REG - Tullow Oil PLC - 2024 Half Year Results
07/08/2024 07:00
For best results when printing this announcement, please click on link below:
http://newsfile.refinitiv.com/getnewsfile/v1/story?guid=urn:newsml:reuters.com:20240807:nRSG4447Za&default-theme=true
RNS Number : 4447Z Tullow Oil PLC 07 August 2024
Tullow oil PLC - 2024 Half Year Results
First half revenue of $759 million, gross profit of $460 million and profit after tax of $196 million
Ghana drilling programme completed safely and ahead of schedule
2024 guidance reiterated
7 August 2024 - Tullow Oil plc ("Tullow"), the independent oil and gas
exploration and production group ("Group"), announces its Half Year Results
for the six months ended 30 June 2024. Details of a management presentation
and webcast that will be held at 9:00 BST today are available on the last page
(#_Management_Presentation_%E2%80%93) of this announcement or visit the
Group's website: www.tullowoil.com (http://www.tullowoil.com)
Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented today:
"During the first half of 2024, Tullow has continued to deliver strong
operational and financial performance. We are pleased to report improved
results across key financial metrics compared to the first half of 2023; with
higher production and oil price realisations combined with lower expenditure.
The Ghana drilling programme was also completed safely, and ahead of schedule.
"We were delighted to reach a major milestone by taking final investment
decision (FID) of our nature-based carbon offset initiative, in partnership
with the Ghana Forestry Commission. The project will deliver certified carbon
offsets in line with Tullow's 2030 Net Zero target, while bringing broader
positive impacts to the local community.
"We now progress into a period of lower capex in the second half of the year
and beyond. We will continue to reduce debt through sustainable free cash flow
generation, strengthening our balance sheet and providing optionality for
investment, growth and future returns."
2024 FIRST HALF RESULTS
· First half Group working interest oil and gas production 63.7
kboepd (1H23: 60.8 kboepd).
· Revenue of $759 million (1H23: $777 million); realised oil price of
$77.7/bbl after hedging (1H23: $73.3/bbl), gross profit of $460 million (1H23:
$351 million); profit after tax of $196 million (1H23: $70 million).
· Capital expenditure of $157 million (1H23: $187 million) and
decommissioning spend of $9 million (1H23: $44 million).
· Free cash flow(1) of $(126) million (1H23: $(142) million), in line
with expectations based on timing of tax payments and capital expenditure
weighted toward the first half of the year.
· Net debt(1) at 30 June 2024 of $1.7 billion (30 June 2023: $1.9
billion); cash gearing of 1.4x net debt/EBITDAX(1) (30 June 2023: 1.7x);
liquidity headroom of $0.7 billion (30 June 2023: $0.7 billion).
2024 FULL YEAR OUTLOOK
· 2024 Group working interest production is expected to be at the
lower end of the Group's 62-68 kboepd range, as previously guided; driven
primarily by underperformance of a single Jubilee well, which came onstream in
February 2024.
· Full year capex and decommissioning guidance of c.$230 million and
c.$70 million, respectively. This represents a c.$20 million capex decrease
(versus previous guidance of c.$250 million) in both Ghana and Gabon.
· A significant free cash flow uplift is expected in the second half
of 2024. Full year free cash flow guidance remains unchanged at $200-300
million at $80/bbl.
· Increased access to oil price upside as legacy hedges fully rolled
off in May 2024; 2H 2024 average floor of $60/bbl and capped upside of
$112/bbl.
· Year-end net debt guidance is unchanged at less than $1.4 billion
with gearing of c.1x (net debt/EBITDAX(1)).
· Tullow has no uncovered debt maturities until May 2026 and
continues to consider options to manage its debt maturities and optimise its
capital structure.
· Outcome of arbitration in respect of Ghana Branch Profits
Remittance Tax expected in the second half of 2024.
· Tullow remains focused on deleveraging and reaching net debt of
less than $1 billion and cash gearing of less than 1x in the near term.
1. Alternative performance measures are reconciled on pages 36 to 38
Operational update
Production
In the first six months of 2024, Group production averaged 63.7 kboepd,
including 7.0 kboepd of gas. As previously disclosed, Group 2024 production is
expected to be at lower end of the 62 to 68 kboepd range.
Group working interest production (kboepd) 1H 2024 Actual 2024 Guidance
Ghana oil 45.5 c.44
Jubilee oil 35.1 c.34
TEN oil 10.4 c.10
Non-operated portfolio oil 11.2 c.11
Gabon oil 10.2 c.10
Cote d'Ivoire oil 1.0 c.1
Group gas production 7.0 c.7
Total 63.7 c.62
Ghana
During the first six months of the year, operational efficiency remained high,
with average facility uptime across the Ghana FPSOs at 97%.
Gross oil production from the Jubilee field averaged 90.1 kbopd (net: 35.1
kbopd) in the first half of the year. This was below expectations, primarily
attributable to poor performance from to the J69 producer well, which was
brought onstream in February 2024. The J69 well is producing significantly
less than expected due to a lack of pressure communication from water
injection in this specific area. This is not being experienced elsewhere and
across the field, water injection has averaged a record c.225 kbwpd. This
improved rate of water injection, together with the new J70 water injection
well brought onstream in June, is resulting in a good uplift in reservoir
pressure which is already increasing production levels and offsetting decline.
As a result, Jubilee oil production is expected to remain at similar levels to
the first half and average c.90 kbopd (net: c.34 kbopd) for the full year.
Five new Jubilee wells (three producers and two water injectors) were brought
onstream during the first half of 2024, bringing the current drilling
programme to an end, approximately six months ahead of schedule and with no
recordable safety incidents. A 4D seismic survey will be completed in early
2025 to update the view of the sub-surface, support drill candidate selection
and optimise well placement ahead of a 2025/26 drilling programme.
During the drill break, work will focus on integrating the results of the
previous drilling programme and optimising pressure support across the field
to maximise production and minimise decline. Tullow will continue to
prioritise safe and reliable operations, with a focus on cost and capital
efficiency to optimise cash flow delivery.
Gross oil production from the TEN fields averaged 19.0 kbopd (net: 10.4 kbopd)
in the first half of the year. The fields have exceeded expectations, with
Enyenra and Ntomme wells responding positively to both injection and
production optimisation. Consequently, full year gross TEN oil production
guidance has been increased to c.18 kbopd (net: c.10 kbopd).
Net gas production in Ghana averaged 6.5 kboepd in the first half of the year.
The interim Gas Sales Agreement remains in place until the fourth quarter of
2025 at $3.00/mmbtu with applicable indexation. Tullow is also in discussion
in relation to potential third party off-take opportunities to create a
significant longer-term revenue stream from gas production.
Non-operated and exploration portfolios
Production from our non-operated portfolio in Gabon and Côte d'Ivoire
averaged 11.7 kboepd net in the first half of the year, in line with
expectations. Full year net production remains unchanged at c.11.5 kboepd.
Tullow was deeply saddened to learn of the incident at the Perenco-operated
Simba field in Gabon in March 2024, which resulted in fatalities. Production
has been shut in while investigations and remediations are taking place.
Production is expected to resume on the Simba field before the end of the
year. Production forecasts for Gabon remain unchanged with lower Simba
production being offset by improvement in other fields, including Ezanga and
Echira.
In Côte d'Ivoire, Tullow continues to work with the operator of the Espoir
field to establish the best way forward for the asset. Tullow continues to
mature prospects on its exploration licences in Côte d'Ivoire and Argentina
alongside seeking potential farm-down Partners.
Kenya
Tullow continues to work collaboratively with the Government of Kenya as they
evaluate the amended Field Development Plan (FDP). The Energy and Petroleum
Regulatory Authority (EPRA) has provided useful feedback and the FDP review
period has been extended for a further six months to 31 December 2024. Tullow
is continuing its cooperation and collaboration with the Government to reach
final approval of the FDP. Discussions continue with prospective strategic
partners for this project.
Reserves and resources
Tullow's review of its reserves and resources position is ongoing,
incorporating 1H production as well as results and performance from the recent
Ghana drill programme. Tullow will publish its 1H24 reserves report in
September, in line with prior years.
Environmental, Safety and Governance (ESG)
Tullow continues to progress along its pathway to Net Zero by 2030 (Scope 1
and 2). The primary focus of the Group's Net Zero strategy is on decarbonising
its operated production facilities in Ghana and Tullow continues to progress
workstreams to eliminate routine flaring by the end of 2025. To address
hard-to-abate residual emissions, in May 2024 Tullow took a final investment
decision (FID) with the Ghana Forestry Commission to invest $90 million over
10 years, implementing a high integrity, jurisdictional based Reduced
Emissions from Deforestation and Degradation (REDD+) programme that will
deliver certified carbon offsets in line with Tullow's 2030 Net Zero roadmap.
The programme is expected to generate up to 1 million tonnes per annum of
certified carbon offsets from c.2 million hectares of land across the Bono and
Bono East regions of Ghana.
Tullow is committed to being a responsible steward of the environment and
ensuring robust systems are in place to manage environmental risks. These
systems were deployed during two losses of primary containments in the first
half of 2024 that resulted in a release of oil to the sea. These were dealt
with quickly, with no major impacts, and a thorough investigation has been
undertaken with actions taken to prevent any recurrence.
In June 2024, Tullow released the Noble Venturer drill ship from its contract
in Ghana, which marked 1,171 days of operations, drilling 21 deep-water wells
without any recordable EHS incidents.
