TIDMTLW
RNS Number : 2715S
Tullow Oil PLC
08 March 2023
Tullow oil PLC - 2022 FULL Year Results
8 March 2023 - 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 2022. Details of a
management presentation and webcast are available on the last page
of this announcement or visit the Group's website
www.tullowoil.com.
Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented
today:
"2022 saw Tullow successfully deliver against our business plan.
A high focus on cost control and a disciplined approach to
operational efficiency has driven a very strong performance for the
year, with group production in line with guidance and expectations,
delivering free cash flow of $267 million, lowering net debt to
$1.9 billion and reducing cash gearing to 1.3x net debt to
EBITDAX.
"Looking ahead, we have multiple catalysts to deliver further
profitable growth. There is strong momentum across the portfolio
with the commissioning of Jubilee South East on track for the
second half of 2023, bringing undeveloped reserves online and
Jubilee gross production to more than 100 kbopd before the end of
the year. Engagements to secure a strategic partner for the Kenya
development project continue and we are preparing a plan of
development to monetise the remaining resources at TEN.
"We have created a unique platform of assets and capability,
including industry leading safety performance, which positions us
strongly to create significant value for all our stakeholders."
2022 FULL YEAR results HIGHLIGHTS
-- Significant growth in revenue to $1,783 million (including
hedge costs of $319 million), representing a c.40% increase versus
2021.
-- Gross profit of $1,086 million (2021: $647 million); profit
after tax of $49 million (2021: loss after tax of $81 million).
-- Increase in underlying operating cash flow(1) to $972 million
(2021: $711 million) and free cash flow(1) to $267 million (2021:
$245 million), despite increased capital expenditure of $354
million (2021: $263 million), decommissioning expenditure of $72
million (2021: $69 million) and $126 million consideration for the
pre-emption transaction in Ghana.
-- Net debt(1) at year-end reduced to $1,864 million (2021:
$2,131 million); cash gearing of net debt to EBITDAX(1) of 1.3
times (2021: 2.2 times) three years ahead of original target;
liquidity headroom of $1,055 million (2021: $876 million).
-- Industry leading safety performance, with zero lost time
injuries and zero Tier 1 process safety incidents across Tullow's
global operations in 2022.
-- Group working interest production averaged 61.1 kboepd (2021:59.2 kboepd).
-- Strong operating, drilling and completion performance in
Ghana, with facilities uptime of c.97% and four Jubilee wells and
two Enyenra wells brought online. Two Ntomme riser base area wells
were also drilled but did not encounter economically developable
resources.
-- The transition of operatorship of the Jubilee FPSO took place
in July 2022 and FPSO uptime averaged c.99% in the second half of
2022, compared to c.95% in the first half.
-- Interim Gas Sales Agreement for 19 bcf of Jubilee gas
executed, representing the first commercialisation of Jubilee
gas.
-- A significant milestone was reached in Ghana with a Letter of
Intent (LoI) signed with the Ghana Forestry Commission for a
nature-based carbon offset project. Final Investment Decision (FID)
is expected in 2023.
-- New exploration licence secured in Côte d'Ivoire (CI-803),
building a strategic position adjacent to the Group's producing
fields in Ghana.
-- Phuthuma Nhleko appointed as Chair from January 2022.
2022 Key Financial Results
2021
2022 Restated(2)
================================ ====== =============
Total revenue ($m) 1,783 1,285
================================ ====== =============
Gross profit ($m) 1,086 647
================================ ====== =============
Profit / (loss) after tax ($m) 49 (81)
================================ ====== =============
Free cash flow ($m)(1) 267 245
================================ ====== =============
Net debt ($m)(1) 1,864 2,131
================================ ====== =============
Gearing (times)(1) 1.3 2.2
================================ ====== =============
1 Alternative performance measures are reconciled on pages 31 to 34.
2 Refer to note 7 for details on prior year restatement.
2023 outlook
-- Group working interest oil production guidance of 58 to 64 kbopd.
-- Gross production from Jubilee expected to increase to over
100 kbopd with four new wells at Jubilee South East and a further
Jubilee producer onstream later this year.
-- Forecast capital expenditure of c.$400 million, split c.$300
million in Ghana, c.$40 million in Gabon, c.$20 million in Côte
d'Ivoire, c.$10 million in Kenya and c.$30 million on exploration
and appraisal activities.
-- Completion of Jubilee South East infrastructure in the first
half of 2023 will mark the end of the current major infrastructure
spend on Jubilee.
-- Forecast decommissioning expenditure of c.$90 million in the
UK and Mauritania, with a further c.$20 million placed into escrow
funds for future decommissioning in Ghana and parts of the
non-operated portfolio. Decommissioning expenditure is weighted
more than 80% to the first half of the year.
-- Full year underlying operating cash flow(1) guidance of
c.$900 million at $100/bbl (c.$800 million at $80/bbl).
-- Full year free cash flow(1) guidance of c.$200 million at
$100/bbl (c.$100 million at $80/bbl). Free cash flow will be
weighted towards the second half of the year as the Jubilee South
East wells come onstream.
-- Cash gearing of net debt to EBITDAX(1) expected to be c.1 times by year end at $100/bbl.
-- Jubilee FPSO operations & maintenance (O&M) costs
expected to be c.23% lower than in 2021, following O&M
transformation undertaken in 2022.
-- Plan to agree a long-term gas sales agreement with the
Government of Ghana covering both Jubilee and TEN fields.
-- Two disputed Ghanaian tax assessments filed for arbitration
with International Chamber of Commerce in London in February
2023.
-- Continued focus on securing FDP approval and a strategic partner for Project Oil Kenya.
-- Richard Miller appointed as Chief Financial Officer (CFO) from January 2023.
-- Roald Goethe appointed as independent non-executive Director from February 2023.
Environment, Social and Governance (ESG)
Environment
Tullow has made progress on its decarbonisation roadmap to
achieve Net Zero on its Scope 1 and 2 CO(2) e emissions by 2030 on
a net equity basis:
-- Significant progress was made on the commitment to eliminate
routine flaring by 2025, the largest source of Scope 1 emissions.
Tullow invested $15 million in its floating production, storage and
offloading (FPSO) vessels in 2022 as part of a multi-year, $45
million decarbonisation programme that is expected to reduce Scope
1 and 2 emissions by c.40% against a 2020 baseline.
-- Tullow completed a feasibility study for a nature-based
carbon offset project that could off-set remaining, hard to abate
CO(2) e emissions, estimated to be 600,000 tonnes per annum. In
December 2022, Tullow signed an LoI with the Ghana Forestry
Commission, marking a key milestone for the project as part of
Tullow's plans to reach Net Zero by 2030. This project can also
support Ghana in meeting its Nationally Determined Contributions
under the Paris Agreement. FID is expected in 2023.
Social
Tullow's Shared Prosperity strategy delivered positive impact
through focusing on young people's education, enterprise support,
developing local supply chains and material fiscal contributions to
host governments. Key highlights include:
-- Supported 6,000+ secondary and tertiary students with Tullow
STEM scholarships, bursaries and after school support in Ghana,
Kenya, Guyana and Suriname.
-- Provided accommodation and classroom facilities for 3,000
pupils through a $10 million infrastructure commitment to promote
enrolment in Free Senior High Schools in Ghana.
-- The Fisherman's Anchor Project provided small loans to over
1,300 businesses; over 90% of the businesses are owned by women and
nearly 90% are fish processing businesses.
-- Spent $173 million with local suppliers in 2022, which
represented 15% of local procurement spend, bringing total five
year spend to c.$1.2 billion.
-- Fiscal contributions to host governments amounted to $468
million in 2022 (2021: $234 million).
-- Employee engagement initiatives in place, including employee
advisory panel and an 88% response rate to our most recent employee
survey, with an overall positivity score of 70%.
(1) Alternative performance measures are reconciled on pages 31
to 34
Governance
Phuthuma Nhleko was appointed as Chair of Tullow in January
2022, having joined as a Non-Executive Director in October 2021.
Jeremy Wilson retired as a Non-Executive Director in October,
having completed nine years on the Board of Tullow. Roald Goethe
was appointed as independent Non-Executive Director of Tullow in
February 2023 following a review of Board composition by the
Nominations Committee. The composition of Tullow's Board reflects
the countries in which it operates, and three out of nine directors
are African nationals. Female representation remains 22% (two out
of nine).
Richard Miller was appointed as CFO and as an Executive Director
of Tullow in January 2023. Richard was appointed as Interim CFO in
April 2022 and has been with Tullow for over 11 years. During that
time Richard led the Tullow Finance team, supporting a number of
acquisitions, disposals and capital markets transactions. Richard
played a significant role in the continued turnaround of Tullow
with the successful rebasing of Tullow's cost structure, the
resetting of the balance sheet and the change to a more focused
capital allocation.
On 30 May 2023, Mike Daly will have served nine years on the
Board as an independent Non-Executive Director and will therefore
not seek re-election as a Director at this year's Annual General
Meeting, anticipated to be on 24 May 2023. He will step down as a
Director with effect from the conclusion of the AGM. The
Nominations Committee is undertaking a search for his replacement,
taking into account the results of the external facilitated
evaluation of Board effectiveness in 2022, the skills and
experience required on the Board to implement the Company's
strategy, and Tullow's inclusion and diversity ambitions.
Operational Review
Production, Reserves and Resources
In 2022, Group working interest production averaged 61.1 kboepd,
in line with guidance following pre-emption of the Deep Water Tano
component of the Kosmos Energy/Occidental Petroleum Ghana
transaction.
Group working interest production guidance for 2023 is 58-64
kboepd, excluding 19 bcf of gas sold under the Interim Gas Sales
Agreement and any additional volumes of gas sold during the course
of the year. The main driver of production growth in 2023 is
expected to be the Jubilee South East development which is due
onstream in the second half of the year. The near-term focus on TEN
is to sustain the strong operational uptime and improve gas
handling on the FPSO this year, which will facilitate a reduction
in flaring and increased gas injection to support oil production.
Improvements on the gas processing facilities will be implemented
during a planned maintenance shutdown, scheduled for the third
quarter of the year. A two week FPSO maintenance shut-down will
impact production from TEN. Production from the non-operated
portfolio will be supported by new wells planned at Tchatamba,
Ezanga and Etame.
Group average working interest production FY 2022 (kboepd) FY 2023 range (kboepd)
=========================================== ================= =======================
Ghana 44.4 48
=========================================== ================= =======================
Jubilee 31.9 37
=========================================== ================= =======================
TEN 12.5 11
=========================================== ================= =======================
Non-operated portfolio 16.7 14
=========================================== ================= =======================
Gabon 14.9 13
=========================================== ================= =======================
Cote d'Ivoire 1.8 1
=========================================== ================= =======================
Group 61.1 58-64
=========================================== ================= =======================
The Group's audited 2P reserves are 229 mmboe at the end of 2022
(2021: 231 mmboe). Group reserves replacement was c.90% as a result
of the additional equity acquired through the pre-emptive
transaction in Ghana and other positive revisions including
transfers from contingent resources, offset by reduction in TEN due
to greater than expected base decline in Enyenra and the two Ntomme
riser base area well results. As at 31 December 2022 the audited 2P
NPV10 was $3,895 million (2021: $3,633 million).
The Group's audited 2C resources reduced to 605mmboe at the end
of 2022 (2021: 625mmboe). This was principally due to the
evaluation of several projects in the TEN development area, some of
which have been upgraded from contingent resources to reserves.
Ghana
Jubilee
Production from the Jubilee field increased from an average of
74.9 kbopd (26.6 kbopd net) in 2021 to 83.6 kbopd (31.9 kbopd net)
in 2022. Continued excellent operational efficiency of c.97% (2021:
c.98%) was achieved and production was supported by four new wells
(one producer and three water injectors) coming online ahead of
schedule due to outstanding drilling and completions
performance.
Two wells were drilled in the Jubilee South East area in the
second half of 2022 and a third well in January 2023. Primary
target reservoir results are in line with expectations, but with
upside from deeper appraisal target reservoirs that encountered oil
resources for future development. These wells will commence
production in the second half of the year after the installation
and tie-in to the Jubilee South East Project subsea infrastructure,
in line with the initial project schedule. The completion of the
Jubilee South East Project will mark the end of the current major
infrastructure spend in the Jubilee area with the majority of
near-term capex expected to be focused on drilling and completing
new wells.
