REG - Tullow Oil PLC - Full Year Results
06/03/2024 07:00
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RNS Number : 7198F Tullow Oil PLC 06 March 2024
Tullow oil PLC - 2023 FULL Year Results
Successful delivery of business plan
2023 free cash flow ahead of expectations and net debt reduction accelerated
Production growth expected in 2024
6 March 2024 - Tullow Oil plc ("Tullow"), the independent oil and gas
exploration and production group ("Group"), announces its Full Year Results
for the year ended 31 December 2023.
Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented today:
"2023 was a year of significant achievements, including start-up of Jubilee
South East that delivered material production growth from our core operated
field, a new revenue stream established from the sale of Ghana associated gas;
and reserves growth in Gabon through licence extensions. We also generated
free cash flow ahead of expectations despite a lower year-on-year realised oil
price and demonstrated our ability to access long-term capital through the
$400 million debt facility agreement with Glencore.
"In line with our strategy, we are continuing to focus relentlessly on
operational excellence, capital efficiency and investments to drive growth.
This strategy is delivering material cashflow generation and we are on track
to deliver our target of c.$800 million free cash flow over the 2023 to 2025
period and optimise our capital structure.
"Tullow has a strong and unique foundation to create material value for our
investors, host nations and stakeholders and we look to the future with
confidence."
2023 FULL YEAR Results Overview
· Group working interest oil and gas production 62.7 kboepd; (2022:
61.1 kboepd).
· Revenue of $1,634 million (2022: $1,783 million), a year-on-year
reduction driven by c.12% lower realised post-hedge oil price of $77.5/bbl
(2022: $88.0/bbl).
· Adjusted EBITDAX(1) of $1,151 million (2022: $1,469 million); gross
profit of $765 million (2022: $1,086 million); loss after tax of $110 million
(2022: profit after tax of $49 million) driven by impairments and write-offs
totalling $435 million (2022: $391 million).
· Free cash flow(1) of $170 million (2022: $267 million) ahead of
guidance despite increased capital expenditure of $380 million (2022: $354
million) and decommissioning spend of $67 million (2022: $72 million).
· Net debt(1) at year-end reduced to $1,608 million (2022: $1,864
million); cash gearing of net debt to adjusted EBITDAX(1) of 1.4 times (2022:
1.3 times); liquidity headroom of $1,000 million (2022: $1,055 million).
· Material step in refinancing strategy with new $400 million five-year
Glencore debt facility, with proceeds available for liability management of
the senior notes maturing in March 2025.
· Completed major infrastructure project with Jubilee South East
brought onstream, marking a material step up in production at Jubilee which
surpassed 100,000 bopd gross.
· Strong operating, drilling and completion performance, with seven
Jubilee wells brought onstream and facilities uptime of c.96% in Ghana.
· c.$30 million revenue from commercialisation of Jubilee associated
gas through Interim Gas Sales Agreement.
· Increased Gabon reserves and centred portfolio around Tchatamba
production hub through swap agreement and licence extensions.
· Sale and exit of Guyana business, in line with strategy to focus
portfolio on high-return assets in Africa.
2024 Guidance
· Production growth in 2024 with group working interest production
expected to average between 62 to 68 kboepd, including c.7 kboepd of gas.
· 2024 capital expenditure of c.$250 million, comprising c.$160 million
in Ghana, c.$60 milllion on the non-operated portfolio, c.$10 million in Kenya
and c.$20 on exploration. Decommissioning spend of c.$50 million for UK and
Mauritania; c.$20 million provisioning for Ghana and Gabon.
· Cash taxes expected to be c.$350 million at $80/bbl, with payments
weighted to the first half of the year.
· Forecast free cash flow of $200-300 million at $80/bbl, with the
range largely driven by timing of revenue receipts for 18 to 19 cargoes lifted
in Ghana during the year.
· Year-end net debt expected to be less than $1.4 billion; cash gearing
of net debt to EBITDAX expected to be c.1x at $80/bbl.
· On track to deliver targeted c.$800 million free cash flow over 2023
to 2025 period, with over $600 million free cash flow expected to be generated
over 2024 to 2025 at $80/bbl.
(1).Alternative performance measures are reconciled on pages 32 to 35.
Management Presentation - WEBCAST - 9:00 GMT
To access the webcast please use the following link and follow the
instructions provided: https://web.lumiconnect.com/#/m/118077766
(https://web.lumiconnect.com/#/m/118077766)
A replay will be available on the website from midday on 6 March 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)
YouTube: www.youtube.com/TullowOilplc (http://www.youtube.com/TullowOilplc)
Facebook: www.facebook.com/TullowOilplc (http://www.facebook.com/TullowOilplc)
LinkedIn: www.linkedin.com/company/Tullow-Oil
(http://www.linkedin.com/company/Tullow-Oil)
chief executive Officer's REview
Successful delivery of business plan
Soon after I joined Tullow in July 2020, we put in place a plan to transform
our business. This plan is achieving targeted results and since the end of
2020 we have generated over $1.1 billion of free cash flow, reduced net debt
by over 30% and taken the business from peak gearing of 3x to 1.4x net debt to
EBITDAX. We have achieved this despite our legacy hedge programme resulting in
non-recurring outflows of c.$600 million between 2021 to 2023, which
suppressed the true cash flow generation capacity of our business.
In 2023, Tullow continued to evolve and we now have a strong and unique
foundation to create material value. Several significant milestones have been
achieved, including the start-up of Jubilee South East which delivered
material production growth from our core operated field. We generated $170
million of free cash flow, ahead of expectations, and reduced our net debt by
over $250 million, despite a lower realised oil price in 2023 compared to 2022
that drove a year-on-year reduction in revenue (2023: $1,634 million; 2022:
$1,783 million). We also demonstrated our ability to access capital through
the $400 million debt facility agreement with Glencore.
Our strategy is underpinned by a relentless focus on three core areas -
operational excellence, capital efficiency and business growth. Through
continued execution of this strategy, we are embedding a performance culture,
retaining our discipline, and establishing a growth outlook. Importantly, we
are now a highly cash generative business and on track to deliver our target
of c.$800 million free cash flow over the 2023 to 2025 period.
Sustainability and shared prosperity
Tullow is committed to building a better future through responsible oil and
gas development. We believe Africa has the potential to play a growing role in
the global energy mix and we actively partner with our host nations to develop
their resources in a low-cost, environmentally and socially responsible
manner. We are encouraged by the commitment to a "just and equitable" energy
transition articulated in the COP28 Agreement. This acknowledges Africa's
minimal contribution to global emissions and recognises the right of African
developing nations to benefit from the development of their natural resources.
Our Shared Prosperity strategy creates economic opportunities for those who
need it most. In 2023, we accelerated our impact through partnerships,
supporting more than 10,000 students and hundreds of businesses across our
countries of operation. We are also driving local content through increased
engagement, support and training of our local supplier base
We have made tangible progress on our pathway to Net Zero by 2030. In 2023,
several process improvement modifications were completed at the Jubilee and
TEN FPSOs, keeping us on track to reach our target to eliminate routine
flaring by 2025. To address the hard-to-abate residual emissions from our
assets, we are taking a hands-on approach to progress a nature-based solution
in partnership with the Ghana Forestry Commission and expect to make a Final
Investment Decision in 2024. The project delivers on our 2030 Net Zero
ambition while also advancing Ghana's national climate goals and aligning with
our Shared Prosperity agenda.
Governance
At the beginning of the year Richard Miller was confirmed as Chief Financial
Officer (CFO), having served as interim CFO since April 2022, and joined the
Board as an Executive Director. Roald Goethe and Rebecca Wiles were appointed
to the Board as independent non-executive Directors in February and June 2023,
respectively. Roald is a highly experienced oil and gas executive who spent a
major part of his career at Trafigura where he worked primarily in West
Africa. Rebecca brings deep technical subsurface and geoscience expertise to
Tullow, following a 33-year career at BP plc. Our Board members bring a
diverse experience set including a deep understanding of Africa, the oil &
gas industry, finance and plc governance. Three out of nine directors are
women.
Operational performance
In 2023, full year working interest production averaged 62.7 kboepd, including
6.9 kboepd of gas. Group working interest production is expected to increase
year-on-year and our guidance range for 2024 is 62-68 kboepd, including c.7
kboepd of gas production.
Group working interest production (kboepd) FY 2023 FY 2024 Guidance
Ghana oil 42.6 48
Jubilee oil 32.5 39
TEN oil 10.1 9
Non-operated portfolio oil 13.2 11
Gabon oil 12.2 10
Cote d'Ivoire oil 1.0 1
Gas production 6.9 7
Group 62.7 62-68
Ghana
The start-up of production from the Jubilee South East project in July was a
landmark event, marking a step change in the field's production with average
daily rates c.30% higher in the second half of the year compared to the first
half with rates reaching levels over 100 kbopd.
Gross oil production from the Jubilee field averaged 83.4 kbopd (32.5 kbopd
net) in 2023. This was below our expectations, primarily due to water
injection reliability challenges and Jubilee South East starting up slightly
later than planned. The water injection reliability issues were resolved in
the fourth quarter of 2023, with upgraded capacity delivering record water
injection rates and observable pressure response in the reservoirs, which will
benefit 2024 production and beyond. Jubilee gas processing was also upgraded
in 2023 and as a result, we have increased capacity to produce oil from wells
with higher associated gas content. These important facility upgrades put us
in a strong position to maintain production in the range of 90-110 kbopd
towards the end of the decade.
Gross oil production from the TEN fields averaged 18.4 kbopd (net: 10.1 kbopd)
during 2023, with improved pressure support from existing injection wells
resulting inbetter management of decline. A planned shutdown was carried out
in July and work was completed to improve asset integrity, enhance production
through improved liquid recovery from gas and reduce flaring. Flaring from TEN
reduced by over 50% post the shutdown, an important step forward in our target
to eliminate routine flaring by 2025.