The Group's Shared Prosperity strategy continues to focus on supporting
enterprise, especially agribusiness, enhancing employability and job creation,
strengthening local economies and improving living standards, through our
different partnerships. In February 2024, Tullow launched the Tullow
AgriVentures Programme (TAP) in partnership with Innohub Ghana. TAP has an
ambition to generate approximately 600 new agriculturally linked ventures and
support 30 existing businesses to grow and create more than 1,500 jobs. Tullow
continues to work closely with local suppliers to drive local content and
strengthen human rights due diligence through increased engagement, support,
and training. In the first half of the year, Tullow received three awards at
the Ghana Shippers' Authority Awards 2024, recognising the Group's commitment
to local content, imports and transparency in the energy sector.
Finance review
Income Statement
Income Statement (key metrics) 1H 2024 1H 2023
Revenue ($m)
Sales volume (boepd) 51,200 56,900
Realised oil price ($/bbl) 77.7 73.3
Total revenue 759 777
Operating income/(costs) ($m)
Underlying cash operating costs(1) (125) (136)
Depreciation, Depletion and Amortisation (DDA) of oil and gas and leased (198) (163)
assets
DDA before impairment charges ($/bbl) 17.1 14.8
(Overlift)/Underlift and oil stock movements 39 (109)
Administrative expenses (31) (19)
Asset revaluation 39 -
Exploration costs written off (3) (10)
Impairment reversal/(Impairment) of property, plant and equipment, net 2 (33)
Gain on bond buyback - 65
Net financing costs (138) (135)
Profit before tax 368 217
Income tax expense (172) (147)
Profit for the period 196 70
Adjusted EBITDAX(1) 1,282 1,171
Basic earnings per share (cents) 13.5 4.9
1. Alternative performance measures are reconciled on pages 36 to 38.
Revenue
Sales Oil Volumes
During the period, there were 51,200 boepd (1H2023: 56,900 boepd) of liftings.
The decrease is mainly due to the reduction of two liftings in Gabon offset by
an increase of one lifting in Ghana with 7 in Jubilee (1H 2023: 6) and 2 in
TEN (1H 2023: 2).
Realised oil price ($/bbl)
The Group's realised oil price after hedging for the period was $77.7/bbl (1H
2023: $73.3/bbl) and before hedging $83.9/bbl (1H 2023: $79.7/bbl). Lower
hedged volumes subject to price caps compared to 1H 2023 have resulted in a
lower hedge loss despite higher oil prices, decreasing total revenue by $57.9
million in 1H 2024 (1H 2023: decrease of $65.9 million).
Gas sales
Included in Total Revenue of $759 million is gas sales of $29 million of which
$25 million relates to Ghana. During the period, Jubilee exported 18,148 mmscf
(gross) of gas at an average price of $2.95/mmbtu.
Cost of Sales
Underlying cash operating costs
Underlying cash operating costs amounted to $125 million; $10.8/boe (1H 2023:
$136 million; $12.4/boe). The cash unit operating costs have decreased against
the comparative period driven by reprioritisation and rephasing of Jubilee
O&M activities in the current period and TEN shutdown preparatory costs in
1H 2023.
Depreciation, depletion, and amortisation
DD&A charges before impairment on production and development assets
amounted to $198 million; $17.1 /boe (1H 2023: $163 million: $14.8/boe). This
increase in DD&A is mainly attributable to increased Jubilee production
and gas commercialisation offset by the impact of 2023 impairments relating to
TEN.
Overlift and oil stock movements
The Group had an underlift compared to an overlift expense in the comparative
period. The change was due to timing of liftings specifically in Gabon
resulting in a higher oil stock position compared to the comparative period.
Jubilee has had one lifting higher in the current period with oil stock
position comparable to prior period as a result of increased production.
Administrative expenses
Administrative expenses of $31 million (1H 2023: $19 million) have increased
against the comparative period due to prior year adjustments and accrual
release in 1H 2023 of $6 million, one-off redundancy costs in 1H 2024 of $1.4
million, increase in payroll costs and phasing of spend in 1H 2024. Full year
forecast administrative costs are expected to be in line with prior year
despite the inflationary environment.
Asset revaluation
The asset revaluation of $39 million relates to assets disposed of as part of
the swap with Perenco (refer to Note 13 for further information).
Exploration costs written off
During the first half of 2024, the Group has written off exploration costs of
$3 million (1H 2023: $10 million) driven by exploration costs in Cote D'Ivoire
and New Venture activities.
Impairment of property, plant and equipment
The Group recognised a net impairment reversal on PP&E of $2 million in
respect of the first half of 2024 (1H 2023: Net impairment $33 million) which
is mainly driven by change in decommissioning discount rates offset by changes
to estimates on the cost of decommissioning for certain UK assets.
Net financing costs
Net financing costs for the period were $138 million (1H 2023: $135 million).
This increase is mainly due to higher interest on obligations under leases of
$17m, offset by lower interest on borrowings of $15 million due to bond
buybacks in 2H 2023 and a prepayment in May 2024 resulting in a lower amount
of outstanding bonds.
A reconciliation of net financing costs is included in Note 9.
Taxation
The overall adjusted net tax expense of $171 million (1H 2023: $147 million)
primarily relates to tax charges in respect of the Group's production
activities in West Africa, reduced by deferred tax credits associated with UK
decommissioning assets, 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 2024.
Based on a profit before tax for the first half of the year of $368 million
(1H 2023: $217 million), the effective tax rate is 46.7% (1H 2023: 67.7%).
After adjusting for non-recurring amounts related to exploration write-offs,
disposals, impairments and their associated deferred tax benefit, the Group's
adjusted tax rate is 51.7% (1H 2023: 56.2%). In the UK there is net interest
and hedging expenses of $123 million (1H 2023: $80 million), however there is
no UK tax benefit as in previous periods.
The Group's future statutory effective tax rate is sensitive to the geographic
mix in which pre-tax profits arise. There is no UK tax benefit from net
interest and hedging expenses, whereas net interest income and hedging profits
would be taxable in the UK. Consequently, the Group's tax charge will continue
to vary according to the jurisdictions in which pre-tax profits occur. The
group has applied the exception to recognising and disclosing information
about deferred tax assets and liabilities relating to pillar two income taxes.
The group's effective tax rate is more than 15% for this period and the group
is not expecting profit to be taxed at less than 15%.
Analysis of adjusted effective tax rate ($m) Adjusted Profit/(loss) Tax Adjusted
before tax
(expense)/credit
Effective tax rate
Ghana 1H 2024 411.5 (144.7) 35.2%
1H 2023 266.0 (97.7) 36.7%
Gabon 1H 2024 80.0 (23.5) 29.3%
1H 2023 105.0 (49.7) 47.3%
Corporate 1H 2024 (164.9) (0.6) (0.4%)
1H 2023 (114.3) 1.7 1.5%
Other non-operated & exploration 1H 2024 4.9 (2.6) 52.6%
1H 2023 5.2 (1.5) 28.7%
Total 1H 2024 331.5 (171.3) 51.7%
1H 2023 261.9 (147.2) 56.2%
Adjusted EBITDAX
Adjusted EBITDAX for the year was $1,282 million (1H 2023: $1,171 million).
The increase in the period was mainly driven by the oil stock movements in the
current period as explained in Cost of Sales section above.
Profit for the year from continuing activities and earnings per share
The profit for the year from continuing activities amounted to $196 million
(1H 2023: $70 million profit). The increase in profit after tax was driven
mainly by a reduction in impairments, asset revaluation gains and provision
releases. Basic earnings per share was 13.5 cents (1H 2023: 4.9 cents earnings
per share).
Balance Sheet and Liquidity management
Balance Sheet and Liquidity management (key metrics) 1H 2024 1H 2023
Capital investment ($m)(1) 157 187
Derivative financial instruments ($m) (32) (79)
Borrowings ($m) (1,980) (2,211)
Underlying operating cash flow ($m) (1) 169 188
Free cash flow ($m)(1) (126) (142)
Net debt ($m)(1) 1,735 1,938
Gearing (times)(1) 1.4 1.7
1. Alternative performance measures are reconciled on pages 36 to 38.
Capital Investment
Capital expenditure amounted to $157 million (1H 2023: $187 million) with $151
million invested in production and development activities of which $108
million was invested in Jubilee mainly comprising of $96 million on drilling
costs and $6 million invested in exploration and appraisal activities.
The Group's 2024 capital expenditure guidance is revised to c.$230 million
which will comprise Ghana of c.$150 million, West African Non-Operated of
c.$50 million, Kenya of c.$10 million and exploration spend of c.$20 million.
Decommissioning
Decommissioning expenditure was $9 million in the first half of 2024 (1H 2023:
$44 million). The Group's decommissioning expenditure guidance related to
decommissioning liabilities in the UK and Mauritania in 2024 is revised to $65
million as the Mauritania operated decommissioning campaign is expected to
commence earlier than previously planned. This increase is offset by deferrals
in Gabon, resulting in decommissioning expenditure guidance for 2024 remaining
unchanged at c.$70 million net to Tullow.
Derivative financial instruments
Tullow has a material hedge portfolio in place to protect against commodity
price volatility and to ensure the availability of cash flow for re-investment
in capital programmes that are driving business delivery.
At 30 June 2024, Tullow's hedge portfolio provides downside protection for
c.60% of forecast production entitlements in the second half of 2024 with
c.$60/bbl weighted average floors across all hedging instruments; for the same
period, c.24% of forecast production entitlements is capped at weighted
average sold calls of c.$112/bbl. A second tier of capped upside exists
through three-way collars on 15% of the total hedged volume with weighted
average sold calls of $83/bbl, however, potential hedging losses on three-way
collars are limited to a $10/bbl range due to the presence of purchased calls,
allowing re-participation in the upside if oil prices rise above $93/bbl on a
weighted average basis.
