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RNS Number : 7651R
Tullow Oil PLC
10 March 2021
Tullow oil PLC - 2020 FULL Year Results
10 March 2021 - Tullow Oil plc ("Tullow"), the independent oil
and gas exploration and production group ("Group"), announces its
Full Year Results for the year ended 31 December 2020. Details of a
management presentation, webcast and conference call are available
on the last page of this announcement or visit the Group's website
www.tullowoil.com.
Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented
today:
" After a year of significant change for Tullow, we are now
executing a robust, cash generative business plan which is focused
on our most productive assets. We have transformed our cost base,
implemented rigorous capital discipline and are well placed to
benefit from higher oil prices. We will start a multi-year,
multi-well drilling programme in Ghana next month to deliver
sustainable and profitable production growth. Our self-help
initiatives will deliver c.$1 billion, including over $700 million
from asset sales in the past year. Strong business delivery,
increased liquidity and improving commodity prices support
constructive refinancing discussions. Importantly, we are also
announcing today that we intend to be Net Zero by 2030 as part of
our commitment to sustainability. This commitment is in line with
our desire to work closely with Host Communities and Governments
and our investors to deliver a long-term and sustainable
business."
2020 FULL YEAR results Summary
-- Group working interest production averaged 74,900 bopd, in line with expectations
-- Revenue of $1,396 million; gross profit of $403 million; loss after tax of $1,222 million
-- Loss after tax driven by non-cash exploration write-offs and
impairments totalling $1,237 million pre-tax
-- Underlying operating cash flow of $598 million(2) and
pre-financing cash flow of $625 million(2)
-- Capital and decommissioning expenditure were $288 million(2) and $58 million respectively
-- Net debt at year-end of c.$2.4 billion(2) ; gearing of
3.0x(2) net debt/EBITDAX; headroom and free cash of c.$1.1
billion
-- Strong operational performance in Ghana; both FPSOs delivered
in excess of 95% uptime during the year
-- $575 million Uganda asset sale to Total completed in November
2020; $75 million contingent payment expected in 2021
long term business plan(1)
-- 10-year business plan presented at a Capital Markets Day on
25 November 2020 (CMD) to deliver material value and cash flow
-- Business plan to generate c.$7 billion underlying operating
cash flow and c.$4 billion pre-financing cash flow @ $55/bbl
-- Material upside to oil price with business plan generating an
additional $1.5 billion of pre-financing cash flow @ $65/bbl
-- Over 90% of capital to focus on West African producing
assets; options being worked to unlock value in Kenya and South
America
-- Cost focus is delivering annual savings of >$125 million
through 53% headcount reduction, outsourcing and other
efficiencies
-- A strong foundation has been created to address near-term
debt maturities and reduce gearing to 1-2x net debt/EBITDAX
-- 2P reserves increased to 260 mmboe representing a 2020
reserves replacement ratio of c.160%, underpinning the business
plan
2021 outlook(1)
-- Group working interest oil production year-to-date in line
with expectations; full year guidance of 60,000 - 66,000 bopd
-- Underlying operating cash flow and pre-financing cash flow
expected to be c.$0.5 billion and c.$0.2 billion respectively at
$50/bbl
-- Every $10/bbl increase in the oil price delivers c.$100
million incremental pre-financing cash flow up to $75/bbl
-- Capex of c.$265 million; decommissioning of c.$100 million;
Ghana drilling programme with four wells in 2021 to start in
April
-- Sale of interests in Equatorial Guinea and Dussafu in Gabon
for up to $180 million agreed; completion expected in H1
-- Suriname exploration well result expected early in Q2;
focused on prospect maturation across the exploration portfolio
-- In Kenya, a comprehensive review of the development concept
is being completed to assess future strategic options
-- The Tullow Board has committed to the Group becoming Net Zero
on its Scope 1 and 2 emissions by 2030
refinancing update
Tullow has been reviewing its business plan and operating
strategy with its creditors and their advisers. The plan is
expected to generate material cash flow and create a solid
foundation to address near-term debt maturities. Tullow's low-cost
asset base is leveraged to oil price upside. As part of the ongoing
refinancing discussions, Tullow has now received approval for a new
debt capacity amount under the Reserve Based Lending facility
("RBL") of $1.7 billion. With this new debt capacity agreed, Tullow
has liquidity headroom and free cash of c.$0.9 billion. The
combination of strong business delivery, increased liquidity,
recent asset sales and higher commodity prices is providing a
positive impetus to constructive discussions with creditors. The
Group is confident that a mutually satisfactory agreement on debt
refinancing can be reached in the first half of this year.
(1) 2021 guidance is provided before adjusting for the effects
of the Equatorial Guinea and Dussafu asset sales
(2) Alternative performance measures are reconciled on pages 26
to 29
2020 key financial results
2020 2019
===================== ======== ========
Total revenue ($m) 1,396 1,683
===================== ======== ========
Gross profit ($m) 403 759
===================== ======== ========
Loss after tax ($m) (1,222) (1,694)
===================== ======== ========
Free cash flow ($m) 432 355
===================== ======== ========
Net debt ($m) 2,376 2,806
===================== ======== ========
Gearing (times) 3.0 2.0
===================== ======== ========
Operational Review
Production, Reserves and Resources
In 2020, Tullow's West Africa oil assets performed in line with
expectations delivering average working interest oil production of
74,900 bopd. In 2021, working interest oil production is expected
to average between 60,000 and 66,000 bopd. This forecast will be
adjusted for the sales of the Equatorial Guinea and Dussafu assets
once these transactions complete. As laid out at the Group's CMD,
investment focused on the Group's cash generative producing assets
in West Africa is expected to increase production in 2022 and
sustain it for the longer term.
Tullow's audited 2P reserves have increased from 243 mmboe at
the end of 2019 to 260 mmboe at the end of 2020. Based on 27 mmboe
of 2020 production, this represents an organic reserves replacement
ratio of c.160%, underpinning the business plan presented at the
CMD. This was largely driven by a 31.5 mmboe increase at Jubilee
following improved field performance and the acceleration of
development projects in the new plan. Tullow's audited 2C resources
decreased from 1,102 mmboe to 640 mmboe, largely resulting from the
Uganda asset sale.
Group average working interest production FY 2020 FY 2021 guidance
=========================================== ======== =================
Ghana 52.4 40.5
=========================================== ======== =================
Jubilee 29.5 24.3
=========================================== ======== =================
TEN 23.0 16.2
=========================================== ======== =================
Equatorial Guinea 4.8 4.8
=========================================== ======== =================
Gabon 15.5 15.4
=========================================== ======== =================
C ô te d'Ivoire 2.1 2.3
=========================================== ======== =================
Oil production 74.9 63.0
=========================================== ======== =================
Net Zero
Tullow has committed to becoming a Net Zero Company by 2030 on
its Scope 1 and 2 emissions through a combination of decarbonising
its operated assets in Ghana and pursuing a nature-based carbon
removal programme. Investment in decarbonisation projects over the
next three years will result in an increase in the gas handling
capacity on Jubilee and enable process modifications on TEN, which
will also put the Group on track to eliminate routine flaring in
Ghana by 2025. To offset the residual difficult-to-abate carbon
emissions, work is under way to identify nature-based carbon
removal projects, such as reforestation, afforestation and
conservation that Tullow will invest in to achieve its Net Zero
ambition by 2030. We will also seek to align our carbon offset
strategy with government priorities, emerging regulation on Article
6 of the Paris Agreement as well as our Shared Prosperity strategy,
focused on creating socio-economic opportunities for our host
communities.