First oil from the Jubilee South East project will be a
significant milestone, bringing previously undeveloped reserves to
production and helping define future growth opportunities in the
Jubilee area. This project, which was delivered through a
multi-national supply chain effort, is being delivered on budget
despite the inflationary environment and challenges associated with
COVID-19 during 2020-22, highlighting Tullow's project management
strengths and ability to integrate deliverables across a global
team.
In 2023, Jubilee oil production is expected to average c.95
kbopd (c.37 kbopd net), with five wells expected to come online,
starting in the middle of the year. Gross oil production from the
Jubilee field is expected to exceed 100 kbopd once all these wells
have been brought online. This rate increase is also enabled by the
successful execution of expansion work on the Jubilee FPSO,
increasing water and gas handling capacity to support the
additional well stock coming online. The focus on operational
excellence in production, drilling and major project delivery in
recent years has yielded appreciable value and will continue to be
an area of leverage for Tullow.
TEN
Production from the TEN fields averaged 23.6 kbopd (12.5 kbopd
net) in 2022. Continued excellent operational efficiency of c.98%
(2021: c.97%) was achieved with overall production at the lower end
of guidance.
Ntomme gross production averaged 16.8 kbopd for the full year.
No new wells were brought online during the year at Ntomme, but
pressure support from existing gas and water injection wells
resulted in steady production. Enyenra gross production averaged
6.8 kbopd for the full year, supported strongly in the fourth
quarter by a new production well, which was brought online in
September 2022. Currently producing 3 kbopd, this well and a new
water injector brought online in December 2022 will contribute to
supporting production in 2023.
Two wells drilled in the Ntomme riser base area did not
encounter economically developable resources and will not be
completed in 2023 as originally intended, removing c.2.5 kbopd net
from previously expected 2023 production.
The longer term plan for TEN is to monetise its significant
remaining resources through infill drilling, phased development of
new areas near existing infrastructure, development of the
significant gas resources and drilling of prospective resources. A
restructuring of the FPSO cost base is under evaluation to enable
sustained cost efficiency in production operations. Tullow expects
to submit a plan of development to the Government of Ghana later
this year.
In 2023, TEN production is expected to average c.20 kbopd (c.11
kbopd net), including the planned two-week maintenance shutdown. No
new wells are planned to be added in TEN in 2023.
Jubilee Operations and Maintenance Transformation
The transition of operatorship to Tullow on the Jubilee FPSO
took place in July 2022. This is a major step in Tullow's
transformation to a leading low-cost deep-water operator, and is
expected to deliver sustainable improvements in safety, reliability
and cost. Following the transition, which is supported by a
comprehensive multi-year transformation plan, FPSO uptime averaged
c.99% in the second half of 2022, compared to c.95% in the first
half. Operations and maintenance (O&M) costs were c.30% lower
in the second half of the year compared to the first, and 2023 full
year O&M costs are expected to be c.23% lower than in 2021,
demonstrating the sustainability of the structural changes
delivered through the transformation, helping mitigate the impact
of inflation through the supply chain, and allowing for sustained
prioritisation of FPSO upkeep activities which are important for
maintaining the FPSO's top-tier performance for the long-term.
Gas Commercialisation
In December 2022, an Interim Gas Sales Agreement for 19 bcf
gross of Jubilee gas was executed, utilising the price for TEN
associated gas referenced in the 2017 TEN Gas Sales Agreement which
was $50c/mmbtu. The 19 bcf is expected to have been supplied by the
middle of the year at an anticipated export rate in excess of 100
mmscfpd, adding c.7 kboepd net production during the first half of
the year. Further gas export will be contingent on reaching
agreement on acceptable commercial terms for future volumes.
Tax exposure
As announced on 14 February 2023, throughout 2021 and 2022,
Tullow has received revised and new tax assessments from the Ghana
Revenue Authority (GRA). Tullow believes these assessments are
without merit and filed requests for arbitration with the
International Chamber of Commerce in London, in accordance with the
dispute resolution process set out in the Petroleum Agreements
which govern TGL's activities in Ghana. Notwithstanding this formal
step, Tullow intends to 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 PORTFOLIO
Production from Tullow's non-operated portfolio in Gabon and
Côte d'Ivoire averaged 16.7 kboepd net in 2022 (2021: 17.2 kboepd
net), supported by new wells brought online in Tchatamba, Ezanga
and Etame. Capital expenditure in Gabon and Côte d'Ivoire in 2022
was c.$43 million net, with approximately 60% allocated to
infrastructure projects, including the tie-back of the Wamba
discovery for a long-term production test.
In Côte d'Ivoire, remediation work on the Espoir FPSO will
continue through 2023. A 4D seismic survey will be acquired over
the licence to support the upcoming infill development drilling
campaign and mature future investment projects.
Net production from the non-operated portfolio is expected to
average c.14 kboepd in 2023, which includes production from the
Wamba discovery long-term production test which will continue
throughout 2023. Total capital expenditure is expected to be c.$60
million net, of which c.75% will be allocated to infrastructure
projects to support future developments and production. The
remaining investment will be in new wells at the Ezanga Complex and
workovers across the portfolio to sustain production levels.
DECOMMISSIONING
In the UK and Mauritania, decommissioning expenditure was c.$72
million in 2022 and is expected to be c.$90 million in 2023 which
is the last year of significant decommissioning spend. At the end
of 2023, it is expected that less than $30 million of
decommissioning liabilities will remain for the two countries.
In 2022, UK decommissioning activity included the removal of
four platforms (three at the Murdoch Hub and the Ketch platform).
Removal of the Ketch pipeline commenced in 2022 and is expected to
complete in the second half of 2023. Eleven Schooner wells were
successfully plugged and abandoned. Plugging and abandonment work
has also begun at the Boulton field, as part of an eight well
campaign in the CMS area. In Mauritania, the Tullow operated Banda
and Tiof decommissioning campaign commenced in December 2022 and is
expected to complete by the middle of the year.
Starting in 2023, c.$20 million will be required to be paid
annually into escrow for future decommissioning of currently
producing assets in Ghana and parts of the non-operated
portfolio.
KENYA
Engagements to secure a strategic partner for the development
project in Kenya are ongoing.
In March 2023, Tullow and its JV Partners submitted an updated
Field Development Plan to the Ministry of Energy and Petroleum and
the Energy and Petroleum Regulatory Commission Authority, for their
approval. This is currently under review by the relevant
authorities.
Kenya continues to remain an important asset in Tullow's
development portfolio, with the potential to add material reserves
and create value for shareholders.
EXPLORATION
Capital expenditure on exploration and appraisal activities was
c.$45 million in 2022 and is expected to be c.$30 million in
2023.
In Guyana, the operator of the Kanuku licence (Tullow 37.5%),
Repsol, drilled the Beebei-Potaro prospect which encountered water
bearing reservoirs, and the well was plugged and abandoned.
In Gabon, Tullow, together with JV Partner Perenco, is focused
on maturing the prospective resource base within the Simba licence,
where several low-risk and compelling investment options adjacent
to infrastructure have been high-graded for near term drilling
programmes.
In Côte d'Ivoire, Tullow, together with its JV Partner PetroCi,
has elected to proceed into the second exploration phase in Block
CI-524 and is maturing a number of drilling candidates. Tullow has
enhanced its strategic position in the Tano Basin, where it has a
differentiated subsurface understanding, with a 90% interest in a
new offshore exploration licence (CI-803), which is adjacent to
Block CI-524 and also to Tullow's producing fields in Ghana.
In the emerging basins of Argentina and Guyana, Tullow continues
to pursue activities to unlock value from its significant
prospective resource base. A two year extension has been secured in
Block MLO-122 in Argentina.
PROPOSED MERGER
On 1 June 2022, Tullow entered into an agreement for a proposed
all-share merger with Capricorn Energy PLC ("Capricorn"). The aim
of the proposed merger was to create a leading African energy
company, and it would have enabled Tullow to accelerate its
deleveraging trajectory and investment in growth.
On 29 September 2022, Tullow noted the announcement released by
Capricorn in connection with its proposed combination with NewMed
Energy Limited Partnership. Tullow's Board decided that it would
not increase the value of Tullow's offer for Capricorn or to elect
to implement its offer by way of a contractual offer, and later
confirmed that it will no longer proceed with the proposed
merger.
Finance review
Income Statement
Income Statement (key metrics) 2022 2021
Restated(1)
================================================================================= ======= =============
Revenue ($m)
================================================================================= ======= =============
Sales volume (boepd) 55,170 55,450
================================================================================= ======= =============
Realised oil price ($/bbl) 88.0 63.3
================================================================================= ======= =============
Total revenue 1,783 1,285
--------------------------------------------------------------------------------- ------- -------------
Operating costs ($m)
================================================================================= ======= =============
Underlying cash operating costs (2) (267) (269)
================================================================================= ======= =============
Depreciation, Depletion and Amortisation (DDA) of oil and gas and leased assets (411) (361)
================================================================================= ======= =============
DDA before impairment charges ($/bbl) (18.4) (16.7)
================================================================================= ======= =============
Underlift and oil stock movements (46) (20)
================================================================================= ======= =============
Administrative expenses (51) (64)
================================================================================= ======= =============
Gain on bargain purchase 197 -
================================================================================= ======= =============
Exploration costs written off (105) (60)
================================================================================= ======= =============
Impairment of property, plant and equipment, net (391) (54)
================================================================================= ======= =============
Net financing costs (293) (312)
================================================================================= ======= =============
Profit from continuing activities before tax 442 215
================================================================================= ======= =============
Income tax expense (393) (296)
================================================================================= ======= =============
Profit/(Loss) for the year from continuing activities 49 (81)
================================================================================= ======= =============
Adjusted EBITDAX (2) 1,469 973
================================================================================= ======= =============
Basic earnings/(loss) per share (cents) 3.4 (5.7)
================================================================================= ======= =============
1 Refer to note 7 for details on prior year restatement.
2 Alternative performance measures are reconciled on pages 31 to 34.
Revenue
Sales Volumes
During the period there were 55,170 boepd (2021: 55,450 boepd)
of liftings. This mainly consisted of 13 liftings in Jubilee of
29,322 boepd and 5 liftings in TEN of 12,270 boepd compared to 10
liftings in Jubilee of 25,987 boepd and 5 liftings in TEN of 13,511
boepd in 2021. The increase in Jubilee liftings was mainly driven
by increased production. Refer to Operations Review on page 3.
Realised oil price ($/bbl)
The Group's realised oil price after hedging for the period was
$88.0/bbl and before hedging $104.3/bbl (2021: $63.3/bbl and
$70.9/bbl, respectively). The higher oil price during 2022 resulted
in hedge losses, decreasing total revenue by $319 million (2021:
decrease of $153 million). The increase in oil prices was triggered
by Russia's invasion of Ukraine in February 2022.
Cost of Sales
Underlying cash operating costs
Underlying cash operating costs amounted to $267 million;
$11.9/boe (2021: $269 million; $12.4/boe). The decrease in
operating costs is due to the disposal of Equatorial Guinea and the
Dussafu asset in Gabon in 2021 and the O&M transformation
project on Jubilee (refer to Operations Review) offset by the
shutdown in Jubilee in Ghana, the Simba expansion project costs in
Gabon and the increased equity interest in Ghana following
pre-emption.
Normalised cash operating costs which exclude COVID-19 operating
procedures, shuttle tanker operations, Construction Support Vessel
(CSV) campaign and shutdown costs were $11.3/boe (2021:
$12.1/boe).
Depreciation, depletion and amortisation
DD&A charges before impairment of oil and gas and leased
assets amounted to $411 million; $18.4/boe (2021: $361 million:
$16.7/boe). This increase in DD&A per barrel is mainly
attributable to Ghana pre-emption which was effective 1Q22 and
downward revision of TEN 2P reserves partially offset by 2021
impairments.
Underlift and oil stock movements
The underlift in the income statement was mainly due to timings
of the liftings in Ghana as well as increased oil prices and stock
positions in Gabon.
Administrative expenses
Administrative expenses of $51 million (2021: $64 million) have
decreased against the comparative period mainly due to lower
payroll related costs as a result of the reduced headcount as well
as a favourable GBP:USD FX variance in 2022. Tullow achieved
approximately $300 million in net cash savings since mid-2020 to
date thereby delivering in excess of the target set.
