REG - Tullow Oil PLC - TULLOW OIL PLC - 2023 HALF YEAR RESULTS
13/09/2023 07:15
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RNS Number : 2277M Tullow Oil PLC 13 September 2023
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
(http://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 million(1); free cash flow of
$(142) million(1).
· Capital investment of $187 million and decommissioning costs of $44
million.
· Net debt at 30 June 2023 of $1.9 billion(1); Gearing of 1.7x net
debt/EBITDAX(1); 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
million(1) generated at $80/bbl. Unchanged full year free cash flow guidance
of c.$100 million(1) at $80/bbl.
· Year-end net debt expected to be c.$1.7 billion(1) 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 flow(1) 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.
****
Webcast - 9:00 BST
Access the webcast using the following link and follow the instructions
provided: https://web.lumiconnect.com/156469303
(https://web.lumiconnect.com/156469303)
Contacts
Tullow Investor Relations Camarco (Media) (+44 20 3781 9244)
ir@tullowoil.com (mailto:ir@tullowoil.com) Billy Clegg
Nicola Rogers Andrew Turner
Matthew Evans
Rebecca Waterworth
(
1)Alternative 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 Restated(1)
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 costs(2) 136 143
Depreciation, Depletion and Amortisation (DD&A) of oil and gas and leased 163 177
assets
DD&A before impairment charges ($/bbl) 14.8 15.6
Overlift, (underlift) and oil stock movements 109 (120)
Administrative expenses 19 23
Gain on bargain purchase - 197
Gain on bond buyback 65 -
Exploration costs written off (10) (87)
Impairment of property, plant and equipment, net (33) (7)
Net financing costs (135) (149)
Profit from continuing activities before tax 217 561
Income tax expense (147) (297)
Profit for the year from continuing activities 70 264
Adjusted EBITDAX (2) 1,171 1,276
Basic earnings per share (cents) 4.9 18.4
(1)Refer to note 2 for details on prior year restatement.
(2)Alternative performance measures are reconciled on pages 36 to 39.
Revenue
Sales volumes
During the period, there were 56,900 boepd (1H2022: 53,500 boepd) of liftings.
The increase is mainly due to an additional lifting in 1H 2023 in Gabon
compared to 1H 2022 where an incident at the Cap Lopez terminal had delayed a
lifting. The total number of liftings in Ghana is comparable to the previous
period with 6 in Jubilee (1H 2022: 5) and 2 in TEN (1H 2022: 3).
Realised oil price ($/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 2022(1) 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 2022(1) 17.9 (5.2) 29.2%
Total - 1H 2023 261.9 (147.2) 56.2%
1H 2022(1) 461.3 (290.8) 63.0%
(1)The 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
(1)Alternative 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 $573 million).
All financial instruments that are initially recognised and subsequently
measured at fair value have been classified in accordance with the hierarchy
described in IFRS 13 Fair Value Measurement. Fair value is the amount for
which the asset or liability could be exchanged in an arm's length transaction
at the relevant date. Where available, fair values are determined using quoted
prices in active markets. To the extent that market prices are not available,
fair values are estimated by reference to market-based transactions or using
standard valuation techniques for the applicable instruments and commodities
involved.
All of the Group's derivatives are Level 2 (1H 2022: Level 2). There were no
transfers between fair value levels during the year.
Hedge position at 30 June 2023 2H 2023(1) 1H 2024(2) 2H 2024(3)
Hedged Volume (kbopd) 34,513 22,734 -
Weighted average bought put (floor) ($/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:
(1)Aug-Dec 23: 5 kbopd $60/bbl straight puts;
(2)1H 2024: c.9 kbopd $60/bbl straight puts,
(3)2H 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 149
and equipment
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 Restated(1) 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
(1)Refer 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 15.1 12.0 30.8
value
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 Year ended 31.12.22 Audited $m
30.06.23 Unaudited $m
30.06.22
Unaudited
$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 reserve(1) $m Hedge reserve(2) $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 Restated(1) 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
(1)Refer 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 result(1) 318.7 77.2 (9.1) (5.6) (73.2) 308.0
Other losses (1.3)
Unallocated corporate expenses(2) (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 liabilities(3) (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)
(1)Segment result is a non-IFRS measure which includes gross profit,
exploration costs written off and impairment of property, plant and equipment.
