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RNS Number : 7788L
Tullow Oil PLC
15 September 2021
Tullow oil PLC - 2021 Half Year Results
15 September 2021 - Tullow Oil (Tullow) announces its Half Year
results for the six months ended 30 June 2021. Details of the
presentation (virtual) and conference call are available on the
last page of this announcement and online at www.tullowoil.com
.
Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented
today:
"Strong operational performance in the first half of the year
and a transformational debt refinancing have put Tullow on a firm
footing to deliver our Business Plan. Our West Africa production
assets have performed well, and we are narrowing production
guidance for 2021 to the upper end of the range. In Kenya, the
revised development plan creates a robust project that has the
potential to deliver material value to the Government of Kenya and
other stakeholders. Through our operations, Tullow continues to
deliver Shared Prosperity and to be an engine for economic and
social change in the developing economies in which we work.
Furthermore, by targeting Net Zero by 2030 and an emphasis on
responsible operations, we are ensuring that the oil and gas
resources of our host countries are developed efficiently and
safely, whilst minimising our environmental impact."
2021 First half results summary
-- Group working interest production for the first half of 2021
averaged 61,230 boepd, in line with expectations.
-- Good operational progress in Ghana; FPSOs delivering over 98%
uptime; sustained increased water injection and gas offtake rates;
first new well in drilling programme, J56 producer, came on stream
delivering production rates ahead of expectations.
-- Progress made on the delivery of Business Plan set out in
November 2020, including target to become Net Zero by 2030.
-- Revenue of $727 million; gross profit of $321 million; profit
after tax of $93 million; underlying operating cash flow of
$218 million and free cash flow of $86 million.
-- Continued focus on costs results in reduced administrative
expenses of $23 million in 1H21, down c.50% year-on-year.
-- Capital investment of $101 million; decommissioning costs of
$37 million. 1H21 operating costs averaged $12.9/bbl, a
year-on-year increase primarily due to lower production and
increased costs related to extended COVID-19 operating
procedures.
-- Net debt at 30 June 2021 of c.$2.3 billion; Gearing of 2.6x
net debt/EBITDAX; liquidity headroom and free cash of $0.7
billion.
-- Completion of comprehensive debt refinancing with $1.8
billion of five-year Senior Secured Notes issued and a new $500
million revolving credit facility.
-- Completion of Equatorial Guinea and Dussafu Marin permit
sales in March and June respectively, receiving $133 million.
Key financial results
1H 2021 1H 2020
=================================================== ======== ========
Sales revenue ($m) 727 731
=================================================== ======== ========
Gross profit ($m) 321 164
=================================================== ======== ========
Underlying cash operating cost per barrel ($/bbl) 12.9 11.0
=================================================== ======== ========
Profit / (loss) after tax ($m) 93 (1,327)
=================================================== ======== ========
Free cash flow ($m) 86 (213)
=================================================== ======== ========
Net debt ($m) 2,290 3,019
=================================================== ======== ========
Gearing (times) 2.6 3.0
=================================================== ======== ========
2021 Guidance
-- Group working interest production narrowed upwards to
58,000-61,000 boepd following deferral of a Jubilee shut-down into
2022 and an increase in production from Simba in Gabon following
acceleration of work into 2H21.
-- Full year capital investment and decommissioning spend of
c.$260 million and c.$90 million respectively.
-- Full year underlying operating cashflow expected to be c.$0.6
billion assuming $60/bbl for the remainder of the year. Post all
costs, Tullow forecasts full year free cash flow of c.$0.1 billion.
If the oil price averages $70/bbl in 2H21, this would increase by
c.$50 million.
-- Tullow's free cash flow guidance includes an expected payment
of $75 million from Total which would be triggered if a Final
Investment Decision (FID) for the Lake Albert Development in Uganda
occurs before the end of the year. Public announcements suggest
good progress is being made in Uganda, with agreements recently in
place to launch the Upstream and Pipeline projects, but if FID does
not occur in 2021, the $75 million payment is expected in 2022.
STRATEGY & BUSINESS PLAN
2021 is a transition year for Tullow as the Group begins to
deliver the 10-year Business Plan presented at its Capital Markets
Day last November. Much has been achieved in the first half of the
year and while the start of drilling in Ghana is one of the most
tangible examples, the Group has also maintained cost discipline,
allocated capital carefully to accelerate high-return projects such
as Simba in Gabon and recently submitted a revised draft
development plan for Kenya, the culmination of over a year's
in-depth work. The issuance of $1.8 billion of Senior Secured Notes
with a $500 million revolving credit facility in May 2021 placed
Tullow on a much firmer financial footing and the Group now has a
clear runway to invest appropriately in its assets to maximise
their value and deliver its cash generative plan.
Over the past few months, Tullow has focused on further refining
the plan for the 2021-2025 period with a base case capital
expenditure of c.$1.3 to c.$1.5 billion during this period. This
expenditure is self-funded and requires no additional borrowing.
Revenues are protected by Tullow's comprehensive prudent hedging
programme and the Group has flexibility to reduce expenditure in
the event of a sustained oil price fall to $55/bbl or below.
Overall, from 2021-2025, Tullow's Business Plan will deliver
growth in production, reserves and underlying value, along with
material cash flow to support deleveraging which will see the Group
reduce its gearing to below 1.5x by 2025.
Maximising value from producing assets
The Jubilee field has c.2 billion barrels of oil initially in
place and to date, Tullow has produced less than half of the
expected ultimate recovery. Accordingly, given the quality of the
field, Jubilee provides a highly profitable investment opportunity
over the 2021-2025 period through a combination of infill drilling,
facilities expansion, and two sanctioned projects in the eastern
part of the field - Jubilee North East and Jubilee South East.
The TEN fields have over 1 billion barrels of oil initially in
place and to date, Tullow has produced less than a third of the
expected ultimate recovery through the Enyenra and Ntomme fields.
Since the 2020 Capital Markets Day, Tullow and its Partners have
had the opportunity to deepen their understanding of the TEN area,
and now have an improved view of the remaining potential.
Accordingly, the JV Partners have evolved their forward strategy on
TEN to concentrate on the biggest and most cost-effective "pools",
particularly in the Greater Ntomme and Tweneboa ("GNT") area. Two
strategically-positioned wells to be drilled in the near-term will
help better define the overall resource base at TEN, with options
to accelerate future development. The Group is also seeking to
commercialise the significant non-associated gas resource in the
TEN fields.
Tullow's non-operated production in Gabon and Cote d'Ivoire
continue to provide positive cash flow through existing production,
infrastructure-led exploration (ILX) and a number of diverse
low-risk investment options and projects.
Value opportunities
In Kenya, the revised development plan has been commercially,
technically and environmentally enhanced. Tullow and its Kenya
Joint Venture (JV) Partners are actively seeking a strategic
partner(s) for the next stage of the project to develop this
discovered resource which has the potential to deliver material
value to the Government of Kenya and the JV Partnership, as well as
other stakeholders.
Tullow is focusing its exploration expertise on unlocking
additional value from our asset base. In Ghana and Côte d'Ivoire,
Tullow's team is maturing prospects around the TEN FPSO and subsea
infrastructure as well as in the adjacent block, CI-524. In the
emerging basins of Guyana and Argentina, Tullow is focused on
limiting its capital exposure while also seeking to capitalise on
its significant positions in both countries.
Tullow's purpose
The oil & gas industry is in flux as many companies allocate
capital away from the upstream and divest assets. However, as long
as global hydrocarbon demand exists, it is imperative that Africa's
oil & gas assets are managed responsibly, efficiently and
transparently and that oil & gas production in developing
economies creates long-lasting economic and social benefits.
Notwithstanding the focus on reducing the use of fossil fuels by
society and through legislation, the oil & gas industry can be
an engine of development in many developing economies, particularly
in Africa. Tullow has a long and proud history in Africa and is
well positioned to continue as a leader in the continent's oil
& gas industry. With a target to achieve Net Zero by 2030 and
an emphasis on responsible operations, Tullow will ensure that the
oil & gas resources of its host countries are developed
efficiently and safely while minimising the environmental impact.
Through its work, Tullow will deliver Shared Prosperity and create
value for our
investors, staff, host nations and communities.
ESG
Net Zero 2030
Tullow is committed to becoming a Net Zero Company by 2030 on
its Scope 1 and 2 emissions. Over the period, this will be achieved
through a combination of decarbonising its operated assets in Ghana
and pursuing a nature-based carbon removal programme.
Over the next three years, Tullow has defined plans to reduce
its CO2/GHG emissions from its operations through an increase in
the gas handling capacity on Jubilee and process modifications on
TEN. These investments are included in the Group's Business Plan
and will put the Group on track to eliminate routine flaring in
Ghana by 2025.
To offset the residual difficult-to-abate carbon emissions,
progress is being made in identifying nature-based carbon removal
projects such as reforestation, afforestation and conservation
projects in Ghana. Ongoing work includes project screening,
feasibility and investment readiness assessments ahead of selecting
projects that deliver carbon offsets and community benefits. Tullow
has appointed Terra Global to carry out feasibility studies in
Ghana to identify projects for future investment.
Governance - Board changes
In June, Tullow announced that Dorothy Thompson CBE,
Non-Executive Chair, had decided to step down from Tullow's Board.
An executive search firm was appointed soon after and the process
to find Dorothy's replacement is progressing well. Tullow expects
to announce its new Chair in the autumn.
Tullow has also announced today in a separate press release that
Les Wood, Chief Financial Officer, has mutually agreed with the
Board that he will step down from Tullow at the end of the first
quarter of 2022.
Operational Review
Production
Group working interest production averaged 61,230 boepd in the
first half of 2021, in line with expectations. Full year guidance
has been narrowed to 58,000-61,000 boepd, towards the upper end of
the range.
Group average working interest production 1H 2021 actual (kboepd) FY 2021 guidance (kboepd)
=========================================== ======================== ==========================
Ghana 42.5 42.1
=========================================== ======================== ==========================
Jubilee 25.1 26.4
=========================================== ======================== ==========================
TEN 17.4 15.7
=========================================== ======================== ==========================
Equatorial Guinea 2.1 1.1
=========================================== ======================== ==========================
Gabon 14.8 15.3
=========================================== ======================== ==========================
C ô te d'Ivoire 1.8 1.5
=========================================== ======================== ==========================
Total production 61.2 60.0
=========================================== ======================== ==========================
Ghana
Jubilee
Gross production from the Jubilee field averaged c.70,600 bopd
(net: c.25,100 bopd) in the first half of the year, slightly ahead
of expectations due to good facility uptime and well performance.
Full year guidance for Jubilee has been slightly adjusted upwards
to c.74,300 bopd (net: c.26,400 bopd) following the decision to
move the planned maintenance shut-down into the first half of 2022.
Shifting the shutdown by approximately six months is expected to
maximise the amount of work achievable as gas enhancement works
planned for 2023 can be brought forward and an expected easing in
COVID-19 restrictions will allow for a more efficient work
programme to be carried out in the planned shutdown period.
The 2021 drilling programme continues and the first well of the
programme, the J-56 producer, came onstream in July 2021 delivering
rates ahead of expectations. The second well, the J-55 water
injector, is expected to be online in the next few weeks and will
be paired with an existing production well. During August, the rig
drilled the top hole of the next Jubilee producer well, J-57-P,
which is expected to be completed and brought online in early 2022.
As a result of the new wells, average production from Jubilee is
expected to increase in the second half of the year before growing
further in 2022 as the drilling campaign continues.
TEN
Gross production from the TEN fields averaged c.37,000 bopd
(net: c.17,400 bopd) in the first half of the year. This is broadly
in line with expectations. Full year gross production from TEN is
expected to be c.33,200 bopd (net: c.15,700 bopd) reflecting the
underlying decline in the field during the year. Drilling of the
Ntomme gas injector well (Nt-06) reached total depth this month
with completion expected to be finished in October. When tied in
later this year, the well is expected to mitigate against further
decline and keep production broadly flat into 2022.
Operational improvement plan
The operational improvement plan in Ghana is an important part
of our strategy to optimise reservoir performance, address
production decline and support long term stable production. The
plan is delivering good results across the key areas of facility
uptime, gas offtake and water injection. The two FPSOs averaged 98%
uptime in the first half of 2021, gas offtake from the Government
of Ghana is averaging c.110 mmscfd and improved Jubilee water
injection rates continue to be in excess of 200 kbwpd.
Non-operated portfolio
Net production from the non-operated portfolio averaged c.18,700
boepd in the first half of 2021, with contributions from Gabon,
Equatorial Guinea and Côte d'Ivoire. Following the sale of assets
in Equatorial Guinea and the Dussafu Marin permit in Gabon net
production from the portfolio for the full year is expected to be
c.17,900 boepd.
Fields in Gabon continue to offer high-return and fast payback
opportunities. As such, capital expenditure has been re-allocated
to accelerate the Simba expansion and an appraisal well at
Tchatamba, into 2021. As part of the Simba expansion, the Simba-3
production well was brought onstream in early September and is
performing in line with expectations. The Tchatamba south appraisal
well, brought forward from 2022, is currently being drilled, and
subject to results, will enable the Tchatamba south east
development to commence in 2022, a year earlier than initially
planned.
As previously announced in Tullow's 2020 Full Year Results,
following a major incident onboard the FPSO in the CNR
International (CNR) operated Espoir field in mid-January 2021,
production was shut in for approximately four weeks in the first
half of the year. A further shut down of approximately two months
is currently under way to carry out remediation work identified by
BW Offshore, the FPSO operator, required for vessel class
certification. The loss of production resulting from these
shut-down periods is factored into the Group's 2021 production
guidance. CNR and Tullow are working together with BW Offshore on
the optimum remediation plan, with work expected to commence in
2022. A further update will be provided in due course once
remediation plans are finalised.
Decommissioning
Decommissioning activities continue in the UK and Mauritania. In
Tullow-operated licences in the UK, final surveys are being planned
to close out the decommissioning programme this year. The Group's
non-operated decommissioning activities are ongoing and are
expected to continue through to 2025.
In Mauritania, preparation is under way to commence the Group's
operated decommissioning programme of the Banda and Tiof fields
with operations now expected to commence in early 2022, subject to
Government approval. Non-operated decommissioning of the Chinguetti
field is ongoing. The full abandonment of the wells was completed
in August ahead of preparing to clear infrastructure from the
seabed in 2022.
Due to a delayed start in some of the activities in Mauritania
and the UK, decommissioning expenditure in 2021 is now expected to
be c. $90 million (down from c.$100 million).
Kenya
Over the past year, Tullow and its Joint Venture (JV) Partners
(Africa Oil and Total Energies) have completed the redesign of the
Kenya development project (Blocks 10BB and 13T licences) to ensure
it is a technically, commercially and environmentally robust
project. A higher production plateau of 120,000 bopd is now
planned, with expected gross oil recovery of 585 mmbo over the full
life of the field. This resource position is supported by external
international auditors Gaffney Cline Associates (GCA) who have
issued a Competent Persons Report (CPR) and confirmed the life of
field resource position of 585 mmbo.
The key changes to the development concept have been driven
by:
1. Incorporating the production data from the Early Oil Pilot
Scheme (EOPS) where 450,000 bbls was produced from Amosing and
Ngamia fields. These two fields account for over 50% of the
resource distribution, leading to greater confidence in achieving
the higher end of the resource distribution range.
2. Optimising the number of wells to be drilled with drilling
initially at the crest of the fields to achieve First Oil. Changing
the producer to injector ratio from 2:1 to 1:1 leading to improved
pressure support and higher resources recovered from the
reservoir.