For the period from January 2025 to June 2025, Tullow's hedge portfolio
provides downside protection for c.45% of forecast production entitlements
with c.$59/bbl weighted average floors, while c.27% is capped though three-way
collars with weighted average sold calls at c.$92/bbl and re-participation in
the upside above c.$102/bbl on a weighted average basis. For the period from
July 2025 to December 2025, three-way collars provide downside protection for
c.10% of forecast production entitlements with c.$60/bbl weighted average
floors and c.$89-$99/bbl call spreads on a weighted average basis.
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 (Level 1). 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 (Level 2).
All of the Group's derivatives are Level 2 (2023: Level 2). There were no
transfers between fair value levels during the year.
At 30 June 2024, the Group's derivative instruments had a net negative fair
value of $32 million (1H23: net negative $79 million).
The following table demonstrates the timing, volumes and prices of the Group's
commodity hedge portfolio at 30 June 2024:
2H24 hedge portfolio at 30 June 2024 bopd Bought put Sold Bought
(floor) call call
Straight puts 12,525 $60 - -
Collars 14,075 $60 $112 -
Three-way collars (call spread) 8,500 $60 $83 $93
Total/Weighted Average 35,100 $60 $101 $93
1H25 hedge portfolio at 30 June 2024 bopd Bought put Sold Bought
(floor) call call
Straight puts 9,500 $58 - -
Collars - - - -
Three-way collars (call spread) 16,000 $59 $92 $102
Total/Weighted Average 25,500 $59 $92 $102
2H25 hedge portfolio at 30 June 2024 bopd Bought put Sold Bought
(floor) call call
Straight puts - - - -
Collars - - - -
Three-way collars (call spread) 6,500 $60 $89 $99
Total/Weighted Average 6,500 $60 $89 $99
Borrowings
On 15 May 2024, the Group made the annual prepayment of $100 million of the
2026 Notes.
The Group's total drawn debt reduced to $2.0 billion, consisting of $0.5
billion nominal value 2025 Notes, $1.4 billion nominal value 2026 Notes and
$0.1 billion outstanding under a Secured Notes Facility.
Management regularly reviews options for optimising the Group's capital
structure and may seek to refinance, retire or purchase any or all of its
outstanding debt from time to time through new debt financings and/or cash
purchases in open market purchases, privately negotiated transactions or
otherwise.
Credit Ratings
Tullow maintains credit ratings with Standard & Poor's (S&P's) and
Moody's Investors Service (Moody's).
Since December 2023, S&P has maintained Tullow's corporate credit rating
at B- with negative outlook, and the rating of the 2026 Notes at B- and the
rating of the 2025 Notes at CCC+. Similarly, Moody's has maintained Tullow's
corporate credit rating at Caa1 with negative outlook, and the rating of 2026
Notes at Caa1 and the rating of the 2025 Notes at Caa2.
Underlying Operating Cash Flow and Free Cash Flow
Underlying operating cash flow amounted to $169 million (1H 2023: $188
million). Cash revenue of $97 million higher due to an additional cash lifting
in the current period and impact of higher oil price, offset by $137 million
higher cash taxes in the current period.
Free cash flow has increased to $(126) million (1H 2023: $(142) million)
primarily due to a decrease in decommissioning spend in current period of $30
million and lower finance costs of $9 million. This is offset by the decrease
in underlying operating cashflow of $19m as explained above.
Net Debt and Gearing
Reconciliation of net debt $m
FY 2023 net debt 1,608
Sales revenue (759)
Operating costs 125
Other operating and administrative expenses 20
Operating cash flow before working capital movements (614)
Movement in working capital 76
Tax paid 308
Purchases of intangible exploration and evaluation assets and property, plant 160
and equipment
Other investing activities (10)
Other financing activities 210
Foreign exchange loss on cash (3)
1H 2024 net debt 1,735
Net debt increased by $127 million during the period to $1,735 million at 30
June 2024 (FY 2023: $1,608 million), consisting of $493 million Senior Notes
due 2025, $1,385 million Senior Secured Notes due 2026 and $130 million
outstanding under a Secured Notes Facility less cash and cash equivalents.
The Gearing ratio has decreased to 1.4 times (1H 2023:1.7 times) due to an
increase in Adjusted EBITDAX as explained above primarily due to movements in
oil stock in the current period.
Ghana tax assessments
A further arbitration hearing was conducted in June 2024 in respect of the
assessment for Branch Profits Remittance Tax (BPRT). This claim relates to the
Ghana Revenue Authority (GRA) seeking to apply BPRT under a law which the
Group considers is not applicable to Tullow Ghana Limited, since it falls
outside the tax regime provided for in the Petroleum Agreements and relevant
double tax treaties. Tullow referred this case to international arbitration in
October 2021 and a decision from the panel is expected in the second half of
the year. Tullow has two further ongoing disputed tax assessments that relate
to the disallowance of loan interest deductions for the fiscal years 2010 -
2020 and proceeds received by Tullow Oil plc under Tullow's corporate Business
Interruption Insurance policy. Both were referred to international arbitration
in 2023, with first hearings scheduled for 2025, however Tullow continues to
engage with the Government of Ghana, including the GRA, with the aim of
resolving the assessments on a mutually acceptable basis.
Liquidity Risk Management and Going concern
The Directors consider the going concern assessment period to be up to 31
August 2025. 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: $82/bbl for 2024, $78/bbl for 2025; and
· Low Case: $70/bbl for 2024, $70/bbl for 2025.
The Low Case includes, amongst other downside assumptions, a 10% production
decrease and 10% increased operating costs compared to the Base Case.
Management has also considered additional outflows in respect of all ongoing
litigations/arbitrations within the Low Case, with an additional $111 million
outflow being included for the cases expected to progress in the period under
assessment. The Low Case does not include the outflow for the full exposure on
Ghana BPRT arbitration of $320 million (refer to note 10 Ghana tax assessments
for details). The remaining arbitration cases are not expected to conclude
within the going concern period and no outflows have been included in that
respect.
At 30 June 2024, the Group had $0.7 billion liquidity headroom consisting of
$0.2 billion free cash and $0.5 billion available under the revolving credit
facility, maturing in December 2024.
The Group or its affiliates may, at any time and from time to time, seek to
refinance, retire or purchase any or all of its outstanding debt through new
debt financings and/or cash purchases, in open-market purchases, privately
negotiated transactions or otherwise. Such refinancings or repurchases, if
any, will be upon such terms and at such prices as management may determine,
and will depend on prevailing market conditions, liquidity requirements and
other factors.
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. The Directors have
also performed a reverse stress test to establish the average oil price
throughout the going concern period required to reduce headroom to zero, that
price was determined to be $20/bbl. 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.
2024 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 2023 Annual Report and are listed below.
1. Business plan not delivered
2. Asset integrity breach
3. Value not unlocked
4. Geopolitical risk
5. Climate change
6. Major accident event
7. Insufficient liquidity and funding capacity to sustain business
8. Capability cannot be attracted, developed or retained
9. Compliance or regulatory breach
10. Major cyber-disruption
The detailed descriptions of the principal risks and how they are being
managed can be found on pages 52 to 56 in the 2023 Annual Report and Accounts.
Events since 30 June 2024
There have not been any events since 30 June 2024 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, 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
Richard Miller
Chief Executive
Officer
Chief Financial Officer
6 August
2024
6 August 2024
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 2024 which comprises of 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
24. 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 2024 is not prepared, in all
material respects, 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.
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
(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 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.
