which comprises Condensed consolidated income statement, Condensed consolidated statement of comprehensive income and expense, Condensed consolidated balance sheet, Condensed statement of changes in equity, Condensed consolidated cash flow statement and the related notes 1 to 23. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.
Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2023 is not prepared, in all material respects, in accordance with UK and EU adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
Basis for Conclusion
We conducted our review in accordance with 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 and EU adopted International Accounting Standard 34, "Interim Financial Reporting".
Conclusions Relating to Going Concern
Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for Conclusion section of this report, 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.
Responsibilities of the directors
The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
In preparing the half-yearly financial report, the directors are responsible for assessing the company's ability to continue as a going concern, disclosing, as applicable, matters related to going concern 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.
Use of our report
This report is made solely to the company in accordance with guidance contained in International Standard on Review Engagements 2410 (UK) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our work, for this report, or for the conclusions we have formed.
Ernst & Young LLP
London
12 September 2023
Condensed consolidated income statement
Six months ended 30 June 2023
|
|
Notes |
Six months ended 30.06.23 Unaudited $m |
Six months ended 30.06.22 Restated1 Unaudited $m |
Year ended 31.12.22 Audited $m |
|
Continuing activities |
|
|
|
|
|
Revenue |
6, 7 |
776.9 |
858.6 |
1,783.1 |
|
Cost of sales |
8 |
(425.6) |
(225.4) |
(697.5) |
|
Gross profit |
|
351.3 |
633.2 |
1,085.6 |
|
Administrative expenses |
8 |
(19.1) |
(23.2) |
(51.0) |
|
Gain on bargain purchase |
|
- |
196.8 |
196.8 |
|
Other (losses)/ gains |
|
(1.3) |
- |
3.1 |
|
Exploration costs written off |
11 |
(10.1) |
(86.6) |
(105.2) |
|
Impairment of property, plant and equipment, net |
12 |
(33.2) |
(6.5) |
(391.2) |
|
Restructuring costs and other provisions |
8 |
- |
(4.6) |
(4.2) |
|
Operating profit |
|
287.6 |
709.1 |
733.9 |
|
(Loss)/ gain on hedging instruments |
|
(0.3) |
- |
0.8 |
|
Gain on bond buyback |
18 |
65.2 |
- |
- |
|
Finance income |
9 |
25.0 |
21.1 |
42.9 |
|
Finance costs |
9 |
(160.3) |
(169.7) |
(335.5) |
|
Profit from continuing activities before tax |
|
217.2 |
560.5 |
442.1 |
|
Income tax expense |
10 |
(147.1) |
(296.6) |
(393.0) |
|
Profit for the year from continuing activities |
|
70.1 |
263.9 |
49.1 |
|
Attributable to |
|
|
|
|
|
Owners of the Company |
|
70.1 |
263.9 |
49.1 |
|
Earnings per ordinary share from continuing activities |
|
¢ |
¢ |
¢ |
|
Basic |
3 |
4.9 |
18.4 |
3.4 |
|
Diluted |
3 |
4.7 |
17.8 |
3.3 |
1Refer to Note 2 for details on prior period restatement.
Condensed consolidated statement of comprehensive income and expense
Six months ended 30 June 2023
|
|
Six months ended 30.06.23 Unaudited $m |
Six months ended 30.06.22 Unaudited $m |
Year ended 31.12.22 Audited $m |
|
Profit for the period |
70.1 |
263.9 |
49.1 |
|
Items that may be reclassified to the income statement in subsequent periods |
|
|
|
|
Cash flow hedges |
|
|
|
|
Gains/ (losses) arising in the period |
68.1 |
(577.2) |
(399.5) |
|
Gains arising in the period - time value |
31.9 |
4.0 |
21.7 |
|
Reclassification adjustments for items included in loss on realisation |
50.8 |
174.4 |
288.5 |
|
Reclassification adjustments for items included in loss on realisation - time value |
15.1 |
12.0 |
30.8 |
|
Exchange differences on translation of foreign operations |
(4.8) |
8.6 |
10.2 |
|
Other comprehensive income/ (expense) |
161.1 |
(378.2) |
(48.3) |
|
Tax relating to components of other comprehensive expense |
- |
- |
- |
|
Net other comprehensive income/ (expense) for the period |
161.1 |
(378.2) |
(48.3) |
|
Total comprehensive income/ (expense) for the period |
231.2 |
(114.3) |
0.8 |
|
Attributable to |
|
|
|
|
Owners of the Company |
231.2 |
(114.3) |
0.8 |
Condensed consolidated balance sheet
As at 30 June 2023
|
|
Notes |
Six months ended |
Six months ended Unaudited $m |
Year ended 31.12.22 Audited $m |
|
Assets |
|
|
|
|
|
Non-current asset |
|
|
|
|
|
Intangible exploration and evaluation assets |
11 |
286.4 |
288.6 |
288.6 |
|
Property, plant and equipment |
12 |
3,008.2 |
3,413.3 |
2,981.4 |
|
Other non-current assets |
14 |
54.1 |
317.3 |
327.1 |
|
Deferred tax assets |
|
13.3 |
343.5 |
14.5 |
|
|
|
3,362.0 |
4,362.7 |
3,611.6 |
|
Current assets |
|
|
|
|
|
Inventories |
16 |
124.9 |
333.3 |
181.6 |
|
Trade receivables |
13 |
164.0 |
290.2 |
26.8 |
|
Other current assets |
14 |
822.5 |
726.6 |
567.9 |
|
Current tax assets |
|
15.9 |
29.9 |
15.4 |
|
Cash and cash equivalents |
16 |
294.6 |
164.1 |
636.3 |
|
|
|
1,421.9 |
1,544.1 |
1,428.0 |
|
Total assets |
|
4,783.9 |
5,906.8 |
5,039.6 |
|
Liabilities |
|
|
|
|
|
Current liabilities |
|
|
|
|
|
Trade and other payables |
17 |
(1,410.0) |
(828.8) |
(750.2) |
|
Borrowings |
18 |
(100.0) |
(100.0) |
(100.0) |
|
Provisions |
19 |
(49.2) |
(205.2) |
(98.8) |
|
Current tax liabilities |
|
(144.2) |
(189.5) |
(186.0) |
|
Derivative financial instruments |
|
(78.6) |
(378.5) |
(186.3) |
|
|
|
(1,782.0) |
(1,702.0) |
(1,321.3) |
|
Non-current liabilities |
|
|
|
|
|
Trade and other payables |
17 |
(84.5) |
(882.3) |
(780.0) |
|
Borrowings |
18 |
(2,110.5) |
(2,370.7) |
(2,372.8) |
|
Provisions |
19 |
(468.6) |
(443.7) |
(415.6) |
|
Deferred tax liabilities |
|
(565.5) |
(889.9) |
(551.5) |
|
Derivative financial instruments |
|
- |
(194.2) |
(57.9) |
|
|
|
(3,229.1) |
(4,780.8) |
(4,177.8) |
|
Total liabilities |
|
(5,011.1) |
(6,482.8) |
(5,499.1) |
|
Net liabilities |
|
(227.2) |
(576.0) |
(459.5) |
|
Equity |
|
|
|
|
|
Called-up share capital |
|
216.2 |
214.9 |
215.2 |
|
Share premium |
|
1,294.7 |
1,294.7 |
1,294.7 |
|
Foreign currency translation reserve |
|
(243.4) |
(240.2) |
(238.6) |
|
Hedge reserve |
|
(31.4) |
(442.1) |
(150.3) |
|
Hedge reserve - time value |
|
(47.4) |
(130.9) |
(94.4) |
|
Merger reserve |
|
755.2 |
755.2 |
755.2 |
|
Retained earnings |
|
(2,171.1) |
(2,027.6) |
(2,241.3) |
|
Equity attributable to equity holders of the Company |
|
(227.2) |
(576.0) |
(459.5) |
|
Total equity |
|
(227.2) |
(576.0) |
(459.5) |
Condensed statement of changes in equity
As at 30 June 2023
|
|
Share capital $m |
Share premium $m |
Foreign currency translation reserve1 $m |
Hedge reserve2 $m |
Hedge reserve - Time value $m |
Merger reserve $m |
Retained earnings $m |
Total equity $m |
|
At 1 January 2022 |
214.2 |
1,294.7 |
(248.8) |
(39.3) |
(146.9) |
755.2 |
(2,295.2) |
(466.1) |
|
Profit for the period |
- |
- |
- |
- |
- |
- |
263.9 |
263.9 |
|
Hedges, net of tax |
- |
- |
- |
(402.8) |
16.0 |
- |
- |
(386.8) |
|
Currency translation adjustments |
- |
- |
8.6 |
- |
- |
- |
- |
8.6 |
|
Exercise of employee share options |
0.7 |
- |
- |
- |
- |
- |
(0.7) |
- |
|
Share-based payment charges |
- |
- |
- |
- |
- |
- |
4.4 |
4.4 |
|
At 30 June 2022 |
214.9 |
1,294.7 |
(240.2) |
(442.1) |
(130.9) |
755.2 |
(2,027.6) |
(576.0) |
|
Loss for the period |
- |
- |
- |
- |
- |
- |
(214.8) |
(214.8) |
|
Hedges, net of tax |
- |
- |
- |
291.8 |
36.5 |
- |
- |
328.2 |
|
Currency translation adjustments |
- |
- |
1.6 |
- |
- |
- |
- |
1.6 |
|
Exercise of employee share options |
0.3 |
- |
- |
- |
- |
- |
(0.3) |
- |
|
Share-based payment charges |
- |
- |
- |
- |
- |
- |
1.4 |
1.4 |
|
At 1 January 2023 |
215.2 |
1,294.7 |
(238.6) |
(150.3) |
(94.4) |
755.2 |
(2,241.3) |
(459.5) |
|
Profit for the period |
- |
- |
- |
- |
- |
- |
70.1 |
70.1 |
|
Hedges, net of tax |
- |
- |
- |
118.9 |
47.0 |
- |
- |
165.9 |
|
Currency translation adjustments |
- |
- |
(4.8) |
- |
- |
- |
- |
(4.8) |
|
Exercise of employee share options |
1.0 |
- |
- |
- |
- |
- |
(1.0) |
- |
|
Share-based payment charges |
- |
- |
- |
- |
- |
- |
1.1 |
1.1 |
|
At 30 June 2023 |
216.2 |
1,294.7 |
(243.4) |
(31.4) |
(47.4) |
755.2 |
(2,171.1) |
(227.2) |
1 The foreign currency translation reserve represents exchange gains and losses arising on translation of foreign currency subsidiaries, monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur, which form part of the net investment in a foreign operation.