3. Adding the Ekales field into the first phase of production.
Ekales is geographically straddled between the Twiga and Amosing
fields and ongoing technical work has helped mature our
understanding. As such, the first phase will now include the
Ngamia, Ekales, Amosing and Twiga (NEAT) fields and will target 390
mmbo of the overall 585 mmbo.
4. Optimising the overall development cost with a facility
design capacity of 130,000 bopd and an increase to the pipeline
size from 18" to 20" to handle the increased flow rates.
Total gross capital expenditure (capex), which covers both the
upstream and the pipeline to First Oil, is expected to be c.$3.4
billion. The increase in capex from the previous design is due to a
bigger facility processing capacity, additional wells to be drilled
and larger diameter crude oil export pipeline, which delivers 30%
increase in resources whilst lowering the unit cost to $22/bbl
(previously c.$31/bbl). The revised concept also allows greater
flexibility in adding additional fields into production without
significant modifications to the project's infrastructure.
Tullow and its JV Partners have taken the opportunity of this
review to improve the environmental and social aspects of the
project. Carbon emissions will be limited through a combination of
heat conservation, use of associated gas for power and reinjection
of excess gas into the reservoir. Further, there are opportunities
to use the Kenyan national grid that is substantially powered by
renewables and options to offset remaining emissions. As per the
previous development plan, the 825-kilometres long pipeline that
will transport the crude oil from Turkana to the port of Lamu will
be heated and buried to avoid long-term disruption. The project
will also require water for reservoir pressure which will be
abstracted through a pipeline from the Turkwell Dam and will also
be used to provide water to local communities. This project would
also be Kenya's first oil and gas development and would represent a
stable, long-term source of income for the Government of Kenya.
Simultaneously to the development, an exploration and appraisal
plan will be put in place to ensure the remaining five discoveries
are efficiently developed. This will extend and sustain initial
plateau rates while keeping costs low by using the rigs used for
development drilling. Future phases will also focus on additional
exploration potential within the Blocks 10BB and 13T licences and
also exploring the wider Blocks 10BA and 12B licence acreage.
Tullow and its JV Partners have submitted a draft FDP to the
Ministry of Energy & Petroleum for their review. The JV
Partners are now working collaboratively with them and will
incorporate their feedback and plan to submit a final FDP by the
end of 2021, in line with licence extension requirements provided
by the Government of Kenya in December 2020. At the same time
Tullow and its JV Partners are actively seeking strategic partners
for the project. Based on the revised plan, Tullow believes that
this project is an attractive commercial prospect for investors
looking to access the East Africa oil and gas sector in both the
upstream and midstream. It is intended that a strategic partner
will be secured ahead of a Final Investment Decision.
Exploration
In Tullow's core area of West Africa, the exploration team is
focused on maturing near-field and infrastructure-led exploration
opportunities around existing producing fields, to unlock
additional value from the Group's asset base. Tullow also continues
to focus on unlocking value from the substantial prospective
resource base in the emerging basins of Guyana and Argentina, while
seeking to mitigate capital exposure from historical work
commitments of c.$50 million in 2022, through farm-downs. These
include the Beebei-Potaro exploration well on the Kanuku Block in
Guyana which will target the prolific Cretaceous light oil play of
the Guyana-Suriname Basin, as well as a seismic acquisition over
Block MLO 122 in Argentina.
Operational activity in the first half of 2021 included the
drilling of the Goliathberg-Voltzberg North well in Suriname Block
47, which encountered minor oil shows. Tullow is considering next
steps for Blocks 47 and 54. The Group has notified the Government
of Suriname of its decision to relinquish Block 62, and Tullow will
exit the licence in October 2021. In Argentina, a multi-client 3D
seismic acquisition was completed on Tullow-operated licences
MLO114 and MLO119 during the first quarter of 2021. In Côte
d'Ivoire seismic activities have now been fully demobilised from
onshore block CI-520 and Tullow has now exited the licence. Tullow
has now exited all onshore blocks in Côte d'Ivoire but retains its
90% interest in the offshore Block CI-524, adjacent to the TEN
field. The Group continues to optimise its portfolio and has exited
Blocks Z38 and Z64 in Peru and PEL 0037 in Namibia. Refer to note
11 for details of the Group exploration write-off assessment.
FINANCE REVIEW
Financial summary 1H 2021 1H 2020
======================================================= ======== ========
Working interest production volume (boepd) 61,230 77,700
======================================================= ======== ========
Sales volume (boepd) 65,800 77,100
======================================================= ======== ========
Realised oil price ($/bbl) 60.8 51.8
======================================================= ======== ========
Total revenue ($m) 727 731
======================================================= ======== ========
Gross profit ($m) 321 164
======================================================= ======== ========
Underlying cash operating costs per boe ($/boe) (1) 12.9 11.0
======================================================= ======== ========
Exploration costs written off ($m) 49 941
======================================================= ======== ========
Impairment of property, plant and equipment, net ($m) 8 418
======================================================= ======== ========
Operating profit/(loss) ($m) 370 (1,306)
======================================================= ======== ========
Profit/ (loss) before tax ($m) 213 (1,436)
======================================================= ======== ========
Profit/(loss) after tax ($m) 93 (1,327)
======================================================= ======== ========
Basic earnings/(loss) per share (cents) 6.5 (94.2)
======================================================= ======== ========
Capital investment ($m) (1) 101 192
======================================================= ======== ========
Last 12 months adjusted EBITDAX ($m) (1) 885 1,013
======================================================= ======== ========
Net debt ($m) (1) 2,290 3,019
======================================================= ======== ========
Gearing (times) (1) 2.6 3.0
======================================================= ======== ========
Free cash flow ($m) (1) 86 (213)
======================================================= ======== ========
Underlying operating cash flow ($m) (1) 218 154
======================================================= ======== ========
Pre- Financing free cash flow ($m) (1) 227 (105)
======================================================= ======== ========
(1) Underlying cash operating costs per boe, capital investment,
adjusted EBITDAX, net debt, gearing, free cash flow, underlying
operating cash flow and pre-financing free cash flow are
alternative performance measures and are explained and reconciled
on pages 36 to 39.
Production and commodity prices
Total Group working interest production averaged 61,230 boepd
(1H 2020: 77,700 boepd), a decrease of 21% for the period. The
decrease in production primarily resulted from the natural decline
in Jubilee and TEN and the sale of Equatorial Guinea and Dussafu
asset in Gabon in 1H21. The drilling of new wells in Ghana to
offset the production decline commenced in 1H21. However, the first
well drilled and completed, J-56, came onstream in July 2021 and as
such did not contribute to 1H21 production.
The realised oil price after hedging for the period was
$60.8/bbl (1H 2020: $51.8/bbl) and before hedging $65.2/bbl (1H
2020: $42.5/bbl). There has been a recovery in oil markets in 2H20
and 1H21, which has led to higher realised prices partially offset
by hedge losses, decreasing total revenue by $52.4 million (1H
2020: increase of $130.8 million).
1H 2021 1H 2020
======================= ======== ========
Profit and Loss
======================= ======== ========
Revenue ($m) 727 731
======================= ======== ========
Overlift expense ($m) (90) (129)
======================= ======== ========
Balance Sheet
======================= ======== ========
Underlift ($m) 4 36
======================= ======== ========
Overlift ($m) (78) (13)
======================= ======== ========
The overlift expense was primarily caused by the timing of
liftings with seven cargos across Ghana, Gabon and Cote d'Ivoire
lifted in June 2021.
Operating costs, depreciation and expenses
Underlying cash operating costs amounted to $143 million;
$12.9/boe (1H 2020: $155 million; $11.0/boe). The increase in cash
unit operating costs is principally due to lower production and
increased costs associated with COVID-19 operating procedures,
partially offset by reduced operating costs mainly associated with
Jubilee and the cessation of shuttle tanker operations in the
Jubilee field in 1Q21 following commissioning of a Catenary Anchor
Leg Mooring buoy. Cash operating costs excluding COVID-19 operating
procedures and shuttle tanker operations were $11.6/boe (1H 2020:
$9.6/boe). The sale of Equatorial Guinea and the Dussafu asset in
Gabon in 1H21 also contributed to the decrease in total operating
costs.
DD&A charges before impairment on production and development
assets amounted to $170 million; $15.3/boe (1H 2020: $267 million;
$18.9/boe). This decrease in DD&A per barrel is mainly
attributable to 2020 impairments and increases to 2020 year end
reserves partially offset by decreased production.
Administrative expenses of $23 million (1H 2020: $51 million)
significantly decreased against the comparative period. In February
2020, Tullow concluded its Business Review, which included a review
of the Group's organisation structure and resources and resulted in
a significant headcount reduction. Furthermore, the Group has
focused on reducing non-payroll G&A costs including
outsourcing, information systems expenses, professional fees and
office rent. However, this is partially offset by the adverse
GBP:USD FX variance in 2021. Tullow is still on target to deliver
sustainable cash savings of over $125 million per annum.
Impairment of property, plant and equipment (PP&E) 1H 2021 1H 2020
==================================================== ======== ========
Pre-tax impairment of PP&E, net ($m) 8 418
==================================================== ======== ========
Associated deferred tax credit ($m) (4) (107)
==================================================== ======== ========
Post-tax impairment of PP&E, net ($m) 4 311
==================================================== ======== ========
The Group recognised a net impairment charge on PP&E of $8
million in respect of first half 2021 (1H 2020: $418 million) due
to changes to estimates on the cost of decommissioning for certain
UK assets.
Exploration costs written off 1H 2021 1H 2020
=================================== ======== ========
Exploration cost written off ($m) 49 941
=================================== ======== ========
During the first half of 2021, the Group has written off
exploration costs of $49 million (1H 2020: $941 million) which are
predominantly driven by write-offs of the GVN-1 well costs in Block
47 in Suriname and subsequently all associated licence costs for
all blocks in Suriname. The remaining write-offs comprise of
licence level costs associated with Peru, Comoros, Côte d'Ivoire
and Namibia due to no planned activity and licence exits. This is
offset by a release of an indirect tax provision following
settlement in Uganda relating to its disposal in 2020.
Disposals
On 9 February 2021, Tullow announced that it signed two separate
sale and purchase agreements with Panoro Energy ASA for all of
Tullow's assets in Equatorial Guinea and the Dussafu Marin permit
asset in Gabon for a total consideration of $180 million, inclusive
of contingent payments.
In March 2021, the Group completed the sale of its assets in
Equatorial Guinea and $89 million was received in cash following
completion adjustments. The net gain on disposal on this
transaction is $123 million.
In June 2021, the Group completed the sale of its Dussafu Marin
permit asset in Gabon and $39 million was received in cash
following completion adjustments. An additional $5 million was
received for completion of both transactions. The net gain on
disposal on this transaction is $5 million.
Derivative financial instruments
Tullow continues to undertake hedging activities as part of the
ongoing management of its business risk to protect against
commodity price volatility and to ensure the availability of cash
flow for re-investment in capital programmes that are driving
business delivery.
At 30 June 2021, Tullow's hedge portfolio provides downside
protection for 51% of forecast production entitlements through to
May 2023 and 29% for a further 12 months to May 2024. Since
completion of the comprehensive debt refinancing in May, new hedges
have been placed with $55/bbl floors and weighted average sold
calls of c.$70/bbl.
At 30 June 2021, the Group's derivative instruments had a net
negative fair value of $148 million (30 June 2020: positive $197
million).
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. 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.
All of the Group's derivatives are Level 2 (1H 2020: Level 2).
There were no transfers between fair value levels during the
year.
2H 2021 hedge position at 30 June 2021 Bopd Bought put (floor) Sold call Bought call
======================================== ======= =================== ========== ============
Collars 39,000 $48.12 $66.47 -
======================================== ======= =================== ========== ============
Three-way collars (call spread) 1,000 $50.00 $72.80 $82.80
======================================== ======= =================== ========== ============
Total/weighted average 40,000 $48.17 $66.63 $82.80
======================================== ======= =================== ========== ============
The 2022, 2023 and 2024 hedging position at 30 June 2021 was
c.23,400 bopd, c.20,000 bopd and c.6,800 bopd hedged with an
average protected floor price of $48/bbl, $55/bbl and $55/bbl
respectively.
Net financing costs
Net financing costs for the period were $157 million (1H 2020:
$131 million). The increase in financing costs during the period is
mainly driven by finance fees, such as legal and advisor fees
related to the assessment of alternative refinancing options of the
extinguished RBL Facility directly expensed to the income statement
($18 million), as well as increased average cost of debt following
completion of the refinancing transactions in May 2021, offset by
the net gain on early settlement and derecognition of the RBL
Facility and the 2022 Notes ($8 million credit).
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 8.
Taxation
The overall net tax expense of $ 120 million (1H 2020: credit of
$109 million) primarily relates to expenses in respect of Ghana and
West Africa non-operated assets net of non-recurring deferred tax
credits associated with exploration write-offs, impairments and
onerous lease provisions. The tax charge has been calculated by
applying the effective tax rate which is expected to apply to each
jurisdiction for the year ending 31 December 2021.
The Group's statutory effective tax rate is 56.4% (1H 2020:
7.6%). After adjusting for the non-recurring amounts related to
exploration write-offs, impairments, restructuring costs, disposals
and onerous lease provisions and their associated tax benefit, the
Group's underlying effective tax rate is 83.1% (1H 2020: (57.7%) ).
The change in effective tax rate from 1H20 to 1H21 is due primarily
to there being no UK tax benefit from net interest and hedging
expenses in 1H21, compared to net profits in 1H20. Non-deductible
expenditure in Ghana and a change to the mix of taxable and
non-taxable profits in Gabon are additional contributing
factors.
Analysis of effective tax rate Profit/(loss) Tax (expense)/credit Effective tax
($'m) before tax rate
================================= ============== ===================== ==============
Ghana - 1H 2021 200.3 (72.6) 36.2%
================================= ============== ===================== ==============
1H 2020 (65.5) 19.7 30.1%
================================= ============== ===================== ==============
Gabon - 1H 2021 79.1 (38.1) 48.2%
================================= ============== ===================== ==============
1H 2020 8.6 (11.1) 128.0%
================================= ============== ===================== ==============
Equatorial Guinea - 1H 2021 15.5 (5.4) 35.0%
================================= ============== ===================== ==============
1H 2020 15.0 (5.3) 35.6%
================================= ============== ===================== ==============
Corporate - 1H 2021 (157.9) (0.6) -0.4%
================================= ============== ===================== ==============
1H 2020 38.1 (9.5) 24.9%
================================= ============== ===================== ==============
Other non-operated & exploration
- 1H 2021 4.6 (0.9) 20.4%
================================= ============== ===================== ==============
1H 2020 (6.3) 0.3 5.1%
================================= ============== ===================== ==============
Total - 1H 2021 141.7 (117.7) 83.1%
================================= ============== ===================== ==============
1H 2020 (10.1) (5.8) (57.7%)
================================= ============== ===================== ==============
Profit/ (Loss) after tax from continuing activities and earnings
/(loss) per share
The profit after tax for the period amounted to $93 million (1H
2020: $1,327 million loss). Basic earnings per share was 6.5 cents
(1H 2020: basic loss per share of 94.2 cents).