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
6 August 2024
Condensed consolidated income statement
Six months ended 30 June 2024
$m Notes Six months ended 30.06.24 Six months ended 30.06.23 Year ended 31.12.23
Unaudited
Unaudited
Audited
Revenue 7 758.8 776.9 1,634.1
Cost of sales 8 (299.2) (425.6) (869.2)
Gross profit 459.6 351.3 764.9
Administrative expenses 8 (30.9) (19.1) (56.1)
Other (losses)/gains - (1.3) 0.2
Asset revaluation 13 38.9 - -
Exploration costs written off 11 (3.1) (10.1) (27.0)
Impairment of property, plant and equipment, net 12 1.7 (33.2) (408.1)
Provisions reversal 8 39.4 - 22.0
Operating profit 505.6 287.6 295.9
Loss on hedging instruments - (0.3) (0.4)
Gain on bond buyback - 65.2 86.0
Finance income 9 39.7 25.0 44.0
Finance costs 9 (177.7) (160.3) (329.6)
Profit from continuing activities before tax 367.6 217.2 95.9
Income tax expense 10 (171.6) (147.1) (205.5)
Profit/(loss) for the year from continuing activities 196.0 70.1 (109.6)
Attributable to
Owners of the Company 196.0 70.1 (109.6)
Earnings/(loss) per ordinary share from continuing activities ¢ ¢ ¢
Basic 13.5 4.9 (7.6)
Diluted 12.9 4.7 (7.6)
Condensed consolidated statement of comprehensive income and expense
Six months ended 30 June 2024
$m Six months ended 30.06.24 Six months ended 30.06.23 Unaudited Year ended 31.12.23
Unaudited
Audited
Profit/(loss) for the period 196.0 70.1 (109.6)
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
(Losses)/gains arising in the period (33.0) 68.1 20.1
(Losses)/gains arising in the period - time value (24.5) 31.9 50.3
Reclassification adjustments for items included in profit on realisation 45.6 50.8 111.3
Reclassification adjustments for items included in loss on realisation - time 14.7 15.1 27.8
value
Exchange differences on translation of foreign operations 1.6 (4.8) (5.8)
Net other comprehensive income for the period 4.4 161.1 203.7
Total comprehensive income for the period 200.4 231.2 94.1
Attributable to
Owners of the Company 200.4 231.2 94.1
Condensed consolidated balance sheet
As at 30 June 2024
$m Notes Six months ended 30.06.24 Six months ended 30.06.23 Year ended 31.12.23
Unaudited
Unaudited
Audited
Assets
Non-current asset
Goodwill 13 44.9 - -
Intangible exploration and evaluation assets 11 295.6 286.4 287.0
Property, plant and equipment 12 2,515.1 3,008.2 2,532.8
Other non-current assets 15 303.5 54.1 338.6
Deferred tax assets 17.0 13.3 19.6
3,176.1 3,362.0 3,178.0
Current assets
Inventories 16 178.1 124.9 107.3
Trade receivables 14 91.6 164.0 43.5
Other current assets 15 476.1 822.5 571.2
Current tax assets 16.9 15.9 3.8
Cash and cash equivalents 17 272.6 294.6 499.0
Assets classified as held for sale - - 55.8
1,035.3 1,421.9 1,280.6
Total assets 4,211.4 4,783.9 4,458.6
Liabilities
Current liabilities
Trade and other payables 18 (667.0) (1,410.0) (775.0)
Borrowings 19 (589.2) (100.0) (100.0)
Provisions 20 (82.3) (49.2) (67.9)
Current tax liabilities (107.4) (144.2) (230.5)
Derivative financial instruments (29.9) (78.6) (35.0)
Liabilities associated with assets classified as held for sale - - (17.6)
(1,475.8) (1,782.0) (1,226.0)
Non-current liabilities
Trade and other payables 18 (712.9) (84.5) (783.2)
Borrowings 19 (1,390.3) (2,110.5) (1,984.6)
Provisions 20 (328.2) (468.6) (403.7)
Deferred tax liabilities (458.4) (565.5) (420.5)
Derivative financial instruments (2.4) - -
(2,892.2) (3,229.1) (3,592.0)
Total liabilities (4,368.0) (5,011.1) (4,818.0)
Net liabilities (156.6) (227.2) (359.4)
Equity
Called-up share capital 217.4 216.2 216.7
Share premium 1,294.7 1,294.7 1,294.7
Foreign currency translation reserve (242.8) (243.4) (244.4)
Hedge reserve (6.3) (31.4) (18.9)
Hedge reserve - time value (26.1) (47.4) (16.3)
Merger reserve 755.2 755.2 755.2
Retained earnings (2,148.7) (2,171.1) (2,346.4)
Equity attributable to equity holders of the Company (156.6) (227.2) (359.4)
Total equity (156.6) (227.2) (359.4)
Condensed statement of changes in equity
Six months ended 30 June 2024
$m Share Share Foreign currency translation reserve¹ Hedge Hedge Merger reserves Retained earnings Total
capital
premium
reserve²
reserve - time
value²
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)
Loss for the period - - - - - - (179.7) (179.7)
Hedges, net of tax - - - 12.5 31.1 - - 43.6
Currency translation adjustments - - (1.0) - - - - (1.0)
Exercise of employee share options 0.5 - - - - - (0.5) -
Share-based payment charges - - - - - - 4.9 4.9
At 1 January 2024 216.7 1,294.7 (244.4) (18.9) (16.3) 755.2 (2,346.4) (359.4)
Profit for the period - - - - - - 196.0 196.0
Hedges, net of tax - - - 12.6 (9.8) - - 2.8
Currency translation adjustments - - 1.6 - - - - 1.6
Exercise of employee share options 0.7 - - - - - (0.7) -
Share-based payment charges - - - - - - 2.4 2.4
At 30 June 2024 217.4 1,294.7 (242.8) (6.3) (26.1) 755.2 (2,148.7) (156.6)
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 2024
$m Notes Six months ended 30.06.24 Unaudited Six months ended 30.06.23 Year ended
Unaudited
31.12.23
Audited
Cash flows from operating activities
Profit from continuing activities before tax 367.6 217.2 95.9
Adjustments for:
Depreciation, depletion and amortisation 12 199.7 167.1 436.6
Other losses/(gains) - 1.3 (0.2)
Asset revaluation 13 (38.9) - -
Taxes paid in kind (5.9) (8.0) (11.0)
Exploration costs written off 11 3.1 10.1 27.0
Impairment of property, plant and equipment, net 12 (1.7) 33.2 408.1
Provisions reversal (39.4) - (22.0)
Payment for provisions 20 (0.6) (0.6) (0.6)
Decommissioning expenditure (9.9) (40.0) (78.1)
Share-based payment charge 2.4 1.1 6.0
Loss on hedging instruments - 0.3 0.4
Gain on bond buyback - (65.2) (86.0)
Finance income 9 (39.7) (25.0) (44.0)
Finance costs 9 177.7 160.3 329.6
Operating cash flow before working capital movements 614.4 451.8 1,061.7
Decrease/ (Increase) in trade and other receivables 33.0 (184.8) (36.3)
(Increase)/ Decrease in inventories (70.9) 49.0 66.6
(Decrease)/ Increase in trade payables (37.6) 61.3 58.7
Cash generated from operating activities 538.9 377.3 1,150.7
Income taxes paid (307.5) (165.3) (274.5)
Net cash from operating activities 231.4 212.0 876.2
Cash flows from investing activities
Proceeds from disposals - - 0.7
Purchase of intangible exploration and evaluation assets (12.8) (14.4) (30.2)
Purchase of property, plant and equipment (139.5) (134.9) (262.3)
Acquisition of additional interests in a joint operation 13 (8.1) - -
Interest received 10.2 13.2 23.3
Net cash used in investing activities (150.2) (136.1) (268.5)
Cash flows from financing activities
Debt arrangement fees - - (5.0)
Repayment of borrowings (100.0) (200.0) (432.2)
Drawdown of borrowings - - 129.7
Payment of obligations under leases (93.9) (90.1) (195.0)
Finance costs paid (116.3) (125.0) (240.0)
Net cash used in financing activities (310.2) (415.1) (742.5)
Net (decrease)/ increase in cash and cash equivalents (229.0) (339.2) (134.8)
Cash and cash equivalents at beginning of period 499.0 636.3 636.3
Foreign exchange gain/(loss) 2.6 (2.5) (2.5)
Cash and cash equivalents at end of period 272.6 294.6 499.0
Notes to the financial statements
Six months ended 30 June 2024
1. General information
The condensed financial statements for the six-month period ended 30 June 2024
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 2023, 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 2023 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 2023, 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 Guidance and Transparency Rules of the
United Kingdom's Financial Conduct Authority (DTR) and the Transparency
(Directive 2004/109/EC) Regulations 2007 as amended.
The accounting policies adopted in the 2024 half-yearly financial report other
than for Goodwill, described below, are the same as those adopted in the
Group's Annual Report and Accounts as at 31 December 2023.
Goodwill
The Group allocates goodwill to cash-generating units (CGUs) that represent
the assets acquired as part of the business combination. Goodwill is tested
for impairment annually as at 31 December and when circumstances indicate that
the carrying value may be impaired. Impairment is determined for goodwill by
assessing the recoverable amount of each CGU (or group of CGUs) to which
goodwill relates. When the recoverable amount of the CGU is less than it's
carrying amount, an impairment loss is recognised. Impairment losses relating
to goodwill cannot be reversed in future periods.
Going Concern
The Directors consider the going concern assessment period to be up to 31
August 2025. 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: $82/bbl for 2024, $78/bbl for 2025; and
Low Case: $70/bbl for 2024, $70/bbl for 2025.
The Low Case includes, amongst other downside assumptions, a 10% production
decrease and 10% increased operating costs compared to the Base Case.
Management has also considered additional outflows in respect of all ongoing
litigations/arbitrations within the Low Case, with an additional $111 million
outflow being included for the cases expected to progress in the period under
assessment. The Low Case does not include the outflow for the full exposure on
Ghana BPRT arbitration of $320 million (refer to note 10 Ghana tax assessments
for details). The remaining arbitration cases are not expected to conclude
within the going concern period and no outflows have been included in that
respect.
At 30 June 2024, 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, maturing in December 2024.
The Group or its affiliates may, at any time and from time to time, seek to
refinance, retire or purchase any or all of its outstanding debt through new
debt financings and/or cash purchases, in open-market purchases, privately
negotiated transactions or otherwise. Such refinancing or repurchases, if any,
will be upon such terms and at such prices as management may determine, and
will depend on prevailing market conditions, liquidity requirements and other
factors.
2. Accounting policies continued
Going concern continued
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. The Directors have
also performed a reverse stress test to establish the average oil price
throughout the going concern period required to reduce headroom to zero, that
price was determined to be $20/bbl. 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 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 $196.0
million (1H 2023: profit of $70.1 million) and a weighted average number of
shares in issue of 1,455.5 million (1H 2023: 1,444.0 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 66.1 million resulting in a diluted
weighted average number of shares of 1,521.6 million (1H 2023: 1,492.4
million).
4. Dividends
The Directors intend to recommend that no 2024 interim dividend be paid.
5. Approval of Accounts
These unaudited half year results were approved by the Board of Directors on 6
August 2024.
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 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 2024, 30 June 2023 and 31 December 2023.
$m Ghana Non-Operated Kenya Exploration Corporate Total
Six months ended 30 June 2024
Sales revenue by origin 703.0 113.7 - - (57.9) 758.8
Segment result(1) 446.2 80.0 - (2.2) (65.8) 458.2
Other provisions 39.4
Unallocated corporate expenses(2) (30.9)
Asset revaluation 38.9
Operating profit 505.6
Loss on hedging instruments -
Gain on bond buyback -
Finance income 39.7
Finance costs (177.7)
Profit before tax 367.6
Income tax expense (171.6)
Profit after tax 196.0
Total assets 3,346.3 341.7 255.8 50.7 216.9 4,211.4
Total liabilities(3) (1,981.8) (287.2) (7.2) (1.8) (2,090.0) (4,368.0)
Other segment information
Capital expenditure:
Property, plant and equipment 90.0 113.7 (0.4) - 2.4 205.7
Intangible exploration and evaluation assets 0.1 2.4 3.9 5.3 - 11.7
Depletion, depreciation and amortization (181.0) (17.4) - - (1.3) (199.7)
Impairment of property, plant and equipment, net - 1.7 - - - 1.7
Exploration costs written off - (0.8) - (2.2) (0.1) (3.1)
1. Segment result is a non IFRS measure which includes
gross profit, exploration costs written off, impairment of property, plant and
equipment. See reconciliation below.