During the year, our operational performance continued to strengthen and
average uptime across our Ghana FPSOs remained high at 96%. The drilling team
also had excellent performance with seven wells (four Jubilee producers and
three Jubilee water injectors) brought onstream during 2023. The cost of
drilling wells in 2023 was on average around 20% lower and c.38 days faster
than the previous campaign in 2018-2020, achieving top-quartile industry
performance. These cost savings and efficiencies have been driven by reducing
non-productive time, improved well design and more effective contracting.
Five new Jubilee wells (three producers and two water injectors) are scheduled
to come onstream in 2024. The first water injector was brought on stream in
January, and two producers were brought on stream in February, with gross
production currently averaging over 100 kbopd. We expect to complete the
current drilling programme around the middle of the year, approximately six
months ahead of schedule. We then intend to take a drilling break in Ghana
with plans to resume drilling in 2025. During this time, we will optimise our
plans for the next phase of investment in Ghana while the existing well stock
and upgraded water injection capacity sustains production at Jubilee and TEN
decline continues to be effectively minimised through improved pressure
support.
Net gas production in Ghana averaged 6.4 kboepd in 2023 and marked the first
commercialisation of associated gas from the Jubilee field. The interim Gas
Sales Agreement, initially valued at $0.50/mmbtu, was amended in July 2023 to
a price of $2.90/mmbtu and subsequently increased in November to $2.95/mmbtu,
after applying year-on-year inflation indexation. This agreement represents a
revenue stream for Tullow of c.$4 million per month.
During the year, discussions continued with the Government of Ghana on the
amended TEN Plan of Development (PoD) and the long-term gas sales agreement.
We remain committed to reaching agreement and progressing a number of
identified projects at TEN in addition to commercialising the material gas
resource base.
In February 2023, we announced that Tullow Ghana Limited (TGL) had filed
requests for arbitration with the International Chamber of Commerce in London
in respect of two disputed tax assessments received from the Ghana Revenue
Authority (GRA). The assessments relate to the disallowance of loan interest
deductions for the fiscal years 2010 - 2020 and proceeds received by Tullow
Oil plc during the financial years 2016 to 2019 under the Group's corporate
Business Interruption Insurance policy.
Tullow had also previously filed a request for arbitration in respect of a
separate assessment for Branch Profits Remittance Tax of $320 million in 2021.
A hearing in respect of this dispute took place in October 2023 with an
outcome expected this year.
We believe that resolution through international arbitration will bring
certainty, which is in the best interest of all stakeholders. In the meantime,
we continue to engage with the Government of Ghana, including the GRA, with
the aim of resolving these disputes on a mutually acceptable basis.
Non-operated and exploration portfolios
In line with expectations, production from our non-operated portfolio in Gabon
and Côte d'Ivoire averaged 13.7 kboepd net in 2023 (2022: 16.7 kboepd net),
including 0.5 kboepd of gas production in Côte d'Ivoire.
Gabon is a key part of our production and infrastructure-led exploration (ILX)
portfolio and in 2023 we took actions that place the Tchatamba facilities as a
core hub for Tullow. In April, we announced the cashless asset swap agreed
with Perenco that enabled us to take more material positions in key fields
around Tchatamba. In August, the Government of Gabon approved the extension of
several of our licences to 2046, reflecting the future potential of the fields
and the longevity of the Tchatamba facilities. 2P reserves additions from the
licence extensions and the asset swap amounts to c.6 mmbbls with a further c.3
mmbbls 2P positive reserves revision from asset performance, overall
representing c.190% reserves replacement in 2023. During 2024, operations in
Gabon will focus on infill drilling to sustain production or minimise decline
across the licences, as well as two ILX wells at the Simba licence.
On Espoir in Côte d'Ivoire, we continue to work with the operator to
establish the best way forward for the asset. On exploration licences CI-524
and CI-803, we are maturing the prospect inventory ahead of drill candidate
selection for an exploration well to potentially be drilled in 2025.
In line with our strategy to focus on producing assets, we no longer have
licences in Guyana following the sale of Tullow Guyana B.V. to Eco Atlantic
and the expiry of the Kanuku licence. Through the sale, which completed in
November 2023, we retain exposure to potential future success on the Orinduik
licence through contingent considerations and royalty payments.
In Argentina, our exploration team has continued to mature a significant
prospective resource base and continues to assess opportunities from these
licences.
Kenya
Kenya remains a material option to drive value and growth for Tullow. An
updated Field Development Plan (FDP) which intends to develop 470 mmboe of 2C
resources to produce up to 120 kbopd, was submitted to the Government in March
2023. We have since worked collaboratively with the Government as they
evaluate the FDP. Once their evaluation is concluded, the FDP will be
submitted to the Cabinet Secretary for Energy and Petroleum for review before
submission to Parliament for final approval. The development has been designed
to be robust at lower oil prices and we continue discussions with prospective
strategic partners for this project.
In June 2023, our interest in Kenya increased from 50% to 100% as a result of
the withdrawal of our Joint Venture Partners for differing reasons. The
increased interest provides us with greater strategic flexibility. While we
continue to progress the FDP, we are also actively working with the Government
of Kenya in developing options to accelerate production and cash flow to
unlock value from this well-matured resource base.
Reserves and resources
At the end of 2023, audited 2P reserves were 212 mmboe (2022: 229 mmboe).
During the year, 23 mmboe of 2P reserves were produced with a replacement
ratio of 26%. Additions were primarily from the extension of production
licences in Gabon and the maturation of several infill wells, both in Gabon
and the Jubilee area. These additions were partly offset by reductions in TEN
2P reserves, mainly driven by a reduced near-term development programme in
light of the ongoing delays to gain Government approval for the TEN amended
PoD. Around 30 mmboe of net gas resources remain classified as 2C pending the
approval of the TEN amended PoD and Gas Sales Agreement. Commercialisation of
these gas resources would place TEN on a much firmer economic footing and
support the maturation of several identified projects.
Tullow's asset base continues to have significant value, and as of 31 December
2023, Tullow's audited 2P NPV10 was $3,406 million. This is slightly down from
2022 ($3,895 million), driven largely by TEN revisions and a lower long-term
oil price assumption as defined by independent third-party reserves auditor,
TRACS.
The Group's audited 2C resources increased to 745 mmboe at the end of 2023
(2022: 605mmboe), reflecting the material scale of opportunity Tullow has to
convert resources into reserves to sustain long-term production. As we now
hold 100% of our Kenya licences, net contingent resources have doubled to
470mmboe. 54mmboe of contingent resources has also been removed following the
sale and exit from Guyana.
Outlook
After reaching an important inflection point in our business plan in 2023,
Tullow has a strong and unique foundation to create material value for our
investors, host nations and wider stakeholders and we look to the future with
confidence.
We will continue to run our business with the same rigorous financial
discipline, prioritising the highest returns and focusing on value-accretive
investments. Our balance sheet will continue to strengthen as we further
reduce our debt and optimise our capital structure. We have made good progress
toward delivering our target of $800 million of free cash flow between 2023
and 2025 and given the quality of our resource base, the opportunity set ahead
of us and a reducing cost outlook, we expect to maintain these levels of free
cash flow generation in subsequent years.
With a strong balance sheet and this sustainable free cash flow outlook, our
business will be well placed to deliver value to our shareholders through
organic and inorganic growth and capital returns.
I thank our shareholders for their continued support as we realise value
across the portfolio in 2024 and beyond.
Finance review
Income Statement
Income Statement (key metrics) 2023 2022
Revenue ($m)
Sales volume (boepd) 55,754 55,170
Realised oil price ($/bbl) 77.5 88.0
Total revenue 1,634 1,783
Operating costs ($m)
Underlying cash operating costs(1) (293) (267)
Depreciation, Depletion and Amortisation (DDA) of oil and gas and leased
assets
(431) (411)
DDA before impairment charges ($/bbl) 18.8 18.4
(Overlift)/Underlift and oil stock movements (109) 46
Administrative expenses (56) (51)
Gain on bargain purchase - 197
Exploration costs written off (27) (105)
Impairment of property, plant and equipment, net (408) (391)
Gain on bond buyback 86 -
Net financing costs (286) (293)
Profit from continuing activities before tax 96 442
Income tax expense (206) (393)
(Loss)/Profit for the year from continuing activities (110) 49
Adjusted EBITDAX(1) 1,151 1,469
Basic (loss)/earnings per share (cents) (7.6) 3.4
1. Alternative performance measures are reconciled on pages 32 to 35.
Revenue
Sales Oil Volumes
During the year, there were 55,754 boepd (2022: 55,170 boepd) of liftings. The
total number of liftings in Ghana is comparable to the previous year with 13
in Jubilee (2022: 12) and 4 in TEN (2022: 5).
Realised oil price ($/bbl)
The Group's realised oil price after hedging for the period was $77.5/bbl and
before hedging $84.3/bbl (2022: $88.0/bbl and before hedging $104.3/bbl).
Lower oil prices compared to 2022 have resulted in a lower hedge loss
decreasing total revenue by $139 million in 2023 (2022: decrease of $319
million).
Gas sales
Included in Total Revenue of $1,634 million is gas sales of $38 million of
which $29 million relates to Ghana. During the year, Ghana exported 35,754
mmscf (gross) of gas at an average price of $1.54/mmbtu.
Refer to Operational Performance section above for detailed gas pricing.
Cost of Sales
Underlying cash operating costs
Underlying cash operating costs amounted to $293 million; $12.8/boe (2022:
$267 million; $11.9/boe). Routine operating costs largely remain unchanged
from prior year. The increase in the current year is largely due to
non-recurring expenditure.