Reconciliation of net debt $m
============================================================================================= ========
Year-end 2020 net debt 2,375.6
============================================================================================= ========
Sales revenue (726.8)
============================================================================================= ========
Operating costs 143.3
============================================================================================= ========
Other operating and administrative expenses 137.0
============================================================================================= ========
Cash flow from operations (446.5)
============================================================================================= ========
Movement in working capital 151.1
============================================================================================= ========
Tax paid 37.3
============================================================================================= ========
Purchases of intangible exploration and evaluation assets and property, plant and equipment 97.2
============================================================================================= ========
Other investing activities (134.1)
============================================================================================= ========
Other financing activities 213.0
============================================================================================= ========
Foreign exchange loss on cash (3.6)
============================================================================================= ========
1H 2021 net debt 2,290.0
============================================================================================= ========
Capital investment
Capital expenditure amounted to $101 million (1H 2020: $192
million) with $65 million invested in production and development
activities and $36 million invested in exploration and appraisal
activities.
Capital investment will continue to be carefully controlled in
the second half of 2021 and total 2021 capital expenditure is
expected to be c.$260 million. The capital investment total is
expected to comprise Ghana capex of c.$160 million, West African
non-operated capex of c.$46 million and Kenya pre-development
expenditure of c.$4 million and exploration and appraisal
expenditure of c.$50 million. This reflects the reduction in capex
following the sales of the Equatorial Guinea assets and the Dussafu
Marin permit in Gabon, offset in part by the acceleration of the
Simba expansion development in Gabon and incremental increases
across Ghana, Gabon and Kenya.
Going concern
The Directors consider the going concern assessment period to be
up to 30 September 2022. 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: $60/bbl for 2021, $60/bbl for 2022; and
Low Case: $45/bbl for 2021, $45/bbl for 2022.
The Low Case includes, amongst other downside assumptions, a 6
per cent production decrease compared to the Base Case as well as
increased outflows associated with an ongoing dispute.
On 17 May 2021, the Group announced the completion of its
offering of $1.8 billion Senior Secured Notes due 2026. The net
proceeds, together with cash on balance sheet, have been used to
(i) repay all amounts outstanding under, and cancel all commitments
made available pursuant to, the Company's RBL Facility, (ii) redeem
in full the Company's senior notes due 2022, (iii) at maturity,
repay in full and cancel the Company's convertible bonds due 2021
and (iv) pay fees and expenses incurred in connection with the
transactions. The Group also entered into a $500 million Super
Senior Revolving Credit Facility (SSRCF) which is undrawn and will
be primarily used for working capital purposes. The 2026 Senior
Notes and the SSRCF do not have any maintenance covenants
(disclosure of key covenants and the determination of availability
under the SSRCF are provided in note 18). Following completion of
these transactions the Directors have concluded that the material
uncertainties noted in the 2020 Annual Report and Accounts,
associated with implementing a Refinancing Proposal and obtaining
amendments or waivers in respect of covenant breaches or, in the
event a Refinancing Proposal is implemented, the revised covenants
are subsequently breached, no longer exist.
The Group had $0.7 billion liquidity headroom of unutilised debt
capacity and free cash as at 30 June 2021. 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. These
forecasts show full availability of the $500 million SSRCF, which
under the Base Case remains undrawn. Furthermore Management have
performed a reverse stress test and the average oil price
throughout the going concern period required to reduce headroom to
zero during the assessment period is $42/bbl. Based on the analysis
above, the Directors have a reasonable expectation that the Company
has adequate resources to continue in operational existence for the
foreseeable future. Thus, they have adopted the going concern basis
of accounting in preparing the half year results.
2021 principal risks and uncertainties
The Board determines the key risks for the Group and monitors
mitigation plans and performance on a monthly basis. An exercise
was performed in June 2021 to assess whether the principal risks
and uncertainties disclosed in the 2020 Annual Report continue to
be appropriate given the change in external risk landscape.
Although there has been some change to sub-risks, the principal
risks and uncertainties facing the Group at half year remain
unchanged from those disclosed in the 2020 Annual Report as listed
below. Whilst the Group has successfully refinanced its debt
facilities in 1H 2021 it still believes that the sustainability of
its capital structure may be a risk in the medium to long term. The
company risk profile continues to be assessed on an ongoing basis
including considering if the pandemic or oil price volatility
results in any new risks or changes to existing risks. Risks
associated with COVID-19 have been considered and managed across
all principal risk categories.
1. Risk of failure to deliver operations, development and subsurface objectives
2. Risk of failure to deliver commercially attractive and timely development projects
3. Risk of disruption to business due to inability to manage stakeholder relations
4. Risk of failure to manage impact of climate change
5. Risk of asset integrity breach or major production failure
6. Risk of insufficient liquidity and funding capacity
7. Risk that we fail to deliver a sustainable capital structure
8. Risk that the transformation plan fails to support the strategy and deliver cost savings
9. Risk that the people strategy and culture do not support the strategy
10. Risk of major compliance breach
11. Risk of major cyber attack
Events since 30 June 2021
There have not been any adjusting events since 30 June 2021 that
have resulted in a material impact on the half year results.
Non-Adjusting event
On 17 May 2021, as part of the refinancing transaction $310
million was agreed to be put into a trustee account for settlement
of principal and accrued interest of the convertible loan notes on
due date. On 12 July 2021, the convertible loan notes were settled
by the trustees by utilising the amount kept in the trust
account.
Responsibility statement
The Directors confirm that to the best of their knowledge:
a. the condensed set of financial statements has been prepared
in accordance with IAS 34 'Interim Financial Reporting';
b. the interim management report includes a fair review of the
information required by DTR 4.2.7R (indication of important events
during the first six months and description of principal risks and
uncertainties for the remaining six months of the year); and
c. the interim management report includes a true and fair review
of the information required by DTR 4.2.8R (disclosure of related
parties' transactions and changes therein).
A list of the current Directors is maintained on the Tullow Oil
plc website: www.tullowoil.com.
By order of the Board,
Rahul Dhir
Chief Executive Officer
14 September 2021
Les Wood
Chief Financial Officer
14 September 2021
Disclaimer
This statement contains certain forward-looking statements that
are subject to the usual risk factors and uncertainties associated
with the oil and gas exploration and production business. Whilst
the Group believes the expectations reflected herein to be
reasonable in light of the information available to them at this
time, the actual outcome may be materially different owing to
factors beyond the Group's control or within the Group's control
where, for example, the Group decides on a change of plan or
strategy. Accordingly, no reliance may be placed on the figures
contained in such forward-looking statements.
Independent review report to Tullow Oil plc
Conclusion
We have been engaged by the Tullow Oil Plc (the Company) to
review the condensed set of financial statements in the half-yearly
financial report for the six months ended 30 June 2021 which
comprises of Condensed consolidated income statement, Condensed
consolidated statement of comprehensive income and expense,
Condensed consolidated balance sheet, Condensed statement of
changes in equity, Condensed consolidated cash flow statement and
the related notes 1 to 23. We have read the other information
contained in the half yearly financial report and considered
whether it contains any apparent misstatements or material
inconsistencies with the information in the condensed set of
financial statements.
Based on our review, nothing has come to our attention that
causes us to believe that the condensed set of financial statements
in the half-yearly financial report for the six months ended 30
June 2021 is not prepared, in all material respects, in accordance
with UK adopted International Accounting Standard 34 and the
Disclosure Guidance and Transparency Rules of the United Kingdom's
Financial Conduct Authority.
Basis for Conclusion
We conducted our review in accordance with International
Standard on Review Engagements 2410 (UK and Ireland) "Review of
Interim Financial Information Performed by the Independent Auditor
of the Entity" issued by the Auditing Practices Board. A review of
interim financial information consists of making enquiries,
primarily of persons responsible for financial and accounting
matters, and applying analytical and other review procedures. A
review is substantially less in scope than an audit conducted in
accordance with International Standards on Auditing (UK) and
consequently does not enable us to obtain assurance that we would
become aware of all significant matters that might be identified in
an audit. Accordingly, we do not express an audit opinion.
As disclosed in note 2, the annual financial statements of the
Group will be prepared in accordance with UK adopted IFRSs. The
condensed set of financial statements included in this half-yearly
financial report has been prepared in accordance with UK adopted
International Accounting Standard 34, "Interim Financial
Reporting.
Responsibilities of the directors
The Directors are responsible for preparing the half-yearly
financial report in accordance with the Disclosure Guidance and
Transparency Rules of the United Kingdom's Financial Conduct
Authority
Auditor's Responsibilities for the review of the financial
information
In reviewing the half yearly report, we are responsible for
expressing to the Company a conclusion on the condensed set of
financial statement in the half-yearly financial report. Our
conclusion, is based on procedures that are less extensive than
audit procedures, as described in the Basis for Conclusion
paragraph of this report.
Use of our report
This report is made solely to the company in accordance with
guidance contained in International Standard on Review Engagements
2410 (UK and Ireland) "Review of Interim Financial Information
Performed by the Independent Auditor of the Entity" issued by the
Auditing Practices Board. To the fullest extent permitted by law,
we do not accept or assume responsibility to anyone other than the
company, for our work, for this report, or for the conclusions we
have formed.
Ernst & Young LLP
London
14 September 2021
Condensed consolidated income statement
Six months ended 30 June 2021
Notes Six months ended 30.06.21 Six months ended 30.06.20 Year ended 31.12.20
Unaudited $m Unaudited $m Audited $m
========================== ====== ========================== ========================== ==========================
Continuing activities
-------------------------- ------ -------------------------- -------------------------- --------------------------
Revenue 6 726.8 731.0 1,396.1
-------------------------- ------ --------------------------
Cost of sales 7 (405.7) (567.0) (993.6)
========================== ====== ========================== ========================== ==========================
Gross profit 321.1 164.0 402.5
========================== ====== ========================== ========================== ==========================
Administrative expenses 7 (23.1) (51.5) (86.7)
-------------------------- ------ --------------------------
Restructuring costs and
provision for onerous
contracts 7 5.9 (58.6) (92.8)
-------------------------- ------ --------------------------
Gain/ (loss) on disposal 10 122.9 (0.1) (3.4)
-------------------------- ------ --------------------------
Exploration costs written
off 11 (49.3) (941.4) (986.7)
-------------------------- ------ --------------------------
Impairment of property,
plant and equipment, net 12 (8.0) (418.3) (250.6)
========================== ====== ========================== ========================== ==========================
Operating profit/ (loss) 369.5 (1,305.9) (1,017.7)
========================== ====== ========================== ========================== ==========================
Gain/ (loss) on hedging
instruments 0.2 1.3 (0.8)
-------------------------- ------ --------------------------
Finance revenue 8 22.1 29.0 59.4
-------------------------- ------ --------------------------
Finance costs 8 (178.7) (159.9) (314.3)
========================== ====== ========================== ========================== ==========================
Profit/ (loss) from
continuing activities
before tax 213.1 (1,435.5) (1,273.4)
========================== ====== ========================== ========================== ==========================
Income tax (expense)/
credit 9 (120.4) 108.7 51.9
========================== ====== ========================== ========================== ==========================
Profit/ (loss) for the
year from continuing
activities 92.7 (1,326.8) (1,221.5)
========================== ====== ========================== ========================== ==========================
Attributable to
-------------------------- ------ -------------------------- -------------------------- --------------------------
Owners of the Company 92.7 (1,326.8) (1,221.5)
-------------------------- ------ -------------------------- -------------------------- --------------------------
Earnings/ (loss) per c c c
ordinary share from
continuing activities
========================== ====== ========================== ========================== ==========================
Basic 3 6.5 (94.2) (86.6)
-------------------------- ------ --------------------------
Diluted 3 6.2 (94.2) (86.6)
========================== ====== ========================== ========================== ==========================
Condensed consolidated statement of comprehensive income and
expense
Six months ended 30 June 2021
Six months ended 30.06.21 Six months ended 30.06.20 Year ended 31.12.20 Audited
Unaudited $m Unaudited $m $m
============================ ============================ ============================ ============================
Profit/ (loss) for the
period 92.7 (1,326.8) (1,221.5)
============================ ============================ ============================ ============================
Items that may be
reclassified to the income
statement in subsequent
periods
============================ ============================ ============================ ============================
Cash flow hedges
---------------------------- ----------------------------
(Loss)/ gain arising in
the period (101.2) 370.6 271.0
---------------------------- ----------------------------
Losses arising in the
period - time value (108.2) (31.9) (37.3)
---------------------------- ----------------------------
Reclassification
adjustments for items
included in loss/
(profit) on realisation 30.8 (155.7) (268.1)
---------------------------- ----------------------------
Reclassification
adjustments for items
included in loss on
realisation - time value 21.6 24.8 49.4
---------------------------- ----------------------------
Exchange differences on
translation of foreign
operations (2.0) (1.8) (5.3)
============================ ============================ ============================ ============================
Other comprehensive
(expense)/ income (159.0) 206.0 9.8
============================ ============================ ============================ ============================
Tax relating to components
of other comprehensive
expense 2.8 (15.5) (2.7)
============================ ============================ ============================ ============================
Net other comprehensive
(expense)/ income for the
period (156.2) 190.5 7.1
============================ ============================ ============================ ============================
Total comprehensive expense
for the period (63.5) (1,136.3) (1,214.4)
============================ ============================ ============================ ============================
Attributable to
============================ ============================ ============================ ============================
Owners of the Company (63.5) (1,136.3) (1,214.4)
============================ ============================ ============================ ============================
Condensed consolidated balance sheet
As at 30 June 2021
Six months ended
Six months ended 30.06.20 Year ended 31.12.20 Audited
Notes 30.06.21 Unaudited $m Restated Unaudited $m $m
============================= ====== ======================= ======================= =============================
Assets
----------------------------- ------ ----------------------- -----------------------------
Non-current asset
----------------------------- ------ ----------------------- -----------------------------
Intangible exploration and
evaluation assets 11 346.3 356.6 368.2
----------------------------- ------ -----------------------------
Property, plant and
equipment 12 3,144.1 3,326.0 3,237.9
----------------------------- ------ -----------------------------
Other non-current assets 14 514.9 577.5 547.4
----------------------------- ------ -----------------------------
Derivative financial
instruments 6.6 43.9 2.6
----------------------------- ------ -----------------------------
Deferred tax assets 490.4 495.5 494.3
============================= ====== ======================= ======================= =============================
4,502.3 4,799.5 4,650.4
============================= ====== ======================= ======================= =============================
Current assets
----------------------------- ------ -----------------------------
Inventories 141.3 121.8 96.1
------ -----------------------------
Trade receivables 13 256.4 64.5 79.0
----------------------------- ------ -----------------------------
Other current assets 14 1,044.0 745.7 717.1
----------------------------- ------ -----------------------------
Current tax assets 41.4 58.5 36.4
----------------------------- ------ -----------------------------
Derivative financial
instruments - 153.0 17.2
----------------------------- ------ -----------------------------
Cash and cash equivalents 301.8 236.3 805.4
----------------------------- ------ -----------------------------
Assets classified as held
for sale - 610.8 155.6
============================= ====== ======================= ======================= =============================
1,784.9 1,990.6 1,906.8
============================= ====== ======================= ======================= =============================
Total assets 6,287.2 6,790.1 6,557.2
============================= ====== ======================= ======================= =============================
Liabilities
----------------------------- ------ -----------------------------
Current liabilities
----------------------------- ------ -----------------------------
Trade and other payables 17 (887.6) (831.6) (750.7)
----------------------------- ------ -----------------------------
Borrowings 18 (297.8) - (3,170.5)
Provisions 19 (255.3) (161.8) (229.8)
Current tax liabilities (95.1) (98.5) (52.2)
Derivative financial
instruments (104.5) - (17.8)
Liabilities directly
associated with assets
classified as held for sale - (28.8) (187.3)
============================= ====== ======================= ======================= =============================
(1,640.3) (1,120.7) (4,408.3)
============================= ====== ======================= ======================= =============================
Non-current liabilities
----------------------------- ------ -----------------------------
Trade and other payables 17 (1,013.3) (1,147.7) (1,064.7)
----------------------------- ------ -----------------------------
Borrowings 18 (2,565.5) (3,239.2) -
----------------------------- ------ -----------------------------
Provisions 19 (575.5) (774.2) (620.9)
----------------------------- ------ -----------------------------
Deferred tax liabilities (709.4) (646.5) (673.3)
----------------------------- ------ -----------------------------
Derivative financial
instruments (50.2) - -
============================= ====== ======================= ======================= =============================
(4,913.9) (5,807.6) (2,358.9)
============================= ====== ======================= ======================= =============================
Total liabilities (6,554.2) (6,928.3) (6,767.2)
============================= ====== ======================= ======================= =============================
Net liabilities (267.0) (138.2) (210.0)
============================= ====== ======================= ======================= =============================
Equity
----------------------------- ------ -----------------------------
Called up share capital 213.8 211.2 211.7
----------------------------- ------ -----------------------------
Share premium 1,294.7 1,294.7 1,294.7
----------------------------- ------ -----------------------------
Equity component of
convertible bonds 48.4 48.4 48.4
----------------------------- ------ -----------------------------
Foreign currency translation
reserve (249.4) (243.9) (247.4)
----------------------------- ------ -----------------------------
Hedge reserve (62.6) 203.9 4.8
----------------------------- ------ -----------------------------
Hedge reserve - time value (92.1) (24.6) (5.4)
----------------------------- ------ -----------------------------
Merger reserve 755.2 755.2 755.2
----------------------------- ------ -----------------------------
Retained earnings (2,175.0) (2,383.1) (2,272.0)
----------------------------- ------ ======================= ======================= -----------------------------
Equity attributable to
equity holders of the
Company (267.0) (138.2) (210.0)
============================= ====== ======================= ======================= =============================
Total equity (267.0) (138.2) (210.0)
============================= ====== ======================= ======================= =============================
Condensed statement of changes in equity
As at 30 June 2021
Equity
component Foreign Hedge
of currency reserve
Share Share convertible translation Hedge - Time Merger Retained Total
capital $m premium $m bonds $m reserve(1) $m reserve(2) $m value $m reserve $m earnings $m equity $m
======================= =========== =========== ============ ============== ============== ========= =========== ============ ==========
At 1 January 2020
(previously reported) 210.9 1,380.0 48.4 (242.1) 4.6 (17.5) 755.2 (1,155.9) 983.6
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Restatement(3) - (85.3) - - - - - 85.3 -
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
At 1 January 2020 (as
adjusted) 210.9 1,294.7 48.4 (242.1) 4.6 (17.5) 755.2 (1,070.6) 983.6
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Loss for the period - - - - - - - (1,326.8) (1,326.8)
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Hedges, net of tax - - - - 199.3 (7.1) - - 192.2
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Currency translation
adjustments - - - (1.8) - - - - (1.8)
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Exercising of employee
share options 0.3 - - - - - - (0.3) -
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Share-based payment
charges - - - - - - - 14.6 14.6
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
At 30 June 2020 (as
adjusted) 211.2 1,294.7 48.4 (243.9) 203.9 (24.6) 755.2 (2,383.1) (138.2)
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Profit for the period - - - - - - - 105.3 105.3
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Hedges, net of tax - - - - (199.1) 19.2 - - (179.9)
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Currency translation
adjustments - - - (3.5) - - - - (3.5)
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Exercising of employee
share options 0.5 - - - - - - (0.5) -
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
Share-based payment
charges - - - - - - - 6.3 6.3
----------------------- ----------- ----------- ------------ -------------- -------------- --------- ----------- ------------ ----------
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 period - - - - - - - 92.7 92.7
Hedges, net of tax - - - - (67.4) (86.7) - - (154.1)
Currency translation
adjustments - - - (2.0) - - - - (2.0)
Exercising of employee
share options 2.1 - - - - - - (2.1) -
Share-based payment
charges - - - - - - - 6.4 6.4
======================= =========== =========== ============ ============== ============== ========= =========== ============ ==========
At 30 June 2021 213.8 1,294.7 48.4 (249.4) (62.6) (92.1) 755.2 (2,175.0) (267.0)
======================= =========== =========== ============ ============== ============== ========= =========== ============ ==========
(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, and exchange gains or losses arising on long-term
foreign currency borrowings which are a hedge against the Group's
overseas investments.