2. Unallocated expenditure and includes amounts of a
corporate nature and not specifically attributable to a geographic area.
3. Total liabilities - Corporate comprise the Group's
external debt and other non-attributable liabilities.
6. Segmental reporting continued
Reconciliation of segment result
$m Six months ended 30.06.24 Unaudited Six months ended 30.06.23 Unaudited Year ended 31.12.23 Audited
Segment result 458.2 308.0 329.8
Add back
Exploration costs written off 3.1 10.1 27.0
Impairment of Property, Plant and Equipment (1.7) 33.2 408.1
Gross profit 459.6 351.3 764.9
$m Ghana Non-Operated Kenya Exploration Corporate Total
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 provisions (1.3)
Gain on bargain purchase -
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, impairment of property, plant and
equipment. See reconciliation above.
2. Unallocated expenditure includes amounts of a
corporate nature and not specifically attributable to a geographic area.
3. Total liabilities - Corporate comprise the Group's
external debt and other non-attributable liabilities.
4.
6. Segmental reporting continued
$m Ghana Non-Operated Kenya Exploration Corporate Total
Year ended 31 December 2023
Sales revenue by origin 1,311.4 461.8 - - (139.1) 1,634.1
Segment result(1) 408.2 114.0 (17.9) (9.9) (164.6) 329.8
Other provisions 22.0
Gain on bargain purchase _
Other gains 0.2
Unallocated corporate expenses(2) (56.1)
Operating profit 295.9
Loss on hedging instruments (0.4)
Gain on bond buyback 86.0
Finance income 44.0
Finance costs (329.6)
Profit before tax 95.9
Income tax expense (205.5)
Profit after tax (109.6)
Total assets 3,529.7 200.9 253.3 48.5 426.2 4,458.6
Total liabilities(3) (2,231.6) (355.1) (10.3) (2.9) (2,218.1) (4,818.0)
Other segment information
Capital expenditure:
Property, plant and equipment 413.7 85.9 (2.2) - 2.1 499.5
Intangible exploration and evaluation assets 0.2 1.6 7.5 16.1 - 25.4
Depletion, depreciation and amortisation (387.7) (44.1) 0.6 - (5.4) (436.6)
Impairment of property, plant and equipment, net (301.2) (97.9) - - (9.0) (408.1)
Exploration costs written off (0.2) 0.9 (17.9) (9.8) - (27.0)
( )
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 above.
2. Unallocated expenditure includes 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.
4.
6. Segmental reporting continued
$m Sales revenue six months ended 30.06.24 Sales revenue six months ended 30.06.23( ) Sales revenue Year ended 31.12.23 Non-current assets 30.06.24(1) Non-current assets 30.06.23(1) Non-current assets 31.12.23(1)
Ghana 703.0 579.4 1,311.4 2,618.9 2,848.5 2,771.0
Total Ghana 703.0 579.4 1,311.4 2,618.9 2,848.5 2,771.0
Kenya - - - 254.4 253.8 250.0
Total Kenya - - - 254.4 253.8 250.0
Argentina - - - 37.8 35.1 36.4
Côte d'Ivoire - - - 7.3 4.7 5.8
Total Exploration - - - 45.1 39.8 42.2
Gabon 93.4 242.1 419.5 227.7 126.9 82.8
Côte d'Ivoire 20.3 21.3 42.3 - 57.7 0.4
Total Non-Operated 113.7 263.4 461.8 227.7 184.6 83.2
Corporate (57.9) (65.9) (139.1) 13.0 22.0 12.0
Total 758.8 776.9 1,634.1 3,159.1 3,348.7 3,158.4
1. Excludes derivative financial instruments and
deferred tax assets.
7. Total revenue
$m Six months ended 30.06.24 Unaudited Six months ended 30.06.23 Unaudited Year ended 31.12.23 Audited
Revenue from contracts with customers
Revenue from crude oil sales 788.1 837.9 1,744.6
Revenue from gas sales 28.6 4.9 28.6
Total revenue from contracts with customers 816.7 842.8 1,773.2
Loss on realisation of cash flow hedges (57.9) (65.9) (139.1)
Total revenue 758.8 776.9 1,634.1
Finance income has been presented as part of net financing costs (refer to
note 9).
8. Other costs
$m Six months ended 30.06.24 Unaudited Six months ended 30.06.23 Unaudited Year ended 31.12.23 Audited
Cost of sales
Operating costs 124.7 136.4 292.9
Depletion and amortisation of oil and gas and leased assets(1) 198.0 163.2 430.8
(Underlift), overlift and oil stock movements(2) (39.2) 108.9 109.3
Royalties 15.7 16.3 33.9
Share-based payment charge included in cost of sales - - 0.4
Other cost of sales - 0.8 1.9
Total cost of sales 299.2 425.6 869.2
Administrative expenses
Share-based payment charge included in administrative expenses 2.0 1.1 5.6
Depreciation of other fixed assets(1) 1.7 3.9 5.8
Other administrative costs 27.2 14.1 44.7
Total administrative expenses(3) 30.9 19.1 56.1
Provisions reversal(4) (39.4) - (22.0)
1. Depreciation expense on leased assets of $42.4
million as per note 12 includes a charge of $0.7 million on leased
administrative assets, which is presented within administrative expenses in
the income statement. The remaining balance of $41.7 million relates to other
leased assets and is included within cost of sales.
2. Refer to Page 5 of Finance Review and Note 16 for
detailed explanations.
3. The increase in other administrative costs is
mainly due to one-off redundancy costs, payroll costs and phasing of costs.
4. A previously recognised provision of $39.4 million
relating to a potential claim arising out of historical contractual agreements
has been released in the current period as no claim was raised.
9. Net financing costs
$m Six months ended 30.06.24 Unaudited Six months ended 30.06.23 Unaudited Year ended 31.12.23 Audited
Interest on borrowings 108.0 122.7 237.0
Interest on obligations for leases 62.0 32.1 78.6
Total borrowing costs 170.0 154.8 315.6
Finance and arrangement fees 0.6 0.1 1.9
Other interest expense 1.3 0.4 2.0
Unwinding of discount on decommissioning provisions 5.8 5.0 10.1
Total finance costs 177.7 160.3 329.6
Interest income on amounts due from Joint Venture partners for leases (24.6) (12.0) (30.1)
Other finance income (15.1) (13.0) (13.9)
Total finance income (39.7) (25.0) (44.0)
Net financing costs 138.0 135.3 285.6
10. Taxation on profit on continuing activities
The overall net tax expense of $171.3 million (1H 2023: $147 million)
primarily relates to tax charges in respect of the Group's production
activities in West Africa, reduced by deferred tax credits associated with UK
decommissioning assets, 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 2024.
Based on a profit before tax for the first half of the year of $368 million
(1H 2023: $217 million), the effective tax rate is 46.7% (1H 2023: 67.7%).
After adjusting for the non-recurring amounts related to exploration
write-offs, impairments, disposals and their associated tax benefit, the
Group's underlying effective tax rate is 51.7% (1H 2023: 56.2%). In the UK
there is net interest and hedging expenses of $123million (1H 2023: $80
million), however there is no UK tax benefit as in previous periods.
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 these claims, the result would be additional unprovided liabilities of
$1,037.7 million (1H 2023: $989.4 million; FY23: $1,030.3 million) which
includes $6.4 million of interest and penalties (1H 2023: $11.5million; FY23:
$6.9million).
Provisions of $86.2million (1H 2023: $99.4 million; FY23: $85.0 million) are
included in income tax payable ($78.7 million (1H 2023: $71.0 million; FY23:
$78.3million)) and provisions $7.5million (1H 2023: $28.4 million; FY23:
$6.7million)). 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 increase in provision of $1.2 million and increase in
contingent liability of $7.4million from 31 December 2023.
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 was held in October 2023, with a second hearing
held in June 2024 and a decision from the panel is expected in the second half
of the year.
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. The parties have agreed a procedural
timetable for the arbitration under which the first Tribunal hearing will be
held in July 2025.
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 parties have agreed a procedural timetable for the
arbitration under which the first Tribunal hearing will be held in November
2025.
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 continuing 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
and a hearing of the merits of the case were heard by the Tribunal on 20 May
2024. Further written submissions are expected to be made to the Tribunal by
both parties during 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
$m Six months ended 30.06.24 Unaudited Six months ended 30.06.23 Unaudited Year ended 31.12.23 Audited
At 1 January 287.0 288.6 288.6
Additions 10.7 7.9 25.4
Acquisitions of additional interest in joint operation 1.0 - -
Exploration costs written off (3.1) (10.1) (27.0)
At 30 June/31 December 295.6 286.4 287.0
The below table provides a summary of the exploration costs written off on a
pre-tax basis by country.