Gain on bargain purchase
On 17 March 2022, the Group completed the pre-emption related to
the sale of Occidental Petroleum's interests in the Jubilee and TEN
fields in Ghana to Kosmos Energy. As a result of this acquisition,
the Group's interest in the TEN fields increased from 47.18% to
54.84%, and from 35.48% to 39.0% in the Jubilee field. The
difference between the fair value of net assets acquired and
consideration paid was recognised within the income statement as a
gain on bargain purchase of $197 million. Refer to note 12 Business
combination.
Exploration costs written off
During 2022, the Group has written off exploration costs of $105
million (2021: $60 million) which are predominantly driven by
write-offs from Guyana after the completion of the Beebei-Potaro
commitment well which was plugged and abandoned.
Impairment of property, plant and equipment
The Group recognised a net impairment charge on producing assets
of $391 million in respect of 2022 (2021: $54 million). Impairments
are mainly due to downward revision of TEN reserves as well as
changes to estimates on the cost of decommissioning for certain UK
and Mauritania assets.
Net financing costs
Net financing costs for the period were $293 million (2021: $312
million). The decrease in financing costs is mainly due to $19
million fees incurred in 2021 in relation to the refinancing of the
RBL facility, and a decrease of $7 million in interest on
obligations under finance leases due to a decrease in lease
liability position offset by an increase in interest on borrowings
of $7 million.
Net financing costs include interest incurred on the Group's
debt facilities, foreign exchange gains/losses, the unwinding of
discount on decommissioning provisions, and the net financing costs
associated with lease assets. These costs are offset by interest
earned on cash deposits. A reconciliation of net financing costs is
included in note 6.
Taxation
The overall net tax expense of $393 million (2021: $296 million)
primarily relates to tax charges in respect of the Group's
production activities in West Africa, as well as UK decommissioning
assets, reduced by deferred tax credits associated with exploration
write-offs, impairments and provisions for onerous service
contracts.
Based on a profit before tax for the year of $442 million (2021:
$215 million), the effective tax rate is 88.9 per cent (2021: 137.6
per cent). After adjusting for non-recurring amounts related to
acquisition through business combination, exploration write-offs,
disposals, impairments, provisions for onerous service contracts
and their associated deferred tax benefit, the Group's adjusted tax
rate is 70.3 per cent (2021: 116.4 per cent). The effective tax
rate has decreased primarily due to the release of provisions on
the settlement of tax audits and higher taxes on uncertain
treatments in the prior year, offset by there being no UK tax
benefit from net interest and hedging expenses of $570m (2021:
$417m). Non-deductible expenditure in Ghana and Gabon and prior
year adjustments are additional contributing factors.
The Group's future statutory effective tax rate is sensitive to
the geographic mix in which pre-tax profits arise. There is no UK
tax benefit from net interest and hedging expenses, whereas net
interest income and hedging profits would be taxable in the UK.
Consequently, the Group's tax charge will continue to vary
according to the jurisdictions in which pre-tax profits occur.
Analysis of adjusted Adjusted Tax (expense)/credit Adjusted
effective tax rate Profit/(loss) Effective
($m) before tax tax rate
====================== ============ =============== ===================== ===========
Ghana FY 2022 994.8 (359.7) 36.2%
====================== ============ =============== ===================== ===========
FY 2021 450.9 (163.3) 36.2%
=================================== =============== ===================== ===========
Gabon FY 2022 316.1 (158.9) 50.3 %
====================== ============ =============== ===================== ===========
FY 2021 185.0 (95.2) 51.5%
=================================== =============== ===================== ===========
Equatorial Guinea FY 2022 - - -
====================== ============ =============== ===================== ===========
FY 2021 15.5 (5.4) 35.0%
=================================== =============== ===================== ===========
Corporate FY 2022 (584.5) 3.5 0.6%
====================== ============ =============== ===================== ===========
FY 2021 (386.0) (41.8) (10.8)%
=================================== =============== ===================== ===========
Other non-operated
& exploration FY 2022 15.9 (6.9) 43.5 %
====================== ============ =============== ===================== ===========
FY 2021(1) 5.1 (9.1) 178.2 %
=================================== =============== ===================== ===========
Total FY 2022 742.3 (522.1) 70.3%
====================== ============ =============== ===================== ===========
FY 2021(1) 270.6 (314.9) 116.4%
=================================== =============== ===================== ===========
1 The prior year has been restated to include the notional tax
on the profit oil within current tax expense in accordance with the
terms of the respective Production Sharing Contracts (PSCs).
Adjusted EBITDAX
Adjusted EBITDAX for the year was $1,469 million (2021: $973
million). The increase from 2021 was predominantly due to higher
revenues.
Profit for the year from continuing activities and earnings per
share
The profit for the year from continuing activities amounted to
$49 million (2021: $81 million loss). Profit after tax has
increased by $130 million driven by higher revenues and lower
costs. Basic earnings per share was 3.4 cents (2021: 5.7 cents loss
per share).
Balance Sheet and Liquidity management
Balance Sheet and Liquidity management (key metrics) 2022 2021
====================================================== ======== ========
Capital investment ($m)(1) 354 263
====================================================== ======== ========
Derivative financial instruments ($m) (244) (180)
====================================================== ======== ========
Borrowings ($m) (2,473) (2,569)
====================================================== ======== ========
Underlying operating cash flow ($m) (1) 972 711
====================================================== ======== ========
Free cash flow ($m)(1) 267 245
====================================================== ======== ========
Net debt ($m)(1) 1,864 2,131
====================================================== ======== ========
Gearing (times)(1) 1.3 2.2
====================================================== ======== ========
1 Alternative performance measures are reconciled on pages 31 to 34.
Capital investment
Capital expenditure amounted to $354 million (2021: $263
million) with $309 million invested in production and development
activities and $45 million invested in exploration and appraisal
activities.
Tullow will continue to maintain capital discipline primarily
directing investment towards maximising value from the Group's
producing assets. The Group's 2023 capital expenditure is expected
to comprise Ghana capex of c.$300 million, West African
non-operated capex of c.$60 million, Kenya capex of c.$10 million
and exploration spend of c.$30 million.
Derivative financial instruments
Tullow has a material hedge portfolio in place to protect
against commodity price volatility and to ensure the availability
of cash flow for re-investment in capital programmes that are
driving business delivery.
At 31 December 2022, Tullow's hedge portfolio provides downside
protection for 64% of forecast production entitlements through to
May 2023 and 40% for a further 12 months to May 2024 with $55/bbl
floors and weighted average sold calls of $75/bbl.
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 (2021: Level 2).
There were no transfers between fair value levels during the
year.
At 31 December 2022, the Group's derivative instruments had a
net negative fair value of $244 million (2021: net negative $180
million).
Hedge position as at 31 December 2022
2023 2024 2025
Hedged volume (bopd) 33,095 11,305 -
============================================= ======== ========
Weighted average bought put (floor) ($/bbl) $55/bbl $55/bbl -
============================================= ======== ========
Weighted average sold call ($/bbl) $75/bbl $75/bbl -
============================================= ======== ========
Borrowings
In May 2022, the Group made a mandatory prepayment of $100
million of the Senior Secured Notes due 2026, which reduced total
drawn debt to $2.5 billion.
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) and Moody's Investors Service (Moody's).
On 31 May 2022, S&P's revised Tullow's outlook to positive,
and re-affirmed Tullow's B- corporate credit rating, the B- rating
of the $1.7 billion Senior Secured Notes due 2026, and the CCC+
rating of the $800 million Senior Notes due 2025. On 18 August
2022, S&P's revised Tullow's outlook to negative following
S&P's downgrade of Ghana's foreign and local currency sovereign
ratings. Concurrently, S&P's affirmed the B- rating of the $1.7
billion Senior Secured Notes due 2026, and the CCC+ rating of the
$800 million Senior Notes due 2025.
On 9 June 2022, Moody's changed Tullow's outlook to positive and
affirmed the B3 corporate credit rating, the B2 rating of the $1.7
billion Senior Secured Notes due 2026, and the Caa2 rating of the
$800 million Senior Notes due 2025. On 6 October 2022, Moody's
placed Tullow's ratings on review for downgrade, primarily driven
by Moody's downgrade and placing on review for further downgrade of
Ghana's long-term issuer and senior unsecured debt ratings to Caa2
from Caa1. On 2 December 2022, Moody's downgraded Tullow's
corporate credit rating to Caa1 with negative outlook, and the
rating of the $1.7 billion Senior Secured Notes due 2026 to Caa1.
Concurrently, Moody's confirmed the Caa2 rating of the $800 million
Senior Notes due 2025. The rating action concluded the review for
downgrade initiated by Moody's on 6 October 2022 and reflected
Moody's downgrade of Ghana's long-term issuer rating to Ca from
Caa2 and the concurrent downward revision of Ghana's local currency
and foreign currency country ceilings to Caa1 and Caa2
respectively, from B2 and B3.
Free cash flow and Underlying operating cash flow
Underlying operating cash flow increased to $972 million (2021:
$711 million), primarily due to an increase in revenue.
Free cash flow increased to $267 million compared to $245
million in 2021 primarily due to an increase in underlying
operating cash flow as explained above and no debt arrangement fees
being incurred in 2022, partially offset by increase in capital
investment due to the increased equity interest in Ghana.
Net debt and Gearing Reconciliation of net debt $m
============================================================================================= ========
Year-end 2021 net debt 2,131
============================================================================================= ========
Sales revenue (1,783)
============================================================================================= ========
Operating costs 267
============================================================================================= ========
Other operating and administrative expenses 257
--------------------------------------------------------------------------------------------- --------
Cash flow from operations (1,259)
============================================================================================= ========
Movement in working capital (29)
============================================================================================= ========
Tax paid 229
============================================================================================= ========
Purchases of intangible exploration and evaluation assets and property, plant and equipment 433
============================================================================================= ========
Other investing activities (77)
============================================================================================= ========
Other financing activities 434
============================================================================================= ========
Foreign exchange loss on cash 2
--------------------------------------------------------------------------------------------- --------
Year-end 2022 net debt 1,864
============================================================================================= ========
Net debt reduced by $267 million during the year to $1,864
million at 31 December 2022 (31 December 2021: $2,131 million),
consisting of $800 million Senior Notes due 2025 and $1,700 million
Senior Secured Notes due 2026 less cash and cash equivalents. In
May 2022, $100 million of the Senior Secured Notes due 2026 was
prepaid at par.
The Gearing ratio has decreased to 1.3 times (2021: 2.2 times)
due to an increase in Adjusted EBITDAX as explained above primarily
due to higher revenues. This is ahead of guidance at the start of
the year which indicated that gearing should reach 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 2024. The Group closely monitors and manages its
liquidity headroom. Cash forecasts are regularly produced, and
sensitivities run for different scenarios including, but not
limited to, changes in commodity prices, different production rates
from the Group's producing assets and different outcomes on ongoing
disputes or litigation.
Management has applied the following oil price assumptions for
the going concern assessment:
Base Case: $84/bbl for 2023, $79/bbl for 2024; and
Low Case: $70/bbl for 2023, $70/bbl for 2024.
The Low Case includes, amongst other downside assumptions, a 5
per cent production decrease compared to the Base Case.
At 31 December 2022, the Group had $1.1 billion liquidity
headroom consisting of c.$0.6 billion free cash and $0.5 billion
available under the revolving credit facility.
The Group's forecasts show that the Group will be able to
operate within its current debt facilities and have sufficient
financial headroom for the going concern assessment period under
its Base Case and Low Case. Based on the analysis above, the
Directors have a reasonable expectation that the Group has adequate
resources to continue in operational existence for the foreseeable
future. Thus, they have adopted the going concern basis of
accounting in preparing the year end result.
Events since 31 December 2022
As announced on 14 February 2023, throughout 2021 and 2022,
Tullow has received revised and new tax assessments from the Ghana
Revenue Authority (GRA). Tullow believes these assessments are
without merit and filed requests for arbitration with the
International Chamber of Commerce in London, in accordance with the
dispute resolution process set out in the Petroleum Agreements
which govern TGL's activities in Ghana. Notwithstanding this formal
step, Tullow intends to continue to engage with the Government of
Ghana, including the GRA, with the aim of resolving these disputes
on a mutually acceptable basis.
In March 2023, Tullow and its JV Partners submitted an updated
Field Development Plan to the Ministry of Energy and Petroleum and
the Energy and Petroleum Regulatory Commission Authority in Kenya,
for their approval. This is currently under review by the relevant
authorities.
In 2023, there were two new appointments:
Richard Miller appointed as Chief Financial Officer (CFO) from
January 2023.