(2) The hedge reserve represents gains and losses on derivatives
classified as effective cash flow hedges.
(3) Comparative information in respect of share premium and
retained earnings at 1 January 2020, 30 June 2020 and for the 6
months ended 30 June 2020 have been restated in relation to the
treatment of the exercise of nil-cost employee share options which
are issued at nominal value rather than market value as previously
recognised. This has an $85.3 million impact on the opening
position as at 1 January 2020 and $85.9 million as at 30 June 2020
and $0.6 million impact on the options issued in 1H 2020. This
restatement was included in the 2020 Annual Report and
Accounts.
Condensed consolidated cash flow statement
Six months ended 30 June 2021
Notes Year ended 31.12.20
Six months ended 30.06.21 Six months ended 30.06.20 Audited
Unaudited $m Unaudited $m $m
========================== ====== ========================== ========================== ==========================
Cash flows from operating
activities
-------------------------- ------ -------------------------- --------------------------
Profit/ (loss) from
continuing activities
before tax 213.1 (1,435.5) (1,273.4)
-------------------------- ------ --------------------------
Adjustments for
-------------------------- ------ --------------------------
Depreciation, depletion
and amortisation 178.7 277.6 467.1
-------------------------- ------ --------------------------
(Gain)/ loss on disposal 10 (122.9) 0.1 3.4
-------------------------- ------ --------------------------
Exploration costs written
off 11 49.3 941.4 986.7
-------------------------- ------ --------------------------
Impairment of property,
plant and equipment, net 12 8.0 418.3 250.6
-------------------------- ------ --------------------------
Restructuring costs and
provision for onerous
contracts 19 (5.9) 58.6 92.8
-------------------------- ------ --------------------------
Payments under
restructuring costs and
provision for onerous
contracts 19 (8.9) (36.1) (58.4)
-------------------------- ------ --------------------------
Decommissioning
expenditure (27.7) (37.8) (57.7)
-------------------------- ------ --------------------------
Share-based payment
charge 6.4 12.0 20.9
-------------------------- ------ --------------------------
(Gain)/ loss on hedging
instruments (0.2) (1.3) 0.8
-------------------------- ------ --------------------------
Finance revenue 8 (22.1) (29.0) (59.4)
-------------------------- ------ --------------------------
Finance costs 8 178.7 159.9 314.3
-------------------------- ------ ========================== ========================== --------------------------
Operating cash flow
before working capital
movements 446.5 328.2 687.7
-------------------------- ------ --------------------------
(Increase)/ decrease in
trade and other
receivables (143.2) 147.1 195.2
------ --------------------------
(Increase)/ decrease in
inventories (50.2) 66.4 85.1
-------------------------- ------ --------------------------
Increase/ (decrease) in
trade payables 42.3 (246.0) (161.9)
========================== ====== ========================== ========================== ==========================
Cash flows from operating
activities 295.4 295.7 806.1
-------------------------- ------ --------------------------
Income taxes paid (37.3) (93.1) (107.5)
-------------------------- ------ ========================== ========================== --------------------------
Net cash from operating
activities 258.1 202.6 698.6
========================== ====== ========================== ========================== ==========================
Cash flows from investing
activities
-------------------------- ------ --------------------------
Proceeds from disposals,
net of cash disposed 10 132.4 0.5 513.4
-------------------------- ------ --------------------------
Purchase of intangible
exploration and
evaluation assets (55.8) (101.2) (213.6)
-------------------------- ------ --------------------------
Purchase of property,
plant and equipment (41.4) (121.0) (217.3)
-------------------------- ------ --------------------------
Interest received 1.7 0.7 1.8
========================== ====== ========================== ========================== ==========================
Net cash from/ (used) in
investing activities 36.9 (221.0) 84.3
========================== ====== ========================== ========================== ==========================
Cash flows from financing
activities
-------------------------- ------ --------------------------
Debt arrangement fees (57.8) - -
-------------------------- ------ --------------------------
Repayment of borrowings 23 (2,080.0) (110.0) (185.0)
-------------------------- ------ --------------------------
Payment into trust for
repayment of convertible
bond(1) (309.8) - -
-------------------------- ------ --------------------------
Drawdown of borrowings 23 1,800.0 270.0 270.0
-------------------------- ------ --------------------------
Repayment of obligations
under leases (68.3) (86.3) (158.2)
-------------------------- ------ --------------------------
Finance costs paid (86.9) (105.0) (198.5)
========================== ====== ========================== ========================== ==========================
Net cash used in
financing activities (802.8) (31.3) (271.7)
========================== ====== ========================== ========================== ==========================
Net (decrease)/ increase
in cash and cash
equivalents (507.8) (49.7) 511.2
-------------------------- ------ --------------------------
Cash and cash equivalents
at beginning of period 805.4 288.8 288.8
-------------------------- ------ --------------------------
Foreign exchange
gain/(loss) 4.2 (2.8) 5.4
========================== ====== ========================== ========================== ==========================
Cash and cash equivalents
at end of period 15 301.8 236.3 805.4
========================== ====== ========================== ========================== ==========================
(1) On 17 May 2021, as part of the refinancing transaction
$309.8 million was agreed to be put into a trustee account for
settlement of principal and accrued interest of the convertible
loan notes on due date. On 12 July 2021 the convertible loan notes
were settled by the trustees by utilising the amount kept in the
trust account. This this has been disclosed as a financing activity
within cash flow statement.
Notes to the condensed financial statements
Six months ended 30 June 2021
1. General information
The condensed financial statements for the six-month period
ended 30 June 2021 have been prepared in accordance with UK adopted
International Accounting Standard (IAS) 34 Interim Financial
Reporting and the requirements of the Disclosure and Transparency
Rules (DTR) of the Financial Conduct Authority (FCA) in the United
Kingdom as applicable to interim financial reporting.
The Condensed financial statements represent a 'condensed set of
financial statements' as referred to in the DTR issued by the FCA.
Accordingly, they do not include all the information required for a
full annual financial report and are to be read in conjunction with
the Group's financial statements for the year ended 31 December
2020, which were prepared in accordance with international
accounting standards in conformity with the requirements of the
Companies Act 2006 and International Financial Reporting Standards
(IFRS) adopted pursuant to Regulation (EC) No 1606/2002 as it
applies in the European Union (EU). The Condensed financial
statements are unaudited and do not constitute statutory accounts
as defined in section 434 of the Companies Act 2006. The financial
information for the year ended 31 December 2020 does not constitute
statutory accounts as defined in section 434 of the Companies Act
2006. This information was derived from the statutory accounts for
the year ended 31 December 2020, a copy of which has been delivered
to the Registrar of Companies. The auditor's report on these
accounts was unqualified, drew attention by way of emphasis of
matter to the material uncertainty related to going concern without
qualifying the accounts and did not contain a statement under
sections 498 (2) or (3) of the Companies Act 2006.
2. Accounting policies
The annual financial statements of Tullow Oil plc will be
prepared in accordance with United Kingdom adopted international
accounting standards ("UK adopted IFRSs"). The condensed set of
financial statements included in this half-yearly financial report
has been prepared in accordance with UK adopted International
Accounting Standard 34 'Interim Financial Reporting', and the
Disclosure and Transparency Rules of the Financial Services
Authority.
There were adjustments made in relation to a recognition of
additional JV receivables ($23.4 million) and reclassification
between accruals ($37.9 million) and provisions ($46 million) that
should have been accounted in the prior period and was not done so
in error. In the directors' judgement, these amounts were not
considered material based on their nature as working capital
reclassifications and in assessment against the relative impact of
the financial statement line items, so the prior period amounts
have not been corrected.
The accounting policies adopted in the 2021 half-yearly
financial report are the same as those adopted in the 2020 Annual
report and accounts.
Going Concern
The Directors consider the going concern assessment period to be
up to 30 September 2022. 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: $60/bbl for 2021, $60/bbl for 2022; and
Low Case: $45/bbl for 2021, $45/bbl for 2022.
The Low Case includes, amongst other downside assumptions, a 6
per cent production decrease compared to the Base Case as well as
increased outflows associated with an ongoing dispute.
On 17 May 2021, the Group announced the completion of its
offering of $1.8 billion Senior Secured Notes due 2026. The net
proceeds, together with cash on balance sheet, have been used to
(i) repay all amounts outstanding under, and cancel all commitments
made available pursuant to, the Company's RBL Facility, (ii) redeem
in full the Company's senior notes due 2022, (iii) at maturity,
repay in full and cancel the Company's convertible bonds due 2021
and (iv) pay fees and expenses incurred in connection with the
transactions. The Group also entered into a $500 million Super
Senior Revolving Credit Facility (SSRCF) which is undrawn and will
be primarily used for working capital purposes. The 2026 Senior
Notes and the SSRCF do not have any maintenance covenants
(disclosure of key covenants and the determination of availability
under the SSRCF are provided in note 18). Following completion of
these transactions the Directors have concluded that the material
uncertainties noted in the 2020 Annual Report and Accounts,
associated with implementing a Refinancing Proposal and obtaining
amendments or waivers in respect of covenant breaches or, in the
event a Refinancing Proposal is implemented, the revised covenants
are subsequently breached, no longer exist.
The Group had $0.7 billion liquidity headroom of unutilised debt
capacity and free cash as at 30 June 2021. 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. These
forecasts show full availability of the $500 million SSRCF, which
under the Base Case remains undrawn. Furthermore Management have
performed a reverse stress test and the average oil price
throughout the going concern period required to reduce headroom to
zero during the assessment period is $42/bbl. Based on the
3. Accounting policies continued
analysis above, the Directors have a reasonable expectation that
the Company has adequate resources to continue in operational
existence for the foreseeable future. Thus, they have adopted the
going concern basis of accounting in preparing the half year
results.
4. Earnings/ (loss) per ordinary share
The calculation of basic earnings/ (loss) per share is based on
the profit/ (loss) for the period after taxation attributable to
equity holders of the parent of $92.7 million (1H 2020: loss of
$1,326.8 million) and a weighted average number of shares in issue
of 1,421.3 million (1H 2020: 1,408.9 million).
The calculation of diluted earnings per share is based on the
profit for the period after taxation as for basic earnings per
share. The number of shares outstanding, however, is adjusted to
show the potential dilution if employee share options are converted
into ordinary shares. The weighted average number of ordinary
shares is increased by 67.5 million resulting in a diluted weighted
average number of shares of 1,488.8 million.
5. Dividends
The Directors intend to recommend that no 2021 interim dividend
be paid.
6. Approval of accounts
These unaudited half year results were approved by the Board of
Directors on 14 September 2021.
7. 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, profit and certain asset
and liability information regarding the Group's reportable business
segments for the period ended 30 June 2021, 30 June 2020 and 31
December 2020.
Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m
================================= ========== ================ ========= =============== ============= ==========
Six months ended 30 June 2021
---------------------------------
Sales revenue by origin 467.8 259.0 - - - 726.8
================================= ========== ================ ========= =============== ============= ==========
Segment result(1) 237.1 94.8 0.8 (63.3) (5.6) 263.8
================================= ========== ================ ========= =============== ============= ==========
Gain on disposal 122.9
---------------------------------
Unallocated corporate
expenses(2) (17.2)
================================= ========== ================ ========= =============== ============= ==========
Operating profit 369.5
---------------------------------
Gain on hedging instruments 0.2
---------------------------------
Finance revenue 22.1
---------------------------------
Finance costs (178.7)
================================= ========== ================ ========= =============== ============= ==========
Profit before tax 213.1
---------------------------------
Income tax expense (120.4)
================================= ========== ================ ========= =============== ============= ==========
Profit after tax 92.7
================================= ========== ================ ========= =============== ============= ==========
Total assets 4,927.0 539.4 289.4 147.9 383.5 6,287.2
================================= ========== ================ ========= =============== ============= ==========
Total liabilities(3) (2,862.4) (483.0) (25.9) (44.5) (3,138.4) (6,554.2)
--------------------------------- ========== ================ ========= =============== ============= ==========
Other segment information
---------------------------------
Capital expenditure:
Property, plant and equipment 95.7 9.7 - 0.3 0.7 106.4
---------------------------------
Intangible exploration and
evaluation assets 0.8 (13.9) 4.4 36.1 - 27.4
---------------------------------
Depletion, depreciation and
amortisation (155.7) (15.3) (0.7) - (7.0) (178.7)
Impairment of property, plant
and equipment, net - (8.0) - - - (8.0)
Exploration costs written off (0.9) 14.1 0.8 (63.3) - (49.3)
================================= ========== ================ ========= =============== ============= ==========
(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) Unallocated expenditure include amounts of a corporate
nature and not specifically attributable to a segment.
(3) Total liabilities - Corporate comprise of the Group's
external debt and other non-attributable liabilities.
6. Segmental reporting continued
Reconciliation of segment result
Six months ended 30.06.21 Six months ended 30.06.20 Year ended 31.12.20 Audited
Unaudited $m Unaudited $m $m
============================ ============================ ============================ ============================
Segment result 263.8 (1,195.7) (834.8)
---------------------------- ---------------------------- ----------------------------
Add back
---------------------------- ---------------------------- ----------------------------
Exploration costs written
off 49.3 941.4 986.7
---------------------------- ---------------------------- ----------------------------
Impairment of Property,
Plant and Equipment 8.0 418.3 250.6
---------------------------- ---------------------------- ----------------------------
Gross profit 321.1 164.0 402.5
---------------------------- ---------------------------- ----------------------------
6. Segmental reporting continued
Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m
================================= ========== ================ ========= =============== ============= ==========
Six months ended 30 June 2020
---------------------------------
Sales revenue by origin 480.1 250.9 - - - 731.0
---------------------------------
Segment result (293.1) (368.6) (429.2) (93.2) (11.6) (1,195.7)
================================= ========== ================ ========= =============== ============= ==========
Loss on disposal (0.1)
================================= ========== ================ ========= =============== ============= ==========
Unallocated corporate expenses (110.1)
---------------------------------
Operating loss (1,305.9)
================================= ========== ================ ========= =============== ============= ==========
Gain on hedging instruments 1.3
---------------------------------
Finance revenue 29.0
---------------------------------
Finance costs (159.9)
---------------------------------
Loss before tax (1,435.5)
================================= ========== ================ ========= =============== ============= ==========
Income tax credit 108.7
---------------------------------
Loss after tax (1,326.8)
================================= ========== ================ ========= =============== ============= ==========
Total assets 4,898.5 1,190.2 295.4 170.6 235.4 6,790.1
================================= ========== ================ ========= =============== ============= ==========
Total liabilities (2,780.5) (683.8) (45.8) (67.6) (3,350.6) (6,928.3)
================================= ========== ================ ========= =============== ============= ==========
Other segment information
================================= ========== ================ ========= =============== ============= ==========
Capital expenditure:
---------------------------------
Property, plant and equipment 77.8 80.2 0.2 0.2 3.7 162.1
---------------------------------
Intangible exploration and
evaluation assets 0.4 35.6 9.0 69.6 - 114.6
---------------------------------
Depletion, depreciation and
amortisation (234.5) (34.4) (0.7) - (8.0) (277.6)
---------------------------------
Impairment of property, plant
and equipment, net (305.8) (112.5) - - - (418.3)
---------------------------------
Exploration costs written off (0.5) (418.0) (429.2) (93.7) - (941.4)
---------------------------------
Year ended 31 December 2020
---------------------------------
Sales revenue by origin 963.5 432.6 - - - 1,396.1
---------------------------------
Segment result 124.9 (410.2) (430.0) (104.3) (15.2) (834.8)
================================= ========== ================ ========= =============== ============= ==========
Loss on disposal (3.4)
---------------------------------
Unallocated corporate expenses (179.5)
================================= ========== ================ ========= =============== ============= ==========
Operating loss (1,017.7)
---------------------------------
Loss on hedging instruments (0.8)
---------------------------------
Finance revenue 59.4
---------------------------------
Finance costs (314.3)
================================= ========== ================ ========= =============== ============= ==========
Loss before tax (1,273.4)
---------------------------------
Income tax credit 51.9
================================= ========== ================ ========= =============== ============= ==========
Loss after tax (1,221.5)
================================= ========== ================ ========= =============== ============= ==========
Total assets 4,859.3 656.3 300.5 181.8 559.3 6,557.2
================================= ========== ================ ========= =============== ============= ==========
Total liabilities (2,696.7) (688.4) (34.1) (44.2) (3,303.8) (6,767.2)
================================= ========== ================ ========= =============== ============= ==========
Other segment information
---------------------------------
Capital expenditure:
---------------------------------
Property, plant and equipment 94.6 127.1 0.6 0.2 7.2 229.7
---------------------------------
Intangible exploration and
evaluation assets 0.9 68.5 9.5 91.8 - 170.7
---------------------------------
Depletion, depreciation and
amortization (390.1) (60.7) (1.5) - (14.8) (467.1)
---------------------------------
Impairment of property, plant
and equipment (149.1) (100.5) - (0.4) (0.6) (250.6)
---------------------------------
Exploration costs written off (0.8) (452.0) (430.0) (103.9) - (986.7)
================================= ========== ================ ========= =============== ============= ==========
6. Segmental reporting continued
Sales revenue Sales revenue
six months six months Sales revenue *Non-current *Non-current *Non-current
ended 30.06.21 ended 30.06.20 Year ended assets assets assets
$m $m 31.12.20 $m 30.06.21 $m 30.06.20 $m 31.12.20 $m
================ =============== =============== =============== =============== =============== ===============
Ghana 467.8 480.2 963.5 3,477.5 3,603.6 3,584.6
---------------- --------------- --------------- --------------- ---------------
Total Ghana 467.8 480.2 963.5 3,477.5 3,603.6 3,584.6
================ =============== =============== =============== =============== =============== ===============
Kenya - - - 256.3 256.9 251.8
Total Kenya - - - 256.3 256.9 251.8
================ =============== =============== =============== =============== =============== ===============
Argentina - - - 29.2 15.6 21.2
Cote d'Ivoire - - - - 4.5 2.7
---------------- --------------- --------------- --------------- ---------------
Guyana - - - 64.9 57.7 61.4
Suriname - - - - 31.4 35.6
Peru - - - - 0.1 0.3
Exploration - - - - 0.5
other -
================ =============== =============== =============== =============== =============== ===============
Total
Exploration - - - 94.1 109.8 121.2
---------------- --------------- --------------- --------------- ---------------
Gabon 178.0 140.5 274.5 61.5 104.1 68.8
---------------- --------------- --------------- --------------- ---------------
Côte
d'Ivoire 25.9 34.6 41.3 75.4 60.9 81.5
---------------- --------------- --------------- --------------- ---------------
Equatorial
Guinea(1) 55.1 75.6 116.8 - 79.7 -
---------------- --------------- --------------- --------------- ---------------
Other - 0.1 - - - -
================ =============== =============== =============== =============== =============== ===============
Total Non-
Operated 259.0 250.8 432.6 136.9 244.7 150.3
================ =============== =============== =============== =============== =============== ===============
Corporate - - - 40.5 45.0 45.6
================ =============== =============== =============== =============== =============== ===============
Total 726.8 731.0 1,396.1 4,005.3 4,260.1 4,153.5
================ =============== =============== =============== =============== =============== ===============
*Excludes derivative financial instruments and deferred tax
assets.
(1) $76.0 million of non-current assets was transferred to
Assets Held for Sale in December 2020. The disposal of Equatorial
Guinea was completed in March 2021. Refer to note 10.
7. Operating profit
Six months ended 30.06.21 Six months ended 30.06.20 Year ended 31.12.20 Audited
Unaudited $m Unaudited $m $m
============================ ============================ ============================ ============================
Operating profit is stated
after charging:
---------------------------- ---------------------------- ----------------------------
Operating costs 143.3 155.3 331.7
---------------------------- ----------------------------
Depletion and amortisation
of oil and gas and leased
assets(1) 169.5 266.7 446.4
---------------------------- ----------------------------
Underlift, overlift and oil
stock movement(2) 89.5 128.9 160.5
---------------------------- ----------------------------
Share-based payment charge
included in cost of sales 0.4 1.3 0.9
---------------------------- ----------------------------
Other cost of sales 3.0 14.8 54.1
============================ ============================ ============================ ============================
Total cost of sales 405.7 567.0 993.6
---------------------------- ============================ ============================ ----------------------------
Administrative expenses
---------------------------- ----------------------------
Share-based payment charge
included in administrative
expenses 6.0 10.7 20.0
---------------------------- ----------------------------
Depreciation of other
property, plant and
equipment(1) 9.2 10.9 20.7
---------------------------- ----------------------------
Other administrative costs 7.9 29.9 46.0
============================ ============================ ============================ ============================
Total administrative
expenses 23.1 51.5 86.7
============================ ============================ ============================ ============================
Total restructuring costs
and provision for onerous
contracts (5.9) 58.6 92.8
============================ ============================ ============================ ============================
(1) Depreciation expense on leased assets of $26.0 million as
per note 12 includes a charge of $1.9 million on leased
administrative assets, which is presented within administrative
expenses in the income statement. The remaining balance of $24.1
million relates to other leased assets and is included within cost
of sales.
(2) Refer to Note 17 for detailed explanation.
8. Net financing costs
Six months ended 30.06.21 Six months ended 30.06.20 Year ended 31.12.20 Audited
Unaudited $m Unaudited $m $m
============================ ============================ ============================ ============================
Interest on bank overdrafts
and borrowings 113.0 106.8 205.8
---------------------------- ----------------------------
Interest on obligations for
leases 43.1 46.1 91.0
============================ ============================ ============================ ============================
Total borrowing costs 156.1 152.9 296.8
---------------------------- ----------------------------
Finance fees 18.7 0.5 0.8
---------------------------- ----------------------------
Other Interest expense 0.2 - 3.6
---------------------------- ----------------------------
Unwinding of discount on
decommissioning provisions 3.7 6.5 13.1
============================ ============================ ============================ ============================
Total finance costs 178.7 159.9 314.3
============================ ============================ ============================ ============================
Interest income on amounts
due from joint venture
partners for leases (19.8) (28.6) (40.6)
============================ ============================ ============================ ============================
Other finance revenue (2.3) (0.4) (18.8)
============================ ============================ ============================ ============================
Total finance revenue (22.1) (29.0) (59.4)
============================ ============================ ============================ ============================
Net financing costs 156.6 130.9 254.9
============================ ============================ ============================ ============================
9. Taxation on profit/ (loss) on ordinary activities
The overall net tax expense of $120.4 million (1H 2020: credit
of $108.7 million) primarily relates to expenses in respect of
Ghana and West Africa non-operated assets net of non-recurring
deferred tax credits associated with exploration write-offs,
impairments and onerous lease provisions. The tax charge has been
calculated by applying the effective tax rate which is expected to
apply to each jurisdiction for the year ending 31 December
2021.
The Group's statutory effective tax rate is 56.4% (1H 2020:
7.6%). After adjusting for the non-recurring amounts related to
exploration write-offs, impairments, restructuring costs, disposals
and onerous lease provisions and their associated tax benefit, the
Group's underlying effective tax rate is 83.1% (1H 2020: (57.7%)).
The change in effective tax rate from 1H20 to 1H21 is due primarily
to there being no UK tax benefit from net interest and hedging
expenses in 1H21, compared to net profits in 1H20. Non-deductible
expenditure in Ghana and a change to the mix of taxable and
non-taxable profits in Gabon are additional contributing
factors.
Uncertain tax positions
The Group is subject to various material claims which arise in
the ordinary course of its business in various jurisdictions,
including cost recovery claims, claims from other regulatory bodies
and both corporate income tax and indirect tax claims. The Group is
in formal dispute proceedings regarding a number of these tax
claims with significant updates described in more detail below. The
resolution of tax positions, through negotiation with the relevant
tax authorities or litigation, can take several years to complete.
In assessing whether these claims should be provided for in the
Financial Statements, Management has considered them in the context
of the applicable laws and relevant contracts for the countries
concerned. Management has applied judgement in assessing the likely
outcome of the claims and has estimated the financial impact based
on external tax and legal advice and prior experience of such
claims.
Due to the uncertainty of such tax items, it is possible that on
conclusion of an open tax matter at a future date the outcome may
differ significantly from Management's estimate. If the Group was
unsuccessful in defending itself from all of these claims, the
result would be additional unprovided liabilities of $1,084.6
million (YE20: $1,070.2 million) which includes $34.1 million of
interest and penalties (YE20: $61.2m).
Provisions of $90.4 million (YE20: $129.3 million) are included
in income tax payable ($34.8 million (YE20: $30.4m)), provisions
($55.5 million (YE20: $52.4m)) and accruals (nil (YE20: $46.4m)).
Where these matters relate to expenditure which is capitalised
within E&A and PP&E, 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 unprovided tax liabilities relating to these
disputes have increased following new claims being initiated and
extrapolation of exposures, but have decreased following the
conclusion of tax authority challenges and matters lapsing under
statutes of limitation, giving rise to an overall decrease in
provision of $38.9m and increase in unprovided tax liabilities of
$14.4m.
Ghana tax assessments
In August 2018, Tullow Ghana Limited ("TGL") received an
assessment from the Ghana Revenue Authority ("GRA") for the
financial years 2014 to 2016. After discussions, a final assessment
was issued in December 2019 for $407.3 million requesting that
$397.7 million be paid by 13 January 2020. The GRA is seeking to
apply branch profits remittance tax under a law which the Group
considers is not applicable to TGL, since it falls outside the tax
regime set out in TGL's petroleum agreement and double tax
treaties. The GRA has additionally assessed TGL for unpaid
withholding taxes and corporate income tax arising from the
disallowance of loan interest. The Group considers that these
assessments also breach TGL's rights under its petroleum
agreements, applicable Ghanaian law and double taxation treaties,
and, in some cases, have arisen as the result of the errors in the
GRA's calculations. In January 2020, TGL issued a Notice of Dispute
with the Ministry of Energy ("MoE"), disputing the issues and
suspending TGL's obligation to pay any taxes until the disputed
issues have been resolved. In April 2020, the GRA issued a Demand
Notice for $365.0 million ($337.6 million branch profits remittance
tax and withholding tax, and $27.4 million corporate income tax)
which was put on hold by the MoE. In September 2021 TGL received a
revised final tax audit report for $471.2 million ($325 million
branch profits remittance tax and withholding tax, and $146.1
million corporate income tax). The Group continues to dispute the
validity of these assessments and is evaluating what steps may be
required in addition to the existing dispute process.