2 The hedge reserve represents gains and losses on derivatives classified as effective cash flow hedges.
Condensed consolidated cash flow statement
Six months ended 30 June 2023
|
|
Notes |
Six months ended 30.06.23 Unaudited $m |
Six months ended 30.06.22 Restated1 Unaudited $m |
Year ended 31.12.22 Audited $m |
|
Cash flows from operating activities |
|
|
|
|
|
Profit from continuing activities before tax |
|
217.2 |
560.5 |
442.1 |
|
Adjustments for |
|
|
|
|
|
Depreciation, depletion and amortisation |
|
167.1 |
183.5 |
425.8 |
|
Gain on bargain purchase |
|
- |
(196.8) |
(196.8) |
|
Other losses/ (gains) |
|
1.3 |
- |
(3.1) |
|
Taxes paid in kind |
|
(8.0) |
(12.9) |
(21.4) |
|
Exploration costs written off |
11 |
10.1 |
86.6 |
105.2 |
|
Impairment of property, plant and equipment, net |
12 |
33.2 |
6.5 |
391.2 |
|
Restructuring costs and other provisions |
19 |
- |
4.6 |
4.2 |
|
Payments under restructuring costs and other provisions |
19 |
(0.6) |
(77.5) |
(127.3) |
|
Decommissioning expenditure |
|
(40.0) |
(28.8) |
(57.7) |
|
Share-based payment charge |
|
1.1 |
4.4 |
5.8 |
|
Loss/ (gain) on hedging instruments |
|
0.3 |
- |
(0.8) |
|
Gain on bond buyback |
18 |
(65.2) |
- |
- |
|
Finance income |
9 |
(25.0) |
(21.1) |
(42.9) |
|
Finance costs |
9 |
160.3 |
169.7 |
335.5 |
|
Operating cash flow before working capital movements |
|
451.8 |
678.7 |
1,259.8 |
|
(Increase)/ decrease in trade and other receivables |
|
(184.8) |
(118.0) |
288.4 |
|
Decrease/ (increase) in inventories |
|
49.0 |
(198.6) |
(48.0) |
|
Increase/ (decrease) in trade payables |
|
61.3 |
(9.8) |
(193.1) |
|
Cash flows from operating activities |
|
377.3 |
352.3 |
1,307.1 |
|
Income taxes paid |
|
(165.3) |
(143.7) |
(229.3) |
|
Net cash from operating activities |
|
212.0 |
208.6 |
1,077.8 |
|
Cash flows from investing activities |
|
|
|
|
|
Proceeds from disposals |
|
- |
68.6 |
68.1 |
|
Purchase of additional interest in joint operation |
|
- |
(126.8) |
(126.8) |
|
Purchase of intangible exploration and evaluation assets |
|
(14.4) |
(17.5) |
(42.6) |
|
Purchase of property, plant and equipment |
|
(134.9) |
(117.3) |
(263.8) |
|
Interest received |
|
13.2 |
1.1 |
8.9 |
|
Net cash (used in)/ from in investing activities |
|
(136.1) |
(191.9) |
(356.2) |
|
Cash flows from financing activities |
|
|
|
|
|
Repayment of borrowings |
23 |
(200.0) |
(100.0) |
(100.0) |
|
Repayment of obligations under leases |
|
(90.1) |
(91.9) |
(203.8) |
|
Finance costs paid |
|
(125.0) |
(126.2) |
(249.0) |
|
Net cash used in financing activities |
|
(415.1) |
(318.1) |
(552.8) |
|
Net decrease in cash and cash equivalents |
|
(339.2) |
(301.4) |
168.8 |
|
Cash and cash equivalents at beginning of period |
|
636.3 |
469.1 |
469.1 |
|
Foreign exchange loss |
|
(2.5) |
(3.6) |
(1.6) |
|
Cash and cash equivalents at end of period |
16 |
294.6 |
164.1 |
636.3 |
1Refer to Note 2 for details on prior period restatement.
Notes to the condensed financial statements
Six months ended 30 June 2023
1. General information
The condensed financial statements for the six-month period ended 30 June 2023 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 2022, 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 2022 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 2022, 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 2023 half-yearly financial report are the same as those adopted in the Group's Annual Report and Accounts as at 31 December 2022. This includes a revised accounting policy in relation to the presentation of corporate income taxes in Gabon and Côte d'Ivoire Production Sharing Contracts (PSCs).
Under the terms of the PSCs the share of the profit oil which the government is entitled to is deemed to include the notional corporate income tax which is paid by the government on behalf of Tullow. From 1 January 2022 the notional corporate income tax is classified as an income tax in accordance with IAS 12 Income taxes which has resulted in a gross up of revenue with a corresponding increase in income tax expense. In the previous years, the Revenues and Taxes from Gabon and Côte d'Ivoire were presented on a net basis. This change has been implemented to more accurately represent the Group's income tax obligations in Gabon and Côte d'Ivoire and to be more comparable with other entities in the sector.
Prior period balances as at 30 June 2022 have been adjusted only to conform with the same presentation. As a result of the change, revenue for the period ended 30 June 2022 increased from $845.7 million to $858.6 million, whilst income tax expense increased from $283.7 million to $296.6 million. There is no impact on profit/(loss) for the year from continuing activities nor on basic and diluted earnings per share. In addition, the restatement had no impact on reported net assets, cash flows or total equity.
The amendments on International Tax Reform - Pillar Two Model Rules introduce a mandatory exception in IAS 12 'Income Taxes' to recognizing and disclosing information about deferred tax assets and liabilities related to Pillar Two income taxes. The amendments have been adopted by the UK Endorsement Board but have yet to be endorsed in the EU. Pillar Two introduces a minimum effective tax rate of 15%, however the operation of the Pillar Two Model Rules is complex, and it is unclear whether the Pillar Two Model Rules create additional temporary differences, whether to remeasure deferred taxes for the Pillar Two model rules and how to determine the tax rate for measuring deferred taxes. Accordingly, the Group has concluded that not accounting for deferred taxes related to Pillar Two income taxes would result in the most appropriate accounting policy pending the completion of the EU endorsement process. The Group is not expecting profits in jurisdictions which are taxed at below 15% and is therefore not anticipating any current tax expense related to Pillar Two income taxes.
Going Concern
The Directors consider the going concern assessment period to be up to 30 September 2024. 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: $76/bbl for 2023, $74/bbl for 2024; and
Low Case: $70/bbl for 2023, $70/bbl for 2024.
2. Accounting policies continued
Going Concern continued
The Low Case includes, amongst other downside assumptions, a 10% production decrease and 12% increased operating costs compared to the Base Case as well as increased outflows associated with ongoing disputes. It also assumes that the TEN FPSO remains leased and not purchased during the assessment period as Tullow has control over the timing of the purchase under the contract.
At 30 June 2023, the Group had $0.7 billion liquidity headroom consisting of c.$0.2 billion free cash and $0.5 billion available under the revolving credit facility.
The Group or its affiliates may, at any time and from time to time, seek to retire or purchase outstanding debt through cash purchases and/or exchanges, in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will be upon such terms and at such prices as management may determine, and will depend on prevailing market conditions, liquidity requirements, contractual restrictions, and other factors. The amounts involved may be material.
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 $70.1 million (1H 2022: profit of $263.9 million) and a weighted average number of shares in issue of 1,444.0 million (1H 2022: 1,435.3 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 48.4 million resulting in a diluted weighted average number of shares of 1,492.4 million (1H 2022: 1,481.0 million).
4. Dividends
The Directors intend to recommend that no 2023 interim dividend be paid.
5. Approval of accounts
These unaudited half year results were approved by the Board of Directors on 12 September 2023.
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 2023, 30 June 2022 and 31 December 2022.
|
|
Ghana $m |
Non-Operated $m |
Kenya $m |
Exploration $m |
Corporate $m |
Total $m |
|
Six months ended 30 June 2023 |
|
|
|
|
|
|
|
Sales revenue by origin |
579.4 |
263.4 |
- |
- |
(65.9) |
776.9 |
|
Segment result1 |
318.7 |
77.2 |
(9.1) |
(5.6) |
(73.2) |
308.0 |
|
Other losses |
|
|
|
|
|
(1.3) |
|
Unallocated corporate expenses2 |
|
|
|
|
|
(19.1) |
|
Operating profit |
|
|
|
|
|
287.6 |
|
Loss on hedging instruments |
|
|
|
|
|
(0.3) |
|
Gain on bond buyback |
|
|
|
|
|
65.2 |
|
Finance income |
|
|
|
|
|
25.0 |
|
Finance costs |
|
|
|
|
|
(160.3) |
|
Profit before tax |
|
|
|
|
|
217.2 |
|
Income tax expense |
|
|
|
|
|
(147.1) |
|
Profit after tax |
|
|
|
|
|
70.1 |
|
Total assets |
3,857.5 |
364.1 |
258.9 |
47.7 |
255.7 |
4,783.9 |
|
Total liabilities3 |
(2,250.8) |
(345.9) |
(10.2) |
(3.9) |
(2,400.3) |
(5,011.1) |
|
Other segment information |
|
|
|
|
|
|
|
Capital expenditure: |
|
|
|
|
|
|
|
Property, plant and equipment |
201.3 |
48.8 |
- |
- |
0.4 |
250.5 |
|
Intangible exploration and evaluation assets |
0.3 |
(4.9) |
3.1 |
9.4 |
- |
7.9 |
|
Depletion, depreciation and amortisation |
(140.7) |
(22.9) |
(0.6) |
- |
(2.9) |
(167.1) |
|
Impairment of property, plant and equipment, net |
- |
(33.2) |
- |
- |
- |
(33.2) |
|
Exploration costs written off |
(0.3) |
4.9 |
(9.1) |
(5.6) |
- |
(10.1) |
1Segment result is a non-IFRS measure which includes gross profit, exploration costs written off and impairment of property, plant and equipment. See reconciliation below.
2Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area.
3Total 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
|
|
Six months ended 30.06.23 Unaudited $m |
Six months ended 30.06.22 Restated1 Unaudited $m |
Year ended 31.12.22 Audited $m |
|
Segment result |
308.0 |
540.1 |
589.2 |
|
Add back |
|
|
|
|
Exploration costs written off |
10.1 |
86.6 |
105.2 |
|
Impairment of Property, Plant and Equipment |
33.2 |
6.5 |
391.2 |
|
Gross profit |
351.3 |
633.2 |
1,085.6 |
1Revenue from crude oil sales has been restated following a revision to the Group's accounting policy.
|
|
Ghana $m |
Non-Operated $m |
Kenya $m |
Exploration $m |
Corporate $m |
Total $m |
|
|
Six months ended 30 June 2022 |
|
|
|
|
|
|
|
|
Sales revenue by origin - restated1 |
781.0 |
267.3 |
- |
- |
(189.7) |
858.6 |
|
|
Segment result - restated1,3 |
609.1 |
215.7 |
- |
(86.9) |
(197.8) |
540.1 |
|
|
Other provisions2 |
|
|
|
|
|
(4.1) |
|
|
Gain on bargain purchase |
|
|
|
|
|
196.8 |
|
|
Unallocated corporate expenses4 |
|
|
|
|
|
(23.7) |
|
|
Operating profit |
|
|
|
|
|
709.1 |
|
|
Finance income |
|
|
|
|
|
21.1 |
|
|
Finance costs |
|
|
|
|
|
(169.7) |
|
|
Profit before tax |
|
|
|
|
|
560.5 |
|
|
Income tax expense - restated1 |
|
|
|
|
|
(296.6) |
|
|
Profit after tax |
|
|
|
|
|
263.9 |
|
|
Total assets |
4,923.2 |
521.9 |
270.8 |
44.8 |
146.1 |
5,906.8 |
|
|
Total liabilities5 |
(2,742.0) |
(494.4) |
(16.9) |
(11.6) |
(3,217.9) |
(6,482.8) |
|
|
Other segment information |
|
|
|
|
|
|
|
|
Capital expenditure: |
|
|
|
|
|
|
|
|
Property, plant and equipment |
135.5 |
20.5 |
- |
- |
0.5 |
156.5 |
|
|
Intangible exploration and evaluation assets |
0.3 |
(1.5) |
2.6 |
19.2 |
- |
20.6 |
|
|
Depletion, depreciation and amortisation |
(158.7) |
(18.6) |
(0.7) |
- |
(5.5) |
(183.5) |
|
|
Impairment of property, plant and equipment, net |
- |
(6.5) |
- |
- |
- |
(6.5) |
|
|
Exploration costs written off |
(0.3) |
1.5 |
- |
(87.8) |
- |
(86.6) |
|
1Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the period ended 30 June 2022 of $12.9 million (FY 2022: $21.4 million), and a corresponding increase to income tax expense. Refer to Note 2.
2This is included within the Restructuring costs and other provisions in the Group Income Statement.
3Segment result is a non-IFRS measure which includes gross profit, exploration costs written off and impairment of property, plant and equipment. See reconciliation below.
4Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area.
5Total liabilities - Corporate comprise of the Group's external debt, derivative financial instruments and other non-attributable liabilities.
6. Segmental reporting continued
|
|
Ghana $m |
Non-Operated $m |
Kenya $m |
Exploration $m |
Corporate $m |
Total $m |
|
|
Year ended 31 December 2022 |
|
|
|
|
|
|
|
|
Sales revenue by origin |
1,578.5 |
524.0 |
- |
- |
(319.4) |
1,783.1 |
|
|
Segment result1 |
692.5 |
337.3 |
(0.5) |
(102.6) |
(337.5) |
589.2 |
|
|
Other provisions2 |
|
|
|
|
|
(4.1) |
|
|
Gain on bargain purchase |
|
|
|
|
|
196.8 |
|
|
Other gains |
|
|
|
|
|
3.1 |
|
|
Unallocated corporate expenses3 |
|
|
|
|
|
(51.1) |
|
|
Operating profit |
|
|
|
|
|
733.9 |
|
|
Gain on hedging instruments |
|
|
|
|
|
0.8 |
|
|
Finance income |
|
|
|
|
|
42.9 |
|
|
Finance costs |
|
|
|
|
|
(335.5) |
|
|
Profit before tax |
|
|
|
|
|
442.1 |
|
|
Income tax expense |
|
|
|
|
|
(393.0) |
|
|
Profit after tax |
|
|
|
|
|
49.1 |
|
|
Total assets |
3,827.7 |
380.6 |
265.6 |
46.0 |
519.7 |
5,039.6 |
|
|
Total liabilities4 |
(2,220.5) |
(401.6) |
(14.1) |
(4.6) |
(2,858.3) |
(5,499.1) |
|
|
Other segment information |
|
|
|
|
|
|
|
|
Capital expenditure: |
|
|
|
|
|
|
|
|
Property, plant and equipment |
342.9 |
26.9 |
- |
- |
0.9 |
370.7 |
|
|
Intangible exploration and evaluation assets |
0.9 |
(1.7) |
(2.1) |
42.1 |
- |
39.2 |
|
|
Depletion, depreciation and amortisation |
(362.1) |
(52.7) |
(1.3) |
- |
(9.7) |
(425.8) |
|
|
Impairment of property, plant and equipment, net |
(380.6) |
(10.6) |
- |
- |
- |
(391.2) |
|
|
Exploration costs written off |
(0.9) |
1.8 |
(0.5) |
(105.6) |
- |
(105.2) |
|
1Segment result is a non-IFRS measure which includes gross profit, exploration costs written off and impairment of property, plant and equipment. See reconciliation below.
2This is included within the Restructuring costs and other provisions in the Group Income Statement.
3Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area.
4Total liabilities - Corporate comprise of the Group's external debt, derivative financial instruments and other non-attributable liabilities.
6. Segmental reporting continued
|
|
Sales revenue six months ended 30.06.23 $m |
Sales revenue six months ended 30.06.22 Restated1 $m |
Sales revenue Year ended 31.12.22 $m |
Non-current assets 30.06.232 $m |
Non-current assets 30.06.222 $m |
Non-current assets 31.12.222 $m |
|
Ghana |
579.4 |
781.0 |
1,578.5 |
2,848.5 |
3,473.9 |
3,087.4 |
|
Total Ghana |
579.4 |
781.0 |
1,578.5 |
2,848.5 |
3,473.9 |
3,087.4 |
|
Kenya |
- |
- |
- |
253.8 |
262.5 |
258.5 |
|
Total Kenya |
- |
- |
- |
253.8 |
262.5 |
258.5 |
|
Argentina |
- |
- |
- |
35.1 |
31.8 |
33.6 |
|
Côte d'Ivoire |
- |
- |
- |
4.7 |
- |
2.4 |
|
Total Exploration |
- |
- |
- |
39.8 |
31.8 |
36.0 |
|
Gabon |
242.1 |
234.4 |
477.0 |
126.9 |
137.0 |
132.6 |
|
Côte d'Ivoire |
21.3 |
32.9 |
47.0 |
57.7 |
86.6 |
59.2 |
|
Total Non-Operated |
263.4 |
267.3 |
524.0 |
184.6 |
223.6 |
191.8 |
|
Corporate |
(65.9) |
(189.7) |
(319.4) |
22.0 |
27.4 |
23.4 |
|
Total |
776.9 |
858.6 |
1,783.1 |
3,348.7 |
4,019.2 |
3,597.1 |
1Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the period ended 30 June 2023 of $8.0 million (1H 2022: $12.9 million; FY 2022: $21.4 million), and a corresponding increase to income tax expense. Refer to Note 2.
2 Excludes derivative financial instruments and deferred tax assets.
7. Total revenue
|
|
Six months ended 30.06.23 Unaudited $m |
Six months ended 30.06.22 Restated1 Unaudited $m |
Year ended 31.12.22 Audited $m |
|
Revenue from contracts with customers |
|
|
|
|
Revenue from crude oil sales |
837.9 |
1,048.3 |
2,102.5 |
|
Revenue from gas sales |
4.9 |
- |
- |
|
Total revenue from contracts with customers |
842.8 |
1,048.3 |
2,102.5 |
|
Loss on realisation of cash flow hedges |
(65.9) |
(189.7) |
(319.4) |
|
Total revenue |
776.9 |
858.6 |
1,783.1 |
1Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the period ended 30 June 2023 of $8.0 million (1H 2022: $12.9 million; FY 2022: $21.4 million), and a corresponding increase to income tax expense. Refer to Note 2.
Finance income has been presented as part of net financing costs (refer to note 9).