Ghana
The effects of the COVID-19 pandemic on our operations have been
managed safely across the business with no impact on Ghana
production. This has been achieved in close cooperation with the
Government of Ghana who have enabled effective testing and
quarantine measures to be put in place. However, this increased the
net cost of operations by c.$10 million in 2020.
Both fields in Ghana performed in line with expectations in
2020, with the Jubilee field averaging 83,600 bopd gross (net:
29,500 bopd) and the TEN field averaging 48,700 bopd gross (net:
23,000 bopd). This production performance was supported by
increased and sustained gas offtake nominations from the Government
of Ghana, approval from the Ministry of Energy to increase flaring,
higher than forecast facility uptime of over 95% at both FPSOs and
improved well optimisation and water injection facility performance
on the Jubilee FPSO.
To deliver an operational turnaround for the Ghana assets
starting in 2020, key areas of focus have been asset integrity,
process safety, maintenance and reliability. Gas offtake and water
injection on Jubilee have been an important part of the strategy to
address the decline in production in the absence of sustained
drilling. The engineering work to increase redundancy and
reliability has resulted in record levels of water injection with
rates now in excess of 200kbwpd, despite a failure in a water
injection riser in November 2020. Sustained water injection helps
support reservoir pressure and improves overall sweep efficiency.
Good progress has also been made on gas offtake. Onshore gas demand
is stabilising, facility reliability has improved and there is
greater alignment with the Government of Ghana on projected
offtake. Overall this has resulted in current offtake levels of
c.125 mmscfd. Gas processing and water injection capacities are
both expected to be steadily enhanced through 2021 and beyond to
deliver long-term stable production.
In consultation with the Ghana joint venture partners and
supported by expert advisors, a comprehensive review of the
investment and production optimisation plans for Jubilee and TEN
was conducted in the second half of 2020. The resulting plan was
presented at the CMD and demonstrated the substantial potential of
the Ghana portfolio given its large resource base and extensive
infrastructure in place. It showed that, managed with a rigorous
focus on costs and capital discipline, these assets have the
potential to generate material cash flow over the next decade and
deliver significant value for Ghana and investors.
The Maersk Venturer drillship has been contracted to start a
multi-well programme which is envisaged to be for a minimum period
of four years. The rig has arrived in Ghanaian waters and is
scheduled to commence drilling in April. The same rig worked on the
previous drilling programme in Ghana, but the contract was
terminated due to the oil price impacts of the COVID-19 pandemic.
The drilling hiatus, along with historical underinvestment has had
a negative impact on 2021 production. In 2021, the rig is expected
to drill and complete four wells in total, consisting of two
Jubilee production wells, one Jubilee water injector well and one
TEN gas injector well to provide pressure support to two Ntomme oil
production wells. This well campaign is expected to begin to offset
near-term production decline and further wells in 2022 will see
production materially recover and be sustained for the long term.
This drilling programme incorporates lessons learned from the
previous programme and is targeting a 20% reduction in drilling
costs through simplified well designs, improved rig reliability and
supply chain savings.
The final phase of the Jubilee Turret Remediation Project was
the installation of a Catenary Anchor Leg Mooring (CALM) buoy to
assist with offloading. The CALM buoy arrived in Ghana early in
2020 and following a series of delays, related to the impacts of
COVID-19 and some equipment issues, the buoy and one of two
offloading lines were installed at the end of 2020 and fully
commissioned in early 2021. The tanker support vessels on contract
since 2016 have now been released resulting in anticipated
operating expense savings of $60 million (gross) per annum going
forwards. Options for the potential need for and installation of a
second offloading line are being considered.
Non-operated portfolio
Production from Tullow's non-operated portfolio averaged 22,400
bopd in 2020. Overall production in the first half of 2020 was
stable at close to 24,000 bopd. However, in August 2020, the Simba
field was required to be shut in to comply with the Gabon
Government's OPEC+ quota. The field was shut-in for a total of two
months having an annualised impact on Group production of c. 1,000
bopd.
In February 2021, Tullow announced an agreement to sell its
entire interests in Equatorial Guinea and the Dussafu assets in
Gabon to Panoro Energy ASA (Panoro) for up to $180 million. These
value accretive transactions will strengthen the balance sheet and
enable the Group to focus on less capital intensive, higher margin
assets elsewhere in the West Africa portfolio. The deal, with an
effective date of 1 July 2020, is expected to complete in the first
half of 2021 and will represent the sale of c.6,000 bopd and c.20
million barrels of 2P reserves.
In mid-January 2021, following a major incident aboard the CNR
operated Espoir field FPSO in Côte d'Ivoire, production was shut in
for approximately four weeks. Production is now returning to full
capacity.
Decommissioning
Asset removal and sea-bed clearance activities in
Tullow-operated licences in the UK North Sea were completed in the
fourth quarter of 2020. Final surveys are planned in order to close
out the operated decommissioning programme this year. The Group's
non-operated decommissioning activities are ongoing and are
expected to continue through to 2025.
In Mauritania, decommissioning of the Chinguetti field wells was
suspended from March 2020 to January 2021, following the
Government's decision to close the borders due to COVID-19.
Planning and engineering for the decommissioning in Tullow-operated
licences at the Banda and Tiof fields is in progress with
operations expected to commence in the fourth quarter of 2021,
subject to Government approval. The overall Mauritania
decommissioning programme, scheduled to complete in 2022, is
however anticipated to increase in cost by c.$30 million over the
next two years, an increase of $15 million since the CMD, due to
COVID-related costs and a new requirement for increased levels of
seabed clearance.
In aggregate, the Group's decommissioning expenditure is
forecast to be c.$100 million per annum for 2021 and 2022,
decreasing to less than $20 million per annum for the subsequent
three years.
Kenya
Throughout 2020, Tullow worked closely with its joint venture
partners to progress the full field development plan. In August
2020, Force Majeure notices that had applied since May 2020 were
withdrawn by Tullow and the joint venture partners. In September
2020, the Government of Kenya agreed to an initial extension for
the 10BB and 13T licence blocks until 31 December 2020 and in
December 2020, following approval of the 2021 Work Programme and
Budget, granted a full extension until 31 December 2021 by which
date the Group is required to submit a Field Development Plan.
At the CMD, Tullow announced a joint decision to re-assess the
development plan and design a project that is economic at low oil
prices whilst preserving the phased development concept. Tullow and
its joint venture partners expect to complete a revised assessment
of the project by the second quarter of 2021.