Kenya tax assessments
In March 2019, Tullow Kenya BV ("TKBV") received an assessment
from the Kenya Revenue Authority ("KRA") for $11.7 million for VAT
on the Block 12A farm-down. The Group considered that VAT was not
applicable since TKBV was not VAT registered at the time of the
disposal and the transaction was in relation to the sale of a
capital asset or part of a business. The KRA sought to apply VAT on
the basis that the transaction was a disposal of trading stock and
therefore the exemption to register for VAT did not apply. This
matter has now been heard by the Tax Appeals Tribunal and TKBV
received a judgment on 30 April 2021 in its favour which set aside
the VAT assessment in its entirety. However, the KRA appealed to
the High Court the decision of the TAT, but they withdrew that
appeal on 19 July 2021 and this was confirmed at a mention before
the court on 18 August 2021. This matter can now be treated as
closed.
9. Taxation on profit/ (loss) on ordinary activities
continued
Uganda Joint Venture Partner tax assessments
TOTAL E&P Uganda B.V. and CNOOC Uganda Limited have reached
a settlement with the Uganda Revenue Authority on all existing and
potential tax litigation and/or assessments for the period up to
June 2015 for PAYE, VAT and WHT, resulting in a reduction in
unprovided liabilities of $22.0 million.
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
anticipate that there will not be material cash taxes paid in
excess of the amounts provided for uncertain tax positions in the
next 12 months.
10. Disposals
Equatorial Guinea and Dussafu asset in Gabon
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. A further $5.0 million of additional consideration was also
received on completion of Dussafu Marin permit asset in Gabon.
On 9 June 2021, the Group completed the sale of Dussafu asset
sale 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.
The asset performance and oil price conditions required for
receipt of contingent future payments are not expected to be met
and accordingly no contingent consideration has been recognised as
at 30 June 2021.
Book value of assets Equatorial Guinea Six
disposed months ended 30.06.21 Dussafu Six months ended Total Six months ended
Unaudited 30.06.21 Unaudited 30.06.21 Unaudited
$m $m $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 70.1
-----------------------------
Total assets disposed 148.3 56.9 205.1
============================= =========================== ============================ ============================
Trade and other payables (36.0) (18.5) (54.5)
-----------------------------
Provisions (118.2) (4.7) (122.9)
-----------------------------
Current tax liabilities (13.6) - (13.6)
-----------------------------
Deferred tax liabilities (17.9) - (17.8)
----------------------------- =========================== ============================ ============================
Total liabilities disposed (185.7) (23.2) (208.8)
============================= =========================== ============================ ============================
Net (liabilities)/ assets
disposed (37.4) 33.7 (3.7)
============================= =========================== ============================ ============================
Cash consideration 93.8 39.0 132.8
============================= =========================== ============================ ============================
Transaction costs (8.4) (0.3) (8.7)
============================= =========================== ============================ ============================
Gain on disposal(1) 122.8 5.0 127.8
============================= =========================== ============================ ============================
(1) In addition to $127.8 million gain on disposal recognised
following the Equatorial Guinea and Dussafu disposals, the Group
recognised a loss of $5.0 million relating to its sale of Dutch
assets to Hague and London Oil plc (HALO) in 2017, and a gain of
$0.1 million relating to other transactions during the period
(1H21: 122.9 million; 1H20: 0.1 million).
Uganda
During 2020, the Group completed the disposal of its interest in
Uganda for upfront cash consideration of $500.0 million, with $75.0
million due on FID and contingent future payments linked to oil
prices. On completion, $514.3 million was received in cash,
representing the upfront consideration plus $14.3 million of
completion adjustments. The $75.0 million payment due on FID has
been recorded as a current receivable and is expected to be
received in 2H21. After deducting transaction costs paid in 2020,
net cash proceeds on disposal was $513.4 million.
10. Disposals continued
Uganda 31.12.2020 Audited
Book value of assets disposed $m
============================================== --------------------------
Intangible exploration and evaluation assets 580.4
----------------------------------------------
Trade receivables 0.3
----------------------------------------------
Other current assets 2.8
----------------------------------------------
Total assets disposed 583.5
============================================== ==========================
Trade and other payables (0.9)
----------------------------------------------
Net assets disposed 582.6
============================================== ==========================
11. Intangible exploration and evaluation assets
Six months ended 30.06.21 Six months ended 30.06.20 Year ended 31.12.20 Audited
Unaudited $m Unaudited $m $m
============================ ============================ ============================ ============================
At 1 January 368.2 1,764.4 1,764.4
---------------------------- ----------------------------
Additions 27.4 108.2 170.7
---------------------------- ----------------------------
Amounts written off (49.3) (941.4) (986.7)
---------------------------- ----------------------------
Transfer from Property, - 3.8 -
Plant and Equipment
---------------------------- ----------------------------
Net transfer to assets held
for sale - (578.5) (580.4)
---------------------------- ----------------------------
Currency translation
adjustments - 0.1 0.2
---------------------------- ============================ ============================ ----------------------------
At 30 June/31 December 346.3 356.6 368.2
============================ ============================ ============================ ============================
Remaining recoverable
Exploration costs written Rationale for write-off six Write-off 30.06.21 amount 30.06.21 Unaudited
off months ended 30.06.21 Unaudited $m $m
============================ ============================ ============================ ============================
Suriname b,c 56.9 -
---------------------------- ----------------------------
Uganda d (15.3) -
---------------------------- ----------------------------
Gabon c 1.7 -
---------------------------- ----------------------------
Peru b 1.0 -
---------------------------- ----------------------------
Cote d'Ivoire b 4.2 -
---------------------------- ----------------------------
Other a,c 0.8 -
---------------------------- ----------------------------
Exploration costs written 49.3 -
off
============================ ============================ ============================ ============================
a. Current year expenditure on assets previously written off
b. Licence relinquishments, expiry, planned exit or reduced
activity
c. Unsuccessful well costs written off
d. Release of indirect tax provision following settlement
11.Intangible exploration and evaluation assets continued
In the prior year, the Group received a licence extension in
Kenya to 31 December 2021. In order to obtain a further license
extension, the Group is required to submit a technically and
commercially compliant Field Development Plan (FDP) to the
Government of Kenya by 31 December 2021. In addition, the Group is
looking for strategic partners to help finance the development of
the project.
Following the redesign of the Kenya development project during
2021, the underlying value of the project has increased. However,
the uncertainty in form of risks around licence extension and
ability to bring in strategic partners to help finance the project
has also increased. As such, the Group has prepared a probabilistic
assessment to assess whether an adjustment to the carrying value of
Kenya exploration asset is required. Based on the result of this
probabilistic assessment, the Group considers no adjustment to the
carrying value is required as at 30 June 2021. Refer to page 5 of
Operational Review for further detail.
Remaining recoverable
Exploration costs written Rationale for write-off six Write-off 30.06.20 amount 30.06.20 Unaudited
off months ended 30.06.20 Unaudited $m $m
============================= ============================ ============================ ===========================
Kenya e 429.2 240.3
----------------------------- ----------------------------
Uganda f 417.5 -
----------------------------- ----------------------------
Peru d 40.1 -
----------------------------- ----------------------------
Comoros b 11.3 -
----------------------------- ----------------------------
Cote d'Ivoire b 9.2 -
----------------------------- ----------------------------
Guyana a 6.9 -
----------------------------- ----------------------------
Other a,c 27.2 -
----------------------------- ---------------------------- ============================ ===========================
Exploration costs written off 941.4 240.3
=========================================================== ============================ ===========================
a. Current year expenditure on assets previously written off
b. Licence relinquishments, expiry, planned exit or reduced
activity
c. Pre-licence exploration expenditure is written off as
incurred
d. Unsuccessful well costs written off
e. Following VIU assessment as a result of reduction in long
term oil price assumption, using a pre-tax discount rate of 18%
f. Written down to the value of the transaction
consideration.
Exploration costs written Rationale for write-off Write-off 31.12.20 Audited Remaining recoverable
off year ended 31.12.20 $m amount 31.12.20 Audited $m
============================= ============================ ============================ ===========================
Kenya e 430.0 247.0
----------------------------- ----------------------------
Uganda f 451.4 -
----------------------------- ----------------------------
Peru b,d 41.2 -
----------------------------- ----------------------------
Comoros b 12.4 -
----------------------------- ----------------------------
Cote d'Ivoire b 14.3 -
----------------------------- ----------------------------
Guyana a 9.2 42.2
----------------------------- ----------------------------
Other a,c 28.2 -
----------------------------- ---------------------------- ============================ ===========================
Exploration costs written off 986.7 289.2
=========================================================== ============================ ===========================
a. Current year expenditure on assets previously written off
b. Licence relinquishments, expiry, planned exit or reduced
activity
c. Pre-licence exploration expenditure is written off as
incurred
d. Unsuccessful well costs written off
e. Following VIU assessment as a result of reduction in long
term oil price assumption, using a pre-tax discount rate of 18%
f. Written down to the value of the transaction
consideration.
12. Property, plant and equipment
Other Other Other
Oil and Right of property, Oil and Right of property, Right of property,
gas use plant and gas use plant and Oil and use plant and
assets assets equipment Total assets assets equipment Total gas assets equipment
six six six six six six six months six months assets Year six Total
months months months months months months ended ended Year ended months Year
ended ended ended ended ended ended Restated(1) Restated(1) ended ended ended ended
30.06.21 30.06.21 30.06.21 30.06.21 30.06.20 30.06.20 30.06.20 30.06.20 31.12.20 31.12.20 31.12.20 31.12.20
Unaudited Unaudited Unaudited Unaudited Unaudited Unaudited Unaudited Unaudited Audited Audited Audited Audited
$m $m $m $m $m $m $m $m $m $m $m $m
=============== ========== ========== ========== ========== ========== ========== ============ ============ ========== ========= ========== ==========
Cost
--------------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
At 1 January 10,460.2 1,018.6 69.6 11,548.4 11,279.6 1,038.5 190.6 12,508.7 11,279.6 1,038.5 190.6 12,508.7
--------------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
Additions 45.4 59.8 1.2 106.4 137.8 19.5 4.8 162.1 203.6 16.5 9.6 229.7
--------------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
Disposals - - (0.8) (0.8) - (7.6) (0.4) (8.0) (11.0) (17.6) (125.6) (154.2)
--------------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
Transfer to
intangible
E&E assets - - - - - (3.8) - - (3.8) - - - -
Transfer
from/(to)
assets held
for sale - - - - - - - - (1,050.9) (19.5) - (1,070.4)
Currency
translation
adjustments 15.4 0.4 0.5 16.3 (72.8) (2.5) (12.4) (87.7) 38.9 0.7 (5.0) 34.6
=============== ========== ========== ========== ========== ========== ========== ============ ============ ========== ========= ========== ==========
At 30 June/31
December 10,521.0 1,078.8 70.5 11,670.3 11,340.8 1,047.9 182.6 12,571.3 10,460.2 1,018.6 69.6 11,548.4
=============== ========== ========== ========== ========== ========== ========== ============ ============ ========== ========= ========== ==========
Depreciation,
depletion and
amortization
and impairment
--------------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
At 1 January (7,915.9) (352.3) (42.3) (8,310.5) (8,194.6) (264.7) (157.7) (8,617.0) (8,194.6) (264.7) (157.7) (8,617.0)
--------------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
Charge for the
year (145.4) (26.0) (7.3) (178.7) (228.8) (41.3) (7.5) (277.6) (382.3) (72.4) (12.4) (467.1)
--------------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
Impairment
loss (8.0) - - (8.0) (418.3) - - (418.3) (250.0) - (0.6) (250.6)
--------------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
Capitalised
depreciation - (14.2) - (14.2) - (13.2) - (13.2) - (23.8) - (23.8)
--------------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
Disposal - - 0.8 0.8 - 1.2 0.3 1.5 10.9 7.1 122.8 140.8
Transfer to
assets held
for sale - - - - - - - - 938.2 1.6 - 939.8
Currency
translation
adjustments (15.4) - (0.2) (15.6) 68.1 0.4 10.8 79.3 (38.1) (0.1) 5.6 (32.6)
=============== ========== ========== ========== ========== ========== ========== ============ ============ ========== ========= ========== ==========
At 30 June/31
December (8,084.7) (392.5) (49.0) (8,526.2) (8,773.6) (317.6) (154.1) (9,245.3) (7,915.9) (352.2) (42.3) (8,310.5)
--------------- ---------- ---------- ---------- ---------- ---------- ---------- ------------ ------------ ---------- --------- ---------- ----------
Net book value
at 30 June/31
December 2,436.3 686.3 21.5 3,144.1 2,567.2 730.3 28.5 3,326.0 2,544.3 666.3 27.3 3,237.9
=============== ========== ========== ========== ========== ========== ========== ============ ============ ========== ========= ========== ==========
(1) Other property, plant and equipment as at 30 June 2020 have
been restated to include a derecognition of an asset that was fully
impaired during the year ended 31 December 2019. The impact
reflected in both cost and accumulated depreciation was $108.1
million on the opening balance as at 1 January 2020, $106.7 million
on disposals and $1.4 million on currency transaction adjustments
during the period ended 30 June 2020. This restatement was included
in the 2020 Annual Reports and Accounts.
12. Property, plant and equipment continued
Impairment/ (reversal)
30.06.21 30.06.21 Remaining recoverable amount
Trigger for impairment/ (reversal) (unaudited) (unaudited)
six months ended 30.06.21 $m $m
=============== ==================================== ======================= ======================================
Limande and
Turnix CGU
(Gabon) a (0.5) 6.7
--------------- ------------------------------------
UK 'CGU' a, b 8.5 -
--------------- ------------------------------------
Impairment 8.0 6.7
===================================================== ======================= ======================================
a. Change to decommissioning estimate
b. The fields in the UK are grouped into one CGU as all fields
share critical gas infrastructure
Impairment
30.06.20 30.06.20 Remaining recoverable amount
(unaudited) (unaudited)
Trigger for impairment six months ended 30.06.20 $m Pre tax discount rate assumption $m
================= ================================================== ============= ================================== ======================================
Limande and
Turnix CGU
(Gabon) a 26.7 13% 4.9
----------------- --------------------------------------------------
Ezanga (Gabon) a 18.1 15% 2.6
----------------- --------------------------------------------------
Oba and Middle
Oba CGU (Gabon) a 3.6 15% 9.3
----------------- --------------------------------------------------
Ruche (Gabon) a,b 23.4 13% 35.6
----------------- --------------------------------------------------
Espoir (Cote
d'Ivoire) a 12.8 10% 60.7
----------------- --------------------------------------------------
TEN (Ghana) a 305.8 10% 1,427.8
----------------- --------------------------------------------------
Mauritania c 16.9 n/a -
----------------- --------------------------------------------------
UK 'CGU' c, d 11.0 n/a -
----------------- -------------------------------------------------- ============= ================================== ======================================
Impairment 418.3 1,540.9
===================================================================== ============= ================================== ======================================
a. Decrease to short, medium and long-term oil price
assumptions
b. Recognition of FPSO lease
c. Change to decommissioning estimate
d. The fields in the UK are grouped into one CGU as all fields
share critical gas infrastructure
Impairment/ (reversal)
31.12.20 31.12.20 Remaining recoverable amount
(audited) (audited)
Trigger for impairment/ (reversal) year ended 31.12.20 $m Pre tax discount rate assumption $m
================= ======================================================== ======================= ================================== ======================================
Limande and
Turnix CGU
(Gabon) a 28.0 13% 7.4
----------------- --------------------------------------------------------
Ezanga (Gabon) a 20.5 15% 1.8
----------------- --------------------------------------------------------
Oba and Middle
Oba CGU (Gabon) a 3.8 15% 8.7
----------------- --------------------------------------------------------
Ruche (Gabon) a,b 1.2 13% 32.4
----------------- --------------------------------------------------------
Espoir (Cote
d'Ivoire) a (2.1) 10% 81.5
----------------- --------------------------------------------------------
TEN (Ghana) a 149.2 10% 1,510.6
----------------- --------------------------------------------------------
Mauritania c 30.6 n/a -
----------------- --------------------------------------------------------
UK 'CGU' c,d 13.2 n/a -
----------------- --------------------------------------------------------
Other c,e 6.2 n/a -
----------------- -------------------------------------------------------- ======================= ================================== ======================================
Impairment 250.6
=========================================================================== ======================= ================================== ======================================
a. Decrease to short, medium and long-term oil price
assumptions
b. Recognition of FPSO lease
c. Change to decommissioning estimate
d. Revision of value based on revision to reserves
d. The fields in the UK are grouped into one CGU as all fields
share critical gas infrastructure
12. Property, plant and equipment continued
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
======== ================= ========= ======== ======== ======== =======================
1H20 $40/bbl* $45/bbl* $50/bbl $55/bbl $60/bbl $60/bbl inflated by 2%
======== ================= ========= ======== ======== ======== =======================
FY 2020 $45/bbl $50/bbl $55/bbl $60/bbl $60/bbl $60/bbl inflated by 2%
======== ================= ========= ======== ======== ======== =======================
*(Forward curve as at 30 June)
13. Trade receivables
Trade receivables comprise amounts due for the sale of oil and
gas. They are generally due for settlement within 30-60 days and
are therefore all classified as current. The Group holds the trade
receivable with the objective of collecting the contractual cash
flows and therefore measures them subsequently at amortised cost
using the effective interest method.
