REG - Tullow Oil PLC - TULLOW OIL PLC - 2022 FULL YEAR RESULTS
08/03/2023 07:15
For best results when printing this announcement, please click on link below:
http://newsfile.refinitiv.com/getnewsfile/v1/story?guid=urn:newsml:reuters.com:20230308:nRSH2715Sa&default-theme=true
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 (http://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: $876 million).
· Industry leading safety performance, with zero lost time injuries and
zero Tier 1 process safety incidents across Tullow's global operations in
2022.
· Group working interest production averaged 61.1 kboepd (2021:59.2
kboepd).
· Strong operating, drilling and completion performance in Ghana, with
facilities uptime of c.97% and four Jubilee wells and two Enyenra wells
brought online. Two Ntomme riser base area wells were also drilled but did not
encounter economically developable resources.
· The transition of operatorship of the Jubilee FPSO took place in July
2022 and FPSO uptime averaged c.99% in the second half of 2022, compared to
c.95% in the first half.
· Interim Gas Sales Agreement for 19 bcf of Jubilee gas executed,
representing the first commercialisation of Jubilee gas.
· A significant milestone was reached in Ghana with a Letter of Intent
(LoI) signed with the Ghana Forestry Commission for a nature-based carbon
offset project. Final Investment Decision (FID) is expected in 2023.
· New exploration licence secured in Côte d'Ivoire (CI-803), building a
strategic position adjacent to the Group's producing fields in Ghana.
· Phuthuma Nhleko appointed as Chair from January 2022.
2022 Key Financial Results
2022 2021
Restated(2)
Total revenue ($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 (411) (361)
assets
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: $417m). Non-deductible
expenditure in Ghana and Gabon and prior year adjustments are additional
contributing factors.
The Group's future statutory effective tax rate is sensitive to the geographic
mix in which pre-tax profits arise. There is no UK tax benefit from net
interest and hedging expenses, whereas net interest income and hedging profits
would be taxable in the UK. Consequently, the Group's tax charge will continue
to vary according to the jurisdictions in which pre-tax profits occur.
Analysis of adjusted effective tax rate ($m) Adjusted Profit/(loss) before tax Tax (expense)/credit Adjusted
Effective 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 $m
Reconciliation of net debt
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 433
and equipment
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
$m Notes 2022 2021
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 ¢ ¢
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 30.8 40.7
value
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
$m Called up share Share Equity component of convertible bonds Foreign currency translation reserve¹ Hedge Merger reserves Retained earnings Total
capital
premium
reserve²
Hedge
reserve -
time
value²
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 (http://www.tullowoil.com) ). Copies of the Annual
Report and Accounts will also be available from the Company's registered
office at Building 9, Chiswick Park, 566 Chiswick High Road, London, W4 5XT.
4. Segmental reporting
The information reported to the Group's Chief Executive Officer for the
purposes of resource allocation and assessment of segment performance is
focused on four Business Units - Ghana, Non-operated producing assets
including Uganda and decommissioning assets, Kenya and Exploration. Therefore,
the Group's reportable segments under IFRS 8 are Ghana, Non-operated, Kenya
and Exploration.
The following tables present revenue, loss and certain asset and liability
information regarding the Group's reportable business segments for the years
ended 31 December 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 84.0 40.8
tax rate of 19% (2020: 19%)
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 Equatorial Guinea Dussafu Total
$m
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.
Country CGU Rationale for 2022 write-off 2022 2022 Remaining recoverable amount
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
$m 2022 2022 2022 2022 2021 2021 2021 2021
Total
Total
Oil and gas assets Other fixed assets Right of use Oil and gas assets Other fixed assets Right of use
assets assets
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 Pre-tax discount rate assumption 2022
2022 Impairment/(reversal) Remaining recoverable amount(d)
impairment/(reversal) $m $m
Limande and Turnix CGU (Gabon) a (1.6) 15% 44.6
Tchatamba (Gabon) a (1.3) 15% 38.0
Oba and Middle Oba CGU (Gabon) a (0.4) 17% 11.8
Echira, Niungo and Igongo (Gabon) a (1.4) 17% 8.6
TEN (Ghana) b 380.6 13% 926.9
Mauritania a 12.8 n/a -
UK CGU 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
$m Decommissioning Other provisions Total Decommissioning 2021 Other provisions Total
2022 2022 2022 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.
Decommissioning provisions Inflation assumption Discount rate assumption Cessation of production assumption Total Discount rate assumption Cessation of production assumption Total
2022 2022 2022 2021 2021 2021
$m $m
Côte 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 mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Petroleum
bcf
bcf
bcf
bcf
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
(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/
(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:
Twitter: www.twitter.com/TullowOilplc (http://www.twitter.com/TullowOilplc)
YouTube: www.youtube.com/TullowOilplc (http://www.youtube.com/TullowOilplc)
Facebook: www.facebook.com/TullowOilplc (http://www.facebook.com/TullowOilplc)
LinkedIn: www.linkedin.com/company/Tullow-Oil
(http://www.linkedin.com/company/Tullow-Oil)
This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact
rns@lseg.com (mailto:rns@lseg.com)
or visit
www.rns.com (http://www.rns.com/)
.
RNS may use your IP address to confirm compliance with the terms and conditions, to analyse how you engage with the information contained in this communication, and to share such analysis on an anonymised basis with others as part of our commercial services. For further information about how RNS and the London Stock Exchange use the personal data you provide us, please see our
Privacy Policy (https://www.lseg.com/privacy-and-cookie-policy)
. END FR SSUSMAEDSEEDRecent news on Tullow Oil
See all newsREG - Tullow Oil PLC - Director/PDMR Shareholding
AnnouncementREG - Tullow Oil PLC - Total Voting Rights
AnnouncementREG - Tullow Oil PLC - Director/PDMR Shareholding
AnnouncementREG - Tullow Oil PLC - Director/PDMR Shareholding
AnnouncementREG - Tullow Oil PLC - Total Voting Rights
Announcement