Depreciation, depletion and amortisation
DD&A charges before impairment on production and development assets
amounted to $431 million; $18.8/boe (2022: $411 million: $18.4/boe). This
increase in DD&A per barrel is mainly attributable to downward revision of
TEN and Espoir 2P reserves offset by 2022 impairments.
Overlift and oil stock movements
The overlift expense is caused by a decrease in the underlift position in
Ghana due to timing of liftings as well as reduced stock positions in Gabon
from higher sales volumes.
Administrative expenses
With the exception of the one-off corporate project expenditure which was
partially offset by lower insurance premiums in the current year, Tullow has
managed to maintain administrative expenses at prior year levels despite the
inflationary environment.
Exploration costs written off
During 2023, the Group has written off exploration costs of $27 million (2022:
$105 million) predominantly driven by Kenya where withdrawal of the JV
Partners led to a re-assessment of risks associated to reaching FID resulting
in a $17.9 million impairment and write-offs of $3.3 million in Cote d'Ivoire,
$3.4 million for the Akoum B well in Gabon and $2.5 million in Guyana.
Impairment of property, plant and equipment
The Group recognised a net impairment charge on PP&E of $408 million in
respect of 2023 (2022: $391 million) largely driven by a reduction in TEN
reserves partially offset by oil price and updated cost assumptions. This was
primarily due to delays in gaining approval for the amended TEN PoD which has
led to the deferral of investment and continued field decline. There was also
an impairment charge in Espoir due to an increase in cost assumptions. Refer
to note 15 for the full year end 2023 audited reserve and resource position.
There were also changes to estimates on the cost of decommissioning for
certain UK and Mauritania assets.
Gain on bond buyback - refer to Borrowings section below.
Net financing costs
Net financing costs for the period were $286 million (2022: $293 million).
This decrease is mainly due to lower interest of $13 million due to the bond
redemption where interest was applied on lower outstanding bonds partially
offset by an increase in the unwinding of discount on decommissioning
provision in Ghana of $4 million.
A reconciliation of net financing costs is included in Note 6.
Taxation
The overall net tax expense of $206 million (2022: $393 million) primarily
relates to tax charges in respect of the Group's production activities in West
Africa, reduced by deferred tax credits associated with future UK
decommissioning expenditure, exploration write-offs and impairments.
Based on a profit before tax for the period of $96 million (2022: $442
million), the effective tax rate is 214.3 per cent (2022: 88.9 per cent).
After adjusting for non-recurring amounts related to gain on bond buybacks,
exploration write-offs, disposals, impairments, provisions and their
associated deferred tax benefit, the Group's adjusted tax rate is 70.2 per
cent (2022:70.3 per cent). The effective tax rate is in line with the prior
year with the impact of non-deductible expenditure in Ghana and Gabon and no
UK tax benefit arising from net interest and hedging expense of $167m (2022:
$570m) being partially offset by deferred tax credits related to non-operated
assets undergoing decommissioning and prior year adjustments.
The Group's future statutory effective tax rate is sensitive to the geographic
mix in which pre-tax profits arise. There is no UK tax benefit from net
interest and hedging expenses, whereas net interest and hedging profits would
be taxable in the UK. Consequently, the Group's tax charge will continue to
vary according to the jurisdictions in which pre-tax profits occur.
Analysis of adjusted effective tax rate ($m) Adjusted Profit/(loss) Tax Adjusted
before tax
(expense)/credit
Effective tax rate
Ghana 2023 584.4 (210.1) 35.9%
2022 994.8 (359.7) 36.2%
Gabon 2023 216.0 (101.2) 46.8%
2022 316.1 (158.9) 50.3%
Corporate 2023 (379.4) 9.6 2.5%
2022 (584.5) 3.5 0.6%
Other non-operated & exploration 2023 1.5 4.7 -324.2%
2022 15.9 (6.9) 43.5%
Total 2023 422.5 (296.9) 70.2%
2022 742.3 (522.1) 70.3%
Adjusted EBITDAX
Adjusted EBITDAX for the year was $1,151 million (2022: $1,469 million). The
decrease from 2022 was predominantly due to lower revenues associated with
reduced oil prices.
(Loss)/profit for the year from continuing activities and (loss)/earnings per share
The loss for the year from continuing activities amounted to $110 million
(2022: $49 million profit). Loss after tax was driven mainly by impairments
and write-offs totalling $435 million. Basic loss per share was 7.6 cents
(2022: 3.4 cents earnings per share).
Balance Sheet and Liquidity management
Balance Sheet and Liquidity management (key metrics) 2023 2022
Capital investment ($m)(1) 380 354
Derivative financial instruments ($m) (35) (244)
Borrowings ($m) (2,085) (2,473)
Underlying operating cash flow ($m) (1) 813 972
Free cash flow ($m)(1) 170 267
Net debt ($m)(1) 1,608 1,864
Gearing (times)(1) 1.4 1.3
1. Alternative performance measures are reconciled on pages 32 to 35.
Capital Investment
Capital expenditure amounted to $380 million (2022: $354 million) with $356
million invested in production and development activities of which $288
million was invested in Jubilee mainly comprising of $173 million spend on
drilling costs and $75 million on Jubilee South East (JSE) and $24 million
invested in exploration and appraisal activities.
The Group's 2024 capital expenditure is expected to be c.$250 million and is
expected to comprise Ghana of c.$160 million, West African Non-Operated of
c.$60 million, Kenya of c.$10 million and exploration spend of c.$20 million.
Decommissioning
Decommissioning expenditure was $67 million in 2023 (2022: $72 million). The
Group's decommissioning budget in 2024 is c.$70 million of which c.$20 million
is provisioning for future decommissioning in Ghana and Gabon. Subject to
programme scheduling, at the end of 2024 it is expected that c.$40 million of
decommissioning liabilities in the UK and Mauritania will remain.
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 31 December 2023, Tullow's hedge portfolio provides downside protection for
c.60% of forecast production entitlements in the first half of 2024 with
c.$57/bbl weighted average floors; for the same period, c.40% of forecast
production entitlements is capped at weighted average sold calls of c.$77/bbl.
In the second half of 2024, Tullow's hedge portfolio provides downside
protection for c.45% of forecast production entitlements with c.$60/bbl
weighted average floors; for the same period, c.20% of forecast production
entitlements is capped at weighted average sold calls of c.$113/bbl.
For the period from June to December 2024, Tullow's hedge portfolio also
includes three-way collars (with call spreads) with weighted average sold
calls of c.$85/bbl and weighted average bought calls of c.$94/bbl, providing
full access to oil price upside beyond the bought call price on c.10% of
forecast production entitlements in this period.
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 (2022: Level 2). There were no
transfers between fair value levels during the year.
At 31 December 2023, the Group's derivative instruments had a net negative
fair value of $35 million (2022: net negative $244 million).
The following table demonstrates the timing, volumes and prices of the Group's
commodity hedge portfolio at year end:
1H24 hedge portfolio at 31 December 2023 bopd Bought put Sold Bought
(floor) call call
Straight puts 11,217 $60.05 - -
Collars 24,344 $55.37 $77.47 -
Three- way collars (call spread) 332 $60.00 $105.60 $114.53
Total/Weighted Average 35,893 $56.88 $77.85 $114.53
2H24 hedge portfolio at 31 December 2023 bopd Bought put Sold Bought
(floor) call call
Straight puts 6,250 $59.96 - -
Collars 12,650 $60.36 $113.45 -
Three- way collars (call spread) 6,500 $60.00 $84.61 $93.55
Total/Weighted Average 25,400 $60.17 $103.66 $93.55
Since the start of 2024, the Company has added a further c.4kbopd of
c.$60/bbl downside protection for the second half of 2024 with a combination
of straight puts and three-way collars with weighted average call spreads of
c.$79-$89/bbl.
Borrowings
On 15 May 2023, the Group made a mandatory prepayment of $100 million of the
Senior Secured Notes due 2026.
On 20 June 2023, the Group repurchased $167 million nominal value of Senior
Notes due 2025 for $100 million cash consideration through an Unmodified Dutch
Auction. A gain on early bond redemption of $65 million is recognised as other
income in the income statement.
On 13 November 2023, Tullow announced that it had entered into a $400 million
five-year notes facility agreement with Glencore Energy UK limited (Glencore).
The facility is available for 18 months and proceeds are to be used for
liability management of the Senior Notes due 2025.
On 1 December 2023, the Group repurchased $115 million nominal value of Senior
Secured Notes due 2026 for $103 million cash consideration through an
Unmodified Dutch Auction. A gain on early bond redemption of $11 million is
recognised as other income in the income statement.
On 20 December 2023, the Group repurchased $141 million nominal value of
Senior Notes due 2025 for $130 million cash consideration through a Modified
Dutch Auction. The cash consideration was funded through an equivalent
drawdown under the Glencore facility. A gain on early bond redemption of $10
million is recognised as other income in the Income Statement.
The Group's total drawn debt reduced to $2.1 billion, consisting of $493
million nominal value Senior Notes due in March 2025, $1,485 million nominal
value Senior Secured Notes due in May 2026 and $130 million outstanding under
the Glencore facility.
Management regularly reviews options for optimising the Group's capital
structure and may seek to retire or purchase outstanding debt from time to
time through cash purchases or exchanges in the open market or otherwise.
Credit Ratings
Tullow maintains credit ratings with Standard & Poor's (S&P's) and
Moody's Investors Service (Moody's).
On 21 June 2023, following completion of a bond tender announced on 12 June
2023, S&P's downgraded Tullow's corporate credit rating to CCC+ with
stable outlook, from B- with negative outlook, and the rating of the Senior
Secured Notes due 2026 to CCC+ from B- and the rating of the Senior Notes due
2025 to CCC from CCC+.
On 21 December 2023, following completion of the bond tenders announced on 15
November 2023, S&P's upgraded Tullow's corporate credit rating to B- with
negative outlook, and the rating of the Senior Secured Notes due 2026 to B-
and the rating of the Senior Notes due 2025 to CCC+.