The balance of trade receivables as of 31 June 2021 is $256.4
million (1H 2020: $64.5 million; FY20: $79.0 million). The increase
as at 30 June 2021 compared to 31 December 2020 and 30 June 2020 of
$177.4 million and $191.9 million, respectively, is mainly due to
increased oil prices as well as additional Jubilee (Ghana) and
Oguendjo (Gabon) liftings in June 2021 which were settled in July
2021.
14. Other assets
30.06.21 Unaudited $m 30.06.20 Unaudited $m 31.12.20 Audited $m
============================================ ====================== ====================== ====================
Non-current
-------------------------------------------- ---------------------- --------------------
Amounts due from joint venture partners(1) 514.9 577.1 547.4
-------------------------------------------- --------------------
Other non-current assets - 0.4 -
============================================ ====================== ====================== ====================
514.9 577.5 547.4
============================================ ====================== ====================== ====================
Current
-------------------------------------------- --------------------
Amounts due from joint venture partners(1) 572.9 593.0 521.9
-------------------------------------------- --------------------
Underlift 3.8 35.9 19.5
-------------------------------------------- --------------------
Prepayments 57.8 64.1 60.7
-------------------------------------------- --------------------
Other current assets(2) 395.9 52.7 115.0
============================================ ====================== ====================== ====================
1,030.4 745.7 717.1
============================================ ====================== ====================== ====================
(1) The decrease in non-current receivables from JV Partners
compared to June 2020 and December 2020 mainly relate to reduction
in time remaining on the TEN FPSO lease, net decrease in GNPC
("Ghana National Petroleum Corporation") receivable partially
offset increases associated with new lease liabilities. The
movement in current receivables from JV Partners relates mainly to
timing of partner balances partially offset by a recognition of the
JV receivable associated with the recognition of the Maersk
Venturer offshore drilling rig as a lease liability (see note
16).
(2) Other current assets mainly include funds paid into trust to
settle principal plus interest of the Convertible Bond at maturity
in July 2021 ($309.8 million) (note 17), the deferred consideration
relating to the Uganda disposal ($75.0 million) (note 10) as well
as the deferred consideration relating to the Netherlands disposal
in 2017 ($3.3 million) and VAT recoverable ($15.0 million).
15. Cash and cash equivalents
30.06.21 Unaudited $m 30.06.20 Unaudited $m 31.12.20 Audited $m
================================================ ====================== ====================== ====================
Cash at bank 138.0 117.9 224.2
------------------------------------------------ --------------------
Short- term deposits and other cash
equivalents(1) 163.8 118.4 581.2
================================================ ====================== ====================== ====================
301.8 236.3 805.4
================================================ ====================== ====================== ====================
(1) As at 31 December 2020, short-term deposits and other cash
equivalents mainly relates to receipt of cash for the disposal of
Uganda of $514.3 million which were used for the repayment of
borrowings in 2021. Refer to note 23.
Cash and cash equivalents include an amount of $72.0 million (1H
2020: $32.0 million); FY20: $54.0 million)) which the Group holds
as operator in JV bank accounts. Included within cash at bank is
$67.4 million (1H 2020: $67.0 million; FY20: $77.1 million) held in
JV bank accounts as the Group's share of security for the letters
of credit issued in relation to decommissioning activities.
16. Assets and liabilities classified as held for sale
On 9 February 2021, the Group announced that it had signed two
separate sale and purchase agreements with Panoro Energy ASA of its
entire interest in Equatorial Guinea and its entire interest in the
Dussafu Marin permit in Gabon, in each case with an effective date
of 1 July 2020. Both transactions completed in 1H21. Refer to note
10.
On 23 April 2020, Tullow announced that it had signed a Sale and
Purchase Agreement with Total Uganda with an effective date of 1
January 2020, in which it agreed to transfer its entire interests
in Blocks 1, 1A, 2 and 3A in Uganda and the proposed East African
Crude Oil Pipeline (EACOP) System to Total. The transaction
completed in 2H20.
17. Trade and other payables
30.06.21 Unaudited $m 30.06.20 Unaudited $m 31.12.20 Audited $m
=============================== ====================== ====================== ====================
Non-current
Other non-current liabilities 81.2 84.4 89.0
Non-current portion of leases 932.1 1,063.4 975.7
=============================== ====================== ====================== ====================
1,013.3 1,147.8 1,064.7
=============================== ====================== ====================== ====================
Current
Trade payables 53.4 85.8 38.3
------------------------------- --------------------
Other payables(1) 56.7 89.3 49.5
------------------------------- --------------------
Overlift 77.7 13.4 3.8
------------------------------- --------------------
Accruals 388.0 370.7 409.4
------------------------------- --------------------
VAT and other similar taxes - 8.9 8.9
------------------------------- --------------------
Current portion of leases 311.8 263.5 240.8
=============================== ====================== ====================== ====================
887.6 831.6 750.7
=============================== ====================== ====================== ====================
(1) Other payables include accrued interest of $50.5 million
(FY20: $40.9 million)
Trade and other payables are non-interest bearing except for
leases.
Payables related to operated joint ventures (primarily related
to Ghana and Kenya) are recorded gross with the debit representing
the partners' share recognised in amounts due from joint venture
partners (note 13). The change in trade payables and in other
payables predominantly represents timing differences and levels of
work activity.
Overlifts of $77.7 million as at 30 June 2021 is attributable to
TEN ($29.3 million), Jubilee ($23.0 million) and Gabon ($25.4
million). This is an increase of $74.9 million and $64.3 million
from December 2020 and June 2020. This was caused by the timing of
liftings with seven cargos across Ghana, Gabon and Cote d'Ivoire
lifted in June 2021.
On 2 April 2021 the Group contracted Maersk Venturer offshore
drilling rig to undertake the drilling work programme for Jubilee
and TEN fields in Ghana. As at 30 June 2021, Tullow carries a right
of use assets of $43.0 million (see note 12), and gross lease
liability of $97.3 million as Tullow entered the lease on behalf of
the JV. A receivable from JV Partners of $53.5 million has been
recognised in other assets to reflect the value of future payments
that will be met by cash calls from JV Partners (see note 14). The
lease has been recognised for an 18-month term, in line with the
early termination option included in the contract and approvals
received by the JV Partners.
18. Borrowings
30.06.21 Unaudited $m 30.06.20 Unaudited $m 31.12.20 Audited $m
================================================ ====================== ====================== ====================
Current
------------------------------------------------ ---------------------- --------------------
Borrowings - within one year
------------------------------------------------ --------------------
6.625% Convertible Bonds due 2021 ($300
million) 297.8 - 290.9
------------------------------------------------ --------------------
6.25% Senior Notes due 2022 ($650 million) - - 646.7
------------------------------------------------ --------------------
7.00% Senior Notes due 2025 ($800 million) - - 791.2
------------------------------------------------ --------------------
Reserves Based Lending credit facility - - 1,441.7
------------------------------------------------ --------------------
Carrying value of total current borrowings 297.8 - 3,170.5
================================================ ====================== ====================== ====================
Non-current
------------------------------------------------ --------------------
Borrowings - after one year but within five
years
------------------------------------------------ --------------------
6.625% Convertible Bonds due 2021 ($300 - 284.5 -
million)
------------------------------------------------ --------------------
6.25% Senior Notes due 2022 ($650 million) - 646.1 -
------------------------------------------------ --------------------
7.00% Senior Notes due 2025 ($800 million) 791.6 790.8 -
------------------------------------------------ --------------------
10.25% Senior Notes due 2026 ($1800 million) 1,773.9 - -
------------------------------------------------ --------------------
Reserves Based Lending credit facility - 1,517.8 -
================================================ ====================== ====================== ====================
Carrying value of total non-current borrowings 2,565.5 3,239.2 -
================================================ ====================== ====================== ====================
Carrying value of total borrowings 2,863.3 3,239.2 3,170.5
================================================ ====================== ====================== ====================
On 17 May 2021, the Group completed a comprehensive refinancing
of its debt with the issuance of a five-year $1.8 billion Senior
Secured Notes ("2026 Notes") and a new $500 million Super Senior
Revolving Credit Facility (SSRCF) which will primarily be used for
working capital purposes.
The 2026 Notes have been used to (i) repay all amounts
outstanding under, and cancel all commitments made available
pursuant to, the Company's Reserves Based Lending Facility, (ii)
redeem in full the Company's Senior Notes due 2022, (iii) at
maturity, on 12 July 2021, repay in full and cancel the Company's
convertible bonds due 2021 and (iv) pay fees and expenses incurred
in connection with the transactions.
The 2026 Notes, maturing in May 2026, require an annual
prepayment of $100 million of the outstanding principal amount plus
accrued and unpaid interest.
The SSRCF, maturing in December 2024, comprises of (i) a $500
million revolving credit facility and (ii) a $100 million letter of
credit facility.
The 2026 Notes and the SSRCF will be senior secured obligations
of Tullow Oil Plc and will be guaranteed by certain of the Group's
subsidiaries.
As at 31 December 2020, the Group has assessed it does not have
an unconditional right to defer payment of the facility, Senior
Notes due 2022, or Senior Notes due 2025 based on a forecast breach
in covenants; as such, these borrowings were classified as current.
Following the refinancing in May 2021, the Senior Notes due 2025
have been classified as non-current in line with their contractual
maturity.
Capital management
The Group defines capital as the total equity and net debt of
the Group. Capital is managed in order to provide returns for
shareholders and benefits to stakeholders and to safeguard the
Group's ability to continue as a going concern. Tullow is not
subject to any externally imposed capital requirements. To maintain
or adjust the capital structure, the Group may put in place new
debt facilities, issue new shares for cash, repay debt, engage in
active portfolio management, adjust the dividend payment to
shareholders, or undertake other such restructuring activities as
appropriate. No significant changes were made to the capital
management objectives, policies or processes during the half year
ended 30 June 2021. The Group monitors capital on the basis of the
gearing, being net debt divided by adjusted EBITDAX, and maintains
a policy target of between 1x and 2x.
SSRCF covenants
The SSRCF does not have any financial maintenance covenants.
Availability under the $500m million cash tranche of the facility
is determined on an annual basis with reference to the Net Present
Value of the 2P reserves of the Group (2P NPV) at the end of the
preceding calendar year. SSRCF debt capacity is calculated as 2P
NPV divided by 1.1x less Senior Notes outstanding.
18. Borrowings continued
Senior Notes covenants
The Senior Notes are subject to customary high yield covenants
including limitations on debt incurrence, asset sales and
restricted payments such as dividends. The key debt incurrence
covenant is the Fixed Charge Cover Ratio ("FCCR").
The FCCR is the ratio of the Consolidated Cash Flow to the Fixed
Charges for the previous twelve months. The 'Consolidated Cash
flow' essentially represents an Adjusted EBITDAX calculation. The
Fixed Charges represent the aggregate financial charges related to
the Company's indebtedness i.e. interest on all the Group's
borrowings and interests under capital leases less any finance
revenues. The Company may incur additional financial indebtedness
if the FCCR for the Company's most recently ended two full fiscal
half-years immediately preceding the date on which such additional
indebtedness is incurred would have been at least 2.25 to 1.0 on a
pro-forma basis. Drawdowns under the SSRCF are not subject to the
FCCR covenant and are always permitted subject to the availability
calculation set out above. There has been no debt incurrence event
since the Senior Notes have been issued.
19. Provisions
Other Other Other
Decommissioning provisions Total Decommissioning provisions Total Decommissioning provisions Total
30.06.21 30.06.21 30.06.21 30.06.20 30.06.20 30.06.20 31.12.20 31.12.20 31.12.20
Unaudited $m Unaudited $m Unaudited $m Unaudited $m Unaudited $m Unaudited $m Audited $m Audited $m Audited $m
=================== ---------------- ------------- ------------- ================ ============= ============= ================ =========== ===========
At 1 January 696.1 154.6 850.7 850.1 76.2 926.3 850.1 76.2 926.3
------------------- ---------------- ------------- ------------- ---------------- ----------- -----------
New provisions,
changes in
estimates and
reclassifications 14.4 36.5 50.9 27.2 61.4 88.6 14.9 136.6 151.5
------------------- ---------------- ------------- ------------- ---------------- ----------- -----------
Changes in
discount rate (31.7) - (31.7) - - - - - -
------------------- ---------------- ------------- ------------- ---------------- ----------- -----------
Transfer to assets
and liabilities
held for sale - - - - - - (129.2) - (129.2)
------------------- ---------------- ------------- ------------- ---------------- ----------- -----------
Payments (36.6) (8.9) (45.5) (37.8) (36.1) (73.9) (57.7) (58.4) (116.1)
------------------- ---------------- ------------- ------------- ---------------- ----------- -----------
Unwinding of
discount 3.7 - 3.7 6.5 - 6.5 13.1 - 13.1
------------------- ---------------- ------------- ------------- ---------------- ----------- -----------
Currency
translation
adjustment 2.3 0.4 2.6 (11.0) (0.5) (11.5) 4.9 0.2 5.1
=================== ================ ============= ============= ================ ============= ============= ================ =========== ===========
At 30 June/31
December 648.2 182.6 830.8 835.0 101.0 936.0 696.1 154.6 850.7
=================== ================ ============= ============= ================ ============= ============= ================ =========== ===========
Current provisions 116.9 138.4 255.3 69.1 92.7 161.8 104.4 125.4 229.8
=================== ================ ============= ============= ================ ============= ============= ================ =========== ===========
Non-current
provisions 531.3 44.2 575.5 765.9 8.3 774.2 591.7 29.2 620.9
=================== ================ ============= ============= ================ ============= ============= ================ =========== ===========
Other provisions include non-income tax provision, restructuring
provision and disputed cases and claims.
The decommissioning provision represents the present value of
decommissioning costs relating to the European and African oil and
gas interests.
In 2021, the Group has increased the decommissioning discount
rate by 0.5% from 31 December 2020 due to a movement in the
risk-free rate. This resulted in a decrease of the provision by
$23.7 million in Ghana, $3.7 million in Cote d'Ivoire and $4.3
million in Gabon.
20. Called up share capital and share premium
As at 30 June 2021, the Group had in issue 1,429.0 million
allotted and fully paid ordinary shares of GBP 10 pence each (30
June 2020: 1,410.9 million).