8. Operating profit
|
|
Six months ended 30.06.23 Unaudited $m |
Six months ended 30.06.22 Unaudited $m |
Year ended 31.12.22 Audited $m |
|
Operating profit is stated after charging/ (deducting): |
|
|
|
|
Operating costs |
136.4 |
142.7 |
266.5 |
|
Depletion and amortisation of oil and gas and leased assets1 |
163.2 |
176.9 |
410.7 |
|
Underlift, overlift and oil stock movements2 |
108.9 |
(119.9) |
(46.3) |
|
Royalties |
16.3 |
33.3 |
61.7 |
|
Share-based payment charge included in cost of sales |
- |
0.2 |
0.4 |
|
Other cost of sales |
0.8 |
(7.8) |
4.5 |
|
Total cost of sales |
425.6 |
225.4 |
697.5 |
|
Administrative expenses |
|
|
|
|
Share-based payment charge included in administrative expenses |
1.1 |
4.2 |
5.4 |
|
Depreciation of other fixed assets1 |
3.9 |
6.6 |
15.1 |
|
Other administrative costs |
14.1 |
12.4 |
30.5 |
|
Total administrative expenses |
19.1 |
23.2 |
51.0 |
|
Total restructuring costs and other provisions |
- |
4.6 |
4.2 |
1Depreciation expense on leased assets of $30.0 million as per note 12 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 $28.0 million relates to other leased assets and is included within cost of sales.
2Refer to page 4 of Finance Review and Note 17 for detailed explanations.
9. Net financing costs
|
|
Six months ended 30.06.23 Unaudited $m |
Six months ended 30.06.22 Unaudited $m |
Year ended 31.12.22 Audited $m |
|
Interest on bank overdrafts and borrowings |
122.7 |
127.1 |
250.4 |
|
Interest on obligations for leases |
32.1 |
37.8 |
76.4 |
|
Total borrowing costs |
154.8 |
164.9 |
326.8 |
|
Finance and arrangement fees |
0.1 |
0.1 |
0.3 |
|
Other interest expense |
0.4 |
1.5 |
2.4 |
|
Unwinding of discount on decommissioning provisions |
5.0 |
3.2 |
6.0 |
|
Total finance costs |
160.3 |
169.7 |
335.5 |
|
Interest income on amounts due from Joint Venture partners for leases |
(12.0) |
(15.7) |
(29.6) |
|
Other finance income |
(13.0) |
(5.4) |
(13.3) |
|
Total finance income |
(25.0) |
(21.1) |
(42.9) |
|
Net financing costs |
135.3 |
148.6 |
292.6 |
Other finance income mainly relates to interest on investments in Money Market Funds of $8.3 million (1H 2022: $0.2 million, FY 2022: $3.7 million) and interest on a Ghana National Petroleum Corporation (GNPC) loan in Ghana of $2.7 million (1H 2022: $0.6 million, FY 2022: $2.7 million).
10. Taxation on profit on ordinary activities
The overall net tax expense of $147.1 million (1H 2022: $296.6 million) primarily relates to tax charges in respect of the Group's production activities in West Africa, reduced by tax credits associated with UK decommissioning, exploration write-offs and impairments. The tax charge has been calculated by applying the effective tax rate which is expected to apply to each jurisdiction for the year ending 31 December 2023.
Based on a profit before tax for the first half of the year of $217.2 million (1H 2022: $560.5 million), the effective tax rate is 67.7% (1H 2022: 52.9%). After adjusting for the non-recurring amounts related to exploration write-offs, impairments, onerous lease provisions and their associated tax benefit, the Group's underlying effective tax rate is 56.2% (1H 2022: 63.0%). The underlying effective tax rate has decreased primarily due to there being no UK tax benefit from net interest and hedging expenses, representing a smaller proportion of the Group's overall profits in 1H 2023 than in 1H 2022. Non-deductible expenditure in Ghana and Gabon and prior year adjustments are additional contributing factors.
Uncertain tax treatments
The Group is subject to various material claims which arise in the ordinary course of its business in various jurisdictions, including cost recovery claims, claims from other regulatory bodies and both corporate income tax and indirect tax claims. The Group is in formal dispute proceedings regarding a number of these tax claims with significant updates described in more detail below. The resolution of tax positions, through negotiation with the relevant tax authorities or litigation, can take several years to complete. In assessing whether these claims should be provided for in the Financial Statements, management has considered them in the context of the applicable laws and relevant contracts for the countries concerned. Management has applied judgement in assessing the likely outcome of the claims and has estimated the financial impact based on external tax and legal advice and prior experience of such claims.
Due to the uncertainty of such tax items, it is possible that on conclusion of an open tax matter at a future date the outcome may differ significantly from management's estimate. If the Group was unsuccessful in defending itself from all of these claims, the result would be additional unprovided liabilities of $989.4 million (1H 2022: $991.9 million; FY 2022: $1,024.0 million) which includes $11.5 million of interest and penalties (1H 2022: $33.0 million; FY 2022: $32.4million).
Provisions of $99.4 million (1H 2022: $106.5 million; FY 2022: $106.4 million) are included in income tax payable ($71.0 million (1H 2022: $70.4 million; FY 2022: $70.6million)) and provisions ($28.4 million (1H 2022: $36.2 million; FY 2022: $35.8million)). Where these matters relate to expenditure which is capitalised within Intangible Exploration and Evaluation Assets and Property, Plant and Equipment, any difference between the amounts accrued and the amounts settled is capitalised within the relevant asset balance, subject to applicable impairment indicators. Where these matters relate to producing activities or historical issues, any differences between the accrued and settled amounts are taken to the group income statement.
The provisions and contingent liabilities relating to these disputes have decreased following the conclusion of tax authority challenges and matters lapsing under statutes of limitation, but have increased, following new claims being initiated and extrapolation of exposures through to 30 June 2023, giving rise to an overall decrease in provision of $7.0 million and decrease in contingent liability of $34.6 million from 31 December 2022.
Ghana tax assessments
In October 2021, Tullow Ghana Limited (TGL) filed a Request for Arbitration with the International Chamber of Commerce (ICC) disputing the US$320 million branch profits remittance tax (BPRT) assessment issued as part of the direct tax audit for the financial years 2014 to 2016. The Ghana Revenue Authority (GRA) is seeking to apply BPRT under a law which the Group considers is not applicable to TGL, since it falls outside the tax regime provided for in the Petroleum Agreements and relevant double tax treaties. The parties have agreed a procedural timetable for the arbitration under which the first Tribunal hearing will be held in October 2023.
In December 2022, TGL received a $190.5m corporate income tax assessment and payment demand from the GRA relating to the disallowance of loan interest for the financial years 2010 to 2020. The Group has previously disclosed assessments by the GRA relating to the same issue; this revised assessment supersedes all previous claims. The Group considers the assessment to breach TGL's rights under its Petroleum Agreements. In February 2023, TGL filed a Request for Arbitration to the ICC, disputing the assessment with the suspension of TGL's obligation to pay any amount in relation to the assessment until the dispute is formally resolved.
In December 2022, TGL received a $196.5m corporate income tax assessment and payment demand from the GRA relating to proceeds received by Tullow during the financial years 2016 to 2019 under Tullow's corporate Business Interruption Insurance policy. The Group considers the assessment to breach TGL's rights under its Petroleum Agreements. In February 2023, TGL filed a Request for Arbitration to the ICC, disputing the assessment with the suspension of TGL's obligation to pay any amount in relation to the assessment until the dispute is formally resolved.
The Group continues to engage with the Government of Ghana with the aim of resolving all tax disputes on a mutually acceptable basis.
10. Taxation on profit on ordinary activities continued
Bangladesh litigation
The National Board of Revenue (NBR) is seeking to disallow $118 million of tax relief in respect of development costs incurred by Tullow Bangladesh Limited (TBL). The NBR subsequently issued a payment demand to TBL in February 2020 for Taka 3,094m (c$37 million) requesting payment by 15 March 2020. However, under the Production Sharing Contract (PSC), the Government is required to indemnify TBL against all taxes levied by any public authority, and the share of production paid to Petrobangla (PB), Bangladesh's national oil company, is deemed to include all taxes due which PB is then obliged to pay to the NBR. TBL sent the payment demand to PB and the Government requesting the payment or discharge of the payment demand under their respective PSC indemnities. On 14 June 2021 TBL issued a formal notice of dispute under the PSC to the Government and PB. A further request for payment was received from NBR on 28 October 2021 demanding settlement by 15 November 2021. Arbitration proceedings were initiated under the PSC on 29 December 2021. A procedural hearing was held on 28 June 2022 which set the timetable for the process going forward. The first submissions were made in October 2022 and the second submissions were made in June 2023; with the first Tribunal hearing scheduled for May 2024.
Timing of cash-flows
While it is not possible to estimate the timing of tax cash flows in relation to possible outcomes with certainty. Management anticipates that there will not be material cash taxes paid in excess of the amounts provided for uncertain tax treatments.