On 22 December 2023, Moody's affirmed Tullow's corporate credit rating at
Caa1, with negative outlook, and the rating of the Senior Secured Notes due
2026 at Caa1 and the rating of the Senior Notes due 2025 at Caa2.
Underlying Operating Cash Flow and Free Cash Flow
Underlying operating cash flow amounted to $813 million (2022: $972 million).
The decrease of $159 million is due to decrease in net revenue of $201 million
driven by lower oil prices and higher tax payments of $21 million partially
offset by lower Gabon royalty payments of $28 million and a one-off payment in
2022 of $77 million relating to a historic dispute that has now been settled.
Free cash flow has decreased to $170 million (2022: $267 million) primarily
due to a decrease in underlying operating cash flow of $159 million as
explained above. There has been a decrease in net cash used in investing
activities of $59 million mainly due to the one-off Ghana pre-emption payment
and Uganda FID consideration receipt in 2022 but this has been offset by an
increase in decommissioning spend of $14 million in the current period.
Net Debt and Gearing
Reconciliation of net debt $m
FY 2022 net debt 1,864
Sales revenue (1,634)
Operating costs 293
Other operating and administrative expenses 279
Operating cash flow before working capital movements (1062)
Movement in working capital (89)
Tax paid 275
Purchases of intangible exploration and evaluation assets and property, plant 292
and equipment
Other investing activities (24)
Other financing activities 435
Gain on bond buyback (86)
Foreign exchange loss on cash 3
FY 2023 net debt 1,608
Net debt reduced by $256 million during the year to $1,608 million at 31
December 2023 (2022: $1,864 million), due to generation of free cash flow of
$170 million (as explained above) as well as the gains on the three bond
buybacks totalling $86 million.
The Gearing ratio has increased to 1.4 times (2022:1.3 times) due to a
decrease in Adjusted EBITDAX as explained above primarily due to lower
revenues associated with reduced oil prices. This is in line with our target
to reach gearing of less than 1.5 times by year-end 2023.
Liquidity Risk Management and Going concern
The Directors consider the going concern assessment period to be up to 31
March 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: $78/bbl for 2024, $75/bbl for 2024; 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 $48 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 7 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 31 December 2023, the Group had $1.0 billion liquidity headroom consisting
of c.$0.5 billion free cash and $0.5 billion available under the revolving
credit facility.
The Group or its affiliates may, at any time and from time to time, seek to
retire or purchase outstanding debt through cash purchases and/or exchanges,
in open-market purchases, privately negotiated transactions or otherwise. Such
repurchases or exchanges, if any, will be upon such terms and at such prices
as management may determine, and will depend on prevailing market conditions,
liquidity requirements, contractual restrictions, and other factors. The
amounts involved may be material. The Group has repaid $0.3 billion and $0.2
billion of the 2025 and 2026 Notes, respectively, during the year. The
repayment of the 2025 Notes was partially funded by a drawdown of $130 million
of the Glencore facility.
The Group's forecasts show that the Group and Parent Company 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 at the end of the going concern period, including a full drawdown of the
Glencore debt facility to support the payment of the 2025 Notes. 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 $45/bbl. Based on the analysis above, the Directors
have a reasonable expectation that the Group and Parent Company has adequate
resources to continue in operational existence for the foreseeable future.
Thus, they have adopted the going concern basis of accounting in preparing
these Annual Results and Accounts.
Events since 31 December 2023
Gabon
On 29 February 2024, Tullow completed the Asset Swap agreement (ASA)
transaction (discussed in note 11. Assets and liabilities classified as held
for sale) with Perenco Oil and Gas Gabon S.A (Perenco). The transaction is a
cashless asset swap to be achieved through the exchange of participating
interests held by both parties in certain licences in Gabon. Management have
determined that the acquisition of the additional interest in the Tchatamba
licence is a Business Combination and the financial impacts cannot be
disclosed in the Annual Report and Accounts as the measurement of the assets
acquired is now underway. Accordingly, the relevant disclosure will be made in
the 2024 half year results.
Kenya
On 1 March 2024 Tullow received a letter from the EPRA extending the review
period of the updated Field Development Plan to 30 June 2024.
There have not been any other events since 31 December 2023 that have resulted
in a material impact on the year-end results.
Responsibility statement
(DTR 4.2 and the Transparency (Directive 2004/109/EC) Regulations (as amended))
The Directors confirm that to the best of their knowledge:
a. the condensed set of financial statements has been prepared in
accordance with IAS 34 'Interim Financial Reporting' as adopted by the UK and
EU and IAS 34 'Interim Financial Reporting' as adopted by the EU, the
Disclosure Guidance and Transparency Rules of the United Kingdom's Financial
Conduct Authority (DTR) and the Transparency (Directive 2004/109/EC)
Regulations 2007 as amended
b. the interim management report includes a fair review of the
information required by DTR 4.2.7R and Regulation 8(2) (indication of
important events during the first six months and description of principal
risks and uncertainties for the remaining six months of the year); and
c. the interim management report includes a true and fair review of the
information required by DTR 4.2.8R and Regulation 8(3) (disclosure of related
parties' transactions and changes therein).
A list of the current Directors is maintained on the Tullow Oil plc website:
www.tullowoil.com.
By order of the Board,
Rahul Dhir
Richard Miller
Chief Executive Officer
Chief
Financial Officer
5 March 2024
5 March 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.
Group income statement
Year ended 31 December 2023
$m Notes 2023 2022
Continuing activities
Revenue 1,634.1 1,783.1
Cost of sales 5 (869.2) (697.5)
Gross profit 764.9 1,085.6
Administrative expenses 5 (56.1) (51.0)
Gain on bargain purchase - 196.8
Other gains 0.2 3.1
Exploration costs written off 8 (27.0) (105.2)
Impairment of property, plant and equipment, net 9 (408.1) (391.2)
Provisions reversal/ (expense) 5 22.0 (4.2)
Operating profit 295.9 733.9
(Loss)/ gain on hedging instruments (0.4) 0.8
Gain on bond buyback 86.0 -
Finance income 6 44.0 42.9
Finance costs 6 (329.6) (335.5)
Profit from continuing activities before tax 95.9 442.1
Income tax expense 7 (205.5) (393.0)
(Loss)/ profit for the year from continuing activities (109.6) 49.1
Attributable to
Owners of the Company (109.6) 49.1
(Loss)/ earnings per ordinary share from continuing activities ¢ ¢
Basic (7.6) 3.4
Diluted (7.6) 3.3
Group statement of comprehensive income and expense
Year ended 31 December 2023
$m 2023 2022
(Loss)/ profit for the year (109.6) 49.1
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
Gains/ (losses) arising in the year 20.1 (399.5)
Gains arising in the year - time value 50.3 21.7
Reclassification adjustments for items included in profit on realisation 111.3 288.5
Reclassification adjustments for items included in loss on realisation - time 27.8 30.8
value
Exchange differences on translation of foreign operations (5.8) 10.2
Other comprehensive income/ (expense) 203.7 (48.3)
Tax relating to components of other comprehensive income/ (expense) - -
Net other comprehensive income/ (expense) for the year 203.7 (48.3)
Total comprehensive income for the year 94.1 0.8
Attributable to
Owners of the Company 94.1 0.8
Group balance sheet
As at 31 December 2023
$m Notes 2023 2022
Assets
Non-current asset
Intangible exploration and evaluation assets 8 287.0 288.6
Property, plant and equipment 9 2,532.8 2,981.4
Other non-current assets 10 338.6 327.1
Deferred tax assets 19.6 14.5
3,178.0 3,611.6
Current assets
Inventories 107.3 181.6
Trade receivables 43.5 26.8
Other current assets 10 571.2 567.9
Current tax assets 3.8 15.4
Cash and cash equivalents 499.0 636.3
Assets classified as held for sale 11 55.8 -
1,280.6 1,428.0
Total assets 4,458.6 5,039.6
Liabilities
Current liabilities
Trade and other payables 12 (775.0) (750.2)
Borrowings (100.0) (100.0)
Provisions 14 (67.9) (98.8)
Current tax liabilities (230.5) (186.0)
Derivative financial instruments (35.0) (186.3)
Liabilities associated with assets classified as held for sale 11 (17.6) -
(1,226.0) (1,321.3)
Non-current liabilities
Trade and other payables 12 (783.2) (780.0)
Borrowings (1,984.6) (2,372.8)
Provisions 14 (403.7) (415.6)
Deferred tax liabilities (420.5) (551.5)
Derivative financial instruments - (57.9)
(3,592.0) (4,177.8)
Total liabilities (4,818.0) (5,499.1)
Net liabilities (359.4) (459.5)
Equity
Called-up share capital 216.7 215.2
Share premium 1,294.7 1,294.7
Foreign currency translation reserve (244.4) (238.6)
Hedge reserve (18.9) (150.3)
Hedge reserve - time value (16.3) (94.4)
Merger reserve 755.2 755.2
Retained earnings (2,346.4) (2,241.3)
Equity attributable to equity holders of the Company (359.4) (459.5)
Total equity (359.4) (459.5)
Group statement of changes in equity
Year ended 31 December 2023
$m Share Share Foreign currency translation reserve¹ Hedge Merger reserves Retained earnings Total
capital
premium
reserve²
Hedge
reserve - time
value²
At 1 January 2022 214.2 1,294.7 (248.8) (39.3) (146.9) 755.2 (2,295.2) (466.1)
Profit for the year - - - - - - 49.1 49.1
Hedges, net of tax - - - (111.0) 52.5 - - (58.5)
Currency translation adjustments - - 10.2 - - - - 10.2
Exercise of employee share options 1.0 - - - - - (1.0) -
Share-based payment charges - - - - - - 5.8 5.8
At 1 January 2023 215.2 1,294.7 (238.6) (150.3) (94.4) 755.2 (2,241.3) (459.5)
Loss for the year - - - - - - (109.6) (109.6)
Hedges, net of tax - - - 131.4 78.1 - - 209.5
Currency translation adjustments - - (5.8) - - - - (5.8)
Exercise of employee share options 1.5 - - - - - (1.5) -
Share-based payment charges - - - - - - 6.0 6.0
At 31 December 2023 216.7 1,294.7 (244.4) (18.9) (16.3) 755.2 (2,346.4) (359.4)
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.