During 2020, the Early Oil Pilot Scheme (EOPS) successfully
completed two years of production and all the required reservoir
and production data gathering was completed as planned. Tullow and
the joint venture partners then closed down EOPS and demobilisation
of all rental equipment was completed. The reservoir and production
data gathered during EOPS is now being used in redesigning the full
field development concept. EOPS production of more than 350,000
barrels of oil from the Ngamia and Amosing fields provided six
months' sustained rate and pressure data. The data confirms
reservoir quality and continuity in both fields, enabling the Group
to optimise plans to focus on the most productive wells at the
crest of the fields, leading to improved rates per well and refined
injector/producer patterns. The impact of this on plateau rates and
recoverable resources is being assessed.
In parallel, the joint venture partners are also working closely
with the Government of Kenya on securing approval of the
Environmental and Social Impact Assessments and finalising the
commercial framework for the project.
Separately, the farm down process was suspended in mid-2020 to
allow time for the joint venture partners to complete their
comprehensive review of the development concept, following which
Tullow will assess its strategic options.
Uganda
On 23 April 2020, Tullow agreed the sale of its assets in Uganda
to Total for $500 million in cash on completion plus $75 million in
cash following the Final Investment Decision (FID) and incremental
post first oil contingent payments linked to oil prices over
$62/bbl. On 28 May 2020 CNOOC Uganda Limited informed both Tullow
and Total that it had elected not to exercise its pre-emption
rights. On 18 June 2020 Tullow published the shareholder circular
relating to the transaction and on 15 July 2020 a General Meeting
was held, at which the transaction received approval with over 99
per cent of the 56 per cent votes cast in favour.
On 6 August 2020 the Government of Uganda provided their consent
to the transfer of operatorship from Tullow to Total and on 21
October 2020, Tullow announced that the Government of Uganda and
the Ugandan Revenue Authority had executed a binding Tax Agreement
that reflected the pre-agreed principles on the tax treatment of
the sale of Tullow's Ugandan assets to Total. The Ugandan Minister
of Energy and Mineral Development also approved the transfer of
Tullow's interests to Total and the transfer of operatorship for
Block 2. Consequently, the sale of the Uganda assets to Total
completed on 10 November 2020 with $500 million consideration
received on the same day.
Based on recent disclosures from Total at their Full Year
results, Tullow expects FID for the Lake Albert Development to be
taken this year which would trigger the $75 million payment to
Tullow.
Exploration
At its CMD, Tullow stated that its focus in exploration was
twofold. First, Tullow's exploration team will fully evaluate the
prospective net risked resources of 900 million barrels of oil
equivalent in emerging basins in Suriname, Guyana, Argentina,
Namibia and Côte d'Ivoire. Secondly, the team will work to support
Tullow's established producing operations in West Africa through
near-field and infrastructure-led exploration.
In 2020, the Group withdrew from its exploration licences in
Jamaica and the Comoros Islands and significantly reduced its
footprint in onshore Côte d'Ivoire and Peru.
In January 2020, Tullow drilled the Carapa-1 well in the Kanuku
licence, offshore Guyana. Although the well was uncommercial on a
standalone basis, the result extended the prolific Cretaceous light
oil play into the Group's Guyana acreage, across both the Kanuku
and Orinduik blocks. Tullow is now working with its joint venture
partners on the overall prospect inventory and developing plans to
unlock value from this acreage.
In February 2020, Tullow drilled the unsuccessful Marina-1 well
in the Z-38 licence offshore Peru, which encountered only light gas
shows and Tullow is now exiting this licence.
In Suriname, the Goliathberg-Voltzberg North well in Block 47 is
drilling currently and is targeting two prospective intervals in a
Cretaceous turbidite play in approximately 1,900 metres of water.
The well is being drilled by the Stena Forth drillship and a result
is expected in the second quarter of 2021.
A multi-client seismic acquisition in Argentina commenced in the
fourth quarter of 2019 over the Tullow-operated MLO 114 and 119
licences but was suspended in May 2020. This campaign re-started in
late 2020 and is due to complete by the end of the first quarter of
this year.
Finance review
Financial summary 2020 2019
======================================================= ======== ========
Working interest production volume (boepd)(1) 74,900 86,800
======================================================= ======== ========
Sales volume (boepd) 74,600 74,000
======================================================= ======== ========
Realised oil price ($/bbl) 50.9 62.4
======================================================= ======== ========
Total revenue ($m) 1,396 1,683
======================================================= ======== ========
Gross profit ($m) 403 759
======================================================= ======== ========
Underlying cash operating costs per boe ($/boe)(2) 12.1 11.1
======================================================= ======== ========
Exploration costs written off ($m) 987 1,253
======================================================= ======== ========
Impairment of property, plant and equipment, net ($m) 251 781
======================================================= ======== ========
Operating loss($m) (1,018) (1,385)
======================================================= ======== ========
Loss before tax ($m) (1,273) (1,653)
======================================================= ======== ========
Loss after tax ($m) (1,222) (1,694)
======================================================= ======== ========
Basic loss per share (cents) (86.6) (120.8)
======================================================= ======== ========
Capital investment ($m)(2) 288 490
======================================================= ======== ========
Adjusted EBITDAX ($m)(2) 804 1,398
======================================================= ======== ========
Net debt ($m)(2) 2,376 2,806
======================================================= ======== ========
Gearing (times)(2) 3.0 2.0
======================================================= ======== ========
Free cash flow ($m)(2) 432 355
======================================================= ======== ========
Underlying operating cash flow ($m) (2) 598 1,166
======================================================= ======== ========
Pre-financing cash flow ($m) (2) 625 574
======================================================= ======== ========
1. Including the impact of production-equivalent insurance
payments from the Jubilee field, Group working interest production
was 74,900 boepd (2019: 86,800 boepd) including working interest
gas production of nil boepd (2019: 100 boepd).
2. Alternative performance measures are explained and reconciled on pages 26 to 29.
Production and commodity prices
Total Group working interest production averaged 74,900 boepd, a
decrease of 12 per cent for the year (2019: 84,880 boepd). The
decrease resulted from field decline and water cut in Ghana,
partially offset by higher uptime on Jubilee. There have also been
Opec+ enforced production cuts impacting certain Gabon fields.
The Group's realised oil price after hedging was $50.9/bbl and
$42.9/bbl before hedging (2019: $62.4/bbl and $64.3/bbl
respectively). The impact of the COVID-19 pandemic on global oil
demand resulted in depressed oil prices during 2020 and significant
discounts to the Dated Brent benchmark oil price for the cargoes
sold during April and May 2020. Low oil prices led to a gain on the
realisation of commodity hedges, increasing total revenue by $219
million (2019: loss of $53 million).
Underlying cash operating costs, depreciation, impairments,
write-offs and administrative expenses
Underlying cash operating costs amounted to $332 million;
$12.1/boe (2019: $351 million; $11.1/boe). The 9 per cent increase
in unit cash operating costs was principally due to lower
production and increased operational costs incurred associated with
COVID-19 which was partially offset by a reduction in underlying
operating costs in the TEN and Jubilee fields.
Depreciation, depletion and amortisation (DD&A) charges on
production and development assets amounted to $446 million;
$16.3/boe (2019: $696 million; $22.0/boe). This decrease in
DD&A per barrel is mainly attributable to 2019 and 1H20
impairments.