Country CGU Rationale for write-off six months ended 30.06.24 Write-off 30.06.24 Unaudited $m Remaining recoverable amount 30.06.24 Unaudited $m
Côte d'Ivoire Block 524 a 1.5 -
New Ventures Various b 0.8 -
Uganda Exploration areas 1, 1A, 2 and 3A c 0.8 -
Total write-off 3.1 -
a. Current year expenditure on assets previously written off
b. New Ventures expenditure is written off as incurred
c. Write-off of indirect tax receivable
Kenya:
Discussions with the Government of Kenya (GoK) on securing government
deliverables and approval of the Field Development Plan (FDP) have been
ongoing since its submission on 10 December 2021. An updated FDP was submitted
on 3 March 2023 and is being reviewed by the GoK before ratification by the
Kenyan Parliament. Since 1 January 2024, the review period for the FDP was
extended to 31 December 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. Pending GoK approval, per the terms of
the agreement, the participating interest (PI) vests in trust for the sole and
exclusive benefit of Tullow, who is the only remaining Joint Venture Partner.
11. Intangible exploration and evaluation assets continued
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 50% ownership 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 PI and is liable for all costs
incurred going forward (except those for which the withdrawing parties remain
liable for). As the sole party, Tullow can control and direct the use of the
asset from 30 June 2023. The position remained unchanged as at 30 June 2024.
Tullow accounted for this as asset acquisition at nil cost. An impairment
assessment was performed at 31 December 2023, following the withdrawal of the
partners and upward revision of oil prices which were identified as impairment
assessment triggers. This resulted in an NPV significantly in excess of the
book value. However, the Group has identified the following uncertainties in
respect of the Group's ability to realise the estimated Value in Use (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 in form of provision of
required infrastructure and fiscal terms. These items require satisfactory
resolution before the Group can take a Final Investment Decision (FID).
Due to the binary nature of these uncertainties, the Group was unable to
either adjust the cash flows or discount rate appropriately. It therefore used
its judgement to determine a risk-adjusted VIU to compare against the net book
value of the asset which resulted in an impairment of $17.9 million being
recognised as at 31 December 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.
At 30 June 2024, the uncertainties outlined have remained largely unchanged
and no material modifications have occurred in the development. Therefore, no
trigger for impairment or impairment reversal was identified.
Country CGU Rationale for write-off/(back) Write-off/(back) 30.06.23 Unaudited $m Remaining recoverable amount 30.06.23 Unaudited $m
six months ended 30.06.23
Guyana Kanuku and Orinduik a, b 1.6 -
Côte d'Ivoire Block 524 b 2.0 -
Kenya Blocks 10BB and 13T c 9.1 246.7
New Ventures Various d 2.1 -
Uganda Exploration areas 1, 1A, 2 and 3A e (4.9) -
Other Various a, b 0.2 -
Total write-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
Country CGU Rationale for write-off/(back) Write-off/ (back) 31.12.23 Audited Remaining recoverable amount 31.12.23
year ended 31.12.23
$m
Audited
$m
Guyana Kanuku a 1.7 -
Guyana Orinduik a 0.7 -
Côte d'Ivoire Block 524 a 3.3 -
Kenya Blocks 10BB and 13T b, c 17.9 242.2
New Ventures Various d 4.1 -
Uganda Exploration areas 1, 1A, 2 and 3A e (4.3) -
Gabon DE8 f 3.4 -
Other Various 0.2 -
Total write-off 27.0 -
a. Current year expenditure on assets previously written off
b. Following VIU assessment subsequent to withdrawal of JV partners
c. Revision of short, medium and long-term oil price assumptions
d. New Ventures expenditure is written off as incurred
e. Release of indirect tax provision following settlement
f. Unsuccessful well costs written off
12. Property, plant and equipment
$m Oil and gas assets Right of use Other fixed assets Total 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
Year
six months ended
six months
six months ended six months
six months
six months Year
Year
ended
ended
Year ended
30.06.24 ended
30.06.24 ended ended
ended ended
ended 31.12.23
30.06.24
30.06.23
ended 31.12.23
Unaudited 30.06.24
Unaudited 30.06.23 30.06.23
30.06.23 31.12.23
Audited
Unaudited
Unaudited
31.12.23 Audited
Unaudited Unaudited Unaudited Unaudited Audited
Audited
Cost
At 1 January 11,282.1 1,268.8 21.9 12,572.8 11,182.6 1,196.8 30.0 12,409.4 11,182.6 1,196.8 30.0 12,409.4
Additions 104.5 1.2 2.6 108.3 249.9 - 0.6 250.5 416.1 81.1 2.3 499.5
Acquisition of additional interest in joint operation 97.4 - - 97.4 - - - - - - - -
Transfer to assets held for sale - - - - - - - - (302.8) - - (302.8)
Asset retirement - (138.3) - (138.3) - - - - (67.7) (10.6) (11.0) (89.3)
Currency translation adjustments (7.9) (0.2) (0.1) (8.2) 47.2 1.3 0.6 49.1 53.9 1.5 0.6 56.0
At 30 June/31 December 11,476.1 1,131.5 24.4 12,632.0 11,479.7 1,198.1 31.2 12,709.0 11,282.1 1,268.8 21.9 12,572.8
Depreciation, depletion and amortization and impairment
At 1 January (9,377.7) (644.8) (17.5) (10,040.0) (8,888.4) (515.2) (24.4) (9,428.0) (8,888.4) (515.2) (24.4) (9,428.0)
Charge for the year (156.3) (42.4) (1.0) (199.7) (135.2) (30.0) (1.9) (167.1) (351.6) (81.4) (3.6) (436.6)
Impairment reversal/(loss) 1.7 - - 1.7 (33.2) - - (33.2) (399.1) (9.0) - (408.1)
Capitalised depreciation - (25.4) - (25.4) - (24.5) - (24.5) - (49.3) - (49.3)
Transfer to assets held for sale - - - - - - - - 247.6 - - 247.6
Asset retirement - 138.3 - 138.3 - - - - 67.7 10.6 11.0 89.3
Currency translation adjustments 7.9 0.2 0.1 8.2 (47.2) (0.4) (0.4) (48.0) (53.9) (0.5) (0.5) (54.9)
At 30 June/31 December (9,524.4) (574.1) (18.4) (10,116.9) (9,104.0) (570.1) (26.7) (9,700.8) (9,377.7) (644.8) (17.5) (10,040.0)
Net book value at 30 June/31 December 1,951.7 557.4 6.0 2,515.1 2,375.7 628.0 4.5 3,008.2 1,904.4 624.0 4.4 2,532.8
12. Property, plant and equipment continued
Trigger for impairment/(reversal) Impairment/ (reversal) 30.06.24 30.06.24 Remaining recoverable amount
six months ended 30.06.24 Unaudited Unaudited
$m $m
Espoir (Cote D'Ivoire) a (4.0) -
UK 'CGU'(1) b 2.3 -
Impairment (1.7) -
1. The fields in the UK are grouped into one CGU as
all fields share critical gas infrastructure.
a. Change to decommissioning discount rate.
b. Change to decommissioning estimate
Trigger for impairment six months ended 30.06.23 Impairment 30.06.23 Remaining recoverable amount
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/ (reversal) year ended 31.12.23 Impairment/ (reversal) 31.12.23 Remaining recoverable amount(2)
31.12.23 Pre-tax discount rate assumption Audited
Audited) $m
$m
Espoir (Cote d'Ivoire) a,c 53.5 14% 0.4
TEN (Ghana) b,c 301.2 14% 528.3
Mauritania d 27.9 n/a -
UK 'CGU'(1) d,e 16.5 n/a -
UK Corporate f 9.0 n/a -
Impairment 408.1
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. Increase in production and development costs.
b. Revision of value based on revisions to reserves.
c. Revision of short, medium and long-term oil price
assumptions.
d. Change to decommissioning estimate.
e. The fields in the UK are grouped into one CGU as
all fields within those countries share critical gas infrastructure.
f. Fully impaired right-of-use asset relating to a vacant office space.
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 2024 $82/bbl $78/bbl $75/bbl $75/bbl $75/bbl $75/bbl inflated at 2%
FY 2023 $78/bbl $75/bbl $75/bbl $75/bbl $75/bbl $75/bbl inflated at 2%
*At 1H 2024 there were no impairment assessments carried out as no triggers
were identified.
13. Business combination
On 29 February 2024 the Group completed the Asset Swap agreement (ASA)
transaction with Perenco Oil and Gas Gabon S.A ("Perenco"). The rationale for
the Transaction is the simplification of the Group's equity ownership across
key fields in Gabon, creating better alignment between the participating
interest partners and streamlining processes such as budgeting, cost
management and capital allocation. The revised portfolio of assets will enable
Tullow to leverage its technical skills and focus on more material positions
in key fields.
The transaction is an asset swap achieved through the exchange of
participating interests held by both parties in certain licences in Gabon. The
exchange represents the acquisition of an additional interest in a joint
operation that constitutes a business and therefore IFRS 11 requires the
application of the principles in IFRS 3 relating to business combinations.
In line with the requirements of IFRS 3, the interests transferred as part of
the consideration, which comprises mainly of Property, Plant, and Equipment of
$54.4 million, have been remeasured to the acquisition date fair value of
$93.3 million. This has resulted in an asset revaluation gain of $38.9 million
recognised in the income statement at 30 June 2024.
The below table shows the pre completion and post completion equities in the
licences subject to the transaction:
Field Pre-completion Post-completion
Kowe (Tchatamba) Acquisition 25.0% 40.0%
DE8 Acquisition 20.0% 40.0%
Simba Disposal 57.5% 40.0%
Limande Disposal 40.0% 0%
Turnix Disposal 27.5% 0%
Moba Disposal 24.3% 0%
Oba Disposal 10.0% 0%
The exchange of the transferred interests between the parties was deemed for
all purposes to be made with effect from the economic date of 1 February 2023
but completed on 29 February 2024 and this is therefore the acquisition date.