Group cash flow statement
Year ended 31 December 2023
$m Notes 2023 2022
Cash flows from operating activities
Profit from continuing activities before tax 95.9 442.1
Adjustments for:
Depreciation, depletion and amortisation 9 436.6 425.8
Gain on bargain purchase - (196.8)
Other gains (0.2) (3.1)
Taxes paid in kind 7 (11.0) (21.4)
Exploration costs written off 8 27.0 105.2
Impairment of property, plant and equipment, net 9 408.1 391.2
Provisions (reversal)/ expense (22.0) 4.2
Payment for provisions 14 (0.6) (127.3)
Decommissioning expenditure 14 (78.1) (57.7)
Share-based payment charge 6.0 5.8
Loss/ (gain) on hedging instruments 0.4 (0.8)
Gain on bond buyback (86.0)
Finance income 6 (44.0) (42.9)
Finance costs 6 329.6 335.5
Operating cash flow before working capital movements 1,061.7 1,259.8
(Increase)/ decrease in trade and other receivables (36.3) 288.4
Decrease/ (increase) in inventories 66.6 (48.0)
Increase/ (decrease) in trade payables 58.7 (193.1)
Cash generated from operating activities 1,150.7 1,307.1
Income taxes paid (274.5) (229.3)
Net cash from operating activities 876.2 1,077.8
Cash flows from investing activities
Proceeds from disposals 0.7 68.1
Purchase of additional interest in joint operation - (126.8)
Purchase of intangible exploration and evaluation assets (30.2) (42.6)
Purchase of property, plant and equipment (262.3) (263.8)
Interest received 23.3 8.9
Net cash used in investing activities (268.5) (356.2)
Cash flows from financing activities
Debt arrangement fees (5.0) -
Repayment of borrowings (432.2) (100.0)
Drawdown of borrowings 129.7 -
Payment of obligations under leases 13 (195.0) (203.8)
Finance costs paid (240.0) (249.0)
Net cash used in financing activities (742.5) (552.8)
Net (decrease)/ increase in cash and cash equivalents (134.8) 168.8
Cash and cash equivalents at beginning of year 636.3 469.1
Foreign exchange loss (2.5) (1.6)
Cash and cash equivalents at end of year 499.0 636.3
Notes to the financial statements
Year ended 31 December 2023
1. Basis of preparation and presentation of financial information
The Financial Statements have been prepared in accordance with UK-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 financial reporting
framework that has been applied in the preparation of the parent company
financial statements is applicable law and United Kingdom Accounting
Standards, including FRS 101 "Reduced Disclosure Framework" (United Kingdom
Generally Accepted Accounting Practice).
The financial information for the year ended 31 December 2023 does not
constitute statutory accounts as defined in sections 435 (1) and (2) of the
Companies Act 2006. Statutory accounts for the year ended 31 December 2022
have been delivered to the Registrar of Companies and those for 2023 will be
delivered following the Company's annual general meeting. The auditor has
reported on these accounts; their reports were unqualified. Their report did
not include a reference to any other matters to which the auditor drew
attention by way of emphasis of matter and did not contain a statement under
section 498 (2) or (3) of the Companies Act 2006.
The Financial Statements have been prepared on the historical cost basis,
except for derivative financial instruments and contingent consideration which
have been measured at fair value which are carried at fair value less cost to
sell. The Financial Statements are presented in US dollars and all values are
rounded to the nearest $0.1 million, except where otherwise stated.
The accounting policies applied are consistent with those adopted and
disclosed in the Group's financial statements for the year ended 31 December
2022. There have been a number of amendments to accounting standards and new
interpretations issued by the International Accounting Standards Board which
were applicable from 1 January 2023, however these have not any impact on the
accounting policies, methods of computation or presentation applied by the
Group. Further details on new International Financial Reporting Standards
adopted will be disclosed in the 2023 Annual Report and Accounts.
Certain new accounting standards and interpretations have been published that
are not mandatory for 31 December 2023 reporting periods and have not been
early adopted by the Group. These standards are not expected to have a
material impact on the entity in the current or future reporting periods and
on foreseeable future transactions.
2. (Loss)/earnings per ordinary share
Basic (loss)/earnings per ordinary share amounts are calculated by dividing
net (loss)/profit for the year attributable to ordinary equity holders of the
Parent by the weighted average number of ordinary shares outstanding during
the year.
Diluted earnings per ordinary share amounts are calculated by dividing net
(loss)/profit for the year attributable to ordinary equity holders of the
Parent by the weighted average number of ordinary shares outstanding during
the year plus the weighted average number of dilutive ordinary shares that
would be issued if employee and other share options were converted into
ordinary shares.
3. 2023 Annual Report and Accounts
The 2023 Annual Report and Accounts will be mailed in March 2024 only to those
shareholders who have elected to receive it. Otherwise, shareholders will be
notified that the Annual Report and Accounts are available on the Group's
website (www.tullowoil.com (http://www.tullowoil.com) ). Copies of the Annual
Report and Accounts will also be available from the Company's registered
office at Building 9, Chiswick Park, 566 Chiswick High Road, London, W4 5XT.
4. Segmental reporting
The information reported to the Group's Chief Executive Officer for the
purposes of resource allocation and assessment of segment performance is
focused on four Business Units - Ghana, Non-operated producing assets
including Uganda and decommissioning assets, Kenya and Exploration. Therefore,
the Group's reportable segments under IFRS 8 are Ghana, Non-operated, Kenya
and Exploration.
The following tables present revenue, loss and certain asset and liability
information regarding the Group's reportable business segments for the years
ended 31 December 2023 and 31 December 2022.
$m Ghana Non-Operated Kenya Exploration Corporate Total
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
Provisions reversal 22.0
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)
Loss 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, 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.
Reconciliation of segment result 2023 2022
Segment result 329.8 589.2
Add back:
Exploration costs written off 27.0 105.2
Impairment of Property, plant and equipment 408.1 391.2
Gross profit 764.9 1,085.6
4. Segmental reporting continued
$m Ghana Non-Operated Kenya Exploration Corporate Total
2022
Sales revenue by origin 1,578.5 524.0 - - (319.4) 1,783.1
Segment result(1) 692.5 337.3 (0.5) (102.6) (337.5) 589.2
Provisions expense (4.1)
Gain on bargain purchase 196.8
Other gains and losses 3.1
Unallocated corporate expenses(2) (51.1)
Operating profit 733.9
Gain on hedging instruments 0.8
Finance income 42.9
Finance costs (335.5)
Profit before tax 442.1
Income tax expense (393.0)
Profit after tax 49.1
Total assets 3,827.7 380.6 265.6 46.0 519.7 5,039.6
Total liabilities(3) (2,220.5) (401.6) (14.1) (4.6) (2,858.3) (5,499.1)
Other segment information
Capital expenditure:
Property, plant and equipment 342.9 26.9 - - 0.9 370.7
Intangible exploration and evaluation assets 0.9 (1.7) (2.1) 42.1 - 39.2
Depletion, depreciation and amortisation (362.1) (52.7) (1.3) - (9.7) (425.8)
Impairment of property, plant and equipment, net (380.6) (10.6) - - - (391.2)
Exploration costs written off (0.9) 1.8 (0.5) (105.6) - (105.2)
1. Segment result is a non IFRS measure which includes gross profit,
exploration costs written off, impairment of property, plant and equipment.
See reconciliation above.
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.
5. Other costs
$m 2023 2022
Cost of sales
Operating costs 292.9 266.5
Depletion and amortisation of oil and gas and leased assets(1) 430.8 410.7
Overlift, underlift and oil stock movements 109.3 (46.3)
Royalties 33.9 61.7
Share-based payment charge included in cost of sales 0.4 0.4
Other cost of sales 1.9 4.4
Total cost of sales 869.2 697.5
Administrative expenses
Share-based payment charge included in administrative expenses 5.6 5.4
Depreciation of other fixed assets 5.8 15.1
Other administrative costs 44.7 30.5
Total administrative expenses 56.1 51.0
Provisions (reversal)/ expense(2) (22.0) 4.2
1. Depreciation expense on leased assets of $81.4 million as per note 9
includes a charge of $2.2 million on leased administrative assets, which is
presented within administrative expenses in the income statement. The
remaining balance of $79.2 million relates to other leased assets and is
included within cost of sales.
The reduction in depreciation of other fixed assets expense is caused by
corporate assets in the UK and Ghana reaching the end of their useful life
during 2022 and 2023.
2. This includes credit to the movements in other provisions of $22.0
million (2022: $4.1 million charge) as well as restructuring and redundancy
costs of $nil (2022: $0.1 million).
The increase in other administrative costs is mainly due to one-off corporate
project spend partially offset by lower insurance premiums in the current
year.