The Group recognised a net impairment charge on producing assets
of $251 million in respect of 2020 (2019: $781 million).
Impairments were primarily due to indicators of impairments
identified in 1H20 as a result of a reduction in short, mid and
long-term prices. In 2H20 an impairment reversal was recorded in
respect of TEN and Espoir resulting in a full year
impairment/reversal of $149 million and $(2.1) million
respectively. This was as a result of increased booked 2P reserves
and in the case of TEN additionally due to lower future capex
assumptions associated with well costs.
The total exploration cost write-offs for the year ended 31
December 2020 were $987 million (2019: $1,253 million),
predominantly driven by a write-down of the value of Kenya due to a
reduction in the Group's long-term accounting oil price assumption
from $65/bbl to $60/bbl and Uganda was written down to the fair
value of the consideration as part of the disposal. The remaining
write-offs include Marina-1 well costs in Peru and the write-off of
licence level costs associated with Peru, Comoros, Côte d'Ivoire
and Namibia due to lower levels of planned activity and licence
exits.
Administrative expenses of $87 million (2019: $112 million)
included an amount of $21 million (2019: $22 million) associated
with share-based payment charges. The decrease in administrative
expenses primarily relates to lower payroll costs due to the
organisational restructuring. The organisational restructuring,
which was completed in 2020, is expected to deliver sustainable
cash savings of over $125 million per annum.
Restructuring costs and provisions for onerous leases
Changes to provisions in 2020 resulted in an income statement
charge of $93 million (2019: charge of $4.2 million). The 2020
charge mainly relates to costs associated with the organisational
restructuring which include redundancy and charges for onerous
office contracts. Of the $93 million provided for in 2020, $58
million was paid in cash.
Disposals
During 2020 the Group completed the disposal of its interests in
Uganda for upfront cash consideration of $500 million, with $75
million due on FID and additional contingent future payments linked
to oil prices. On completion $514 million was received in cash,
representing the upfront consideration plus $14 million of
completion adjustments. The $75 million payment due on FID has been
recorded as a current receivable as it is expected to be received
in 2021. After deducting transaction costs paid in 2020, net cash
proceeds on disposal were $513.4 million.
Derivative financial instruments
Tullow continues to undertake hedging activities as part of its
ongoing financial risk management 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. Hedging was paused from April to June 2020 due to the
very low oil price environment. Hedging restarted in July 2020 but
focused only on 2021.
All of the Group's derivatives are Level 2 (2019: Level 2).
There were no transfers between fair value levels during the
year.
At 31 December 2020, the Group's derivative instruments had a
net positive fair value of $2 million (2019: net negative $12
million).
2021 hedge position at 31 December 2020 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 hedging position at 31 December 2020 was c.2,000 bopd
hedged with an average floor price protected of $50.63/bbl. In
February 2021, the Group added a further 9,000 bopd of 2022
straight put options. The new average protected level is
$41/bbl.
Net financing costs
Net financing costs for the year were $255 million (2019: $267
million). The decrease in financing costs is associated with the
reduction in interest on borrowings due to a reduction in the
average level of net debt in 2020 compared to 2019 and a reduction
in finance costs associated with the TEN FPSO lease. 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 leased assets, offset by interest earned on cash deposits and
capitalised borrowing costs.
Taxation
The net tax credit of $52 million (2019: expense of $41 million)
primarily relates to tax charges in respect of the Group's
production activities in West Africa, as well as UK decommissioning
assets, more than offset by deferred tax credits associated with
exploration write-offs, impairments and provisions for onerous
service contracts.
Based on a loss before tax for the period of $1,273 million
(2019: loss of $1,653 million), the effective tax rate is 4.1 per
cent (2019: negative 2.4 per cent). After adjusting for
non-recurring amounts related to restructuring costs, exploration
write-offs, disposals, impairments, provisions for onerous service
contracts and their associated deferred tax benefit, the Group's
adjusted tax rate is 35.6 per cent (2019: 70.3 per cent). The
adjusted tax rate has decreased due to utilisation of previously
unrecognised losses in the UK and prior year adjustments offset by
the impact of withholding tax.
The Group's future statutory effective tax rate is sensitive to
the geographic mix in which pre-tax profits and exploration costs
written off arise. Unsuccessful exploration is often incurred in
jurisdictions where the Group has no taxable profits such that no
related tax benefit results. Consequently, the Group's tax charge
will continue to vary according to the jurisdictions in which
pre-tax profits and exploration cost write-offs occur.
Loss after tax from continuing activities and loss per share
The loss for the year from continuing activities amounted to
$1,222 million (2019: $1,694 million loss). Basic loss per share
was 86.6 cents (2019: 120.8 cents loss).
Reconciliation of net debt $m
============================================================================================= ==========
Year-end 2019 net debt 2,805.5
============================================================================================= ==========
Sales revenue (1,396.1)
============================================================================================= ==========
Operating costs 331.7
============================================================================================= ==========
Other operating and administrative expenses 376.7
============================================================================================= ==========
Cash flow from operations 687.7
============================================================================================= ==========
Movement in working capital (118.4)
============================================================================================= ==========
Tax paid 107.5
============================================================================================= ==========
Purchases of intangible exploration and evaluation assets and property, plant and equipment 430.9
============================================================================================= ==========
Other investing activities (515.2)
============================================================================================= ==========
Other financing activities 356.7
============================================================================================= ==========
Foreign exchange loss on cash (3.7)
============================================================================================= ==========
Year end 2020 net debt 2,375.6
============================================================================================= ==========
Capital investment
Capital expenditure amounted to $288 million (2019: $490
million) with $206 million invested in development activities and
$82 million invested in exploration and appraisal activities. This
includes $7 million of capital expenditure associated with Uganda
which was reimbursed by Total on completion of the Uganda
Transaction.
Tullow will continue to focus on capital discipline with 2021
capital investment largely directed at maximising value from the
Group's producing assets. The Group's 2021 capital expenditure is
expected to total c.$265 million which comprises Ghana capex of
c.$140 million primarily associated with the reinstatement of
drilling in 2021, West Africa non-operated capex of c.$60 million,
Kenya capex of c.$5 million, and exploration capex of c.$60
million.
Borrowings
During the year, commitments under Tullow's RBL facility reduced
from $2,400 million to $1,980 million following voluntary
cancellations of commitments in March and in May. Tullow's debt
facilities further include $300 million convertible notes due in
2021, $650 million senior notes due in 2022 and $800 million senior
notes due in 2025. Liquidity headroom of unutilised debt capacity
and free cash was c.$1.1 billion at the end of 2020. Tullow's RBL
facility is subject to bi-annual debt capacity redeterminations. In
October 2020, Tullow requested a redetermination to commence
following the CMD and to complete in January 2021. Tullow
subsequently agreed with the lenders under the RBL Facility to an
extension of the January 2021 redetermination date by up to one
month. The redetermination concluded in early March with $1.7
billion debt capacity approved by the lending syndicate.