See reconciliation below.
(2)Unallocated expenditure and net liabilities include amounts of a corporate
nature and not specifically attributable to a geographic area.
(3)Total liabilities - Corporate comprise of the Group's external debt,
derivative financial instruments and other non-attributable liabilities.
6. Segmental reporting continued
Reconciliation of segment result
Six months ended 30.06.23 Unaudited $m Six months ended 30.06.22 Restated(1) 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
(1)Revenue 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 - restated(1) 781.0 267.3 - - (189.7) 858.6
Segment result - restated(1,3) 609.1 215.7 - (86.9) (197.8) 540.1
Other provisions(2) (4.1)
Gain on bargain purchase 196.8
Unallocated corporate expenses(4) (23.7)
Operating profit 709.1
Finance income 21.1
Finance costs (169.7)
Profit before tax 560.5
Income tax expense - restated(1) (296.6)
Profit after tax 263.9
Total assets 4,923.2 521.9 270.8 44.8 146.1 5,906.8
Total liabilities(5) (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)
( )
(1)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 2022 of $12.9 million (FY 2022: $21.4 million), and a
corresponding increase to income tax expense. Refer to Note 2.
(2)This is included within the Restructuring costs and other provisions in the
Group Income Statement.
(3)Segment result is a non-IFRS measure which includes gross profit,
exploration costs written off and impairment of property, plant and equipment.
See reconciliation below.
(4)Unallocated expenditure and net liabilities include amounts of a corporate
nature and not specifically attributable to a geographic area.
(5)Total liabilities - Corporate comprise of the Group's external debt,
derivative financial instruments and other non-attributable liabilities.
6. Segmental reporting continued
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 result(1) 692.5 337.3 (0.5) (102.6) (337.5) 589.2
Other provisions(2) (4.1)
Gain on bargain purchase 196.8
Other gains 3.1
Unallocated corporate expenses(3) (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 liabilities(4) (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)
( )
(1)Segment result is a non-IFRS measure which includes gross profit,
exploration costs written off and impairment of property, plant and equipment.
See reconciliation below.
(2)This is included within the Restructuring costs and other provisions in the
Group Income Statement.
(3)Unallocated expenditure and net liabilities include amounts of a corporate
nature and not specifically attributable to a geographic area.
(4)Total 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 Restated(1 Sales revenue Year ended 31.12.22 $m Non-current assets 30.06.23(2) $m Non-current assets 30.06.22(2) $m Non-current assets 31.12.22(2) $m
) $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
(1)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. 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 Restated(1) 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
(1)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. 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 assets(1) 163.2 176.9 410.7
Underlift, overlift and oil stock movements(2) 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 assets(1) 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
(1)Depreciation 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.
(2)Refer 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- Write-off 31.12.22 Audited $m Remaining recoverable amount 31.12.22 Audited $m
off year ended
31.12.22
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 Right of use Other fixed assets Total six months Oil and gas assets Right of use Other fixed assets Total Oil and gas assets Right of use Other fixed assets Total
assets
six months
assets
six months
assets
six months
six months ended
six months
ended six months
six months
six months Year ended 31.12.22
Year ended
Year ended 31.12.22
ended
ended
ended
30.06.23 ended
30.06.23 ended ended
ended Audited ended
Audited
30.06.23
30.06.22
$m
31.12.22
$m
Unaudited 30.06.23
Unaudited 30.06.22 30.06.22
30.06.22 31.12.22
$m
Unaudited
$m
Unaudited
Audited
Unaudited
$m Unaudited Unaudited
$m Unaudited Audited
$m
$m
$m
$m
$m
$m
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 Impairment 30.06.23 Remaining recoverable amount
six months ended 30.06.23 30.06.23 Unaudited
Unaudited $m
$m
Mauritania a 27.6 -
UK 'CGU'(1) a 5.6 -
Impairment 33.2 -
(1)The 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 Remaining recoverable amount
30.06.22 Unaudited
Unaudited $m
$m
Mauritania a 4.9 -
UK 'CGU'(1) a 1.6 -
Impairment 6.5 -
(1)The 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 Remaining recoverable amount(2)
31.12.22 Pre-tax discount rate assumption Audited
Audited) $m
$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
(1)The fields in the UK are grouped into one CGU as all fields within those
countries share critical gas infrastructure.