Roald Goethe appointed as independent non-executive Director
from February 2023.
There have not been any other events since 31 December 2022 that
have resulted in a material impact on the year end results.
Group income statement
Year ended 31 December 2022
2021
$m Notes 2022 Restated(1)
================================================================ ====== ======== =============
Continuing activities
---------------------------------------------------------------- ------ -------- -------------
Revenue 1,783.1 1,285.4
---------------------------------------------------------------- ------
Cost of sales 5 (697.5) (638.9)
================================================================ ====== ======== =============
Gross profit 1,085.6 646.5
================================================================ ====== ======== =============
Administrative expenses 5 (51.0) (64.1)
---------------------------------------------------------------- ------
Gain on bargain purchase 12 196.8 -
---------------------------------------------------------------- ------
Gain on disposals 8 - 120.3
---------------------------------------------------------------- ------
Other gains and losses 3.1 -
---------------------------------------------------------------- ------
Exploration costs written off 9 (105.2) (59.9)
---------------------------------------------------------------- ------
Impairment of property, plant and equipment, net 10 (391.2) (54.3)
---------------------------------------------------------------- ------
Restructuring costs and other provisions 5 (4.2) (61.8)
================================================================ ====== ======== =============
Operating profit 733.9 526.7
================================================================ ====== ======== =============
Gain on hedging instruments 0.8 -
---------------------------------------------------------------- ------
Finance income 6 42.9 44.3
---------------------------------------------------------------- ------
Finance costs 6 (335.5) (356.1)
================================================================ ====== ======== =============
Profit from continuing activities before tax 442.1 214.9
================================================================ ====== ======== =============
Income tax expense 7 (393.0) (295.6)
================================================================ ====== ======== =============
Profit/ (loss) for the year from continuing activities 49.1 (80.7)
================================================================ ====== ======== =============
Attributable to
---------------------------------------------------------------- ------
Owners of the Company 49.1 (80.7)
---------------------------------------------------------------- ------
Earnings/ (loss) per ordinary share from continuing activities c c
================================================================ ====== ======== =============
Basic 3.4 (5.7)
Diluted 3.3 (5.7)
================================================================ ====== ======== =============
1 Refer to Note 7 for details on prior year restatement.
Group statement of comprehensive income and expense
Year ended 31 December 2022
$m 2022 2021
===================================================================================== ======== ========
Profit/ (loss) for the year from continuing activities 49.1 (80.7)
===================================================================================== ======== ========
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
Loss arising in the year (399.5) (159.3)
-------------------------------------------------------------------------------------
Gains/ (losses) arising in the period - time value 21.7 (182.1)
-------------------------------------------------------------------------------------
Reclassification adjustments for items included in profit on realisation 288.5 112.3
-------------------------------------------------------------------------------------
Reclassification adjustments for items included in loss on realisation - time value 30.8 40.7
-------------------------------------------------------------------------------------
Exchange differences on translation of foreign operations 10.2 (1.4)
===================================================================================== ======== ========
Other comprehensive expense (48.3) (189.8)
===================================================================================== ======== ========
Tax relating to components of other comprehensive expense - 2.7
===================================================================================== ======== ========
Net other comprehensive expense for the year (48.3) (187.1)
===================================================================================== ======== ========
Total comprehensive income/ (expense) for the year 0.8 (267.8)
===================================================================================== ======== ========
Attributable to
===================================================================================== ======== ========
Owners of the Company 0.8 (267.8)
===================================================================================== ======== ========
Group balance sheet
As at 31 December 2022
$m Notes 2022 2021
====================================================== ====== ========== ==========
Assets
------------------------------------------------------ ------ ----------
Non-current asset
------------------------------------------------------ ------ ----------
Intangible exploration and evaluation assets 9 288.6 354.6
------------------------------------------------------ ------ ----------
Property, plant and equipment 10 2,981.4 2,914.6
------------------------------------------------------ ------ ----------
Other non-current assets 11 327.1 489.1
------------------------------------------------------ ------ ----------
Deferred tax assets 14.5 354.4
====================================================== ====== ========== ==========
3,611.6 4,112.7
====================================================== ====== ========== ==========
Current assets
------------------------------------------------------ ------ ----------
Inventories 181.6 134.8
------------------------------------------------------ ------ ----------
Trade receivables 26.8 99.8
------------------------------------------------------ ------ ----------
Other current assets 11 567.9 704.5
------------------------------------------------------ ------ ----------
Current tax assets 15.4 19.7
------------------------------------------------------ ------ ----------
Cash and cash equivalents 636.3 469.1
====================================================== ====== ========== ==========
1,428.0 1,427.9
====================================================== ====== ========== ==========
Total assets 5,039.6 5,540.6
====================================================== ====== ========== ==========
Liabilities
------------------------------------------------------ ------ ----------
Current liabilities
------------------------------------------------------ ------ ----------
Trade and other payables 13 (750.2) (751.1)
------------------------------------------------------ ------ ----------
Borrowings (100.0) (100.0)
Provisions 14 (98.8) (296.5)
Current tax liabilities (186.0) (115.1)
Derivative financial instruments (186.3) (80.9)
(1,321.3) (1,343.6)
====================================================== ====== ========== ==========
Non-current liabilities
------------------------------------------------------ ------ ----------
Trade and other payables 13 (780.0) (987.1)
------------------------------------------------------ ------ ----------
Borrowings (2,372.8) (2,468.7)
------------------------------------------------------ ------ ----------
Provisions 14 (415.6) (431.0)
------------------------------------------------------ ------ ----------
Deferred tax liabilities (551.5) (677.3)
------------------------------------------------------ ------ ----------
Derivative financial instruments (57.9) (99.0)
====================================================== ====== ========== ==========
(4,177.8) (4,663.1)
====================================================== ====== ========== ==========
Total liabilities (5,499.1) (6,006.7)
====================================================== ====== ========== ==========
Net liabilities (459.5) (466.1)
====================================================== ====== ========== ==========
Equity
------------------------------------------------------ ------ ----------
Called up share capital 215.2 214.2
------------------------------------------------------ ------ ----------
Share premium 1,294.7 1,294.7
------------------------------------------------------ ------ ----------
Foreign currency translation reserve (238.6) (248.8)
------------------------------------------------------ ------ ----------
Hedge reserve (150.3) (39.3)
------------------------------------------------------ ------ ----------
Hedge reserve - time value (94.4) (146.9)
------------------------------------------------------ ------ ----------
Merger reserve 755.2 755.2
------------------------------------------------------ ------ ----------
Retained earnings (2,241.3) (2,295.2)
------------------------------------------------------ ------ ---------- ----------
Equity attributable to equity holders of the Company (459.5) (466.1)
====================================================== ====== ========== ==========
Total equity (459.5) (466.1)
====================================================== ====== ========== ==========
Group statement of changes in equity
Year ended 31 December 2022
Equity Hedge
component Foreign reserve
Called of currency -
up share Share convertible translation Hedge time Merger Retained
$m capital premium bonds reserve(1) reserve(2) value(2) reserves earnings Total
=============== ========== ======== =========== =========== =========== ========== ========= ========= =======
At 1 January
2021 211.7 1,294.7 48.4 (247.4) 4.8 (5.4) 755.2 (2,272.0) (210.0)
Profit for the
year - - - - - - - (80.7) (80.7)
Hedges, net
of tax - - - - (44.1) (141.5) - - (185.6)
Derecognition
of the
convertible
bond(3) - - (48.4) - - - - 48.4 -
Currency
translation
adjustments - - - (1.4) - - - - (1.4)
Exercise of
employee share
options 2.5 - - - - - - (2.5) -
Share-based
payment
charges - - - - - - - 11.6 11.6
At 31 December
2021 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 31 December
2022 215.2 1,294.7 - (238.6) (150.3) (94.4) 755.2 (2,241.3) (459.5)
================ ========= ======== =========== =========== =========== ========== ========= ========= =======
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.
3 On 12 July 2021 Tullow repaid the $300 million Convertible
Bond due 2021. As the conversion option was not exercised, the
equity component of $48.4 million has been transferred from the
separate reserve to retained earnings.
Group cash flow statement
Year ended 31 December 2022
$m Notes 2022 2021
Restated(1)
========================================================== ====== ======== =============
Profit from continuing activities before tax 442.1 214.9
---------------------------------------------------------- ------ -------------
Adjustments for:
---------------------------------------------------------- ------ -------------
Depreciation, depletion and amortisation 10 425.8 378.9
---------------------------------------------------------- ------ -------------
Gain on bargain purchase 12 (196.8) -
---------------------------------------------------------- ------ -------------
Gain on disposals - (120.3)
---------------------------------------------------------- ------ -------------
Other gains and losses (3.1) -
---------------------------------------------------------- ------ -------------
Taxes paid in kind 7 (21.4) (12.2)
---------------------------------------------------------- ------ -------------
Exploration costs written off 9 105.2 59.9
---------------------------------------------------------- ------ -------------
Impairment of property, plant and equipment, net 10 391.2 54.3
---------------------------------------------------------- ------ -------------
Restructuring costs and other provisions 4.2 61.8
---------------------------------------------------------- ------ -------------
Payment under restructuring costs and other provisions 14 (127.3) (12.6)
---------------------------------------------------------- ------ -------------
Decommissioning expenditure 14 (57.7) (52.8)
---------------------------------------------------------- ------ -------------
Share-based payment charge 5.8 11.6
---------------------------------------------------------- ------ -------------
Gain on hedging instruments (0.8) -
---------------------------------------------------------- ------ -------------
Finance income 6 (42.9) (44.3)
---------------------------------------------------------- ------ -------------
Finance costs 6 335.5 356.1
---------------------------------------------------------- ------ -------- -------------
Operating cash flow before working capital movements 1,259.8 895.3
---------------------------------------------------------- ------ -------------
Decrease/ (increase) in trade and other receivables 288.4 (17.9)
------ -------------
Increase in inventories (48.0) (41.9)
---------------------------------------------------------- ------ -------------
(Decrease)/increase in trade payables (193.1) 7.5
========================================================== ====== ======== =============
Cash generated from operating activities 1,307.1 843.0
---------------------------------------------------------- ------ -------------
Income taxes paid (229.3) (56.1)
---------------------------------------------------------- ------ -------- -------------
Net cash from operating activities 1,077.8 786.9
========================================================== ====== ======== =============
Cash flows from investing activities
---------------------------------------------------------- ------ -------------
Proceeds from disposals 11 68.1 132.8
---------------------------------------------------------- ------ -------------
Purchase of additional interest in joint operation (126.8) -
---------------------------------------------------------- ------ -------------
Purchase of intangible exploration and evaluation assets (42.6) (86.1)
---------------------------------------------------------- ------ -------------
Purchase of property, plant and equipment (263.8) (150.4)
---------------------------------------------------------- ------ -------------
Interest received 8.9 2.0
========================================================== ====== ======== =============
Net cash used in from investing activities (356.2) (101.7)
========================================================== ====== ======== =============
Cash flows from financing activities
---------------------------------------------------------- ------ -------------
Debt arrangement fees - (56.6)
---------------------------------------------------------- ------ -------------
Repayment of borrowings (100.0) (2,379.9)
---------------------------------------------------------- ------ -------------
Drawdown of borrowings - 1,800.0
---------------------------------------------------------- ------ -------------
Payment of obligations under leases (203.8) (155.9)
Finance costs paid (249.0) (234.9)
Net cash used in financing activities (552.8) (1,027.3)
========================================================== ====== ======== =============
Net increase/ (decrease) in cash and cash equivalents 168.8 (342.1)
Cash and cash equivalents at beginning of year 469.1 805.4
Foreign exchange gain (1.6) 5.8
========================================================== ====== ======== =============
Cash and cash equivalents at end of year 636.3 469.1
========================================================== ====== ======== =============
1 Refer to Note 7 for details on prior year restatement.
Notes to the financial statements
Year ended 31 December 2022
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 2022
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 2021 have been delivered to the Registrar of
Companies and those for 2022 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 2021, with an exception of the change
discussed below. 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 2022, 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 2022 Annual Report and
Accounts.
Certain new accounting standards and interpretations have been
published that are not mandatory for 31 December 2022 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.
Changes in accounting policy
The Group has revised its accounting policy in relation to the
presentation of corporate income taxes in Gabon and Côte d'Ivoire
Production Sharing Contracts (PSCs).