On 26 February 2021, the Group submitted a liquidity forecast
test to the lenders in respect of the February 2021 RBL
redetermination. The Directors concluded that the information
submitted to the lenders under the RBL Facility fulfilled the
requirements of the liquidity forecast test. At the date of
approving the Annual Report and Accounts, an approval in respect of
this test is yet to be received, therefore a risk remains that the
Group could fail this test.
As at 31 December 2020, the Group has assessed it does not have
an unconditional right to defer payment of the RBL facility, Senior
Notes due 2022 or Senior Notes due 2025 based on a forecast breach
in covenants, as such these borrowings have been classified as
current. Refer to going concern disclosure for further details.
Credit ratings
Tullow maintains corporate credit ratings with Standard &
Poor's and Moody's Investors Service. In March 2020, Standard &
Poor's downgraded Tullow's corporate credit rating to CCC+ from B
and assigned a negative outlook; consequently, Standard &
Poor's also downgraded the rating of Tullow's corporate bonds to
CCC+ from B, in line with the corporate credit rating. In October,
Standard & Poor's affirmed the corporate credit rating at CCC+
and revised the outlook to stable. In March, Moody's Investors
Service downgraded Tullow's corporate credit rating to B3 from B2
and placed the rating under review for a possible downgrade;
consequently, the rating of Tullow's corporate bonds was lowered to
Caa2 from Caa1. In November, Moody's Investors Service downgraded
Tullow's corporate credit rating to Caa1 from B3 and assigned a
negative outlook; the rating of Tullow's corporate bonds remained
unchanged at Caa2.
On 5 February 2021 Standard & Poor's placed Tullow's CCC+
corporate credit rating and CCC+ corporate bond rating on negative
credit watch.
Liquidity risk management and going concern
Assessment period and assumptions
The Group closely monitors and carefully manages its liquidity
risk. Cash flow forecasts are regularly updated, and sensitivities
run for different scenarios, including, but not limited to, changes
in commodity price and different forecasts for the Group's
producing assets. The Directors consider the Going Concern
assessment period to be 13 months to April 2022, thereby including
the maturity of the $650 million Senior Notes due in April 2022 in
the assessment. Management has applied the following oil price
assumptions for the Going Concern assessment:
-- Base Case: $50/bbl for 2021 and $55/bbl for 2022, and
-- Low Case: $45/bbl for 2021 and $50/bbl for 2022.
The Low Case includes, amongst other downside assumptions, an 8%
production decrease compared to the Base Case as well as deferred
receipts from portfolio management and increased outflows
associated with ongoing disputes. No mitigating actions have been
included in either case.
The Base Case and Low Case scenarios forecast sufficient
financial headroom for the 12 months from approval of the 2020
Annual Report and Accounts on 10 March 2021. However, both
scenarios forecast a liquidity shortfall in April 2022 following
the repayment of the $650 million Senior Notes due in April 2022,
which falls within the liquidity forecast test periods in respect
of the February 2021, September 2021 and March 2022 RBL
redeterminations. Both cases assume amendments or waivers are
received for any forecast Liquidity Forecast Test or gearing
covenant breach as described below.
Refinancing Proposal
The Base Case and Low Case scenarios forecast a liquidity
shortfall in April 2022, which could result in a failure to pass
the Liquidity Forecast Test, as described below, in respect of the
February 2021, September 2021 and March 2022 RBL redeterminations,
and the gearing covenant tests, as described below, in respect of
30 June 2021 and 31 December 2021. The Group's management has
therefore commenced discussions with its existing and potential new
creditors, the objective of which is to raise new funding and/or
agree certain amendments to the terms, including the covenants
and/or maturity dates, of some or all of the RBL Facility, the
Convertible Bonds, the 2022 Senior Notes and the 2025 Senior Notes
with, if necessary, such amendments being approved by shareholders
(Refinancing Proposal). Whilst the Directors believe that a
Refinancing Proposal would be in the commercial interests of all
stakeholders, there can be no certainty that the creditors and, if
necessary, shareholders will agree to a Refinancing Proposal,
implementation of which is therefore outside the control of the
Group.
Liquidity Forecast Test covenant compliance
As part of each RBL redetermination process the Group is
required to demonstrate to the reasonable satisfaction of the
relevant majority of its lenders under the RBL Facility that it
has, or will have, sufficient funds available to meet the Group's
financial commitments for a period of 18 months starting from the
first month immediately following the relevant RBL redetermination
(Liquidity Forecast Test).
On 26 February 2021 the Group submitted a Liquidity Forecast
Test to the lenders in respect of the February 2021 RBL
redetermination. The Directors concluded that the information
submitted to the lenders under the RBL Facility, which is different
from the Base Case and the Low Case scenarios described above and
includes mitigating actions, fulfilled the requirements of the
Liquidity Forecast Test. At the date of approving the 2020 Annual
Report and Accounts, an approval in respect of this test is yet to
be received, therefore a risk remains that the Group could fail
this test.
If the lenders under the RBL Facility were to conclude that the
information submitted does not fulfil the requirements of the
Liquidity Forecast Test and the Group was unable to cure the
resulting default by the end of April 2021, there would be an event
of default. Such event of default would allow the lenders under the
RBL Facility, at their discretion, to cancel the RBL Facility and
demand that all outstanding borrowings under the RBL Facility be
repaid and/or enforce their security rights. This would in turn
trigger other creditors' rights to call cross-defaults under the
other financing arrangements of the Group (namely the Convertible
Bonds, the 2022 Senior Notes and the 2025 Senior Notes) which could
result in the entirety of the Group's borrowings potentially
becoming immediately repayable by the end of April 2021. While
discussions in respect of a Refinancing Proposal are continuing the
Directors believe that, if required, a waiver of such a potential
event of default in respect of the Liquidity Forecast Test could be
agreed with the lenders under the RBL Facility.
The Group is also required to submit Liquidity Forecast Tests in
respect of the September 2021 and March 2022 RBL redeterminations.
The Base Case and Low Case scenarios forecast, before mitigations,
a potential liquidity shortfall and therefore a potential failure
of these tests. However, the Directors believe that a Refinancing
Proposal could be implemented in time for the September 2021 RBL
redetermination such that no shortfall will be forecast as part of
the Liquidity Forecast Tests in September 2021 and March 2022. If
no Refinancing Proposal has been implemented, and refinancing
discussions were no longer continuing, by September 2021 there
would be a significant risk of the Group entering into, or being
in, insolvency proceedings, the implications of which are described
in the section Implications and material uncertainties below.
Gearing covenant compliance
The RBL Facility contains a gearing covenant which is tested for
each 12-month period ending on 30 June and 31 December each year,
and which requires that net debt of the Group as defined in the RBL
Facility agreement is lower than 3.5 times consolidated EBITDAX
(earnings before interest tax, depreciation and exploration
write-offs) for each relevant 12-month period. Under both the Base
Case and the Low Case scenarios, the Group's gearing is forecast to
be in excess of the RBL gearing covenant when calculated at 30 June
2021 and 31 December 2021, the two testing dates falling within the
Going Concern assessment period.