The transaction was intended to be cash neutral on the economic date as the
fair value of the assets exchanged were considered to be equal at that time
and therefore no additional consideration would have been payable by either
party at that time. However, as the transaction completed more than a year
later, the ASA included provisions to ensure the neutrality of the transaction
via cash adjustments for the period between the economic date and the
completion date, the agreed adjustment upon completion was $8.1 million which
has been included within investing activities in the cash flow statement.
The fair values of the identifiable assets and liabilities acquired were:
Fair value recognised on
acquisition
$m
Intangible assets 1.0
Property, plant and equipment 97.4
Other current assets 0.7
Goodwill 44.9
Total assets acquired 144.0
Trade and other payables -
Provisions (5.8)
Deferred tax liabilities (44.9)
Total liabilities assumed (50.7)
Net identifiable assets acquired 93.3
Total purchase consideration (93.3)
Consideration satisfied by exchange of assets (85.2)
Consideration satisfied by cash (8.1)
Purchase of O&G Assets per the cash flow statement (8.1)
13. Business combination continued
Valuation methodology and assumptions
The fair value of the purchase consideration of $93.3 million reflects the
discounted future cash flows of the assets and liabilities exchanged as part
of the swap as the transaction is intended to be value neutral. Provisions
represent the present value of decommissioning costs which are expected to be
incurred after the end of the licence in 2046.
Goodwill of $44.9 million was recognised upon acquisition due to the
requirement of IAS 12 to recognise a deferred tax liability or asset for the
difference between the fair value of the assets acquired and liabilities
assumed, and their respective tax bases. Therefore, goodwill has arisen as a
direct result of the recognition of the deferred tax liability. None of the
goodwill is deductible for income tax purposes.
The disclosure requirement of IFRS 3 in relation to contributions to revenue
and profit or loss have not been included as they are impracticable to obtain
due to Tullow not being the operator of the assets.
No material acquisition-related costs were incurred in relation to the
transaction.
14. 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 2024 of $91.6 million (1H 2023:
$164.0 million; FY 2023: $43.5 million) relates to June 2024 gross gas sales
in Ghana ($75.4m) and oil liftings in Gabon ($11.7m) and Cote D'Ivoire
($4.5m).
15. Other assets
$m 30.06.24 Unaudited 30.06.23 Unaudited 31.12.23 Audited
Non-current
Amounts due from joint venture partners 296.5 50.6 332.5
VAT recoverable 7.0 3.5 6.1
303.5 54.1 338.6
Current
Amounts due from joint venture partners 440.7 769.4 498.1
Underlifts 11.1 20.7 47.8
Prepayments 21.4 27.1 21.1
Other current assets 2.9 5.3 4.2
476.1 822.5 571.2
779.6 876.6 909.8
The movement between current and non-current amounts due from joint venture
partners is mainly driven by the receivables relating to the TEN FPSO lease
and loan balances in Ghana.
Underlifts of $11.1 million as at 30 June 2024 are due to the timing of
liftings and are mainly attributable to the Jubilee field in Ghana.
16. Inventories
$m 30.06.24 Unaudited 30.06.23 Unaudited 31.12.23 Audited
Warehouse stock and materials 67.3 65.5 71.5
Oil stock 110.8 59.4 35.8
178.1 124.9 107.3
The increase in oil stock from 31 December 2023 is driven by an increase in
Gabon of $39.0 million due to timing of liftings and a $32.1m stock increase
in Ghana.
17. Cash and cash equivalents
$m 30.06.24 Unaudited 30.06.23 Unaudited 31.12.23 Audited
Cash at bank 100.4 96.4 114.9
Short- term deposits and other cash equivalents 172.2 198.2 384.1
272.6 294.6 499.0
Short- term deposits and other cash equivalents include an amount of $59.1
million (1H 2023: $53.1 million; FY 2023: $36.9 million) which the Group holds
as operator in joint venture bank accounts. Included within cash at bank is
$8.9 million (1H 2023: $4.5 million; FY 2023: $4.5 million) of restricted cash
held as collateral for performance bonds issued in relation to exploration
activities.
18. Trade and other payables
$m 30.06.24 Unaudited 30.06.23 Unaudited 31.12.23 Audited
Current
Trade payables 58.2 65.1 22.3
Other payables 78.7 56.8 65.3
Overlifts 3.3 - 3.1
Accruals 380.1 461.9 498.6
Current portion of leases 146.7 826.2 185.7
667.0 1,410.0 775.0
Non-current
Other non-current liabilities 57.4 46.2 62.2
Non-current portion of leases 655.5 38.3 721.0
712.9 84.5 783.2
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). In 2H 2023, a decision was made to not exercise the option
to purchase the TEN FPSO in April 2024, and the lease accounting assumptions
were updated to reflect the best estimate view that the FPSO will continue to
be leased until cessation of production in 2032.
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 15). The change in
trade payables and in other payables predominantly represents timing
differences and levels of work activity.
19. Borrowings
$m 30.06.24 Unaudited 30.06.23 Unaudited 31.12.23 Audited
Current
Borrowings - within one year
7.00% Senior Notes due 2025 489.2 - -
10.25% Senior Notes due 2026 100.0 100.0 100.0
Carrying value of total current borrowings 589.2 100.0 100.0
Non-current
Borrowings - after one year but within five years
7.00% Senior Notes due 2025 - 628.3 489.0
10.25% Senior Notes due 2026 1,272.9 1,482.2 1,371.0
Secured Notes Facility due 2028 117.4 - 124.6
Carrying value of total non-current borrowings 1,390.3 2,110.5 1,984.6
Carrying value of total borrowings 1,979.5 2,210.5 2,084.6
The Group's capital structure includes $1.4 billion senior secured notes due
in May 2026 (2026 Notes), $0.5 billion senior notes due in March 2025 (2025
Notes), a $0.4 billion Secured Notes Facility and an undrawn $500 million
Super Senior Revolving Credit Facility (SSRCF) which will primarily be used
for working capital purposes. The 2026 Notes 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 2024, the Group made the annual prepayment of $100 million of the
2026 Notes.
The 2025 Notes are due in a single payment in March 2025.
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 2024. Letters of
credit amounting to $4 million (FY 2023: $10 million) have been issued under
the facility.
Unamortised debt arrangement fees for the 2026 Notes, 2025 Notes, Secured
Notes Facility and the SSRCF are $12.3 million (FY 2023: $14.3 million), $3.3
million (FY 2023: $3.6 million), $12.2 million (FY 2023: $5.0) and $1.0
million (FY 2023: $2.3 million) respectively.
The 2026 Notes, the Secured Notes Facility 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. The Group is not subject to any externally imposed capital
requirements. To maintain or adjust the capital structure, management may put
in place new debt facilities, issue new shares for cash, repay debt, engage in
active portfolio management, adjust the dividend payment to shareholders, or
undertake such other restructuring activities as appropriate. 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.
19. Borrowings continued
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.
The Group or its affiliates may, at any time and from time to time, seek to
refinance, retire or purchase any or all of its outstanding debt through new
debt refinancings and/or cash purchases, in open-market purchases, privately
negotiated transactions or otherwise. Such refinancings or repurchases, if
any, will be upon such terms and at such prices as management may determine,
and will depend on prevailing market conditions, liquidity requirements and
other factors.
Secured Notes Facility covenants
The Secured Notes Facility does not have any financial maintenance covenants.
The facility is subject to substantially the same covenants as the 2026 Notes,
with additional restrictions related to the use of proceeds from any
incurrence of new indebtedness ranking senior to the facility or sharing the
same collateral.
Tullow is permitted to refinance the SSRCF and the 2026 Notes on a
like-for-like basis.
Tullow is permitted to refinance the 2025 Notes with new indebtedness which is
unsecured and ranks junior to the Secured Notes Facility.
20. Provisions
$m Decommissioning Other provisions 30.06.24 Unaudited Total Decommissioning Other provisions 30.06.23 Unaudited Total 30.06.23 Unaudited Decommissioning Other provisions 31.12.23 Audited Total 31.12.23 Audited
30.06.24 Unaudited
30.06.24 Unaudited
30.06.23 Unaudited
31.12.23
Audited
At 1 January 377.9 93.7 471.6 398.1 116.3 514.4 398.1 116.3 514.4
New provisions, changes in estimates and reclassifications (23.0) (39.9) (62.9) 42.0 (1.4) 40.6 47.8 (21.9) 25.9
Acquisitions 5.8 - 5.8 - - - - - -
Transfer to assets and liabilities held for sale - - - - - - (14.2) - (14.2)
Payments (9.0) (0.6) (9.6) (43.8) (0.6) (44.4) (66.4) (0.6) (67.0)
Unwinding of discount 5.8 - 5.8 5.0 - 5.0 10.1 - 10.1
Currency translation adjustment (0.2) - (0.2) 2.4 (0.2) 2.2 2.5 (0.1) 2.4
At 30 June/31 December 357.3 53.2 410.5 403.7 114.1 517.8 377.9 93.7 471.6
Current provisions 69.0 13.3 82.3 36.2 13.0 49.2 53.4 14.5 67.9
Non-current provisions 288.3 39.9 328.2 367.5 101.1 468.6 324.5 79.2 403.7
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 included a provision relating to a potential
claim arising out of historical contractual agreements, this provision has
been released in the current period as no claim arose in respect of the
agreement.
The decommissioning provision represents the present value of decommissioning
costs relating to the European and African oil and gas interests. 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.
In 2024, the discount rate applied to the decommissioning provisions increased
to 4.5% driven by an increase in the 10- and 20-year US Treasury Bills' rates.
This resulted in an overall decrease in decommissioning provisions.
21. Called up share capital and share premium
As at 30 June 2024, the Group had in issue 1,458.0 million allotted and fully
paid ordinary shares of GBP 10 pence each (1H 23: 1,448.3 million, FY 2023:
1,452.5million).