11. Intangible exploration and evaluation assets
|
|
Six months ended 30.06.23 Unaudited $m |
Six months ended 30.06.22 Unaudited $m |
Year ended 31.12.22 Audited $m |
|
At 1 January |
288.6 |
354.6 |
354.6 |
|
Additions |
7.9 |
20.6 |
39.2 |
|
Exploration costs written off |
(10.1) |
(86.6) |
(105.2) |
|
At 30 June/31 December |
286.4 |
288.6 |
288.6 |
The below table provides a summary of the exploration costs written off on a pre-tax basis by country.
|
Exploration costs written off |
Rationale for write-off/(back) six months ended 30.06.23 |
Write-off/(back) 30.06.23 Unaudited $m |
Remaining recoverable amount 30.06.23 Unaudited $m |
|
Guyana |
a, b |
1.6 |
- |
|
Côte d'Ivoire |
b |
2.0 |
- |
|
Kenya |
c |
9.1 |
246.7 |
|
New Ventures |
d |
2.1 |
- |
|
Uganda |
e |
(4.9) |
- |
|
Other |
a, b |
0.2 |
- |
|
Exploration costs written off |
|
10.1 |
- |
a. Licence relinquishments, expiry, planned exit or reduced activity
b. Current year expenditure on assets previously written off
c. Following VIU assessment subsequent to withdrawal of JV partners
d. New Ventures expenditure is written off as incurred
e. Release of indirect tax provision
11. Intangible exploration and evaluation assets continued
Since 1 January 2022, there have been ongoing discussions with the Government of Kenya (GoK) on approval of the Field Development Plan (FDP) submitted on 10 December 2021 and securing government deliverables. An updated FDP was submitted on 3 March 2023 and is being reviewed by the GoK before ratification by the Kenyan Parliament. Energy and Petroleum Regulatory Authority (EPRA), the regulator, has recently engaged third party consultants to review the revised FDP and extended the review period to Q1 2024. The Group expects a production licence to be granted once Government due process has been completed.
On 22 May 2023, Africa Oil Corporation (AOC) and Total Energies (TE) gave notice of their respective withdrawal from the Blocks 10BA, 10BB and 13T Production Sharing Contracts (PSCs) and the Joint Operating Agreements (JOAs), effective 30 June 2023, quoting differing internal strategic objectives as reasons. The withdrawal is ultimately subject to the GoK's consent, at which stage the transaction will be considered completed and Tullow will have full rights and liabilities under the JOA. Per the terms of the agreement, until such approval, the participating interest will remain in trust for the sole and exclusive benefit of Tullow, who is the only remaining joint venture partner.
In Management's view, in light of public statements and announcements made by AOC and TE to this effect, and in accordance with the terms of the Joint Operating Agreement, it is considered that the ownership of the 50% held by AOC and TE was passed on 30 June 2023, resulting in Tullow holding 100%. From that date, Tullow has the right to benefit from the participating interest and is liable for all costs incurred going forward. As the sole party, Tullow can control and direct the use of the asset from 30 June 2023. Tullow accounted for this as asset acquisition at nil cost.
The withdrawal of the partners is considered to be an impairment trigger, and in line with its accounting policy the Group has performed a VIU assessment. The cash flows were discounted using a pre-tax nominal discount rate of 20%. Oil price assumptions are detailed in Note 12. This resulted in an NPV significantly in excess of the book value of $255.8 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 a Final Investment Decision (FID). The Group continues to progress with the farm down process.
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. Certain risks have increased since 31 December 2022, predominantly around farm down and project financing. This has been partially offset by an increased equity interest in the project.
Based on this, the NPV has been revised to $246.7 million and an impairment of $9.1 million has been recognized as at 30 June 2023.
Should the uncertainties around the project be resolved, there will be a reversal of a previously recorded impairment. However, if the uncertainties are not resolved there will be an additional impairment of $246.7 million. A reduction or increase in the two-year forward curve of $5/bbl, based on the approximate range of annualized average oil price over recent history, and a reduction or increase in the medium and long-term price assumptions of $5/bbl, based on the range of annualized average historical prices, are considered to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices specified above would increase the impairment charge by $31.6 million, whilst increases to oil prices specified above would result in a credit to the impairment charge of $37.0 million. A 1% change in the pre-tax discount rate would result in an additional impairment charge of $34.7 million. The Group believes a 1% change in the pre-tax discount rate to be a reasonable possibility based on historical analysis of the Group's and a peer group of companies' impairments.
|
Exploration costs written off |
Rationale for write-off six months ended 30.06.22 |
Write-off 30.06.22 Unaudited $m |
Remaining recoverable amount 30.06.22 Unaudited $m |
|
Guyana |
a,d |
84.2 |
- |
|
Côte d'Ivoire |
b |
2.0 |
- |
|
Other |
a, b, c |
0.4 |
- |
|
Exploration costs written off |
|
86.6 |
- |
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
11. Intangible exploration and evaluation assets continued
|
Exploration costs written off |
Rationale for write- off year ended 31.12.22 |
Write-off 31.12.22 Audited $m |
Remaining recoverable amount 31.12.22 Audited $m |
|
Guyana |
a, b |
97.7 |
- |
|
Côte d'Ivoire |
c |
3.1 |
- |
|
New Ventures |
d |
3.0 |
- |
|
Other |
|
1.4 |
- |
|
Total write-off |
|
105.2 |
- |
a. Unsuccessful well costs written off.
b. Licence relinquishments, expiry, planned exit or reduced activity.
c. Current year expenditure on assets previously written off.
d. New Ventures expenditure is written off as incurred.
12. Property, plant and equipment
|
|
Oil and gas assets six months ended 30.06.23 Unaudited |
Right of use ended 30.06.23 Unaudited |
Other fixed assets ended 30.06.23 Unaudited |
Total six months ended 30.06.23 Unaudited |
Oil and gas assets six months ended 30.06.22 Unaudited |
Right of use ended 30.06.22 Unaudited |
Other fixed assets ended 30.06.22 Unaudited |
Total six months ended 30.06.22 Unaudited |
Oil and gas assets Year ended 31.12.22 Audited |
Right of use ended 31.12.22 Audited |
Other fixed assets ended 31.12.22 Audited |
Total Year ended 31.12.22 Audited |
|
Cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
At 1 January |
11,182.6 |
1,196.8 |
30.0 |
12,409.4 |
10,521.7 |
1,091.7 |
69.5 |
11,682.9 |
10,521.7 |
1,091.7 |
69.5 |
11,682.9 |
|
Additions |
249.9 |
- |
0.6 |
250.5 |
142.8 |
12.9 |
0.8 |
156.5 |
305.2 |
63.5 |
2.0 |
370.7 |
|
Acquisitions |
- |
- |
- |
- |
473.2 |
- |
- |
473.2 |
473.2 |
- |
- |
473.2 |
|
Transfer |
- |
- |
- |
- |
- |
86.6 |
- |
86.6 |
- |
86.6 |
- |
86.6 |
|
Asset retirement |
- |
- |
- |
- |
- |
- |
- |
- |
- |
(41.7) |
(38.1) |
(79.8) |
|
Currency translation adjustments |
47.2 |
1.3 |
0.6 |
49.1 |
(113.5) |
(3.2) |
(3.7) |
(120.4) |
(117.5) |
(3.3) |
(3.4) |
(124.2) |
|
At 30 June/31 December |
11,479.7 |
1,198.1 |
31.2 |
12,709.0 |
11,024.2 |
1,188.0 |
66.6 |
12,278.8 |
11,182.6 |
1,196.8 |
30.0 |
12,409.4 |
|
Depreciation, depletion and amortization and impairment |
|
|
|
|
|
|
|
|
|
|
|
|
|
At 1 January |
(8,888.4) |
(515.2) |
(24.4) |
(9,428.0) |
(8,263.7) |
(450.8) |
(53.8) |
(8,768.3) |
(8,263.7) |
(450.8) |
(53.8) |
(8,768.3) |
|
Charge for the year |
(135.2) |
(30.0) |
(1.9) |
(167.1) |
(155.7) |
(23.2) |
(4.6) |
(183.5) |
(353.7) |
(60.9) |
(11.2) |
(425.8) |
|
Impairment loss |
(33.2) |
- |
- |
(33.2) |
(6.5) |
- |
- |
(6.5) |
(391.2) |
- |
- |
(391.2) |
|
Capitalised depreciation |
- |
(24.5) |
- |
(24.5) |
- |
(23.4) |
- |
(23.4) |
- |
(46.1) |
- |
(46.1) |
|
Asset retirement |
- |
- |
- |
- |
- |
- |
- |
- |
- |
41.7 |
38.1 |
79.8 |
|
Currency translation adjustments |
(47.2) |
(0.4) |
(0.4) |
(48.0) |
112.5 |
0.8 |
2.9 |
116.2 |
120.2 |
0.9 |
2.5 |
123.6 |
|
At 30 June/31 December |
(9,104.0) |
(570.1) |
(26.7) |
(9,700.8) |
(8,313.4) |
(496.6) |
(55.5) |
(8,865.5) |
(8,888.4) |
(515.2) |
(24.4) |
(9,428.0) |
|
Net book value at 30 June/31 December |
2,375.7 |
628.0 |
4.5 |
3,008.2 |
2,710.8 |
691.4 |
11.1 |
3,413.3 |
2,294.2 |
681.6 |
5.6 |
2,981.4 |
The currency translation adjustments arose due to the movement against the Group's presentation currency, USD, of the Group's UK assets which have functional currencies of GBP.
12. Property, plant and equipment continued
|
|
Trigger for impairment six months ended 30.06.23 |
Impairment 30.06.23 Unaudited $m |
30.06.23 Remaining recoverable amount Unaudited $m |
|
Mauritania |
a |
27.6 |
- |
|
UK 'CGU'1 |
a |
5.6 |
- |
|
Impairment |
|
33.2 |
- |
1The fields in the UK are grouped into one CGU as all fields share critical gas infrastructure.
a. Change to decommissioning estimate.
|
|
Trigger for impairment six months ended 30.06.22 |
Impairment 30.06.22 Unaudited $m |
30.06.22 Remaining recoverable amount Unaudited $m |
|
Mauritania |
a |
4.9 |
- |
|
UK 'CGU'1 |
a |
1.6 |
- |
|
Impairment |
|
6.5 |
- |
1The fields in the UK are grouped into one CGU as all fields share critical gas infrastructure.
a. Change to decommissioning estimate.
|
|
Trigger for impairment/ (reversal) year ended 31.12.22 |
Impairment/ (reversal) 31.12.22 Audited) $m |
Pre-tax discount rate assumption |
31.12.22 Remaining recoverable amount2 Audited $m |
|
Limande and Turnix CGU (Gabon) |
a |
(1.6) |
15% |
44.6 |
|
Tchatamba (Gabon) |
a |
(1.3) |
15% |
38.0 |
|
Oba and Middle Oba CGU (Gabon) |
a |
(0.4) |
17% |
11.8 |
|
Echira, Niungo and Igongo (Gabon) |
a |
(1.4) |
17% |
8.6 |
|
TEN (Ghana) |
b |
380.6 |
13% |
926.9 |
|
Mauritania |
a |
12.8 |
n/a |
- |
|
UK 'CGU'1 |
a |
2.5 |
n/a |
- |
|
Impairment |
|
391.2 |
|
|
1The fields in the UK are grouped into one CGU as all fields within those countries share critical gas infrastructure.