6. Net financing costs
$m 2023 2022
Interest on bank overdrafts and borrowings 237.0 250.4
Interest on obligations for leases 78.6 76.4
Total borrowing costs 315.6 326.8
Finance and arrangement fees 1.9 0.3
Other interest expense 2.0 2.4
Unwinding of discount on decommissioning provisions 10.1 6.0
Total finance costs 329.6 335.5
Interest income on amounts due from Joint Venture partners for leases (30.1) (29.6)
Other finance income (13.9) (13.3)
Total finance income (44.0) (42.9)
Net financing costs 285.6 292.6
7. Taxation on profit on continuing activities
$m 2023 2022
Current tax on profits for the year
UK corporation tax (1.9) (11.8)
Foreign tax 322.2 321.0
Taxes paid in kind under production sharing contracts 11.0 21.4
Adjustments in respect of prior periods 10.8 (3.3)
Total corporate tax 342.1 327.3
UK petroleum revenue tax (0.7) (2.8)
Total current tax 341.4 324.5
Deferred tax
Origination and reversal of temporary differences
UK corporation tax (22.9) 11.4
Foreign tax (106.5) 54.0
Adjustments in respect of prior periods (2.8) (2.9)
Total deferred corporate tax (132.2) 62.5
Deferred UK petroleum revenue tax (3.7) 6.0
Total deferred tax (135.9) 68.5
Total income tax expense 205.5 393.0
$m 2023 2022
Profit from continuing activities before tax 95.9 442.1
Tax on profit from continuing activities at the standard UK corporation 22.5 84.0
tax rate of 23.5% (2022: 19%)
Effects of:
Non-deductible exploration expenditure 3.4 0.5
Other non-deductible expenses 35.4 27.8
Net deferred tax asset not recognised 65.1 138.5
Utilisation of tax losses not previously recognised (0.2) (0.4)
Adjustment relating to prior years (2.8) (6.2)
Other tax rates applicable outside the UK 82.4 214.6
Other income not subject to corporation tax (0.3) (0.1)
Tax impact of acquisition through business combination - (65.7)
Group total tax expense for the year 205.5 393.0
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 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. 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.
7. Taxation on profit on continuing activities continued
Uncertain tax treatments continued
Provisions of $85.0 million (2022: $106.4 million) are included in income tax
payable ($78.3 million (2022: $70.6 million)) and provisions ($6.7 million
(2022: $35.8 million)). 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.
Due to the uncertainty of such tax items, it is possible that on conclusion of
an open tax matter at a future date the outcome may differ significantly from
management's estimate. If the Group was unsuccessful in defending itself from
all of these claims, the result would be additional liabilities of $1,030.3
million (2022: $1,024.0 million) which includes $6.9 million of interest and
penalties (2022: $32.4 million).
The provisions and contingent liabilities relating to these disputes have
decreased following the conclusion of tax authority challenges and matters
lapsing under the statute of limitations, but have increased, following new
claims being initiated and extrapolation of exposures through to 31 December
2023, giving rise to an overall decrease in provision of $21.4 million and
increase in contingent liability of $6.2 million.
Ghana tax assessments
In October 2021, Tullow Ghana Limited (TGL) filed a Request for Arbitration
with the International Chamber of Commerce (ICC) disputing the $320.3 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 arbitration hearing
took place in October 2023 and a decision is expected in the current financial
year. TGL is not required to pay any amounts of BPRT until the dispute is
formally resolved.
In December 2022, TGL received a $190.5 million 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 with 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 arbitration hearing is
scheduled to commence on 30 June 2025.
In December 2022, TGL received a $196.5 million 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 arbitration hearing is scheduled
to commence on 17 November 2025.
The Group continues to engage with the Government of Ghana with the aim of
resolving the BPRT, loan interest and insurance disputes on a mutually
acceptable basis.
Bangladesh litigation
The National Board of Revenue (NBR) is seeking to disallow $118.6 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 3,094.3 million (c.$29.3 million) requesting payment by 15 March
2020. However, under the Production Sharing Contract (PSC), the Government is
required to indemnify TBL against all taxes levied by any public authority,
and the share of production paid to Petrobangla (PB), Bangladesh's national
oil company, is deemed to include all taxes due which PB is then obliged to
pay to the NBR. TBL sent the payment demand to PB and the Government
requesting the payment or discharge of the payment demand under their
respective PSC indemnities. On 14 June 2021, TBL issued a formal notice of
dispute under the PSC to the Government and PB. A further request for payment
was received from NBR on 28 October 2021 demanding settlement by 15 November
2021. Arbitration proceedings were initiated under the PSC on 29 December
2021. A procedural hearing was held on 28 June 2022 which set the timetable
for the process going forward. The first submissions have been made in October
2022 with counter submissions received on 17 January 2023. The second
submission was made in June 2023 with the first Tribunal hearing scheduled for
20-24 May 2024. A decision is expected in H1 2025.
Other items
Other items totalling $294.0 million (2022: $280.0 million) comprise exposures
in respect of claims for corporation tax in respect of disallowed expenditure
or withholding taxes that are either currently under discussion with the tax
authorities or which arise in respect of known issues for periods not yet
under audit.
Timing of cash flows
While it is not possible to estimate the timing and amount of tax cash flows
in relation to possible outcomes with certainty, as they are subject to
outcome of court / arbitration proceedings and any potential appeals,
management anticipates that there will not be material cash taxes paid in
excess of the amounts provided for uncertain tax treatments.
8. Intangible exploration and evaluation assets
$m 2023 2022
At 1 January 288.6 354.6
Additions 25.4 39.2
Amounts written off (27.0) (105.2)
At 31 December 287.0 288.6
The below table provides a summary of the exploration costs written off on a
pre-tax basis by country.
Country CGU Rationale for 2023 2023 Remaining recoverable amount
2023 write-off
write-off/ (back)
$m
$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.
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. Energy and Petroleum Regulatory Authority (EPRA),
the regulator, has engaged third party consultants to review the revised FDP
and the current review period ends on 30 June 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.
In management's view, in light of public statements and announcements made by
AOC and TE to this effect, and in accordance with the terms of the Joint
Operating Agreement, it is considered that the ownership of the 50% held by
AOC and TE was passed on 30 June 2023, resulting in Tullow holding 100%. From
that date, Tullow has the right to benefit from the 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 31
December 2023. Tullow accounted for this as asset acquisition at nil cost.
The withdrawal of the partners and an upward revision to the Group's oil
prices as detailed in note 9 are considered to be impairment assessment
triggers for the asset as at 31 December 2023, and in line with its accounting
policy the Group has performed a VIU assessment. The cash flows were
discounted using a pre-tax nominal discount rate of 20% (2022: 20%). This
resulted in an NPV significantly in excess of the book value of $260.1
million. However, the Group has identified the following uncertainties in
respect of the Group's ability to realise the estimated VIU; receiving and
subsequently finalising an acceptable offer from a strategic partner and
securing governmental approvals relating thereto, obtaining financing for the
project and government deliverables 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). The Group
continues to progress with the farm-down process.
8. Intangible exploration and evaluation assets continued
Kenya continued
Due to the binary nature of these uncertainties the Group was unable to either
adjust the cash flows or discount rate appropriately. It has therefore used
its judgement and assessed a probability of achieving FID and therefore the
recognition of commercial reserves. This probability was applied to the VIU to
determine a risk-adjusted VIU and compared against the net book value of the
asset. Certain risks have increased since 31 December 2022, predominantly
around farm-down and project financing. This has been partially offset by an
increased equity interest in the project and changes in oil price assumptions.
Based on this, the NPV has been revised to $242.2 million and an impairment of
$17.9 million has been 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 $242.2 million. A
reduction or increase in the two-year forward curve of $5/bbl, based on the
approximate range of annualised average oil price over recent history, and a
reduction or increase in the medium and long-term price assumptions of $5/bbl,
based on the range of annualised average historical prices, are considered to
be reasonably possible changes for the purposes of sensitivity analysis.
Decreases to oil prices specified above would increase the impairment charge
by $37.9 million, whilst increases to oil prices specified above would result
in a credit to the impairment charge of $37.7 million. A 1% change in the
pre-tax discount rate would result in an additional impairment charge of $33.9
million. The Group believes a 1% change in the pre-tax discount rate to be a
reasonable possibility based on historical analysis of the Group's and a peer
group of companies' impairments.
Guyana
On 10 August 2023, Tullow announced that it had agreed to sell its total
interest in Tullow Guyana B.V., which includes the Orinduik licence (60%
operated equity) in Guyana, to Eco Guyana Oil and Gas (Barbados) Limited in
exchange for an upfront cash consideration of $0.7 million and contingent
consideration linked to a series of potential future milestones.
The transaction completed on 16 November 2023 and resulted in $0.7 million of
gain on disposal recognised in the income statement.
9. Property, plant and equipment
$m 2023 2023 2023 2023 2022 2022 2022 2022
Oil and gas assets Other fixed assets Right of use Total
Oil and gas assets
Other fixed assets
Right of Total
assets
use
assets
Cost
At 1 January 11,182.6 30.0 1,196.8 12,409.4 10,521.7 69.5 1,091.7 11,682.9
Additions 416.1 2.3 81.1 499.5 305.2 2.0 63.5 370.7
Acquisitions(1) - - - - 473.2 - - 473.2
Transfer(1) - - - - - - 86.6 86.6
Transfer to assets held for sale (302.8) - - (302.8) - - - -
Asset retirement (67.7) (11.0) (10.6) (89.3) - (38.1) (41.7) (79.8)
Currency translation adjustments 53.9 0.6 1.5 56.0 (117.5) (3.4) (3.3) (124.2)
At 31 December 11,282.1 21.9 1,268.8 12,572.8 11,182.6 30.0 63.5 370.7
Depreciation, depletion, amortisation and impairment
At 1 January (8,888.4) (24.4) (515.2) (9,428.0) (8,263.7) (53.8) (450.8) (8,768.3)
Charge for the year (351.6) (3.6) (81.4) (436.6) (353.7) (11.2) (60.9) (425.8)
Impairment loss (399.1) - (9.0) (408.1) (391.2) - - (391.2)
Capitalised depreciation - - (49.3) (49.3) - - (46.1) (46.1)
Transfer to assets held for sale 247.6 - - 247.6 - - - -
Asset retirement 67.7 11.0 10.6 89.3 - 38.1 41.7 79.8
Currency translation adjustments (53.9) (0.5) (0.5) (54.9) 120.2 2.5 0.9 123.6
At 31 December (9,377.7) (17.5) (644.8) (10,040.0) (8,888.4) (24.4) (515.2) (9,428.0)
Net book value at 31 December 1,904.4 4.4 624.0 2,532.8 2,294.2 5.6 681.6 2,981.4
1. This relates to an acquisition through business combination discussed
in note 15 of the 2022 Annual Report and Accounts.