The Group has requested an amendment in respect of these gearing
covenant testing dates as part of the Refinancing Proposal
described above. In the event that such amendments are not agreed
on time for the testing date falling on 30 June 2021, the Directors
would expect to request a waiver or amendment for that testing date
only in the first instance, and if needed for the testing date
falling on 31 December 2021 in the second half of the year. The
Directors believe that the Group would be able to secure such
amendments or waivers, which would be both consistent with past
practice and the Directors' reasonable expectation of the
commercial interests of the Group and its lenders.
If the Group is unable to agree an amendment or waiver of the
gearing covenant, if required, in respect of the 30 June 2021
testing date, the Directors will deliver to the relevant lenders a
notification of non-compliance, which is required to be delivered
as soon as the Group's unaudited financial statements for the half
year ended 30 June are available, but no later than 28 September
2021. If a subsequent 75-day period expires without the Company
having resolved the non-compliance there will be an event of
default under the RBL Facility by mid-December 2021.
Implications and material uncertainties
The Directors note that implementing a Refinancing Proposal or
obtaining amendments or waivers in respect of covenant breaches is
outside the control of the Group. If the Directors are unable to
implement a Refinancing Proposal or, if necessary, obtain
amendments or waivers in respect of covenant breaches, the ability
of the Group to continue trading would depend upon the Group being
able to negotiate a financial restructuring proposal with its
creditors and, if necessary, that proposal being approved by
shareholders. Whilst the Board would seek to negotiate such a
financial restructuring proposal with its creditors, there is no
certainty that the creditors would engage with the Board in those
circumstances. There would therefore be a significant risk of the
Group entering into insolvency proceedings, which the Directors
consider would likely result in limited or no value being returned
to shareholders.
The Directors have concluded that the uncertainties 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, are material uncertainties that may cast
significant doubt that the Group will be able to continue as a
Going Concern. Notwithstanding these material uncertainties, the
Board's confidence in the Group's ability to implement a
Refinancing Proposal supports the preparation of the financial
statements on a Going Concern basis. The financial statements do
not include the adjustments that would result if the Group were
unable to continue as a Going Concern.
Events since 31 December 2020
The six-monthly redetermination of Tullow's Reserves Based
Lending (RBL) facility was originally expected to conclude at the
end of January. Tullow and its lending banks agreed to extend the
process by up to one month, which allowed for additional time to
review Tullow's new business plan and operating strategy. Tullow
has now received approval for a new debt capacity amount under the
facility of $1.7 billion.
On 9 February 2021, Tullow announced that it had signed two
separate sale and purchase agreements with Panoro for all of
Tullow's assets in Equatorial Guinea (the EG Transaction) and the
Dussafu asset in Gabon (the Dussafu transaction) for up to $180
million consisting of up to $105 million for the EG Transaction, up
to $70 million for the Dussafu Transaction and a further $5 million
consideration to be paid after both transactions have completed.
The EG Transaction constitutes a Class 1 transaction under the UK
Listing Rules and is subject to the approval of Tullow's
shareholders. The Dussafu Transaction constitutes a Class 2
transaction and therefore does not require shareholder approval.
Completion of the EG Transaction and the Dussafu Transaction are
not inter-conditional. However, both transactions are subject to
customary government and other approvals.
On 2 March 2021, further to the announcement made on 9 February
2021, Tullow published the shareholder circular relating to the EG
Transaction having received approval from the Financial Conduct
Authority. The General Meeting to approve the transaction will take
place on 18 March 2021.
Group income statement
Year ended 31 December 2020
$m Notes 2020 2019
============================================================= ====== ========== ==========
Continuing activities
------------------------------------------------------------- ------ ---------- ----------
Sales revenue 1,396.1 1,682.6
------------------------------------------------------------- ------ ----------
Other operating income - lost production insurance proceeds 7 - 42.7
------------------------------------------------------------- ------ ----------
Cost of sales 5 (993.6) (966.7)
============================================================= ====== ========== ==========
Gross profit 402.5 758.6
============================================================= ====== ========== ==========
Administrative expenses 5 (86.7) (111.5)
------------------------------------------------------------- ------ ----------
(Loss)/gain on disposal (3.4) 6.6
------------------------------------------------------------- ------ ----------
Exploration costs written off 10 (986.7) (1,253.4)
------------------------------------------------------------- ------ ----------
Impairment of property, plant and equipment, net 11 (250.6) (781.2)
------------------------------------------------------------- ------ ----------
Restructuring costs and provisions for onerous contracts 5 (92.8) (4.2)
============================================================= ====== ========== ==========
Operating loss (1,017.7) (1,385.1)
============================================================= ====== ========== ==========
Loss on hedging instruments (0.8) (1.5)
------------------------------------------------------------- ------ ----------
Finance revenue 6 59.4 55.5
------------------------------------------------------------- ------ ----------
Finance costs 6 (314.3) (322.3)
============================================================= ====== ========== ==========
Loss from continuing activities before tax (1,273.4) (1,653.4)
============================================================= ====== ========== ==========
Income tax credit/(expense) 8 51.9 (40.7)
============================================================= ====== ========== ==========
Loss for the year from continuing activities (1,221.5) (1,694.1)
============================================================= ====== ========== ==========
Attributable to
------------------------------------------------------------- ------ ----------
Owners of the Company (1,221.5) (1,694.1)
------------------------------------------------------------- ------ ----------
Loss per ordinary share from continuing activities c c
============================================================= ====== ========== ==========
Basic (86.6) (120.8)
Diluted (86.6) (120.8)
============================================================= ====== ========== ==========
Group statement of comprehensive income and expense
Year ended 31 December 2020
$m 2020 2019
===================================================================================== ========== ==========
Loss for the year from continuing activities (1,221.5) (1,694.1)
===================================================================================== ========== ==========
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
Gain/(loss) arising in the year 271.0 (118.6)
------------------------------------------------------------------------------------- ----------
Losses arising in the period - time value (37.3) (73.6)
------------------------------------------------------------------------------------- ----------
Reclassification adjustments for items included in profit on realisation (268.1) (7.6)
------------------------------------------------------------------------------------- ----------
Reclassification adjustments for items included in loss on realisation - time value 49.4 61.0
------------------------------------------------------------------------------------- ----------
Exchange differences on translation of foreign operations (5.3) (3.5)
===================================================================================== ========== ==========
Other comprehensive income/(expense) 9.8 (142.3)
===================================================================================== ========== ==========
Tax relating to components of other comprehensive (2.7) -