(2)The 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 Other provisions 30.06.23 Unaudited $m Total 30.06.23 Unaudited $m Decommissioning 30.06.22 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
Unaudited $m Unaudited $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 borrowings(1) (200.0) (100.0) (100.0)
Non-cash movements/presented in other cash flow lines
Gain on bond buyback(1) (65.2) - -
Amortisation of arrangement fees and accrued interest 2.9 2.0 4.1
(1)Refer 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
bcf
bcf
bcf
bcf mmboe(3)
COMMERCIAL RESERVES(1)
1 January 2023 164.3 157.3 37.8 5.1 - - - - 202.1 162.4 229.1
Production(2) (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 RESOURCES(1)
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
( )
(1)Proven 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.
(2)Production accounted for all assets from January to June 2023.
(3)A 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 adjustments(1) 22.1 29.4
Less cash and cash equivalents(2) (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
Restated(2)
Adjusted EBITDAX(1) 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 $1,275.5 million, and
reducing gearing from 1.9 to 1.8. Refer to Note 2.
Underlying cash operating costs
Underlying cash operating costs is a useful indicator of the Group's costs
incurred to produce oil and gas. Underlying cash operating costs eliminates
certain non-cash accounting adjustments to the Group's cost of sales to
produce oil and gas. Underlying cash operating costs is defined as cost of
sales, depletion and amortisation of oil and gas assets, underlift, overlift
and oil stock movements, share-based payment charge included in cost of sales,
and certain other cost of sales. Underlying cash operating costs are divided
by production to determine underlying cash operating costs per boe.
In 2023 and 2022, Tullow incurred abnormal non-recurring costs which are
presented separately below. The adjusted normalised cash operating costs are a
helpful indicator to the forward underlying costs of the business.
1H 2023 1H 2022
Cost of sales 425.6 225.4
Add
Lease payments related to operating activity 7.2 7.9
Less
Depletion and amortisation of oil and gas and leased assets(1) 163.2 176.9
Underlift, overlift and oil stock movements(2) 108.9 (119.9)
Royalties 16.3 33.3
Share-based payment charge included in cost of sales(3) - 0.2
Other cost of sales(4) 8.0 0.1
Underlying cash operating costs 136.4 142.7
Non-recurring costs(5) (15.6) (14.4)
Total normalised operating costs 120.8 128.3
Production (MMboe) 11.0 11.0
Underlying cash operating costs per boe ($/boe) 12.4 13.0
Normalised cash operating costs per boe ($/boe) 11.0 11.6
(1)Depletion and amortisation of oil and gas assets is the depreciation and
amortisation of the Group's oil and gas assets over the life of an asset on a
unit of production basis.
(2)Under lifting or offtake arrangements for oil and gas produced in certain
operations in which the Group has interests with other commercial partners,
each participant may not receive and sell its precise share of the overall
production in each period. The resulting imbalance between cumulative
entitlement and cumulative production less stock constitutes "underlift" or
"overlift". Underlift and overlift are valued at market value and included
within other current assets and other current payables on the Group's balance
sheet, respectively. Movements during an accounting period are charged to cost
of sales rather than charged through revenue, and as a result gross profit is
recognised on an entitlements basis.
(3)Share-based payment charge included in cost of sales relates to the portion
of the non-cash share-based payment charge that relates to employees who work
on operational projects.
(4)Other cost of sales includes purchases of gas from third parties to fulfil
gas sales contracts and royalties paid in cash.
(5)Non-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 (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/
(https://www.tullowoil.com/investors/results-reports-and-presentations/)
Contacts
Tullow Oil plc (Investors) Camarco (Media)
(London) (London)
(+44 20 3249 9000) (+44 20 3781 9244)
Nicola Rogers Billy Clegg
Matthew Evans 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 (http://www.tullowoil.com)
.
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