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 EBITDAX1 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 flow1 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
debt1 at year-end reduced to $1,608 million (2022:
$1,864 million); cash gearing of net debt to adjusted
EBITDAX1 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
A replay will be
available on the website from midday on 6 March 2024:
https://www.tullowoil.com/investors/results-reports-and-presentations/
CONTACTS
Tullow Oil plc
(London)
(+44 20 3249 9000)
Nicola Rogers
Matthew Evans
|
Camarco
(London)
(+44 20 3781 9244)
Billy Clegg
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
YouTube: www.youtube.com/TullowOilplc
Facebook: www.facebook.com/TullowOilplc
LinkedIn: 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
costs1
|
(293)
|
(267)
|
Depreciation, Depletion and Amortisation (DDA)
of oil and gas and leased assets
|
(431)
|
(411)
|
DDA before impairment charges
($/bbl)
|
18.8
|
18.4
|
(Overlift)/Underlift and oil stock
movements
|
(109)
|
46
|
Administrative expenses
|
(56)
|
(51)
|
Gain on bargain purchase
|
-
|
197
|
Exploration costs written off
|
(27)
|
(105)
|
Impairment of property, plant and equipment,
net
|
(408)
|
(391)
|
Gain on bond buyback
|
86
|
-
|
Net financing costs
|
(286)
|
(293)
|
Profit from continuing activities before
tax
|
96
|
442
|
Income tax expense
|
(206)
|
(393)
|
(Loss)/Profit for the year from continuing
activities
|
(110)
|
49
|
Adjusted EBITDAX1
|
1,151
|
1,469
|
Basic (loss)/earnings per share
(cents)
|
(7.6)
|
3.4
|
1. Alternative performance
measures are reconciled on pages 32 to 35.
Revenue
Sales Oil Volumes
During the year, there were 55,754 boepd
(2022: 55,170 boepd) of liftings. The total number of
liftings in Ghana is comparable to the previous year with 13 in
Jubilee (2022: 12) and 4 in TEN (2022: 5).
Realised oil price ($/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)
before tax
|
Tax
(expense)/credit
|
Adjusted
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
(floor)
|
Sold
call
|
Bought
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
(floor)
|
Sold
call
|
Bought
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 and equipment
|
292
|
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 value
|
27.8
|
30.8
|
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
capital
|
Share
premium
|
Foreign currency translation
reserve¹
|
Hedge
reserve²
|
Hedge
reserve - time
value²
|
Merger
reserves
|
Retained
earnings
|
Total
|
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).
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 result1
|
408.2
|
114.0
|
(17.9)
|
(9.9)
|
(164.6)
|
329.8
|
Provisions reversal
|
|
|
|
|
|
22.0
|
Other gains
|
|
|
|
|
|
0.2
|
Unallocated corporate
expenses2
|
|
|
|
|
|
(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 liabilities3
|
(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 result1
|
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
expenses2
|
|
|
|
|
|
(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 liabilities3
|
(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
assets1
|
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)/ expense2
|
(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
tax rate of 23.5% (2022: 19%)
|
22.5
|
84.0
|
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 write-off
|
2023
write-off/ (back)
$m
|
2023
Remaining recoverable amount
$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
Oil and gas
assets
|
2023
Other fixed
assets
|
2023
Right of use
assets
|
2023 Total
|
2022
Oil and gas assets
|
2022
Other fixed assets
|
2022
Right of
use assets
|
2022 Total
|
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
|
Acquisitions1
|
-
|
-
|
-
|
-
|
473.2
|
-
|
-
|
473.2
|
Transfer1
|
-
|
-
|
-
|
-
|
-
|
-
|
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 impairment
|
2023 Impairment $m
|
Pre-tax
discount rate
assumption
|
2023 Remaining
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
$m
|
2023
|
2022
|
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 liabilities1
|
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 2023
|
Other
provisions 2023
|
Total 2023
|
Decommissioning
2022
|
Other
provisions 2022
|
Total 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)
|
Acquisitions1
|
-
|
-
|
-
|
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
assumption1
|
Discount rate
assumption
2023
|
Cessation of production
assumption
2023
|
Total
2023 $m
|
Discount rate
assumption
2022
|
Cessation of production
assumption
2022
|
Total
2022 $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
|
Kenya6
|
Exploration
|
Total
|
|
Oil
mmbbl
|
Gas
bcf
|
Oil
mmbbl
|
Gas
bcf
|
Oil
mmbbl
|
Gas
bcf
|
Oil
mmbbl
|
Gas
bcf
|
Oil
mmbbl
|
Gas
bcf8
|
Petroleum
mmboe
|
COMMERCIAL
RESERVES1
|
|
|
|
|
|
|
|
|
|
|
1 January 2023
|
164.3
|
157.3
|
37.8
|
5.1
|
-
|
-
|
-
|
-
|
202.1
|
162.4
|
229.1
|
Revisions3,4
|
(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)
|
Acquisitions5
|
-
|
-
|
7.5
|
-
|
-
|
-
|
-
|
-
|
7.5
|
-
|
7.5
|
Disposals7
|
-
|
-
|
(5.5)
|
-
|
-
|
-
|
-
|
-
|
(5.5)
|
-
|
(5.5)
|
31 December 2023
|
143.8
|
151.7
|
41.9
|
6.8
|
-
|
-
|
-
|
-
|
185.8
|
158.5
|
212.2
|
CONTINGENT RESOURCES2
|
|
|
|
|
|
|
|
|
|
|
1 January 2023
|
185.0
|
577.8
|
36.0
|
8.6
|
231.4
|
-
|
54.5
|
-
|
506.9
|
586.4
|
604.6
|
Revisions3,4
|
(32.2)
|
(66.8)
|
1.8
|
1.1
|
-
|
-
|
-
|
-
|
(30.4)
|
(65.7)
|
(41.4)
|
Acquisitions
|
-
|
-
|
3.2
|
-
|
239.0
|
-
|
-
|
-
|
242.2
|
-
|
242.2
|
Disposals7
|
|
|
(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.
$m
|
|
2023
|
2022
|
Cost of sales
|
|
869.2
|
697.5
|
Add
|
|
|
|
Lease payments related to operating
activity
|
|
7.2
|
14.0
|
Less
|
|
|
|
Depletion and amortisation of oil and gas and
leased assets
|
|
430.8
|
410.7
|
Underlift, overlift and oil stock
movements
|
|
109.3
|
(46.3)
|
Share-based payment charge included in cost of
sales
|
|
0.4
|
0.4
|
Royalties
|
|
33.9
|
61.7
|
Other cost of sales
|
|
9.1
|
18.5
|
Underlying
cash operating costs
|
|
292.9
|
266.5
|
Non-recurring costs1
|
|
(25.9)
|
(14.7)
|
Total
normalised cash operating costs
|
|
267.0
|
251.8
|
Production (MMboe)
|
|
22.9
|
22.3
|
Underlying
cash operating costs per boe ($/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
|