(expense)/income
===================================================================================== ========== ==========
Other comprehensive income/(expense) for
the year 7.1 (142.3)
===================================================================================== ========== ==========
Total comprehensive expense for the period (1,214.4) (1,836.4)
===================================================================================== ========== ==========
Attributable to
===================================================================================== ========== ==========
Owners of the Company (1,214.4) (1,836.4)
===================================================================================== ========== ==========
Group balance sheet
As at 31 December 2020
$m Notes 2020 2019
========================================================================= ====== ========== ==========
Assets
------------------------------------------------------------------------- ------ ----------
Non-current asset
------------------------------------------------------------------------- ------ ----------
Intangible exploration and evaluation assets 10 368.2 1,764.4
------------------------------------------------------------------------- ------ ----------
Property, plant and equipment 11 3,237.9 3,891.7
------------------------------------------------------------------------- ------ ----------
Other non-current assets 12 547.4 623.2
------------------------------------------------------------------------- ------ ----------
Derivative financial instruments 2.6 3.1
------------------------------------------------------------------------- ------ ----------
Deferred tax assets 494.3 517.5
========================================================================= ====== ========== ==========
4,650.4 6,799.9
========================================================================= ====== ========== ==========
Current assets
------------------------------------------------------------------------- ------ ----------
Inventories 96.1 191.5
------ ----------
Trade receivables 79.0 38.7
------------------------------------------------------------------------- ------ ----------
Other current assets 12 717.1 928.7
------------------------------------------------------------------------- ------ ----------
Current tax assets 36.4 42.9
------------------------------------------------------------------------- ------ ----------
Derivative financial instruments 17.2 0.7
------------------------------------------------------------------------- ------ ----------
Cash and cash equivalents 805.4 288.8
------------------------------------------------------------------------- ------ ----------
Assets classified as held for sale 13 155.6 -
========================================================================= ====== ========== ==========
1,906.8 1,491.3
========================================================================= ====== ========== ==========
Total assets 6,557.2 8,291.2
========================================================================= ====== ========== ==========
Liabilities
------------------------------------------------------------------------- ------ ----------
Current liabilities
------------------------------------------------------------------------- ------ ----------
Trade and other payables 14 (750.7) (1,127.6)
------------------------------------------------------------------------- ------ ----------
Provisions 15 (229.8) (172.8)
------------------------------------------------------------------------- ------ ----------
Borrowings (3,170.5) -
------------------------------------------------------------------------- ------ ----------
Current tax liabilities (52.2) (159.6)
Derivative financial instruments (17.8) (14.8)
Liabilities directly associated with assets classified as held for sale 13 (187.3) -
(4,408.3) (1,474.8)
========================================================================= ====== ========== ==========
Non-current liabilities
------------------------------------------------------------------------- ------ ----------
Trade and other payables 14 (1,064.7) (1,212.9)
------------------------------------------------------------------------- ------ ----------
Borrowings - (3,071.7)
------------------------------------------------------------------------- ------ ----------
Provisions 15 (620.9) (753.6)
------------------------------------------------------------------------- ------ ----------
Deferred tax liabilities (673.3) (793.4)
------------------------------------------------------------------------- ------ ----------
Derivative financial instruments - (1.2)
========================================================================= ====== ========== ==========
(2,358.9) (5,832.8)
========================================================================= ====== ========== ==========
Total liabilities (6,767.2) (7,307.6)
========================================================================= ====== ========== ==========
Net (liabilities)/ assets (210.0) 983.6
========================================================================= ====== ========== ==========
Equity
------------------------------------------------------------------------- ------ ----------
Called up share capital 211.7 210.9
------------------------------------------------------------------------- ------ ----------
Share premium 1,294.7 1,294.7
------------------------------------------------------------------------- ------ ----------
Equity component of convertible bonds 48.4 48.4
------------------------------------------------------------------------- ------ ----------
Foreign currency translation reserve (247.4) (242.1)
------------------------------------------------------------------------- ------ ----------
Hedge reserve 4.8 4.6
------------------------------------------------------------------------- ------ ----------
Hedge reserve - time value (5.4) (17.5)
------------------------------------------------------------------------- ------ ----------
Merger reserve 755.2 755.2
------------------------------------------------------------------------- ------ ----------
Retained earnings (2,272.0) (1,070.6)
------------------------------------------------------------------------- ------ ========== ----------
Equity attributable to equity holders of the Company (210.0) 983.6
========================================================================= ====== ========== ==========
Total equity (210.0) 983.6
========================================================================= ====== ========== ==========
Group statement of changes in equity (restated)
Year ended 31 December 2020
Equity Hedge
component Foreign reserve
Called of currency -
up share Share convertible translation Hedge time Merger Retained
$m capital premium bonds reserve(1) reserve value(2) reserves earnings Total
================ ========== ======== =========== ============ ======== ========== ========= ========= =========
At 1 January
2019
(previously
reported) 209.1 1,344.2 48.4 (238.6) 130.8 (4.9) 755.2 649.0 2,893.2
================= ========= ======== =========== ============ ======== ========== ========= ========= =========
Restatement(3) - (49.5) - - - - - 49.5 -
================= ========= ======== =========== ============ ======== ========== ========= ========= =========
At 1 January
2019 209.1 1,294.7 48.4 (238.6) 130.8 (4.9) 755.2 698.5 2,893.2
(as adjusted)
================= ========= ======== =========== ============ ======== ========== ========= ========= =========
Profit for the
year - - - - - - - (1,694.1) (1,694.1)
Hedges, net
of tax - - - - (126.2) (12.6) - - (138.8)
Currency
translation
adjustments - - - (3.5) - - - - (3.5)
Exercise of
employee share
options (3) 1.8 - - - - - - (1.8) -
Share-based
payment charges - - - - - - - 27.7 27.7
Dividends paid - - - - - - - (100.9) (100.9)
================= ========= ======== =========== ============ ======== ========== ========= ========= =========
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
year - - - - - - - (1,221.5) (1,221.5)
Hedges, net
of tax - - - - 0.2 12.1 - - 12.3
Currency
translation
adjustments - - - (5.3) - - - - (5.3)
Exercise of
employee share
options 0.8 - - - - - - (0.8) -
Share-based
payment charges - - - - - - - 20.9 20.9
At 31 December
2020 211.7 1,294.7 48.4 (247.4) 4.8 (5.4) 755.2 (2,272.0) (210.0)
================= ========= ======== =========== ============ ======== ========== ========= ========= =========
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 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 a $49.5 million and $35.8 million impact on the opening
position as at 1 January 2019 and on the options issued in 2019
respectively.