Under the terms of the PSCs the share of the profit oil which
the government is entitled to is deemed to include the notional
corporate income tax which is paid by the government on behalf of
Tullow. From 1 January 2022 the notional corporate income tax is
classified as an income tax in accordance with IAS 12 Income taxes
which has resulted in a gross up of revenue with a corresponding
increase in income tax expense. In the previous years, the Revenues
and Taxes from Gabon and Côte d'Ivoire were presented on a net
basis. This change has been implemented to more accurately
represent the Group's income tax obligations in Gabon and Côte
d'Ivoire and to be more comparable with other entities in the
sector. Prior period balances have been adjusted to conform with
the same presentation. As a result of the change, revenue for the
year ended 31 December 2021 increased from $1,273.2 million to
$1,285.4 million, whilst income tax expense increased from $283.4
million to $295.5 million. There is no impact on profit/(loss) for
the year from continuing activities nor on basic and diluted
earnings per share. In addition, the restatement had no impact on
reported net assets, cash flows or total equity. Accordingly, an
additional balance sheet as at 1 January 2020 has not been
presented. Refer to Note 7.
Other than the above, the Group's accounting policies are
consistent with the prior year.
2. Earnings/(loss) per ordinary share
Basic earnings/(loss) per ordinary share amounts are calculated
by dividing net profit/ (loss) 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 profit/ (loss) 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. 2022 Annual Report and Accounts
The 2022 Annual Report and Accounts will be mailed in March 2023
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 2022 and 31 December
2021.
$m Ghana Non-Operated Kenya Exploration Corporate Total
============================= ========== ============= ======= ============ ========== ==========
2022
-----------------------------
Sales revenue by origin 1,578.5 524.0 - - (319.4) 1,783.1
============================= ========== ============= ======= ============ ========== ==========
Segment result(1) 692.5 337.3 (0.5) (102.6) (337.5) 589.2
============================= ========== ============= ======= ============ ========== ==========
Other provisions(2) (4.1)
-----------------------------
Gain on bargain purchase 196.8
-----------------------------
Other gains and losses 3.1
-----------------------------
Unallocated corporate
expenses(3) (51.1)
----------------------------- ---------- ------------- ------- ------------ ---------- ----------
Operating profit 733.9
Gain on hedging instruments 0.8
Finance income 42.9
-----------------------------
Finance costs (335.5)
============================= ========== ============= ======= ============ ========== ==========
Profit before tax 442.1
-----------------------------
Income tax expense (393.0)
============================= ========== ============= ======= ============ ========== ==========
Profit after tax 49.1
============================= ========== ============= ======= ============ ========== ==========
Total assets 3,827.7 380.6 265.6 46.0 519.7 5,039.6
============================= ========== ============= ======= ============ ========== ==========
Total liabilities(4) (2,220.5) (401.6) (14.1) (4.6) (2,858.3) (5,499.1)
----------------------------- ========== ============= ======= ============ ========== ==========
Other segment information
-----------------------------
Capital expenditure:
Property, plant and
equipment 342.9 26.9 - - 0.9 370.7
-----------------------------
Intangible exploration
and evaluation assets 0.9 (1.7) (2.1) 42.1 - 39.2
-----------------------------
Depletion, depreciation
and amortisation (362.1) (52.7) (1.3) - (9.7) (425.8)
Impairment of property,
plant and equipment,
net (380.6) (10.6) - - - (391.2)
Exploration costs written
off (0.9) 1.8 (0.5) (105.6) - (105.2)
============================= ========== ============= ======= ============ ========== ==========
1 Segment result is a non IFRS measure which includes gross
profit, exploration costs written off, impairment of property,
plant and equipment. See reconciliation below.
2 This is included within Restructuring costs and other
provisions in the Group Income Statement.
3 Unallocated expenditure and include amounts of a corporate
nature and not specifically attributable to a geographic area. The
liabilities comprise the Group's external debt and other
non-attributable corporate liabilities.
4 Total liabilities - Corporate comprise of the Group's external
debt and other non-attributable liabilities.
Reconciliation of segment result 2022 2021
Restated(1)
============================================= ======== =============
Segment result 589.2 532.2
--------------------------------------------- -------------
Add back:
--------------------------------------------- -------------
Exploration costs written off 105.2 59.9
--------------------------------------------- -------------
Impairment of Property, plant and equipment 391.2 54.3
--------------------------------------------- -------------
Gross profit 1,085.6 646.5
============================================= ======== =============
1 Revenue from crude oil sales has been restated following a
revision to the Group's accounting policy. This resulted in an
increase to revenue for the year ended 31 December 2022 of $21.4
million (2021: $12.2 million), and a corresponding increase to
income tax expense. Refer to note 7.
1.
4. Segmental reporting continued
$m Ghana Non-Operated Kenya Exploration Corporate Total
============================ ========== ============= ======= ============ ========== ==========
2021
----------------------------
Sales revenue by origin
- restated(6) 1,020.4 417.9 - - (152.9) 1,285.4
---------------------------- ----------
Segment result(1) -
restated(6) 469.8 298.7 - (70.5) (165.7) 532.3
============================ ========== ============= ======= ============ ========== ==========
Other provisions(2) 6.6 - (13.2) - (52.1) (58.7)
----------------------------
Gain on disposal 120.3
----------------------------
Unallocated corporate
expenses(3) (67.2)
============================ ========== ============= ======= ============ ========== ==========
Operating profit 526.7
----------------------------
Finance income 44.3
----------------------------
Finance costs (356.1)
============================ ========== ============= ======= ============ ========== ==========
Profit before tax 214.9
----------------------------
Income tax expense (295.6)
============================ ========== ============= ======= ============ ========== ==========
Loss after tax (80.7)
============================ ========== ============= ======= ============ ========== ==========
Total assets - restated(6) 4,283.8 501.2 264.6 122.3 368.8 5,540.6
============================ ========== ============= ======= ============ ========== ==========
Total liabilities -
restated(6) (2,529.3) (478.9) (18.0) (12.8) (2,967.7) (6,006.7)
============================ ========== ============= ======= ============ ========== ==========
Other segment information
----------------------------
Capital expenditure:
----------------------------
Property, plant and
equipment 99.6 43.9 - - 4.6 148.1
----------------------------
Intangible exploration
and evaluation assets(5) 1.2 (11.8) 8.2 48.8 - 46.3
----------------------------
Depletion, depreciation
and amortisation (334.5) (28.8) (1.4) (0.1) (14.1) (378.9)
----------------------------
Impairment of property,
plant and equipment,
net (119.1) 64.8 - - - (54.3)
----------------------------
Exploration costs written
off(5) (1.2) 11.8 - (70.5) - (59.9)
============================ ========== ============= ======= ============ ========== ==========
1 Segment result is a non-IFRS measure which includes gross
profit, exploration costs written off and impairment of property,
plant and equipment. See reconciliation below.
2 This is included within the Restructuring costs and other
provisions in the Group Income Statement.
3 Unallocated expenditure includes amounts of a corporate nature
and not specifically attributable to a geographic area.
4 Total liabilities - Corporate comprise of the Group's external
debt and other non-attributable liabilities.
5 Non-operated segment includes release of $15.3 million
indirect tax provision following settlement.
6 Segment revenue and segment result allocation between the
reportable segments have been restated to correct a prior period
error arising from incorrect classification of loss on realisation
of the cash flow hedges within reportable segments. Total balances
have remained unchanged.
The allocation for the year ended 31 December 2021 increased
revenue for Ghana and Non-Operated by $109.8 million and $43.1
million, respectively, whilst the hedging loss of $152.9 million
was allocated to Corporate.
Total assets and total liabilities allocation between the
reportable segments have been restated to correct a prior period
error arising from incorrect classification of tax assets and
liabilities within reportable segments.
The above balances have been restated by:
$m Ghana Non-Operated Kenya Exploration Corporate Total
========================================== ======= ============= ====== ============ ========== ======
Total assets - increase/(decrease) (35.1) 5.4 (6.0) (22.0) 57.8 -
Total liabilities - (increase)/ decrease (32.0) (11.2) 6.0 24.0 13.2 -
========================================== ======= ============= ====== ============ ========== ======
In addition, revenue from crude oil sales has been restated
following a revision to the Group's accounting policy. This
resulted in an increase to revenue for the year ended 31 December
2022 of $21.4 million (2021: $12.2 million), and a corresponding
increase to income tax expense. Refer to note 7.
5. Other costs
$m 2022 2021
================================================================ ======= =======
Cost of sales
---------------------------------------------------------------- -------
Operating costs 266.5 268.7
---------------------------------------------------------------- -------
Depletion and amortisation of oil and gas and leased assets(1) 410.7 360.9
---------------------------------------------------------------- -------
Underlift, overlift and oil stock movements (46.3) (20.0)
---------------------------------------------------------------- -------
Royalties 61.7 40.5
---------------------------------------------------------------- -------
Share-based payment charge included in cost of sales 0.4 0.5
---------------------------------------------------------------- -------
Other cost of sales 4.4 (11.7)
================================================================ ======= =======
Total cost of sales 697.5 638.9
---------------------------------------------------------------- ------- -------
Administrative expenses
---------------------------------------------------------------- -------
Share-based payment charge included in administrative expenses 5.4 11.1
---------------------------------------------------------------- -------
Depreciation of other fixed assets 15.1 18.0
Other administrative costs 30.5 35.0
================================================================ ======= =======
Total administrative expenses 51.0 64.1
================================================================ ======= =======
Total restructuring costs and other provisions(2) 4.2 61.8
================================================================ ======= =======
1 Depreciation expense on leased assets of $60.9 million as per
note 10 includes a charge of $3.9 million on leased administrative
assets, which is presented within administrative expenses in the
income statement. The remaining balance of $57.0 million relates to
other leased assets and is included within cost of sales.
2 This includes restructuring and redundancy costs of $0.1
million (2021: $3.1 million) as well as movements in other
provisions of $4.1 million (2021: $58.7 million).
6. Net financing costs
$m 2022 2021
======================================================================= ======= =======
Interest on bank overdrafts and borrowings 250.4 243.0
----------------------------------------------------------------------- -------
Interest on obligations for leases 76.4 83.4
======================================================================= ======= =======
Total borrowing costs 326.8 326.4
----------------------------------------------------------------------- -------
Finance and arrangement fees 0.3 19.1
----------------------------------------------------------------------- -------
Other Interest expense 2.4 3.0
----------------------------------------------------------------------- -------
Unwinding of discount on decommissioning provisions 6.0 7.6
======================================================================= ======= =======
Total finance costs 335.5 356.1
Interest income on amounts due from Joint Venture partners for leases (29.6) (38.8)
Other finance income (13.3) (5.5)
======================================================================= ======= =======
Total finance income (42.9) (44.3)
======================================================================= ======= =======
Net financing costs 292.6 311.8
======================================================================= ======= =======
7. Taxation on profit on continuing activities
$m 2022 2021
Restated(1)
======================================================= ======= =============
Current tax on profits for the year
UK corporation tax (11.8) (19.2)
Foreign tax 321.0 162.2
Taxes paid in kind under production sharing contracts 21.4 12.2
Adjustments in respect of prior periods (3.3) (3.3)
======================================================= ======= =============
Total corporate tax 327.3 151.9
UK petroleum revenue tax (2.8) (1.2)
======================================================= ======= =============
Total current tax 324.5 150.7
======================================================= ======= =============
Deferred tax
Origination and reversal of temporary differences
UK corporation tax 11.4 18.1
Foreign tax 54.0 80.3
Adjustments in respect of prior periods (2.9) 43.8
======================================================= ======= =============
Total deferred corporate tax 62.5 142.2
Deferred UK petroleum revenue tax 6.0 2.7
======================================================= ======= =============
Total deferred tax 68.5 144.9
======================================================= ======= =============
Total income tax expense 393.0 295.6
======================================================= ======= =============
1 Income tax expense has been restated following a revision to
the Group's accounting policy. The revenue from certain Production
Sharing Contracts in Gabon and Côte d'Ivoire is now presented gross
of corporate income taxes deemed to have been paid as part of the
Government's share of profit oil. This resulted in an increase to
revenue for the year ended 31 December 2022 of $21.4 million (2021:
$12.2 million), and a corresponding increase to income tax expense.
This change has been implemented to more accurately represent the
income taxes suffered by the Group on its profits in Gabon and Côte
d'Ivoire and to be more comparable with other entities in the
sector.