2The remaining recoverable amount of the asset is its value in use.
a. Change to decommissioning estimate.
b. Revision of value based on revisions to reserves.
The Group applied the following nominal oil price assumption for impairment assessments:
|
|
Year 1 |
Year 2 |
Year 3 |
Year 4 |
Year 5 |
Year 6 onwards |
|
1H 2023 |
$76/bbl |
$74/bbl |
$70/bbl |
$70/bbl |
$70/bbl |
$70/bbl inflated at 2% |
|
FY 2022 |
$84/bbl |
$79/bbl |
$70/bbl |
$70/bbl |
$70/bbl |
$70/bbl inflated at 2% |
*At 1H 2022 there were no impairment assessments carried out.
13. Trade receivables
Trade receivables comprise amounts due for the sale of oil and gas. They are generally due for settlement within 30-60 days and are therefore all classified as current. The Group holds the trade receivable with the objective of collecting the contractual cash flows and therefore measures them subsequently at amortised cost using the effective interest method.
The balance of trade receivables as of 30 June 2023 of $164.0 million (1H 2022: $290.2 million; FY 2022: $26.8 million) mainly relates to June 2023 oil liftings in Ghana ($65.4 million), Gabon ($67.8 million) and Côte d'Ivoire ($9.9 million) which were collected in July 2023.
14. Other assets
|
|
30.06.23 Unaudited $m |
30.06.22 Unaudited $m |
31.12.22 Audited $m |
|
Non-current |
|
|
|
|
Amounts due from joint venture partners |
50.6 |
314.4 |
323.3 |
|
VAT recoverable |
3.5 |
2.9 |
3.8 |
|
|
54.1 |
317.3 |
327.1 |
|
Current |
|
|
|
|
Amounts due from joint venture partners |
769.4 |
584.0 |
452.3 |
|
Underlifts |
20.7 |
76.0 |
76.2 |
|
Prepayments |
27.1 |
59.8 |
31.3 |
|
Other current assets |
5.3 |
6.8 |
8.1 |
|
|
822.5 |
726.6 |
567.9 |
|
|
876.6 |
1,043.9 |
895.0 |
The movement between current and non-current amounts due from joint venture partners is driven by the receivables relating to the TEN FPSO lease. This is based on the assumption that the lease term will end in April 2024 when the purchase option is assumed to be exercised.
Underlifts of $20.7 million as at 30 June 2023 are due to the timing of liftings and are mainly attributable to the Jubilee field in Ghana.
15. Inventories
|
|
30.06.23 Unaudited $m |
30.06.22 Unaudited $m |
31.12.22 Audited $m |
|
Warehouse stock and materials |
65.5 |
53.7 |
69.1 |
|
Oil stock |
59.4 |
279.6 |
112.5 |
|
|
124.9 |
333.3 |
181.6 |
The decrease in oil stock from 30 June 2022 was mainly driven by the Cap Lopez incident in Gabon which delayed lifting by a month in 1H 2022.
The decrease in oil stock from 31 December 2022 is driven by a decrease in Gabon of $72.9 million due to an additional lifting in June 2023, partially offset by a stock increase in Ghana.
16. Cash and cash equivalents
|
|
30.06.23 Unaudited $m |
30.06.22 Unaudited $m |
31.12.22 Audited $m |
|
Cash at bank |
96.4 |
90.4 |
305.3 |
|
Short- term deposits and other cash equivalents |
198.2 |
73.7 |
331.0 |
|
|
294.6 |
164.1 |
636.3 |
Short- term deposits and other cash equivalents include an amount of $53.1 million (1H 2022: $51.8 million; FY 2022: $74.7 million) which the Group holds as operator in joint venture bank accounts. Included within cash at bank is $4.5 million (1H 2022: $3.8 million; FY 2022: $7.0 million) of restricted cash held as collateral for performance bonds issued in relation to exploration activities.
17. Trade and other payables
|
|
30.06.23 Unaudited $m |
30.06.22 Unaudited $m |
31.12.22 Audited $m |
|
Current |
|
|
|
|
Trade payables |
65.1 |
54.8 |
68.4 |
|
Other payables |
56.8 |
62.0 |
51.3 |
|
Overlifts |
- |
93.9 |
- |
|
Accruals |
461.9 |
403.2 |
379.3 |
|
Current portion of leases |
826.2 |
214.9 |
251.2 |
|
|
1,410.0 |
828.8 |
750.2 |
|
Non-current |
|
|
|
|
Other non-current liabilities |
46.2 |
45.1 |
47.1 |
|
Non-current portion of leases |
38.3 |
837.2 |
732.9 |
|
|
84.5 |
882.3 |
780.0 |
Accruals mainly relate to capital expenditure, interest expense on bonds and loans and staff related expenses.
Other non-current liabilities include balances related to JV Partners.
Trade and other payables are non-interest bearing except for leases.
The movement between current and non-current portion of leases is driven by TEN FPSO (Ghana). This is based on the assumption that the lease term will end in April 2024 when the purchase option is assumed to be exercised.
Payables related to operated joint ventures (primarily related to Ghana and Kenya) are recorded gross with the debit representing the partners' share recognised in amounts due from joint venture partners (note 14). The change in trade payables and in other payables predominantly represents timing differences and levels of work activity.
Included in the lease liabilities as at 30 June 2022 and 31 December 2022 is $19.0 million and $6.6 million, respectively, related to Espoir FPSO (Côte d'Ivoire). The JV partnership exercised the option to purchase the FPSO, and the transaction completed on 12 June 2023 for a gross consideration of $20.0 million ($4.7 million net to Tullow).
18. Borrowings
|
|
30.06.23 Unaudited $m |
30.06.22 Unaudited $m |
31.12.22 Audited $m |
|
Current |
|
|
|
|
Borrowings - within one year |
|
|
|
|
10.25% Senior Notes due 2026 |
100.0 |
100.0 |
100.0 |
|
Carrying value of total current borrowings |
100.0 |
100.0 |
100.0 |
|
Non-current |
|
|
|
|
Borrowings - after one year but within five years |
|
|
|
|
7.00% Senior Notes due 2025 |
628.3 |
792.5 |
792.8 |
|
10.25% Senior Notes due 2026 |
1,482.2 |
1,578.2 |
1,580.0 |
|
Carrying value of total non-current borrowings |
2,110.5 |
2,370.7 |
2,372.8 |
|
Carrying value of total borrowings |
2,210.5 |
2,470.7 |
2,472.8 |
The Group's capital structure includes $1.6bn senior secured notes (2026 Notes), $0.6bn senior notes due 2025 (2025 Notes) and an undrawn $500 million Super Senior Revolving Credit Facility (SSRCF) which will primarily be used for working capital purposes. The 2026 Notes, maturing in May 2026, require an annual prepayment of $100 million, in May, of the outstanding principal amount plus accrued and unpaid interest, with the balance due on maturity.
On 15 May 2023, the Group made the annual prepayment of $100 million of the 2026 Notes, which reduced total debt to $2.4 billion. On 20 June 2023, the Group repurchased $167 million nominal value of 2025 Notes for $100 million through an Unmodified Dutch Auction. This further reduced total debt to $2.2 billion. A gain on early bond buyback of $65 million is recognised as other income in the income statement. The outstanding 2025 Notes, amounting to $633 million nominal value, are due in March 2025.
18. Borrowings continued
The SSRCF, maturing in December 2024, comprises of (i) a $500 million revolving credit facility and (ii) a $100 million letter of credit facility. The revolving credit facility remains undrawn as at 30 June 2023. Letters of credit amounting to $23 million (FY 2022: $44 million) have been issued under the facility.
Unamortised debt arrangement fees for the 2026 Notes, 2025 Notes and the SSRCF are $17.9 million, $5.0 million and $3.6 million respectively.
The 2026 Notes and the SSRCF are senior secured obligations of Tullow Oil Plc and are guaranteed by certain subsidiaries of the Group.
Capital management
The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders and benefits to stakeholders and to safeguard the Group's ability to continue as a going concern. Tullow is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, the Group may put in place new debt facilities, issue new shares for cash, repay debt, engage in active portfolio management, or undertake other such restructuring activities as appropriate. No significant changes were made to the capital management objectives, policies or processes during the half year ended 30 June 2023. The Group monitors capital on the basis of the gearing, being net debt divided by adjusted EBITDAX, and maintains a policy target of less than 1x.
SSRCF covenants
The SSRCF does not have any financial maintenance covenants. Availability under the $500 million cash tranche of the facility is determined on an annual basis with reference to the Net Present Value of the 2P reserves of the Group (2P NPV) at the end of the preceding calendar year. SSRCF debt capacity is calculated as 2P NPV divided by 1.1x less senior secured debt outstanding.
2025 Notes and 2026 Notes covenants
The 2025 Notes and the 2026 Notes are subject to customary high yield covenants including limitations on debt incurrence, asset sales and restricted payments such as prepayments of junior debt and dividends.
Key covenants in the current business cycle are considered to be those related to debt incurrence and restricted payments. For definitions of the capitalised terms used in the following paragraphs please refer to the offering memorandum of the 2025 Notes and/or the 2026 Notes.