In the six months ended 30 June 2024, the Group issued 5.5 million shares in
respect of employee share options (1H 23: 8.7 million; FY 2023: 12.9 million
new shares in respect of employee share options).
22. Contingent Liabilities
$m 30.06.24 Unaudited 30.06.23 Unaudited 31.12.23 Audited
Contingent liabilities
Performance guarantees(1) 28.1 63.3 42.7
Other contingent liabilities(2) 83.1 55.8 84.4
111.2 119.1 127.1
1. Performance guarantees are in respect of
abandonment obligations, committed work programmes and certain financial
obligations.
2. Other contingent liabilities include amounts for
ongoing legal disputes with third parties where we consider the likelihood of
cash outflow to be higher than remote but not probable. The timing of any
economic outflow if it were to occur would likely range between one and five
years.
23. Events since 30 June 2024
There have not been any events since 30 June 2024 that have resulted in a
material impact on the interim results.
24. Cash flow statement reconciliations
Movement in borrowings ($m) 1H24 FY23 1H23 FY22 1H24 Movement 1H23 Movement 2023 Movement
Borrowings 1,979.5 2,084.6 2,210.5 2,472.8 (105.1) (262.3) (388.2)
Associated cash flows
Debt arrangement fees - - (5.0)
Repayment of borrowings(1) (100.0) (200.0) (432.2)
Drawdown of borrowings - - 129.7
Non-cash movements/presented in other cash flow lines
Gain on bond buyback(1) - (65.2) (86.0)
Amortisation of arrangement fees and accrued interest (5.1) 2.9 5.3
Alternative performance measures
The Group uses certain measures of performance that 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 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, capitalised share-based payment
charge, capitalised finance costs, additions to administrative assets,
Norwegian tax refund and certain other adjustments. The Directors believe that
capital investment is a useful indicator of the Group's organic expenditure on
exploration and evaluation assets and oil and gas assets incurred during a
period because it eliminates certain accounting adjustments such as
capitalised finance costs and decommissioning asset additions.
$m 1H 2024 1H 2023
Additions to property, plant and equipment 201.9 249.9
Additions to intangible exploration and evaluation assets 11.7 7.9
Less
Decommissioning asset adjustments (23) 42.0
Right-of-use asset additions 1.2 -
Lease payments related to capital activities (21.9) (26.3)
Additions to administrative assets 2.6 0.6
Other non-cash capital expenditure 98.1 54.6
Capital investment 156.6 186.9
Movement in working capital 1.2 (38.2)
Additions to administrative assets 2.6 0.6
Cash capital expenditure per the cash flow statement 160.4 149.3
Net debt
Net debt is a useful indicator of the Group's indebtedness, financial
flexibility and capital structure because it indicates the level of cash
borrowings after taking account of cash and cash equivalents within the
Group's business that could be utilised to pay down the outstanding cash
borrowings. Net debt is defined as current and non-current borrowings plus
non-cash adjustments, less cash and cash equivalents. Non-cash adjustments
include unamortised arrangement fees, adjustment to convertible bonds, and
other adjustments. The Group's definition of net debt does not include the
Group's leases as the Group's focus is the management of cash borrowings and a
lease is viewed as deferred capital investment. The value of the Group's lease
liabilities as at 30 June 2024 was $146.7 million current and $655.5 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.
$m 1H 2024 1H 2023
Current borrowings 589.2 100.0
Non-current borrowings 1,390.3 2,110.5
Non-cash adjustments(1) 28.0 22.1
Less cash and cash equivalents(2) (272.6) (294.6)
Net debt 1,734.9 1,938.0
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 $59
million (1H 2023: $53.1 million) which the Group holds as operator in joint
venture bank accounts. Included within cash at bank is $9 million (1H 2023:
$4.5 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, asset revaluations, other gains
and losses, gain on bond buyback, exploration cost written off, impairment of
property, plant and equipment net, and provision for onerous contracts.
1H 2024 1H 2023
Adjusted EBITDAX(1) 1,281.8 1,171.4
Net debt 1,734.9 1,938.0
Gearing (times) 1.4 1.7
1. Last 12 months (LTM). Refer to the 2023 Annual
Report and Accounts and 2023 Half year results for a full reconciliation of
2023 and 1H 2023 Adjusted EBITDAX.
Underlying cash operating costs
Underlying cash operating costs is a useful indicator of the Group's costs
incurred to produce oil and gas. Underlying cash operating costs eliminates
certain non-cash accounting adjustments to the Group's cost of sales to
produce oil and gas. Underlying cash operating costs is defined as cost of
sales less operating lease expense, depletion and amortisation of oil and gas
assets, underlift, overlift and oil stock movements, share-based payment
charge included in cost of sales, royalties and certain other cost of sales.
Underlying cash operating costs are divided by production to determine
underlying cash operating costs per boe.
In 2024 and 2023, 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.
$m 1H 2024 1H 2023
Cost of sales 299.2 425.6
Add
Lease payments related to operating activity 6.6 7.2
Less
Depletion and amortisation of oil and gas and leased assets(1) 198.0 163.2
Underlift, (overlift) and oil stock movements(2) (39.2) 108.9
Royalties 15.7 16.3
Other cost of sales(3) 6.6 8.0
Underlying cash operating costs 124.7 136.4
Non-recurring costs(4) (4.8) (15.6)
Total normalised cash operating costs 119.9 120.8
Production (MMboe) 11.6 11.0
Underlying cash operating costs per boe ($/boe) 10.8 12.4
Normalised cash operating costs per boe ($/boe) 10.3 11.0
1. Depletion and amortisation of oil and gas assets is
the depreciation and amortisation of the Group's oil and gas assets over the
life of an asset on a unit of production basis.
2. Under lifting or offtake arrangements for oil and
gas produced in certain operations in which the Group has interests with other
commercial partners, each participant may not receive and sell its precise
share of the overall production in each period. The resulting imbalance
between cumulative entitlement and cumulative production less stock
constitutes "underlift" or "overlift". Underlift and overlift are valued at
market value and included within other current assets and other current
payables on the Group's balance sheet, respectively. Movements during an
accounting period are charged to cost of sales rather than charged through
revenue, and as a result gross profit is recognised on an entitlements basis.
3. Other cost of sales includes purchases of gas from
third parties to fulfil gas sales contracts and royalties paid in cash.
4. Non-recurring costs include O&M (Operations
& Maintenance) costs, facility projects costs, oil spill response, and
Refrigeration compressor motor repairs.
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 from/(used) in investing
activities, repayment of obligations under leases, finance costs paid and
foreign exchange gain/(loss).
$m 1H 2024 1H 2023
Net cash from operating activities 231.4 212.0
Net cash used in investing activities (150.2) (136.1)
Repayment of obligations under leases (93.9) (90.1)
Finance costs paid (116.3) (125.0)
Foreign exchange loss 2.6 (2.5)
Free cash flow (126.4) (141.7)
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 cash flow
This is a useful indicator of the Group's 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.
$m 1H 2024 1H 2023
Net cash from operating activities 231.4 212.0
Add
Decommissioning expenditure 9.9 40.0
Lease payments related to capital activities 21.9 26.3
Less
Repayment of obligations under leases (93.9) (90.1)
Underlying operating cash flow 169.3 188.2
Net cash used in investing activities (150.2) (136.1)
Decommissioning expenditure (9.9) (40.0)
Lease payments related to capital activities (21.9) (26.3)
Pre-financing free cash flow (12.7) (14.2)
Management Presentation - WEBCAST - 9:00 BST
To access the webcast please use the following link and follow the
instructions provided:
https://web.lumiconnect.com/141796088 (https://web.lumiconnect.com/141796088)
A replay will be available on the website from midday on 7 August 2024:
https://www.tullowoil.com/investors/results-reports-and-presentations/
(https://www.tullowoil.com/investors/results-reports-and-presentations/)
Contacts
Tullow Oil plc Camarco
(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 energy company that is building a better future
through responsible oil and gas development in Africa. The Company's
operations are focused on its West-African producing assets in Ghana, Gabon
and Côte d'Ivoire, alongside a material discovered resource base in Kenya.
Tullow is committed to becoming Net Zero on its Scope 1 and 2 emissions by
2030 and has a Shared Prosperity strategy that delivers lasting socio-economic
benefits for its host nations. The Group is quoted on the London and Ghana
stock exchanges (symbol: TLW). For further information, please refer to:
www.tullowoil.com.
Follow Tullow on:
Twitter: www.twitter.com/TullowOilplc (http://www.twitter.com/TullowOilplc)
LinkedIn: www.linkedin.com/company/Tullow-Oil
(http://www.linkedin.com/company/Tullow-Oil)
This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact
rns@lseg.com (mailto:rns@lseg.com)
or visit
www.rns.com (http://www.rns.com/)
.
RNS may use your IP address to confirm compliance with the terms and conditions, to analyse how you engage with the information contained in this communication, and to share such analysis on an anonymised basis with others as part of our commercial services. For further information about how RNS and the London Stock Exchange use the personal data you provide us, please see our
Privacy Policy (https://www.lseg.com/privacy-and-cookie-policy)
. END IR BRGDIGDGDGSLRecent news on Tullow Oil
See all newsREG - Tullow Oil PLC - Director/PDMR Shareholding
AnnouncementREG - Tullow Oil PLC - Holding(s) in Company
AnnouncementREG - Tullow Oil PLC - Heads of terms for sale of Kenyan assets for $120m
AnnouncementREG - Tullow Oil PLC - ANNUAL AND SUSTAINABILITY REPORT & NOTICE OF AGM
AnnouncementREG - Tullow Oil PLC - Director/PDMR Shareholding
Announcement