$m 2022 2021
Restated
========================================================================= ======= ==========
Profit from continuing activities before tax 442.1 214.9
========================================================================= ======= ==========
Tax on profit from continuing activities at the standard UK corporation
tax rate of 19% (2020: 19%) 84.0 40.8
========================================================================= ======= ==========
Effects of:
Non-deductible exploration expenditure 0.5 8.5
Other non-deductible expenses 27.8 13.3
Deferred tax asset not recognised 138.5 94.4
Utilisation of tax losses not previously recognised (0.4) (0.1)
Adjustment relating to prior years (6.2) 40.4
Other tax rates applicable outside the UK 214.6 118.3
Other income not subject to corporation tax (0.1) (20.0)
Tax impact of acquisition through business combination (note 12) (65.7) -
========================================================================= ======= ==========
Group total tax expense for the year 393.0 295.6
========================================================================= ======= ==========
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.
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 $1,024.0 million (2021:
$1,025.5 million) which includes $32.4 million of interest and
penalties (2021: $33.6 million).
7. Taxation on profit on continuing activities continued
Uncertain tax treatments continued
Provisions of $106.4 million (2021: $127.9 million) are included
in income tax payable ($70.6 million (2021: $34.1 million)),
deferred tax liability ($nil (2021:41.0 million)), and provisions
($35.8 million (2021: $52.8 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.
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 2022, giving rise
to an overall decrease in provision of $21.5 million and decrease
in contingent liability of $1.5 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 million branch profits remittance tax (BPRT)
assessment issued as part of the direct tax audit for the financial
years 2014 to 2016. The GRA is seeking to apply BPRT under a law
which the Group considers is not applicable to TGL, since it falls
outside the tax regime provided for in the Petroleum Agreements and
relevant double tax treaties. The parties have agreed a procedural
timetable for the arbitration under which the first Tribunal
hearing will be held in October 2023.
In December 2022, TGL received a $190.5 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.
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 Group continues to engage with the Government of Ghana with
the aim of resolving all tax disputes on a mutually acceptable
basis.
Bangladesh litigation
The National Board of Revenue (NBR) is seeking to disallow $118
million of tax relief in respect of development costs incurred by
Tullow Bangladesh Limited (TBL). The NBR subsequently issued a
payment demand to TBL in February 2020 for Taka 3,094 million
(c.$37 million) requesting payment by 15 March 2020. However, under
the Production Sharing Contract (PSC), the Government is required
to indemnify TBL against all taxes levied by any public authority,
and the share of production paid to Petrobangla (PB), Bangladesh's
national oil company, is deemed to include all taxes due which PB
is then obliged to pay to the NBR. TBL sent the payment demand to
PB and the Government requesting the payment or discharge of the
payment demand under their respective PSC indemnities. On 14 June
2021, TBL issued a formal notice of dispute under the PSC to the
Government and PB. A further request for payment was received from
NBR on 28 October 2021 demanding settlement by 15 November 2021.
Arbitration proceedings were initiated under the PSC on 29 December
2021. A procedural hearing was held on 28 June 2022 which set the
timetable for the process going forward. The first submissions have
been made in October 2022 with the first Tribunal hearing scheduled
for May 2024.
Other items
Other items totalling $280.0 million (2021: $547.5 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 of tax cash
flows in relation to possible outcomes with certainty, Management
anticipates that there will not be material cash taxes paid in
excess of the amounts provided for uncertain tax treatments.
8. Asset Disposals
On 31 March 2021, the Group completed the sale of its assets in
Equatorial Guinea with a cash consideration received of $88.9
million. This transaction included contingent future payments of up
to $16.0 million which are linked to asset performance and oil
price. As per the SPA, a further $5.0 million of additional
consideration was also received on completion of Dussafu Marin
Permit in Gabon.
On 9 June 2021, the Group completed the asset sale of Dussafu
Marin Permit in Gabon with a cash consideration received of $39.0
million. This transaction included contingent future payments of up
to $24.0 million which are linked to asset performance and oil
price.
Given Tullow no longer holds interest in the above assets, based
on publicly available information the Company has assessed that the
asset performance condition is not met. Accordingly, no contingent
consideration has been recognised as at 31 December 2021.
Book value of assets disposed
$m Equatorial Guinea Dussafu Total
==================================== ------------------ -------- --------
Property, plant and equipment 72.9 52.0 124.9
------------------------------------
Inventories 6.9 3.2 10.1
------------------------------------
Other current assets 68.5 1.7 70.2
------------------------------------
Total assets disposed 148.3 56.9 205.2
==================================== ================== ======== ========
Trade and other payables (36.1) (18.5) (54.6)
------------------------------------
Provisions (118.2) (4.7) (122.9)
------------------------------------
Current tax liabilities (13.6) - (13.6)
------------------------------------
Deferred tax liabilities (17.8) - (17.8)
------------------------------------ ================== ======== ========
Total liabilities disposed (185.7) (23.2) (208.9)
==================================== ================== ======== ========
Net (liabilities)/ assets disposed (37.4) 33.7 (3.7)
==================================== ================== ======== ========
Cash consideration 93.8 39.0 132.8
==================================== ================== ======== ========
Transaction costs (11.0) (0.3) (11.3)
==================================== ================== ======== ========
Gain on disposal(1) 120.2 5.0 125.2
==================================== ================== ======== ========
1 In 2021, in addition to $125.2 million gain on disposals
recognised following the Equatorial Guinea and Dussafu disposals,
the Group recognised a loss of $5.1 million relating to its sale of
Dutch assets to Hague and London Oil plc (HALO) in 2017, and a gain
of $0.2 million relating to other transactions during the period
which resulted in an overall gain of $120.3 million. No gain on
disposals was recognised for the year ended 31 December 2022.
Uganda
Contingent asset
During 2020, the Group completed the disposal of its interest in
Uganda for upfront cash consideration of $500.0 million, with $75.0
million received following FID and contingent future payments
linked to oil prices. Given the existing uncertainties around the
project, management has concluded that the conditions for
recognition of an asset associated with contingent consideration
under IFRS 15 were not met as of 31 December 2022.
9. Intangible exploration and evaluation assets
$m 2022 2021
=============================== ======== =======
At 1 January 354.6 368.2
------------------------------- -------
Additions(1) 39.2 46.3
------------------------------- -------
Exploration costs written off (105.2) (59.9)
------------------------------- -------
At 31 December 288.6 354.6
=============================== ======== =======
1 In Kenya, proceeds from Early Oil Pilot Scheme (EOPS) cargo
sales of $6.9 million have been recorded as a credit against
capital expenditure.
The below table provides a summary of the exploration costs
written off on a pre-tax basis by country.
2022 Remaining
Rationale 2022 recoverable
for 2022 write off amount
Country CGU write-off $m $m
=================== ========== =========== =========== ===============
Guyana Kanuku a, b 75.3 -
------------------- ---------- -----------
Guyana Orinduik b 22.4 -
------------------- ---------- -----------
Côte d'Ivoire Block 524 c 3.1 -
------------------- ---------- -----------
New Ventures Various d 3.0 -
------------------- ---------- -----------
Other Various 1.4 -
------------------- ---------- -----------
Total write-off 105.2 -
=================== ========== =========== =========== ===============
a. Unsuccessful well costs written off.
b. Licence relinquishments, expiry, planned exit or reduced
activity.
c. Current year expenditure on assets previously written
off.
d. New Ventures expenditure is written off as incurred.
In Kenya, the Group had received a 15-month licence extension
from September 2020 to December 2021 which was contingent on
certain conditions, including submission of a technically and
commercially compliant Field Development Plan (FDP). On 10 December
2021, Tullow and its Joint Venture Partners submitted an FDP to the
Government of Kenya and fulfilled its licence obligations. The
Group expects a production licence to be granted once due
Government process has been completed.
Since 1 January 2022, there have been ongoing discussions with
the Government of Kenya on approval of the FDP and securing
government deliverables. An updated FDP was submitted on 3 March
2023 and is being reviewed by the Government of Kenya before
ratification by the Kenyan Parliament. In addition, the Company
continues to progress with the farm down process.
In line with its accounting policy, the Group has performed a
VIU assessment of the Kenya asset following identification of
triggers for impairment and impairment reversal. This resulted in
an NPV significantly in excess of the book value of $252.6 million.
However, the Group has identified the following uncertainties in
respect to the Group's ability to realise the estimated VIU;
receiving and subsequently finalising an acceptable offer from a
strategic partner and securing governmental approvals relating
thereto, obtaining financing for the project and government
deliverables. These items require satisfactory resolution before
the Group can take a Final investment Decision (FID). 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.
Based on this there is no impairment or impairment reversal as at
31 December 2022. The cash flows in the VIU assessment were
discounted using a pre-tax nominal discount rate of 20%. Refer to
note 10 for oil price assumptions.
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 $252.6 million. A reduction or increase in the
two-year forward curve of $5/bbl, based on the approximate range of
annualized average oil price over recent history, and a reduction
or increase in the medium and long-term price assumptions of
$5/bbl, based on the range of annualized average historical prices,
are considered to be reasonably possible changes for the purposes
of sensitivity analysis. Decreases to oil prices specified above
would result in an impairment charge of $31.6 million, whilst
increases to oil prices specified above would result in an
impairment reversal of $35.2 million. A 1% increase in the pre-tax
discount rate would result in an impairment charge of $34.2
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.
10. Property, plant and equipment
2022 2022 2021 2021
2022 Other Right of 2021 Other Right of use
Oil and gas fixed use 2022 Oil and gas fixed 2021
$m assets assets assets Total assets assets assets Total
================= =========== =========== =========== ========= =========== =========== ============ =========
Cost
At 1 January 10,521.7 69.5 1,091.7 11,682.9 10,460.2 69.6 1,018.6 11,548.4
Additions 305.2 2.0 63.5 370.7 73.0 1.6 73.5 148.1
Acquisitions(1) 473.2 - - 473.2
Transfer(2) - - 86.6 86.6
Asset retirement - (38.1) (41.7) (79.8) - (1.4) - (1.4)
Currency
translation
adjustments (117.5) (3.4) (3.3) (124.2) - - - -
================= =========== =========== =========== ========= =========== =========== ============ =========
At 31 December 11,182.6 30.0 63.5 370.7 10,521.7 69.5 1,091.7 11,682.9
================= =========== =========== =========== ========= =========== =========== ============ =========
Depreciation,
depletion,
amortisation and
impairment
At 1 January (8,263.7) (53.8) (450.8) (8,768.3) (7,915.9) (42.3) (352.3) (8,310.5)
Charge for the
year (353.7) (11.2) (60.9) (425.8) (304.9) (13.4) (60.6) (378.9)
Impairment loss (391.2) - - (391.2) (54.3) - - (54.3)
Capitalised
depreciation - - (46.1) (46.1) - - (38.0) (38.0)
Asset retirement - 38.1 41.7 79.8 - 1.4 - 1.4
Currency
translation
adjustments 120.2 2.5 0.9 123.6 11.4 0.5 0.1 12.0
================= =========== =========== =========== ========= =========== =========== ============ =========
At 31 December (8,888.4) (24.4) (515.2) (9,428.0) (8,263.7) (53.8) (450.8) (8,768.3)
================= =========== =========== =========== ========= =========== =========== ============ =========
Net book value
at 31 December 2,294.2 5.6 681.6 2,981.4 2,258.0 15.7 640.9 2,914.6
----------------- ----------- ----------- ----------- --------- ----------- ----------- ------------ ---------
1 This relates to an acquisition through business combination discussed in Note 12.
2 As a result of Ghana pre-emption a proportionate amount has
been reclassified from receivables due from joint venture partners
to right of use assets relating to the Group's existing interest in
lease contracts in the joint operation.
The currency translation adjustments arose due to the movement
against the Group's presentation currency, USD, of the Group's UK
assets which have functional currencies of GBP.