Tullow is permitted to incur additional debt if the ratio of Consolidated Cash Flow to Fixed Charges for the previous 12 months is at least 2.25 times on a pro forma basis.
Tullow is permitted to incur secured debt if the 2P Reserves Coverage Ratio is at least 2.0 times on a pro forma basis.
Tullow is permitted to incur debt to refinance the 2025 Notes on a like for like basis, i.e. subordinated to the 2026 Notes.
Tullow is permitted to make payments towards the 2025 Notes amounting to the greater of $100 million per year and 50% of the Consolidated Net Income of the Group for the period from 1 January 2021 to the end of the most recently completed fiscal half-year for which internal financial statements are available if, after giving pro forma effect to the payment(s), the 2P Reserves Coverage Ratio is equal to or greater than 1.5 times.
Tullow is permitted to make payments towards the 2025 Notes amounting to the greater of $100 million per year, 50% of the Consolidated Net Income of the Group for the period from 1 January 2021 to the end of the most recently completed fiscal half-year for which internal financial statements are available and 100% of Consolidated Cash Flow per year if, after giving pro forma effect to the payment(s), the 2P Reserves Coverage Ratio is equal to or greater than 2.0 times and the Consolidated Leverage Ratio is less than 1.5 times.
19. Provisions
|
|
Decommissioning 30.06.23 Unaudited $m |
Other provisions 30.06.23 Unaudited $m |
Total 30.06.23 Unaudited $m |
Decommissioning 30.06.22 Unaudited $m |
Other provisions 30.06.22 Unaudited $m |
Total 30.06.22 Unaudited $m |
Decommissioning 31.12.22 Audited $m |
Other provisions 31.12.22 Audited $m |
Total 31.12.22 Audited $m |
|
At 1 January |
398.1 |
116.3 |
514.4 |
498.7 |
228.8 |
727.5 |
498.7 |
228.8 |
727.5 |
|
New provisions, changes in estimates and reclassifications |
42.0 |
(1.4) |
40.6 |
(2.4) |
(18.8) |
(21.2) |
(47.6) |
(19.7) |
(67.3) |
|
Acquisitions |
- |
- |
- |
24.8 |
36.8 |
61.6 |
24.8 |
36.8 |
61.6 |
|
Payments |
(43.8) |
(0.6) |
(44.4) |
(32.5) |
(77.5) |
(110.0) |
(72.1) |
(127.3) |
(199.4) |
|
Unwinding of discount |
5.0 |
- |
5.0 |
3.2 |
- |
3.2 |
6.0 |
- |
6.0 |
|
Currency translation adjustment |
2.4 |
(0.2) |
2.2 |
(10.5) |
(1.7) |
(12.2) |
(11.6) |
(2.3) |
(13.9) |
|
At 30 June/31 December |
403.7 |
114.1 |
517.8 |
481.3 |
167.6 |
648.9 |
398.1 |
116.3 |
514.4 |
|
Current provisions |
36.2 |
13.0 |
49.2 |
106.1 |
99.1 |
205.2 |
87.7 |
11.1 |
98.8 |
|
Non-current provisions |
367.5 |
101.1 |
468.6 |
375.2 |
68.5 |
443.7 |
310.4 |
105.2 |
415.6 |
Other provisions include non-income tax provision and disputed cases and claims. Management estimates non-current other provisions would fall due between two and five years.
Non-current other provisions mainly relate to the Bangladesh litigation. Refer to Note 10. Taxation on profit on continuing activities. This also includes a provision relating to a potential claim arising out of historical contractual agreement. Further information is not provided as it will be seriously prejudicial to the Company's interest.
The decommissioning provision represents the present value of decommissioning costs relating to the European and African oil and gas interests. The increase in the provision in 2023 relates to changes in cost estimates in UK and Mauritania, as well as new wells drilled in the Jubilee field in Ghana.
The Group has assumed cessation of production as the estimated timing for outflow of expenditure. However, expenditure could be incurred prior to cessation of production or after and actual timing will depend on a number of factors including, underlying cost environment, availability of equipment and services and allocation of capital.
20. Called up share capital and share premium
As at 30 June 2023, the Group had in issue 1,448.3 million allotted and fully paid ordinary shares of GBP 10 pence each (1H 21: 1,438.3 million, FY 2022: 1,439.6million).
In the six months ended 30 June 2023, the Group issued 8.7 million shares in respect of employee share options (1H 22: 6.2 million; FY 2022: 7.5 million new shares in respect of employee share options).
21. Contingent Liabilities
|
|
30.06.23 Unaudited $m |
30.06.22 Unaudited $m |
31.12.22 Audited $m |
|
Contingent liabilities |
|
|
|
|
Performance guarantees |
63.3 |
89.6 |
84.1 |
|
Other contingent liabilities |
55.8 |
60.2 |
55.8 |
|
|
119.1 |
149.8 |
139.9 |
Performance guarantees are in respect of abandonment obligations, committed work programmes and certain financial obligations.
Other contingent liabilities
This includes amounts for ongoing legal disputes with third parties where we consider the likelihood of cash outflow to be higher than remote but not probable. The timing of any economic outflow if it were to occur would likely range between one and five years.
22. Events since 30 June 2023
Gabon
Approval of asset swap with Perenco
On 28 April 2023, Tullow announced that through its wholly owned subsidiary, Tullow Oil Gabon S.A., it had signed an asset swap agreement (ASA) with Perenco Oil and Gas Gabon S.A. (Perenco). Under the ASA, Tullow has agreed to assign and transfer certain of its existing participating interests in Limande, Turnix, M'oba, Oba and Simba assets to Perenco in return for the assignment and transfer by Perenco of 15% if its participating interests in Kowe (Tchatamba) and 20% of its participating interests in DE8 assets to Tullow.
The exchange of the transferred Interests between the parties will be deemed for all purposes to be made with effect from the economic date of 1 February 2023. Due to the agreed neutrality of the transaction, no additional consideration is payable by either party in respect thereof. The ASA includes provisions to ensure the neutrality of the transaction via cash adjustments for the period between signing and completion.
On completion, all assets and associated liabilities relating to the existing participating interests held in Limande, Turnix, M'Oba and Oba assets, together with 17.5% of Tullow's interest in Simba, will be disposed. All assets impacted by the transaction are included in the "Non-Operated" business unit applied for segment performance reporting.
The transaction is expected to complete by the end of 2023, subject to the fulfilment of certain conditional precedents, including the written approval of the relevant Governmental Authority of the Gabonese Republic of the amendment of the Tullow Protocol. (The "Tullow Protocol" is an investment convention that applies to certain Tullow licences.)
Management concluded that the assets did not meet the IFRS 5 Held for Sale(HFS) criteria as of 30 June 2023 because the approval of the Tullow Protocol was considered a substantive condition without which the transaction would be unlikely to proceed. Subsequent to the reporting date, the approval has been received and the HFS criteria was met on 19 July 2023.
Licence extensions
On 9 August 2023, Tullow announced that it had gained approval from the Government of Gabon for the extension of several of its Gabon licences operated by Perenco, from 2034 to 2046. In addition to fulfilling the conditional precedent to the swap transaction, the licence extension increases the value of Tullow's resource base through the addition of c.5mmbbls net 2P reserves that are expected to deliver c.100% 2P reserves replacement in Gabon this year.
Guyana
On 10 August 2023, Tullow announced that it had agreed to sell its total interest in Tullow Guyana B.V., which includes the Orinduik licence (60% operated equity) in Guyana, to Eco Guyana Oil and Gas (Barbados) Limited in exchange for an upfront cash consideration of $0.7 million and contingent consideration linked to a series of potential future milestones, triggered as follows:
· $4 million payment in the event of a commercial discovery
· $10 million payment upon the issuance of a production licence from the Government of Guyana
· Royalty payments on future production - 1.75% of the 60% working interest entitlement revenue net of capital expenditure and lifting costs.
The transaction is subject to customary government and other approvals and is expected to complete in the second half of 2023.
There have not been any other events since 30 June 2023 that have resulted in a material impact on the interim results.
23. Cash flow statement reconciliations
|
Movement in borrowings |
1H23 $m |
FY22 $m |
1H22 $m |
FY21 $m |
1H23 Movement |
1H22 Movement |
2022 Movement |
|
Borrowings |
2,210.5 |
2,472.8 |
2,470.7 |
2,568.7 |
(262.3) |
(98.0) |
(95.9) |
|
Associated cash flows |
|
|
|
|
|
|
|
|
Repayment of borrowings1 |
|
|
|
|
(200.0) |
(100.0) |
(100.0) |
|
Non-cash movements/presented in other cash flow lines |
|
|
|
|
|
|
|
|
Gain on bond buyback1 |
|
|
|
|
(65.2) |
- |
- |
|
Amortisation of arrangement fees and accrued interest |
|
|
|
|
2.9 |
2.0 |
4.1 |
1Refer to Note 18 for the detailed explanation of the movement in borrowings.