In the six months ended 30 June 2021, the Group issued 14.9
million shares in respect of employee share options (1H 2020:3.0
million new shares in respect of employee share options)
21. Contingent Liabilities
30.06.21 Unaudited $m 30.06.20 Unaudited $m 31.12.20 Audited $m
============================== ====================== ====================== ====================
Contingent liabilities
------------------------------ ---------------------- --------------------
Performance guarantees 102.8 111.6 115.6
------------------------------ --------------------
Other contingent liabilities 83.6 116.5 82.9
============================== ====================== ====================== ====================
186.4 228.1 198.5
============================== ====================== ====================== ====================
Performance guarantees are in respect of abandonment
obligations, committed work programmes and certain financial
obligations.
Other contingent liabilities
This includes amounts for ongoing legal disputes with third
parties where we consider the likelihood of cash outflow to be
higher than remote but not probable. The timing of any economic
outflow if it were to occur would likely range between one and five
years.
In January 2013, the Group acquired Spring Energy Norway AS
(Spring) from HitecVision V (Hitec), a Norwegian private equity
company, and Spring employee minority shareholders. In addition to
the initial consideration payable under the sale and purchase
agreement for Spring, the Group undertook to make contingent bonus
payments to Hitec and the Spring employee minority shareholders in
the event of the discovery on or before 31 December 2016 of
commercially viable reserves from four identified drilling
prospects (including the Wisting prospect in licence PL537).
In September 2013, OMV Norge AS, the operator of PL537,
announced that it had made a discovery by drilling the Wisting
prospect. Hitec claims that the conditions for a bonus payment
under the Spring SPA had been met in respect of the Wisting
prospect in PL537 as at December 2016. Tullow has disputed this
position. An arbitration was commenced in Norway to determine if a
bonus payment is payable in respect of the Wisting discovery and a
decision is expected to be made in late 2021. Hitec has claimed
US$95 million, including interest(which Tullow has disputed). This
claim amount is based on a preliminary calculation that is subject
to update.
In 2016, the Group sold its interest in PL537 to Equinor but
remains responsible for this dispute.
22. Events since 30 June 2021
On 17 May 2021, as part of the refinancing transaction $309.8
million was agreed to be put into a trustee account for settlement
of principal and accrued interest of the convertible loan notes on
due date. On 12 July 2021 the convertible loan notes were settled
by the trustees by utilizing the amount kept in the trust account.
This is a non-adjusting event.
23. Cash flow statement reconciliations
Movement in borrowings 1H 21 $m FY 20 $m 1H 20 $m FY 19 $m 1H21 Movement 1H20 Movement 2020 Movement
========================== --------- --------- --------- --------- ============== ============== ==============
Borrowings 2,863.3 3,170.5 3,239.2 3,071.7 (307.2) 167.5 98.8
-------------------------- --------- --------- --------- --------- --------------
Associated cash flows
Debt arrangement fees (57.8) - -
Repayment of borrowings (2,080.0) (110.0) (185.0)
Drawdown of borrowings 1,800.0 270.0 270.0
========================== --------- --------- --------- --------- ============== -------------- --------------
Non-cash
movements/presented in
other cash flow lines
Amortisation of
arrangement fees and
accrued interest 30.6 7.5 13.8
-------------------------- --------- --------- ========= ========= -------------- -------------- --------------
Commercial Reserves and Contingent Resources summary working
interest basis
Ghana Non-Operated Kenya Exploration Total
--------------- ---------------- -------------- -------------- --------------------------
Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Total
mmbbl bcf mmbbl bcf mmbbl bcf mmbbl bcf mmbbl bcf mmboe
======================= ======= ====== ======= ======= ======= ===== ======= ===== ======= ======= ========
COMMERCIAL RESERVES(1)
======================= ======= ====== ======= ======= ======= ===== ======= ===== ======= ======= ========
1 January 2021 180.1 179.2 48.4 11.1 - - - - 228.5 190.2 260.2
-----------------------
Revisions - - 0.2 (0.1) - - - - 0.2 (0.1) 0.2
-----------------------
Disposals - - (14.7) - - - - - (14.7) - (14.7)
-----------------------
Production (7.7) - (3.3) (0.7) - - - - (11.0) (0.7) (11.1)
======================= ======= ====== ======= ======= ======= ===== ======= ===== ======= ======= ========
30 June 2021 172.4 179.2 30.6 10.3 - - - - 203.0 189.5 234.6
======================= ======= ====== ======= ======= ======= ===== ======= ===== ======= ======= ========
CONTINGENT
RESOURCES(2)
======================= ======= ====== ======= ======= ============== ======= ===== ======= ======= ========
1 January 2021 217.0 749.1 59.5 78.4 170.8 - 54.5 - 501.7 827.5 639.7
-----------------------
Revisions - - (0.2) 0.3 60.6 - - - 60.4 0.3 60.4
-----------------------
Disposals/
Relinquishments - - (30.1) (77.5) - - - - (30.1) (77.5) ( 43.0)
-----------------------
30 June 2021 217.0 749.1 29.2 1.2 231.4 - 54.5 - 532.1 750.3 657.1
======================= ======= ====== ======= ======= ======= ===== ======= ===== ======= ======= ========
TOTAL
-----------------------
30 June 2021 389.4 928.3 59.8 11.5 231.4 - 54.5 - 735.1 939.8 891.7
======================= ======= ====== ======= ======= ======= ===== ======= ===== ======= ======= ========
(1) Proven and Probable Commercial Reserves are as audited and
reported by an independent engineer. Reserves estimates for each
field are reviewed by the independent engineer based on significant
new data or a material change with a review of each field
undertaken at least every two years, with the exception of minor
assets contributing less than 5 per cent of the Group's
reserve.
(2) Proven and Probable Contingent Resources are as audited and
reported by an independent engineer. Resources estimates are
reviewed by the independent engineer based on significant new data
received following exploration or appraisal drilling.
The Group provides for depletion and amortisation of tangible
fixed assets on a net entitlement basis, which reflects the terms
of the Production Sharing Contracts related to each field. Total
net entitlement reserves were 224.7 mmboe at 30 June 2021 (31
December 2020: 248.9 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 development within the
foreseeable future. Kenya contingent resources have increased
following a review by independent auditor, Gaffney, Cline &
Associates that utilised additional data from the Early Oil Pilot
Scheme. Refer to page 5 for further details.
Alternative performance measures
The Group uses certain measures of performance which 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 and free 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, additions to administrative
assets 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.
1H 2021 1H 2020
=========================================================== ======== ========
Additions to property, plant and equipment 106.4 162.1
=========================================================== ======== ========
Additions to intangible exploration and evaluation assets 27.4 114.6
=========================================================== ======== ========
Less
=========================================================== ======== ========
Decommissioning asset adjustments (17.3) 27.2
=========================================================== ======== ========
Right-of-use asset additions 59.8 19.5
=========================================================== ======== ========
Lease payments related to capital activities (8.7) (2.2)
=========================================================== ======== ========
Capitalised share-based payment charge - 0.6
=========================================================== ======== ========
Additions to administrative assets 1.2 4.8
=========================================================== ======== ========
Other non-cash capital expenditure (2.4) 34.5
=========================================================== ======== ========
Capital investment 101.2 192.3
=========================================================== ======== ========
Movement in working capital (5.2) 25.1
=========================================================== ======== ========
Additions to administrative assets 1.2 4.8
=========================================================== ======== ========
Cash capital expenditure per the cash flow statement 97.2 222.2
=========================================================== ======== ========
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
payments to convertible bond trustees and cash and cash
equivalents. Non-cash adjustments include unamortised arrangement
fees, adjustment to convertible bonds, and other adjustments. The
Group's definition of net debt does not include the Group's leases
as the Group's focus is the management of cash borrowings and a
lease is viewed as deferred capital investment. The value of the
Group's lease liabilities as at 30 June 2021 was $311.8 million
current and $932.1 million non-current; it should be noted that
these balances are recorded gross for operated assets and are
therefore not representative of the Group's net exposure under
these contracts.
1H 2021 1H 2020
========================================= ======== ========
Current borrowings 297.8 -
========================================= ======== ========
Non- current borrowings 2,565.5 3,239.2
========================================= ======== ========
Non-cash adjustments(1) 38.3 16.6
========================================= ======== ========
Payment to Convertible Bond trustees(2) (309.8) -
========================================= ======== ========
Less cash and cash equivalents(3) (301.8) (236.3)
========================================= ======== ========
Net debt 2,290.0 3,019.5
========================================= ======== ========
(1) Non-cash adjustments include unamortised arrangement fees
which are incurred on creation or amendment of borrowing facilities
as well as the Convertible Bonds which were measured at fair value.
The difference between the fair value and the principal of the bond
was included as a component of equity and a decrease to borrowings.
Over the life of the Convertible Bond, the fair value reduces until
the carrying value of the borrowings is equal to the principal
outstanding for repayment on maturity.
(2) As part of the refinancing, it was agreed that Tullow would
pay $300 million plus coupon of $10 million to the Convertible
Bonds Paying Agent (Deutsche Bank) on 17 May 2021. This amount was
held in Trust until repayment on maturity date of 12 July 2021.
(3) Cash and cash equivalents include an amount of $72 million
(1H 2020: $32 million) which the Group holds as operator in JV bank
accounts. Included within cash at bank is $67 million (1H 2020: $67
million) held in JV bank accounts as the Group's share of security
for the letters of credit issued in relation to decommissioning
activities.
Gearing and Adjusted EBITDAX
Gearing is a useful indicator of the Group's indebtedness,
financial flexibility and capital structure and can assist
securities analysts, investors and other parties to evaluate the
Group. Gearing is defined as net debt divided by adjusted EBITDAX.
This definition of gearing differs from the one included in the RBL
facility agreements. Adjusted EBITDAX is defined as profit/(loss)
from continuing activities adjusted for income tax
(expense)/credit, finance costs, finance revenue, gain on hedging
instruments, depreciation, depletion and amortisation, share-based
payment charge, restructuring costs, gain/(loss) on disposal,
exploration cost written off, impairment of property, plant and
equipment net, and provision for onerous service contracts.
1H 2021 1H 2020
===================== ======== ========
Adjusted EBITDAX(1) 884.9 1,012.9
===================== ======== ========
Net debt 2,290.0 3,019.5
===================== ======== ========
Gearing (times) 2.6 3.0
===================== ======== ========
(1) Last 12 months (LTM). Refer to the 2020 Annual Report and
Accounts for a full reconciliation of Adjusted EBITDAX.
Underlying cash operating costs
Underlying cash operating costs is a useful indicator of the
Group's costs incurred to produce oil and gas. Underlying cash
operating costs eliminates certain non-cash accounting adjustments
to the Group's cost of sales to produce oil and gas. Underlying
cash operating costs is defined as cost of sales, depletion and
amortisation of oil and gas assets, underlift, overlift and oil
stock movements, share-based payment charge included in cost of
sales, and certain other cost of sales. Underlying cash operating
costs are divided by production to determine underlying cash
operating costs per boe.
1H 2021 1H 2020
================================================================ ======== ========
Cost of sales 405.7 567.0
================================================================ ======== ========
Add
================================================================ ======== ========
Lease payments related to operating activity 9.2 1.2
================================================================ ======== ========
Less
================================================================ ======== ========
Depletion and amortisation of oil and gas and leased assets(1) 169.5 266.7
================================================================ ======== ========
Underlift, overlift and oil stock movements(2) 89.5 128.9
================================================================ ======== ========
Share-based payment charge included in cost of sales(3) 0.4 1.3
================================================================ ======== ========
Other cost of sales(4) 12.2 16.0
================================================================ ======== ========
Underlying cash operating costs 143.3 155.3
================================================================ ======== ========
Working Interest Production (MMboe) 11.1 14.1
================================================================ ======== ========
Underlying cash operating costs per boe ($/boe) 12.9 11.0
================================================================ ======== ========
(1) Depletion and amortisation of oil and gas assets is the
depreciation and amortisation of the Group's oil and gas assets
over the life of an asset on a unit of production basis.
(2) Under lifting or offtake arrangements for oil and gas
produced in certain operations in which the Group has interests
with other commercial partners, each participant may not receive
and sell its precise share of the overall production in each
period. The resulting imbalance between cumulative entitlement and
cumulative production less stock constitutes "underlift" or
"overlift". Underlift and overlift are valued at market value and
included within other current assets and other current payables on
the Group's balance sheet, respectively. Movements during an
accounting period are charged to cost of sales rather than charged
through revenue, and as a result gross profit is recognised on an
entitlements basis.
(3) Share-based payment charge included in cost of sales relates
to the portion of the non-cash share-based payment charge that
relates to employees who work on operational projects.
(4) Other cost of sales includes purchases of gas from third
parties to fulfil gas sales contracts and royalties paid in
cash.
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 used in investing activities, less debt
arrangement fees, repayment of obligations under leases, finance
costs paid and foreign exchange gain/ (loss).
1H 2021 1H 2020
=============================================== ======== ========
Net cash from operating activities 258.1 202.6
=============================================== ======== ========
Net cash from/ (used) in investing activities 36.9 (221.0)
=============================================== ======== ========
Debt arrangement fees (57.8) -
=============================================== ======== ========
Repayment of obligations under leases (68.3) (86.3)
=============================================== ======== ========
Finance costs paid (86.9) (105.0)
=============================================== ======== ========
Foreign exchange gain/ (loss) 4.2 (2.8)
=============================================== ======== ========
Free cash flow 86.2 (212.5)
=============================================== ======== ========
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 free cash flow
This is a useful indicator of the Group's assets 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.
1H 2021 1H 2020
============================================== ======== ========
Net cash from operating activities 258.1 202.6
============================================== ======== ========
Less
============================================== ======== ========
Decommissioning expenditure 27.7 37.8
============================================== ======== ========
Plus
============================================== ======== ========
Repayment of obligations under leases (68.3) (86.3)
============================================== ======== ========
Underlying operating cash flow 217.5 154.1
============================================== ======== ========
Net cash from/(used) in investing activities 36.9 (221.0)
============================================== ======== ========
Decommissioning expenditure (27.7) (37.8)
============================================== ======== ========
Pre-financing free cash flow 226.7 (104.7)
============================================== ======== ========
Events on the day
In conjunction with these results, Tullow is conducting a
virtual presentation webcast.
09:00 GMT - UK/European conference call
To access the call please dial the appropriate number below
shortly before the call and ask for the Tullow Oil plc conference
call. The telephone numbers and access codes are:
Live event
===================== =====================
All participants +44 (0) 20 7192 8338
---------------------
UK freephone 0800 279 6619
---------------------
Event plus passcode 1378144
===================== =====================
Webcast
To join the live audio webcast or play the on-demand version,
please use this link:
https://edge.media-server.com/mmc/p/d5erhti3
The replay will be available from noon on 15 September 2021.
Contacts
Tullow Oil plc Murrays
(London) (Dublin)
(+44 20 3249 9000) (+353 1 498 0300)
Nicola Rogers, Matthew Evans (Investors) Pat Walsh
George Cazenove (Media) Joe Heron
========================================== ===================
Notes to editors
Tullow is an independent oil and gas, exploration and production
group which is quoted on the London, Irish and Ghanaian stock
exchanges (symbol: TLW). The Group has interests in over 40
exploration and production licences across 11 countries including
Ghana where it operates the Jubilee and TEN fields. In March 2021,
Tullow committed to becoming Net Zero on its Scope 1 and 2
emissions by 2030.
For further information, please refer to our website at
www.tullowoil.com.
Follow Tullow on:
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END
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