During 2022 and 2021, 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
===== ======== ======== ======== ======== ======== =======================
2022 $84/bbl $79/bbl $70/bbl $70/bbl $70/bbl $70/bbl inflated at 2%
----- ======== ======== ======== ======== ======== =======================
2021 $76/bbl $71/bbl $68/bbl $65/bbl $65/bbl $65/bbl inflated at 2%
===== ======== ======== ======== ======== ======== =======================
10. Property, plant and equipment continued
Trigger for 2022 2022
2022 Impairment/(reversal) Remaining recoverable amount(d)
impairment/(reversal) $m Pre-tax discount rate assumption $m
=========== ======================== ======================= ================================= =================================
Limande and
Turnix CGU
(Gabon) a (1.6) 15% 44.6
Tchatamba
(Gabon) a (1.3) 15% 38.0
Oba and Middle
Oba CGU
(Gabon) a (0.4) 17% 11.8
Echira, Niungo
and Igongo
(Gabon) a (1.4) 17% 8.6
TEN (Ghana) b 380.6 13% 926.9
Mauritania a 12.8 n/a -
UK CGU a,c 2.5 n/a -
391.2
--------------------------------------- ----------------------- --------------------------------- ---------------------------------
a. Change to decommissioning estimate.
b. Revision of value based on revisions to reserves
c. The fields in the UK are grouped into one CGU as all fields
within those countries share critical gas infrastructure.
d. The remaining recoverable amount of the asset is its value in
use.
Impairments identified in the TEN fields of $380.6 million were
primarily due to lower 2P reserves partially offset by oil price
assumptions.
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 annualized average oil price over recent history, and a
reduction or increase in the medium and long-term price assumptions
of $5/bbl, based on the range of annualized average historical
prices, are considered to be reasonably possible changes for the
purposes of sensitivity analysis. Decreases to oil prices specified
above would increase the impairment charge by $131.4 million for
Ghana and increase the impairment by $19.2 million for
Non-Operated, whilst increases to oil prices specified above would
result in a credit to the impairment charge of $122.0 million for
Ghana and no change to Non-Operated. A 1% increase in the pre-tax
discount rate would increase the impairment by $33.0 million for
Ghana and increase the impairment by $2.9 million for Non-Operated.
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 peer group of companies' impairments.
11. Other assets
$m 2022 2021
========================================= ====== ========
Non-current
----------------------------------------- --------
Amounts due from joint venture partners 323.3 486.0
----------------------------------------- --------
VAT recoverable 3.8 3.1
========================================= ====== ========
327.1 489.1
========================================= ====== ========
Current
----------------------------------------- --------
Amounts due from joint venture partners 452.3 554.7
----------------------------------------- --------
Underlifts 76.2 26.7
----------------------------------------- --------
Prepayments 31.3 49.6
----------------------------------------- --------
Other current assets 8.1 73.5
----------------------------------------- ====== --------
567.9 704.5
========================================= ====== ========
895.0 1,193.6
========================================= ====== ========
The decrease in non-current receivables from JV Partners
compared to December 2021 mainly relates to reduction in time
remaining on the TEN FPSO lease, net decrease in GNPC (Ghana
National Petroleum Corporation) receivable and reduction in partner
share following Ghana pre-emption.
11. Other assets continued
The movement in current receivables from JV Partners relates
mainly to timing of partner balances and reduction in partner share
following Ghana pre-emption.
The decrease in other current assets compared to 2021 is mainly
due to a collection of the deferred consideration relating to the
Uganda disposal in March 2022 ($67.9 million net).
12. Business combination
Summary of acquisition
On 17 March 2022 the Group completed the pre-emption related to
the sale of Occidental Petroleum's interests in the Jubilee and TEN
fields in Ghana to Kosmos Energy. As a result of this acquisition,
the Group's interest in the TEN fields increased from 47.18% to
54.84%, and from 35.48% to 39.0% in the Jubilee field. Tullow did
not obtain control as a result of this transaction, as all joint
venture partners retain joint control.
The total purchase consideration, which was funded from cash on
the balance sheet, comprises of $118.2 million cash settled on
completion, and $8.6 million subsequent post-completion adjustment
paid in May 2022. There is no element of contingent consideration
included in the purchase price.
The fair values of the identifiable assets and liabilities
acquired were:
$m Fair value recognised on acquisition
==================================== -------------------------------------
Property, plant and equipment 473.2
------------------------------------
Inventories 12.1
------------------------------------
Other current assets 31.4
------------------------------------
Total assets acquired 516.7
==================================== =====================================
Trade and other payables (10.5)
------------------------------------
Provisions (61.6)
------------------------------------
Deferred tax liabilities (143.6)
------------------------------------ =====================================
Total liabilities assumed (215.5)
==================================== =====================================
Net identifiable assets acquired 301.0
==================================== =====================================
Purchase consideration transferred (126.8)
==================================== =====================================
Deemed settlement of provision 22.6
==================================== =====================================
Gain on bargain purchase 196.8
==================================== =====================================
There were no acquisitions in the year ended 31 December
2021.
The property, plant and equipment acquired through the business
combination has been recognised at the fair value based on the net
present value of the discounted future cash flows. Significant
inputs to the valuation include short- and long-term commodity
prices, reserve estimates, production volume profiles, planned
development expenditure, cost profiles and discount rates, and are
consistent with those applied by management when testing assets for
impairments.
The fair value of acquired other receivables is nil. The gross
contractual amount for other receivables due is $0.9 million, with
a loss allowance of $0.9 million recognised on acquisition.
The deferred tax liability mainly comprises the tax effect of
the accelerated depreciation for tax purposes of tangible
assets.
Contingent liabilities recognised in a business combination
A contingent liability recognised in a business combination is
initially measured at its fair value. Subsequently, it is measured
at the higher of the amount that would be recognised in accordance
with the requirements for provisions as per IAS 37 "Provisions,
Contingent Liabilities and Contingent Assets", or the amount
initially recognised less (when appropriate) cumulative
amortisation recognised in accordance with the requirements for
revenue recognition.
As part of the pre-emption Tullow has taken on pro-rated
exposure relating to Anadarko WCTP Company's (Anadarko) BPRT and
AOE disputed claims. In February 2018, Anadarko, whom Occidental
Petroleum acquired the interests from, received a provisional
assessment for AOE for $346.6 million, including a penalty of
$329.5 million (the portion of this claim related to Tullow's
acquired interests was $67.2 million), covering the financial years
2006 to 2016 and in November 2018 the Ministry of Finance confirmed
that the assessment was suspended pending the Government reaching a
final view on the basis for calculating AOE. Anadarko continued to
dispute the AOE assessment issued and considered no AOE was payable
for these periods. In September 2021, Anadarko received a revised
tax audit report from the GRA for the
12. Business combination continued
financial years 2014 to 2018 including a $228.3m branch profits
remittance tax (BPRT) assessment (including late payment interest
of $52.1m) (the portion of this claim related to Tullow's acquired
interests was $67.1 million). The Anadarko BPRT assessment is
covered by a Notice of Dispute issued in June 2020.
A contingent liability at fair value of $36.8 million was
recognised at the acquisition date for provisions resulting from
certain contractual indemnities. There was no change in provision
as at 31 December 2022.
Revenue and net profit contribution
The acquired business contributed revenues of $133.2 million and
net profit of $19.6 million to the Group for the period from 17
March 2022 to 31 December 2022. If the acquisition had occurred on
1 January 2022, the consolidated pro-forma revenues would have been
$169.2 million higher and the consolidated pro-forma profit for the
period ended 31 December 2022 would have been higher by $11.4
million.
These amounts have been calculated using the acquired interest's
results and adjusting them for the additional depreciation and
amortisation that would have been charged assuming the fair value
adjustments to property, plant and equipment had applied from 1
January 2022, together with the consequential tax effects.
Acquisition-related costs
Acquisition-related costs of $0.6 million are included in
administrative expenses in the statement of profit or loss and in
operating cash flow in the statement of cash flows.
Recognition of gain on bargain purchase
The difference between the fair value of net assets acquired and
consideration paid was recognised within the income statement as
gain on bargain purchase of $196.8 million. This is mostly due to
the change in the oil markets from 2021, when the transaction
between Occidental Petroleum and Kosmos Energy was negotiated, to
March 2022, when the acquisition was completed by Tullow. The
consideration paid by Tullow for the acquired interest was based on
the proportionate consideration agreed between Occidental Petroleum
and Kosmos Energy, subject to completion adjustments. Additionally,
the original transaction between the two parties was driven by the
seller's intention to leave the region and dispose of the non-core
elements of the portfolio which it had acquired from Anadarko
Petroleum in August 2019.
13. Trade and other payables
$m 2022 2021
========================================== ====== ======
Current liabilities
------------------------------------------ ------
Trade payables 68.4 60.2
------------------------------------------ ------
Other payables 51.4 57.4
------------------------------------------ ------
Overlifts - 0.7
------------------------------------------ ------
Accruals(1) 379.3 381.3
------------------------------------------ ------
Current portion of lease liabilities 251.2 251.5
========================================== ====== ======
750.2 751.1
========================================== ====== ======
Non-current liabilities
------------------------------------------ ------
Other non-current liabilities(2) 47.1 75.2
------------------------------------------ ------
Non-current portion of lease liabilities 732.9 911.9
------------------------------------------ ====== ------
780.0 987.1
========================================== ====== ======
1 Accruals mainly relate to capital expenditure, interest
expense on bonds and staff related expenses.
2 Other non-current liabilities include balances related to JV Partners.
Trade and other payables are non-interest bearing except for
leases.
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 11). The change in trade payables and in other
payables predominantly represents timing differences and levels of
work activity.
The decrease in non-current portion of lease liabilities mainly
relates to reduction in time remaining on the TEN FPSO lease.
14. Provisions
Decommissioning Other provisions Total Decommissioning Other provisions Total
$m 2022 2022 2022 2021 2021 2021
=============================== =============== ================ ======= =============== ================ ======
At 1 January 498.7 228.8 727.5 696.1 154.6 850.7
New provisions, changes
in estimates and
reclassifications (47.6) (19.7) (67.3) (134.8) 90.0 (44.8)
Acquisitions(1) 24.8 36.8 61.6 - - -
Payments (72.1) (127.3) (199.4) (69.3) (15.7) (85.0)
Unwinding of discount 6.0 - 6.0 7.6 - 7.6
Currency translation
adjustment (11.6) (2.3) (13.9) (0.9) (0.1) (1.0)
------------------------------- --------------- ---------------- ------- --------------- ---------------- ------
At 31 December 398.1 116.3 514.4 498.7 228.8 727.5
=============================== =============== ================ ======= =============== ================ ======
Current provisions 87.7 11.1 98.8 101.2 195.3 296.5
=============================== =============== ================ ======= =============== ================ ======
Non-current provisions 310.4 105.2 415.6 397.5 33.5 431.0
------------------------------- --------------- ---------------- ------- --------------- ---------------- ------
1 This relates to an acquisition through business combination discussed in note 12.
Other provisions include non-income tax provisions of $68.3
million (2021: $52.8 million) and $48.0 million (2021: $176.0
million) of disputed cases and claims. Management estimates
non-current other provisions would fall due between two and five
years.
Non-Current other provisions mainly relates to Bangladesh
litigation. Refer to Uncertain Tax Treatments in Accounting
Policies for further detail. This also includes a provision
relating to a potential claim arising out of historical contractual
agreement. Further information is not provided as it will be
seriously prejudicial to the Company's interest.
On 15 February 2022, an arbitration panel delivered an award
against Tullow in respect to a historic contractual dispute in
Norway related to the acquisition of Spring Energy Norway AS
(Spring) from HiTecVision (HiTec). The Tribunal decided by way of
split decision that conditions under the Spring SPA in respect of
the bonus payment had been met. The Tribunal ruled that Tullow
should pay $76 million to HiTec (an amount which includes interest
and costs) and a further amount of $0.7 million in respect of
Tribunal costs. This balance was provided for as at 31 December
2021 and was settled in March 2022.
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 2022, the Group has increased the decommissioning discount
rate by 1.5-2% from 31 December 2021 due to movement in the
risk-free rate. This resulted in a decrease of the provision by
$39.5 million in Ghana, $15.6 million in Côte d'Ivoire and $12.1
million in Gabon.