Commercial Reserves and Contingent Resources summary working interest basis
|
|
Ghana |
Non-Operated |
Kenya |
Exploration |
Total |
||||||
|
|
Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas |
Oil mmbbl |
Gas |
Oil mmbbl |
Gas |
Oil mmbbl |
Gas |
Total |
|
COMMERCIAL RESERVES1 |
|
|
|
|
|
|
|
|
|
|
|
|
1 January 2023 |
164.3 |
157.3 |
37.8 |
5.1 |
- |
- |
- |
- |
202.1 |
162.4 |
229.1 |
|
Production2 |
(7.1) |
(6.7) |
(2.5) |
(0.5) |
- |
- |
- |
- |
(9.6) |
(7.3) |
(10.8) |
|
30 June 2023 |
157.2 |
150.6 |
35.3 |
4.6 |
- |
- |
- |
- |
192.5 |
155.1 |
218.3 |
|
CONTINGENT RESOURCES1 |
|
|
|
|
|
|
|
|
|
|
|
|
1 January 2023 |
185.0 |
577.8 |
36.0 |
8.6 |
231.4 |
- |
54.5 |
- |
506.8 |
586.3 |
604.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30 June 2023 |
185.0 |
577.8 |
36.0 |
8.6 |
231.4 |
- |
54.5 |
- |
506.8 |
586.3 |
604.6 |
|
TOTAL |
|
|
|
|
|
|
|
|
|
|
|
|
30 June 2023 |
342.2 |
728.4 |
71.3 |
13.2 |
231.4 |
|
54.5 |
- |
699.3 |
741.4 |
822.9 |
1Proven and Probable Reserves & Contingent Resources above are as audited and reported by independent third-party reserve auditors as of 31 December 2022 and production to 30 June 2023.
2Production accounted for all assets from January to June 2023.
3A gas conversion factor of 6 mscf/boe is used to calculate the total petroleum mmboe.
The Group provides for depletion and amortisation of tangible fixed assets on a net entitlement basis, which reflects the terms of the Production Sharing Contracts related to each field. Total net entitlement reserves were 209.3 mmboe as at 30 June 2023 (31 December 2022: 219.6 mmboe).
Contingent Resources relate to resources in respect of which development plans are in the course of preparation or further evaluation is under way with a view to future development.
Alternative performance 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, free cash flow, underlying operating cash flow and pre-financing 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 asset additions, additions to administrative assets and certain other adjustments. The Directors believe that capital investment is a useful indicator of the Group's organic expenditure on exploration and appraisal assets and oil and gas assets incurred during a period because it eliminates certain accounting adjustments such as decommissioning asset adjustments.
|
|
1H 2023 |
1H 2022 |
|
Additions to property, plant and equipment |
249.9 |
156.5 |
|
Additions to intangible exploration and evaluation assets |
7.9 |
20.6 |
|
Less |
|
|
|
Decommissioning asset adjustments |
42.0 |
22.4 |
|
Right-of-use asset additions |
- |
12.9 |
|
Lease payments related to capital activities |
(26.3) |
(19.5) |
|
Additions to administrative assets |
0.6 |
0.8 |
|
Other non-cash capital expenditure |
54.6 |
4.5 |
|
Capital investment |
186.9 |
156.0 |
|
Movement in working capital |
(38.2) |
(22.0) |
|
Additions to administrative assets |
0.6 |
0.8 |
|
Cash capital expenditure per the cash flow statement |
149.3 |
134.8 |
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 payments to convertible bond trustees and 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 2023 was $826.2 million current and $38.3 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 2023 |
1H 2022 |
|
Current borrowings |
100.0 |
100.0 |
|
Non-current borrowings |
2,110.5 |
2,370.7 |
|
Non-cash adjustments1 |
22.1 |
29.4 |
|
Less cash and cash equivalents2 |
(294.6) |
(164.1) |
|
Net debt |
1,938.0 |
2,336.0 |
1 Non-cash adjustments include unamortised arrangement fees which are incurred on creation or amendment of borrowing facilities.
2 Cash and cash equivalents include an amount of $53.1 million (1H 2022: $51.8 million) which the Group holds as operator in joint venture bank accounts. Included within cash at bank is $4.5 million (1H 2022: $3.8 million) of restricted cash held as collateral for performance bonds issued in relation to exploration activity.
Gearing and Adjusted EBITDAX
Gearing is a useful indicator of the Group's indebtedness, financial flexibility and capital structure and can assist securities analysts, investors and other parties to evaluate the Group. Gearing is defined as net debt divided by adjusted EBITDAX. This definition of gearing differs from the one included in the RBL facility agreements. Adjusted EBITDAX is defined as profit/(loss) from continuing activities adjusted for income tax (expense)/credit, finance costs, finance revenue, gain on hedging instruments, depreciation, depletion and amortisation, share-based payment charge, restructuring costs, gain/(loss) on disposal, gain on bargain purchase, other gains and losses, gain on bond buyback, exploration cost written off, impairment of property, plant and equipment net, and provision for onerous service contracts.
|
|
1H 2023 |
1H 2022 Restated2 |
|
Adjusted EBITDAX1 |
1,171.4 |
1,275.5 |
|
Net debt |
1,938.0 |
2,336.0 |
|
Gearing (times) |
1.7 |
1.8 |
1 Last 12 months (LTM). Refer to the 2022 Annual Report and Accounts and 2022 Half year results for a full reconciliation of 2022 and 1H 2022 Adjusted EBITDAX.
2 Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the period ended 30 June 2023 of $8.0 million (1H 2022: $12.9 million; FY 2022: $21.4 million), and a corresponding increase to income tax expense.
The restatement impacted Adjusted EBITDAX and Gearing as at 30 June 2022, increasing Adjusted EBITDAX from $1,262.6 million to $1,275.5 million, and reducing gearing from 1.9 to 1.8. Refer to Note 2.
Underlying cash operating costs
Underlying cash operating costs is a useful indicator of the Group's costs incurred to produce oil and gas. Underlying cash operating costs eliminates certain non-cash accounting adjustments to the Group's cost of sales to produce oil and gas. Underlying cash operating costs is defined as cost of sales, depletion and amortisation of oil and gas assets, underlift, overlift and oil stock movements, share-based payment charge included in cost of sales, and certain other cost of sales. Underlying cash operating costs are divided by production to determine underlying cash operating costs per boe.
In 2023 and 2022, Tullow incurred abnormal non-recurring costs which are presented separately below. The adjusted normalised cash operating costs are a helpful indicator to the forward underlying costs of the business.
|
|
1H 2023 |
1H 2022 |
|
Cost of sales |
425.6 |
225.4 |
|
Add |
|
|
|
Lease payments related to operating activity |
7.2 |
7.9 |
|
Less |
|
|
|
Depletion and amortisation of oil and gas and leased assets1 |
163.2 |
176.9 |
|
Underlift, overlift and oil stock movements2 |
108.9 |
(119.9) |
|
Royalties |
16.3 |
33.3 |
|
Share-based payment charge included in cost of sales3 |
- |
0.2 |
|
Other cost of sales4 |
8.0 |
0.1 |
|
Underlying cash operating costs |
136.4 |
142.7 |
|
Non-recurring costs5 |
(15.6) |
(14.4) |
|
Total normalised operating costs |
120.8 |
128.3 |
|
Production (MMboe) |
11.0 |
11.0 |
|
Underlying cash operating costs per boe ($/boe) |
12.4 |
13.0 |
|
Normalised cash operating costs per boe ($/boe) |
11.0 |
11.6 |
1Depletion 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.
2Under 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.
3Share-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.
4Other cost of sales includes purchases of gas from third parties to fulfil gas sales contracts and royalties paid in cash.
5Non-recurring costs include O&M (Operations & Maintenance) costs, riser remediation costs, facility projects costs, OOSYS (Oil offloading system) costs, CSV (Construction Support Vessel) campaign costs and shutdown costs.
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 and foreign exchange gain/ (loss).
|
|
1H 2023 |
1H 2022 |
|
Net cash from operating activities |
212.0 |
208.6 |
|
Net cash used in investing activities |
(136.1) |
(191.9) |
|
Repayment of obligations under leases |
(90.1) |
(91.9) |
|
Finance costs paid |
(125.0) |
(126.2) |
|
Foreign exchange loss |
(2.5) |
(3.6) |
|
Free cash flow |
(141.7) |
(205.0) |
Underlying operating cash flow
This is a useful indicator of the Group's assets' ability to generate cash flow to fund further investment in the business, reduce borrowings and provide returns to shareholders. Underlying operating cash flow is defined as net cash from operating activities less repayments of obligations under leases plus decommissioning expenditure.
Pre-financing free cash flow
This is a useful indicator of the Group's assets' ability to generate cash flow to reduce borrowings and provide returns to shareholders through dividends. Pre-financing free cash flow is defined as net cash from operating activities, and net cash used in investing activities, less repayment of obligations under leases and foreign exchange gain.
|
|
1H 2023 |
1H 2022 |
|
Net cash from operating activities |
212.0 |
208.6 |
|
Less |
|
|
|
Decommissioning expenditure |
40.0 |
28.8 |
|
Lease payments related to capital activities |
26.3 |
19.5 |
|
Add |
|
|
|
Repayment of obligations under leases |
(90.1) |
(91.9) |
|
Underlying operating cash flow |
188.2 |
165.0 |
|
Net cash used in investing activities |
(136.1) |
(191.9) |
|
Decommissioning expenditure |
(40.0) |
(28.8) |
|
Lease payments related to capital activities |
(26.3) |
(19.5) |
|
Pre-financing free cash flow |
(14.2) |
(75.2) |
WEBCAST - 9:00 BST
To access the webcast please use the following link and follow the instructions provided:
https://web.lumiconnect.com/156469303
A replay will be available on the website from midday on 13 September 2023:
https://www.tullowoil.com/investors/results-reports-and-presentations/
Contacts
|
|
|
|
Tullow Oil plc (Investors) (London) (+44 20 3249 9000) Nicola Rogers Matthew Evans |
Camarco (Media) (London) (+44 20 3781 9244) Billy Clegg Andrew Turner Rebecca Waterworth |
Notes to editors
Tullow is an independent oil & gas, exploration and production group which is quoted on the London, Irish and Ghanaian stock exchanges (symbol: TLW). The Group has interests in over 30 licences across eight countries. In March 2021, Tullow committed to becoming Net Zero on its Scope 1 and 2 emissions by 2030.
For further information, please refer to our website at www.tullowoil.com.
Follow Tullow on:
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