9. Property, plant and equipment continued
During 2023 and 2022, 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
2023 $78/bbl $75/bbl $75/bbl $75/bbl $75/bbl $75/bbl inflated at 2%
2022 $84/bbl $79/bbl $70/bbl $70/bbl $70/bbl $70/bbl inflated at 2%
Trigger for 2023 Pre-tax discount rate assumption 2023
2023 Impairment Remaining
impairment $m
recoverable amount (g)
$m
Espoir (Côte 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 d, e 16.5 n/a -
UK Corporate f 9.0 n/a -
Impairment 408.1
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.
g. The remaining recoverable amount of the asset is its value in use.
Impairments identified in the TEN fields of $301.2 million were primarily due
to lower 2P reserves partially offset by an increase in oil price. This was
primarily due to delays in gaining approval for the amended TEN PoD which has
led to the deferral of investment and continued field decline.
Oil prices stated above are benchmark prices to which an individual field
price differential is applied. All impairment assessments are prepared on a
VIU basis using discounted future cash flows based on 2P reserves profiles. A
reduction or increase in the two-year forward curve of $5/bbl, based on the
approximate range of annualised average oil price over recent history, and a
reduction or increase in the medium and long-term price assumptions of $5/bbl,
based on the range of annualised average historical prices, are considered to
be reasonably possible changes for the purposes of sensitivity analysis.
Decreases to oil prices specified above would increase the impairment charge
by $76.4 million for Ghana and increase the impairment by $0.4 million for
Non-Operated, whilst increases to oil prices specified above would result in a
reduction in the impairment charge of $72.6 million for Ghana and $17.1
million for Non-Operated. A 1% increase in the pre-tax discount rate would
increase the impairment by $15.6 million for Ghana and increase the impairment
by $0.4 million for Non-Operated. The Group believes a 1% increase in the
pre-tax discount rate to be a reasonable possibility based on historical
analysis of the Group's and peer group of companies' impairments.
10. Other assets
$m 2023 2022
Non-current
Amounts due from Joint Venture Partners 332.5 323.3
VAT recoverable 6.1 3.8
338.6 327.1
Current
Amounts due from Joint Venture Partners 498.1 452.3
Underlifts 47.8 76.2
Prepayments 21.1 31.3
Other current assets 4.2 8.1
571.2 567.9
909.8 895.0
The increase in current receivables from JV Partners compared to December 2022
mainly relates to partner's share of increased accrual balances (note 12), net
increase in GNPC (Ghana National Petroleum Corporation) receivable and other
working capital movements, partially offset by a lower balance of current
receivables relating to leases.
11. Assets and liabilities classified as held for sale
On 28 April 2023, Tullow announced that through its wholly owned subsidiary,
Tullow Oil Gabon S.A., it had signed an Asset Swap Agreement (ASA) with
Perenco Oil and Gas Gabon S.A. (Perenco). Under the ASA, Tullow has agreed to
assign and transfer certain of its existing participating interests in
Limande, Turnix, M'oba, Oba and 17.5% in Simba assets to Perenco in return for
the assignment and transfer by Perenco of 15% of its participating interests
in Kowe (Tchatamba) and 20% of its participating interests in DE8 licence to
Tullow.
Due to the agreed neutrality of the transaction, no additional consideration
is payable by either party in respect thereof. The ASA includes provisions to
ensure the neutrality of the transaction via cash adjustments for the period
between economic date and completion date.
On completion, all assets and associated liabilities relating to the existing
participating interests held in Limande, Turnix, M'Oba and Oba assets,
together with 17.5% of Tullow's interest in Simba, will be disposed. All
assets impacted by the transaction are included in the 'Non-Operated' Business
Unit applied for segment performance reporting.
Management concluded that the asset met the IFRS 5 Held for Sale criteria on
19 July 2023, when the agreed form of the amendment to the Tullow Protocol was
submitted to the relevant Governmental Authority of the Gabonese Republic (the
Tullow Protocol is an investment convention that applies to certain Tullow
licences). All other conditions precedent to the completion of the transaction
were considered reasonably certain to occur within 12 months of 19 July 2023.
The transaction completed on 29 February 2024. Refer to Events since 31
December 2023 in the Finance Review.
The major classes of assets and liabilities comprising the assets classified
as held for sale as at 31 December 2023 were as follows:
$m 2023
Assets
Property, plant and equipment 55.2
Other debtors 0.6
Assets classified as held for sale 55.8
Liabilities (1.4)
Accruals (2.0)
Decommissioning provision (14.2)
Liabilities directly associated with assets classified as held for sale (17.6)
Net assets directly associated with disposal group 38.2
12. Trade and other payables
2023 2022
$m
Current liabilities
Trade payables 22.3 68.4
Other payables 65.3 51.4
Overlifts 3.1 -
Accruals 498.6 379.3
Current portion of lease liabilities 185.7 251.2
775.0 750.2
Non-current liabilities
Other non-current liabilities(1) 62.2 47.1
Non-current portion of lease liabilities 721.0 732.9
783.2 780.0
1. Other non-current liabilities include balances related to JV
Partners.
Accruals mainly relate to capital expenditure, interest expense on bonds and
staff-related expenses. The movement in the balance is predominantly driven by
an increased level of activity in Ghana during the year relating to Jubilee
South East.
Trade and other payables are non-interest bearing except for leases (note 13).
The change in trade payables and in other payables predominantly represents
timing differences and levels of work activity.
Payables related to operated Joint Ventures (primarily in Ghana and Kenya) are
recorded gross with the amount representing the partners' share recognised in
amounts due from Joint Venture Partners (note 10).
The movement in current lease liabilities is mainly driven by the
remeasurement of the TEN FPSO lease discussed in Note 13.
13. Leases
This note provides information for leases where the Group is a lessee. The
Group did not enter into any contracts acting as a lessor.
i) Amounts recognised in the balance sheet
Right-of-use assets Lease liabilities
$m 2023 2022 2023 2022
Right-of-use assets (included within property, plant and equipment) and lease
liabilities
Property leases 22.0 39.2 27.6 34.6
Oil and gas production and support equipment leases 576.9 639.0 826.4 942.4
Transportation equipment leases 25.1 3.4 52.7 7.1
Total 624.0 681.6 906.7 984.1
Current provisions 185.7 251.2
Non-current 721.0 732.9
Total 906.7 984.1
Additions to the right-of-use assets during the 2023 financial year were $81.1
million. Refer to note 9.
TEN FPSO
The Group's leases balance includes the TEN FPSO, classified as 'Oil and Gas
production and support equipment'. During the year, the assumption that the
TEN FPSO lease term would end in April 2024, when the purchase option was
assumed to be exercised, was updated to reflect the best estimate view that
the FPSO will continue to be leased until the cessation of production in 2032.
It also assumes an exercise of the extension option.
The resulting lease liability remeasurement had the following impact on the
balances:
$m 2023
Lease liability (39.2)
Right-of-use asset (included within Property, plant and equipment) 25.6
Amounts due from Joint Venture Partners 13.6
13. Leases continued
As at 31 December 2023, the present value of the TEN FPSO right-of-use asset
was $549.0 million (2022: $596.9 million).
The present value of the TEN FPSO gross lease liability was $763.5 million
(2022: $847.9 million).
A receivable from the Joint Venture Partners of $288.8 million (2022: $330.1
million) was recognised in other assets (note 10) to reflect the value of
future payments that will be met by cash calls from partners relating to the
TEN FPSO lease. The present value of the receivable from the Joint Venture
Partners unwinds over the expected life of the lease and the unwinding of the
discount is reported within finance income.
Carrying amounts of the lease liabilities and Joint Venture leases receivables
and the movements during the period:
$m Lease liabilities Joint Venture lease receivables Total
At 1 January 2022 (1,163.4) 531.0 (632.4)
Additions and changes in lease estimates (89.4) 40.2 (49.2)
Acquisitions - (86.6) (86.6)
Payments/(receipts) 342.0 (138.2) 203.8
Interest (expense)/income (76.4) 29.6 (46.8)
Currency translation adjustments 3.1 - 3.2
At 1 January 2023 (984.1) 376.1 (608.0)
Additions and changes in lease estimates (174.1) 79.8 (94.3)
Payments/(receipts) 331.5 (136.5) 195.0
Interest (expense)/income (78.6) 30.1 (48.5)
Currency translation adjustments (1.4) - (1.4)
At 31 December (906.7) 349.5 (557.2)
ii) Amounts recognised in the statement of profit or loss
$m 2023 2022
Depreciation charge of right-of-use assets
Property leases 7.3 14.0
Oil and gas production and support equipment leases 74.1 46.9
Total 81.4 60.9
Interest expense on lease liabilities (included in finance costs) 78.6 76.4
Interest income on amounts due from Joint Venture Partners (30.1) (29.6)
Expense relating to short-term leases 1.0 2.0
Expense relating to leases of low-value assets 0.9 1.8
Total 131.8 111.5
The total net cash outflow for leases in 2023 was $195.0 million (2022: $203.8
million).