Total Total
Discount rate assumption Cessation of production assumption 2022 Discount rate assumption Cessation of production assumption 2021
Decommissioning provisions Inflation assumption 2022 2022 $m 2021 2021 $m
============================ ===================== ========================= =================================== ====== ========================= =================================== ======
C ô te d'Ivoire 2% 3.5% 2035 45.6 1.5% 2033 61.7
---------------------------- --------------------- ------------------------- ----------------------------------- ------ ------------------------- ----------------------------------- ------
Gabon 2% 3.5% 2025-2037 49.2 1.5-2% 2026-2036 61.9
---------------------------- --------------------- ------------------------- ----------------------------------- ------ ------------------------- ----------------------------------- ------
Ghana 2% 3.5% 2036 190.2 1.5-2% 2035-2036 193.3
---------------------------- --------------------- ------------------------- ----------------------------------- ------ ------------------------- ----------------------------------- ------
Mauritania n/a n/a 2018 56.0 n/a 2018 61.6
---------------------------- --------------------- ------------------------- ----------------------------------- ------ ------------------------- ----------------------------------- ------
UK n/a n/a 2018 57.1 n/a 2018 120.2
============================ ===================== ========================= =================================== ====== ========================= =================================== ======
398.1 498.7
============================ ===================== ========================= =================================== ====== ========================= =================================== ======
1 Short term inflation rate assumption has increased from 2% to
4.7% in 2023 and to 2.5% in 2024. Medium and long-term rates of 2%
remained unchanged from 31 December 2021.
The Group's decommissioning activities in the UK and Mauritania
are ongoing and the majority of the future costs is expected to be
incurred in 2023 ($87.4 million). The remaining activities are
planned to continue through to 2027, with an associated expenditure
of $25.7 million.
15. Commercial Reserves and Contingent Resources summary working
interest basis
Ghana Non-Operated Kenya Exploration Total
---------------- ----------------------- ------------- -------------- -------------------
Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Petroleum
mmbbl bcf mmbbl bcf mmbbl bcf mmbbl bcf mmbbl bcf mmboe
================== ======= ======= ====== ====== ======= ===== ====== ===== ======= ======= ==========
COMMERCIAL
RESERVES(1)
================== ======= ======= ====== =============== ===== ====== ===== ======= ======= ==========
1 January 2022 168.3 138.9 38.8 7.1 - - - - 207.1 145.9 231.4
------------------
Revisions(3,4,6) (4.5) 4.3 4.8 (0.6) - - - - 0.4 3.8 1.0
------------------
Acquisitions(7) 16.7 14.1 - - - - - - 16.7 14.1 19.0
------------------
Production(6) (16.2) - (5.8) (1.4) - - - - (22.1) (1.4) (22.3)
------------------
31 December 2022 164.3 157.3 37.8 5.1 202.1 162.4 229.1
================== ======= ======= ====== ====== ======= ===== ====== ===== ======= ======= ==========
CONTINGENT
RESOURCES(2)
================== ======= ======= ====== =============== ===== ====== ===== ======= ======= ==========
1 January 2022 212.1 585.2 29.7 0.9 231.4 - 54.5 - 527.6 586.1 625.4
------------------
Revisions(3,4,6) (47.8) (77.1) 6.3 7.7 - - - - (41.4) (69.4) (53.0)
Acquisitions(7) 20.7 69.7 - - - - - - 20.7 69.7 32.3
================== ======= ======= ====== ====== ======= ===== ====== ===== ======= ======= ==========
31 December 2022 185.0 577.8 36.0 8.6 231.4 - 54.5 - 506.9 586.4 604.6
================== ======= ======= ====== ====== ======= ===== ====== ===== ======= ======= ==========
TOTAL
------------------
31 December 2022 349.3 735.1 73.8 13.7 231.4 - 54.5 - 709.0 748.8 833.7
================== ======= ======= ====== ====== ======= ===== ====== ===== ======= ======= ==========
1 Commercial Reserves above are as audited and reported by
independent third-party reserve auditors. The auditor was provided
with all the significant data up until 31 December 2022.
2 Contingent Resources above are also as audited and reported by
independent third-party auditors based on best available
information as of 31 December 2022. Numbers represent the working
interest net to Tullow.
3 Reserves and Resources revisions in Ghana relate to successful
infill drilling and good field performance in Jubilee and the
maturation of a number of projects on TEN: the Tweneboa Oil
development, infill well on Ntomme and the Enyenra South extension
development. This is balanced by a downward revision of Ntomme and
Enyenra reflecting field production performance and removal of
reserves associated with the two TEN Riser Base wells drilled in
2022.
4 Reserves revisions in Gabon mainly relate to development
progress in Tchatamba, and reserves in Etame.
5 Resource estimates for Kenya are from independent evaluation
of resources by independent third-party reserve auditors.
6 A gas conversion factor of 6 Mscf/boe is used to calculate the total Petroleum mmboe.
7 Acquisitions in Ghana relates to the pre-emption of the Deep
Water Tano component of the Kosmos Energy/Occidental Petroleum
Ghana transaction. This transaction increased Tullow's equity
interests to 39.0% in the Jubilee field and to 54.8% in the TEN
fields.
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 219.6 mmboe at 31 December 2022 (31
December 2021: 222.0 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 appraisal 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 2022 2021
=========================================================== ====== =======
Additions to property, plant and equipment 370.7 148.1
----------------------------------------------------------- ------ -------
Additions to intangible exploration and evaluation assets 39.2 46.3
----------------------------------------------------------- ------ -------
Less
----------------------------------------------------------- ------ -------
Changes to decommissioning asset estimate (19.9) (134.8)
----------------------------------------------------------- ------ -------
Right-of-use asset additions 63.5 73.5
----------------------------------------------------------- ------ -------
Lease payments related to capital activities (40.2) (26.8)
----------------------------------------------------------- ------ -------
Additions to administrative assets 2.0 1.6
----------------------------------------------------------- ------ -------
Other non-cash capital expenditure 50.4 17.7
=========================================================== ====== =======
Capital investment 354.1 263.2
=========================================================== ====== =======
Movement in working capital (49.7) (28.3)
----------------------------------------------------------- ------ -------
Additions to administrative assets 2.0 1.6
----------------------------------------------------------- ------ -------
Cash capital expenditure per the cash flow statement 306.4 236.5
=========================================================== ====== =======
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 2022 2021
================================ ======= =======
Borrowings 2,472.8 2,568.7
-------------------------------- ------- -------
Non-cash adjustments 27.2 31.3
-------------------------------- ------- -------
Less cash and cash equivalents (636.3) (469.1)
-------------------------------- ------- -------
Net debt 1,863.7 2,130.9
================================ ======= =======
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 profit/(loss) from continuing
activities adjusted for income tax (expense)/credit, finance costs,
finance revenue, gain/(loss) on hedging instruments, depreciation,
depletion and amortisation, share-based payment charge,
restructuring costs, gain/(loss) on disposal, exploration costs
written off, impairment of property, plant and equipment net, and
other provisions.
$m 2022 2021 Restated(1)
================================================= ======= =================
Profit/(Loss) from continuing activities 49.1 (80.7)
-------------------------------------------------- ------- -----------------
Adjusted for
------------------------------------------------- ------- -----------------
Income tax expense 393.0 295.6
-------------------------------------------------- ------- -----------------
Finance costs 335.5 356.1
-------------------------------------------------- ------- -----------------
Finance revenue (42.9) (44.3)
-------------------------------------------------- ------- -----------------
Gain on hedging instruments (0.8) -
-------------------------------------------------- ------- -----------------
Gain on bargain purchase (196.8) -
-------------------------------------------------- ------- -----------------
Depreciation, depletion and amortisation 425.8 378.9
-------------------------------------------------- ------- -----------------
Share-based payment charge 5.8 11.6
-------------------------------------------------- ------- -----------------
Restructuring costs and other provisions 4.2 61.8
-------------------------------------------------- ------- -----------------
Gain on disposal (0.4) (120.3)
-------------------------------------------------- ------- -----------------
Exploration costs written off 105.2 59.9
-------------------------------------------------- ------- -----------------
Impairment of property, plant and equipment, net 391.2 54.3
-------------------------------------------------- ------- -----------------
Adjusted EBITDAX 1,468.9 972.9
================================================== ======= =================
Net debt 1,863.7 2,130.9
================================================== ======= =================
Gearing (times) 1.3 2.2
================================================== ======= =================
1 Revenue from crude oil sales has been restated following a
revision to the Group's accounting policy. This resulted in an
increase to revenue for the year ended 31 December 2022 of $21.4
million (2021: $12.2 million), and a corresponding increase to
income tax expense. Refer to note 7.
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 2021 and 2022, Tullow incurred abnormal non-recurring costs
which are presented separately below. The adjusted normalised cash
operating costs are a helpful indicator to the forward underlying
costs of the business.
$m 2022 2021
============================================================= ====== ======
Cost of sales 697.5 638.9
------------------------------------------------------------- ------ ------
Less:
------------------------------------------------------------- ------ ------
Depletion and amortisation of oil and gas and leased assets 410.7 360.9
------------------------------------------------------------- ------ ------
Underlift, overlift and oil stock movements (46.3) (20.0)
------------------------------------------------------------- ------ ------
Share-based payment charge included in cost of sales 0.4 0.5
------------------------------------------------------------- ------ ------
Royalties 61.7 40.0
============================================================= ====== ======
Other cost of sales 4.4 (11.7)
============================================================= ====== ======
Underlying cash operating costs 266.5 268.7
============================================================= ====== ======
Covid-19 & OOSYS costs (14.7) (7.9)
============================================================= ====== ======
Total normalised cash operating costs 251.8 260.8
============================================================= ====== ======
Production (MMboe) 21.6 21.6
============================================================= ====== ======
Underlying cash operating costs per boe ($/boe) 12.3 12.4
============================================================= ====== ======
Normalised cash operating costs per boe ($/boe) 11.3 12.1
------------------------------------------------------------- ------ ------
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 2022 2021
======================================= ======= =======
Net cash from operating activities 1,077.8 786.9
--------------------------------------- ------- -------
Net cash used in investing activities (356.2) (101.7)
--------------------------------------- ------- -------
Repayment of obligations under leases (203.8) (155.9)
--------------------------------------- ------- -------
Finance costs paid (230.5) (234.9)
--------------------------------------- ------- -------
Debt arrangement fees - (56.6)
--------------------------------------- ------- -------
Foreign exchange gain (1.6) 6.9
======================================= ======= =======
Free cash flow 267.2 244.7
======================================= ======= =======
Underlying operating cash flow
This is a useful indicator of the Group's assets ability to
generate cash flow to fund further investment in the business,
reduce borrowings and provide returns to shareholders. Underlying
operating cash flow is defined as net cash from operating
activities less repayments of obligations under leases plus
decommissioning expenditure.
Pre-financing cash flow
This is a useful indicator of the Group's ability to generate
cash flow to reduce borrowings and provide returns to shareholders
through dividends. Pre-financing free cash flow is defined as net
cash from operating activities, and net cash used in investing
activities, less repayment of obligations under leases and foreign
exchange gain.
$m 2022 2021
============================================== ======= =======
Net cash from operating activities 1,077.8 786.9
---------------------------------------------- ------- -------
Less
---------------------------------------------- ------- -------
Decommissioning expenditure 57.7 52.8
---------------------------------------------- ------- -------
Lease payments related to capital activities 40.2 26.8
---------------------------------------------- ------- -------
Plus
---------------------------------------------- ------- -------
Repayment of obligations under leases (203.8) (155.9)
============================================== ======= =======
Underlying operating cash flow 971.9 710.6
============================================== ======= =======
Net cash from/(used in) investing activities (356.2) (101.7)
---------------------------------------------- ------- -------
Decommissioning expenditure (57.7) (52.8)
---------------------------------------------- ------- -------
Lease payments related to capital activities (40.2) (26.8)
---------------------------------------------- ======= =======
Pre-financing cash flow 517.8 529.3
============================================== ======= =======
Management Presentation - WEBCAST - 9:00 GMT
To access the webcast please use the following link and follow
the instructions provided:
https://web.lumiconnect.com/130749289
A replay will be available on the website from midday on 8 March
2023:
https://www.tullowoil.com/investors/results-reports-and-presentations/
CONTACTS
Tullow Oil plc Camarco
(London) (London)
(+44 20 3249 9000) (+44 20 3781 9244)
Robert Hellwig Billy Clegg
Nicola Rogers Georgia Edmonds
Matthew Evans Rebecca Waterworth
==================== ====================
Notes to editors
Tullow is an independent oil & gas, exploration and
production group which is quoted on the London and Ghanaian stock
exchanges
(symbol: TLW) and is a constituent of the FTSE250 index. The
Group has interests in over 30 licences across eight countries. In
March
2021, Tullow committed to becoming Net Zero on its Scope 1 and 2
emissions by 2030.
For further information, please refer to our website at
www.tullowoil.com.
Follow Tullow on:
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YouTube: www.youtube.com/TullowOilplc
Facebook: www.facebook.com/TullowOilplc
LinkedIn: www.linkedin.com/company/Tullow-Oil
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END
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