14. Provisions
$m Decommissioning Other provisions Total Decommissioning 2022 Other provisions Total
2023 2023 2023 2022 2022
At 1 January 398.1 116.3 514.4 498.7 228.8 727.5
New provisions, changes in estimates and reclassifications 47.8 (21.9) 25.9 (47.6) (19.7) (67.3)
Acquisitions(1) - - - 24.8 36.8 61.6
Transfer to assets and liabilities held for sale (14.2) - (14.2) - - -
Payments (66.4) (0.6) (67.0) (72.1) (127.3) (199.4)
Unwinding of discount 10.1 - 10.1 6.0 - 6.0
Currency translation adjustment 2.5 (0.1) 2.4 (11.6) (2.3) (13.9)
At 31 December 377.9 93.7 471.6 398.1 116.3 514.4
Current provisions 53.4 14.5 67.9 87.7 11.1 98.8
Non-current provisions 324.5 79.2 403.7 310.4 105.2 415.6
1. This relates to an acquisition through business combination discussed
in note 15 of the 2022 Annual Report and Accounts.
Other provisions include non-income tax provisions of $38.8 million (2022:
$68.3 million) and $54.9 million (2022: $48.0 million) of disputed cases and
claims. Management estimates non-current other provisions would fall due
between two and five years.
Non-Current other provisions includes a provision relating to a potential
claim arising out of historical contractual agreement. Further information is
not provided as it will be seriously prejudicial to the Company's interest.
The decommissioning provision represents the present value of decommissioning
costs relating to the European and African oil and gas interests. The 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 2023, after the extension of several licences in Gabon, the discount rate
has increased from 3.5% to 4% for those assets with an assumed cessation of
production date post 2038. This is due to a rate difference between the 10-
and 20-year US Treasury Bills which are used as a data source. This resulted
in a decrease in the provision of $3.1 million in Gabon.
Decommissioning provisions Inflation assumption(1) Discount rate assumption Cessation of production assumption Total Discount rate assumption Cessation of production assumption Total
2023 2023 2023 2022 2022 2022
$m $m
Côte d'Ivoire 2% 3.5% 2032 47.1 3.5% 2035 45.6
Gabon 2% 3.5-4% 2034-2047 28.7 3.5% 2025-2037 49.2
Ghana 2% 3.5% 2032-2036 208.2 3.5% 2036 190.2
Mauritania n/a n/a 2018 54.7 n/a 2018 56.0
UK n/a n/a 2018 39.2 n/a 2018 57.1
377.9 398.1
1. Short-term inflation rate assumption has decreased from 2.5% to 2.4%
in 2024. Medium and long-term rates of 2% remained unchanged from 31 December
2022.
The Group's decommissioning activities are ongoing in the UK and Mauritania,
with $53.4 of the future costs expected to be incurred in 2024. The remaining
activities are planned to continue through to 2027, with an associated
expenditure of $40.4 million.
15. Commercial Reserves and Contingent Resources summary working interest
basis
Ghana Non-Operated Kenya(6) Exploration Total
Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Petroleum
bcf
bcf
bcf
bcf
bcf(8)
mmboe
COMMERCIAL
RESERVES(1)
1 January 2023 164.3 157.3 37.8 5.1 - - - - 202.1 162.4 229.1
Revisions(3,4) (4.9) 8.4 7.0 2.8 - - - - 2.1 11.2 4.0
Production (15.5) (14.0) (4.9) (1.1) - - - - (20.4) (15.1) (22.9)
Acquisitions(5) - - 7.5 - - - - - 7.5 - 7.5
Disposals(7) - - (5.5) - - - - - (5.5) - (5.5)
31 December 2023 143.8 151.7 41.9 6.8 - - - - 185.8 158.5 212.2
CONTINGENT RESOURCES(2)
1 January 2023 185.0 577.8 36.0 8.6 231.4 - 54.5 - 506.9 586.4 604.6
Revisions(3,4) (32.2) (66.8) 1.8 1.1 - - - - (30.4) (65.7) (41.4)
Acquisitions - - 3.2 - 239.0 - - - 242.2 - 242.2
Disposals(7) (5.9) (54.5) (60.4) - (60.4)
31 December 2023 152.8 511.0 35.1 9.7 470.4 - - - 658.3 520.7 745.0
TOTAL
31 December 2023 296.6 662.7 77.0 16.5 470.4 - - - 844.1 679.2 957.2
1. Reserves presented are 'Proven and Probable'. They are as audited and
reported by independent third-party reserves auditor at YE 2023 and adjusted
for production for January - December 2023.
2. Contingent Resources are 'Proven and Probable'. They are as audited and
reported by independent third-party reserves auditor as at YE 2023 based on
best available information.
3. Reserves and Resources revisions in Ghana relate to evaluation of the
Jubilee South East (JSE) project, infill drilling and field performance in
Jubilee during 2023, which is offset by the recategorisation of the Tweneboa
oil project from reserves to contingent resource.
4. Reserves revisions in Gabon mainly relate to extension of Production
licences except for Etame and Ezanga, maturation of Echira Infill wells and
overall good field performance across all assets.
5. Reserves revisions in Gabon also include an asset swap with Perenco, in
which M'Oba, Oba, Limande, Turnix and a percentage of Simba have been
exchanged for an increased working interest in Tchatamba and the DE8
licence.
6. Kenya contingent resources have doubled to 470mmstb, with Tullow now
holding 100% of the licence, and a Field Development Plan under discussion
with government.
7. Guyana contingent resources have been removed following agreement with our
JV Partner Eco and the expiry of the Kanuku licence.
8. A gas conversion factor of 6 mscf/boe is used to calculate the total
Petroleum mmboe.
The Group provides for depletion and amortisation of tangible fixed assets on
a net entitlements basis, which reflects the terms of the Production Sharing
Contracts related to each field. Total net entitlement reserves were 204.5
mmboe at 31 December 2023 (31 December 2022: 219.6 mmboe).
Contingent Resources relate to resources in respect of which development plans
are in the course of preparation or further evaluation is under way with a
view to future development.
Alternative performance measures
The Group uses certain measures of performance 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 2023 2022
Additions to property, plant and equipment 416.1 370.7
Additions to intangible exploration and evaluation assets 25.4 39.2
Less
Changes to decommissioning asset estimate 47.8 (19.9)
Right-of-use asset additions 81.1 63.5
Lease payments related to capital activities (53.6) (40.2)
Additions to administrative assets 2.3 2.0
Other non-cash capital movements (16.0) 50.4
Capital investment 379.9 354.1
Movement in working capital (89.7) (49.7)
Additions to administrative assets 2.3 2.0
Cash capital expenditure per the cash flow statement 292.5 306.4
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.
$m 2023 2022
Borrowings 2,084.6 2,472.8
Non-cash adjustments 22.8 27.2
Less cash and cash equivalents (499.0) (636.3)
Net debt 1,608.4 1,863.7
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. Adjusted EBITDAX is defined as (loss)/profit
from continuing activities adjusted for income tax expense, finance costs,
finance revenue, loss/(gain) on hedging instruments, gain on bargain purchase,
other losses, depreciation, depletion and amortisation, share-based payment
charge, restructuring costs,loss/(gain) on disposal, gain on bond buy back,
exploration costs written off, impairment of property, plant and equipment net
and provision (reversal)/ expense.
$m 2023 2022
(Loss)/Profit from continuing activities (109.6) 49.1
Adjusted for
Income tax expense 205.5 393.0
Finance costs 329.6 335.5
Finance revenue (44.0) (42.9)
Loss/(Gain) on hedging instruments 0.4 (0.8)
Gain on bargain purchase - (196.8)
Other gains (0.2) (0.4)
Depreciation, depletion and amortisation 436.6 425.8
Share-based payment charge 6.0 5.8
Provision (reversal)/expense (22.0) 4.2
Gain on bond buy back (86.0) -
Exploration costs written off 27.0 105.2
Impairment of property, plant and equipment, net 408.1 391.2
Adjusted EBITDAX 1,151.4 1,468.9
Net debt 1,608.4 1,863.7
Gearing (times) 1.4 1.3
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 2022 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.
$m 2023 2022
Cost of sales 869.2 697.5
Add
Lease payments related to operating activity 7.2 14.0
Less
Depletion and amortisation of oil and gas and leased assets 430.8 410.7
Underlift, overlift and oil stock movements 109.3 (46.3)
Share-based payment charge included in cost of sales 0.4 0.4
Royalties 33.9 61.7
Other cost of sales 9.1 18.5
Underlying cash operating costs 292.9 266.5
Non-recurring costs(1) (25.9) (14.7)
Total normalised cash operating costs 267.0 251.8
Production (MMboe) 22.9 22.3
Underlying cash operating costs per boe ($/boe) 12.8 11.9
Normalised cash operating costs per boe ($/boe) 11.7 11.3
1. Non-recurring costs include riser remediation costs, facility
projects costs, CSV (Construction Support Vessel) campaign costs and shutdown
costs.
Free cash flow
Free cash flow is a useful indicator of the Group's ability to generate cash
flow to fund the business and strategic acquisitions, reduce borrowings and
provide returns to shareholders through dividends. Free cash flow is defined
as net cash from operating activities, and net cash from/(used) in investing
activities, repayment of obligations under leases, finance costs paid and
foreign exchange gain/(loss).
$m 2023 2022
Net cash from operating activities 876.2 1,077.8
Net cash used in investing activities (268.5) (356.2)
Repayment of obligations under leases (195.0) (203.8)
Finance costs paid (240.0) (249.0)
Foreign exchange loss (2.5) (1.6)
Free cash flow 170.2 267.2
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 2023 2022
Net cash from operating activities 876.2 1,077.8
Decommissioning expenditure 78.1 57.7
Lease payments related to capital activities 53.6 40.2
Repayment of obligations under leases (195.0) (203.8)
Underlying operating cash flow 812.9 971.9
Net cash from/(used in) investing activities (268.5) (356.2)
Decommissioning expenditure (78.1) (57.7)
Lease payments related to capital activities (53.6) (40.2)
Pre-financing cash flow 412.7 517.8
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