Group cash flow statement
Year ended 31 December 2020
$m Notes 2020 2019
======================================================================= ====== ========== ==========
Loss for the year from continuing activities (1,273.4) (1,653.4)
----------------------------------------------------------------------- ------ ----------
Adjustments for:
----------------------------------------------------------------------- ------ ----------
Depreciation, depletion and amortisation 11 467.1 724.6
----------------------------------------------------------------------- ------ ----------
Loss/(gain) on disposal 3.4 (6.6)
----------------------------------------------------------------------- ------ ----------
Exploration costs written off 10 986.7 1,253.4
----------------------------------------------------------------------- ------ ----------
Impairment of property, plant and equipment, net 11 250.6 781.2
----------------------------------------------------------------------- ------ ----------
Restructuring costs and provision for onerous contracts 92.8 (0.4)
----------------------------------------------------------------------- ------ ----------
Payment under restructuring costs and provision for onerous contracts 15 (58.4) (20.4)
----------------------------------------------------------------------- ------ ----------
Decommissioning expenditure 15 (57.7) (75.1)
----------------------------------------------------------------------- ------ ----------
Share-based payment charge 20.9 24.8
----------------------------------------------------------------------- ------ ----------
Loss on hedging instruments 0.8 1.5
----------------------------------------------------------------------- ------ ----------
Finance revenue 6 (59.4) (55.5)
----------------------------------------------------------------------- ------ ----------
Finance costs 6 314.3 322.3
----------------------------------------------------------------------- ------ ========== ----------
Operating cash flow before working capital movements 687.7 1,296.4
----------------------------------------------------------------------- ------ ----------
Decrease in trade and other receivables 195.2 241.4
------ ----------
Decrease/(increase) in inventories 85.1 (56.6)
----------------------------------------------------------------------- ------ ----------
Decrease in trade payables (161.9) (131.5)
======================================================================= ====== ========== ==========
Cash generated from operating activities 806.1 1,349.7
----------------------------------------------------------------------- ------ ----------
Income taxes paid (107.5) (91.0)
----------------------------------------------------------------------- ------ ========== ----------
Net cash from operating activities 698.6 1,258.7
======================================================================= ====== ========== ==========
Cash flows from investing activities
----------------------------------------------------------------------- ------ ----------
Proceeds from disposals 9 513.4 7.0
----------------------------------------------------------------------- ------ ----------
Purchase of intangible exploration and evaluation assets (213.6) (259.4)
----------------------------------------------------------------------- ------ ----------
Purchase of property, plant and equipment (217.3) (261.5)
----------------------------------------------------------------------- ------ ----------
Interest received 1.8 1.9
======================================================================= ====== ========== ==========
Net cash from/ (used)in investing activities 84.3 (512.0)
======================================================================= ====== ========== ==========
Cash flows from financing activities
----------------------------------------------------------------------- ------ ----------
Repayment of borrowings (185.0) (520.0)
----------------------------------------------------------------------- ------ ----------
Drawdown of borrowings 270.0 375.0
----------------------------------------------------------------------- ------ ----------
Payment of obligations under leases (158.2) (172.1)
Finance costs paid (198.5) (215.4)
Dividends paid - (100.9)
======================================================================= ====== ========== ==========
Net cash used in financing activities (271.7) (633.4)
======================================================================= ====== ========== ==========
Net increase in cash and cash equivalents 511.3 113.3
Cash and cash equivalents at beginning of year 288.8 179.8
Foreign exchange gain/(loss) 5.4 (4.3)
======================================================================= ====== ========== ==========
Cash and cash equivalents at end of year 805.4 288.8
======================================================================= ====== ========== ==========
Notes to the financial statements
Year ended 31 December 2020
1. Basis of preparation and presentation of financial information
Whilst the financial information in this preliminary
announcement has been prepared in accordance with International
Financial Reporting Standards (IFRS) and International Financial
Reporting Interpretation Committee (IFRIC) interpretations adopted
for use by the European Union, with those parts of the Companies
Act 2006 applicable to companies reporting under IFRS and with the
requirements of the United Kingdom Listing Authority (UKLA) Listing
Rules, this announcement does not contain sufficient information to
comply with IFRS. The Group will publish full financial statements
that comply with IFRS in April 2021.
The financial information for the year ended 31 December 2020
does not constitute statutory accounts as defined in sections 435
(1) and (2) of the Companies Act 2006. Statutory accounts for the
year ended 31 December 2019 have been delivered to the Registrar of
Companies and those for 2020 will be delivered following the
Company's annual general meeting. The auditor has reported on these
accounts; their reports were unqualified though they drew attention
to material uncertainties related to going concern. Their report
did not include a reference to any other matters to which the
auditor drew attention by way of emphasis of matter and did not
contain a statement under section 498 (2) or (3) of the Companies
Act 2006.
The Financial Statements have been prepared on the historical
cost basis, except for derivative financial instruments, share
based payments, and contingent consideration that have been
measured at fair value and assets classified as held for sale which
are carried at fair value less cost to sell. The Financial
Statements are presented in US dollars and all values are rounded
to the nearest $0.1 million, except where otherwise stated.
The accounting policies applied are consistent with those
adopted and disclosed in the Group's financial statements for the
year ended 31 December 2019. There have been a number of amendments
to accounting standards and new interpretations issued by the
International Accounting Standards Board which were applicable from
1 January 2020, however these have not any impact on the accounting
policies, methods of computation or presentation applied by the
Group. Further details on new International Financial Reporting
Standards adopted will be disclosed in the 2020 Annual Report and
Accounts.
Certain new accounting standards and interpretations have been
published that are not mandatory for 31 December 2020 reporting
periods and have not been early adopted by the Group. These
standards are not expected to have a material impact on the entity
in the current or future reporting periods and on foreseeable
future transactions.
2. Loss per share
Basic loss per ordinary share amounts are calculated by dividing
net loss for the year attributable to ordinary equity holders of
the Parent by the weighted average number of ordinary shares
outstanding during the year.
Diluted loss per ordinary share amounts are calculated by
dividing net loss for the year attributable to ordinary equity
holders of the Parent by the weighted average number of ordinary
shares outstanding during the year plus the weighted average number
of dilutive ordinary shares that would be issued if employee and
other share options or the convertible bonds were converted into
ordinary shares.
The adjustment in respect of convertible bonds and share options
had an anti-dilutive impact on earnings and was thus not considered
in determining diluted underlying EPS for the year ended 31
December 2020 and 2019.
3. 2020 Annual Report and Accounts
The 2020 Annual Report and Accounts will be mailed in April 2021
only to those shareholders who have elected to receive it.
Otherwise, shareholders will be notified that the Annual Report and
Accounts are available on the Group's website ( www.tullowoil.com
). Copies of the Annual Report and Accounts will also be available
from the Company's registered office at Building 9, Chiswick Park,
566 Chiswick High Road, London, W4 5XT.
4. Segmental reporting
During 2020, the Group reorganised its operational and
organisational structure so that the management and resources of
the business are better aligned with the delivery of the business
objectives. As a result, the information reported to the Group's
Chief Executive Officer for the purposes of resource allocation and
assessment of segment performance has changed to focus on four new
Business Units - Ghana, Non-operated producing assets including
Uganda and decommissioning assets, Kenya and Exploration.
Therefore, the Group's reportable segments under IFRS 8 are Ghana,
Non-operated, Kenya and Exploration.
The following tables present revenue, loss and certain asset and
liability information regarding the Group's reportable business
segments for the years ended 31 December 2020 and 31 December
2019.The table for the year ended 31 December 2019 has been
restated to reflect the new reportable segments of the business
$m Ghana Non-Operated Kenya Exploration Corporate Total
=================================== ========== ============= ======== ============ ========== ==========
2020
-----------------------------------
Sales revenue by origin 963.5 432.6 - - - (1,396.1)
=================================== ========== ============= ======== ============ ========== ==========
Segment result(1) 124.9 (410.2) (430.0) (104.3) (15.2) (834.8)
=================================== ========== ============= ======== ============ ========== ==========
Loss on disposal (3.4)
-----------------------------------
Unallocated corporate expenses(2) (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 amortisation (390.1) (60.7) (1.5) - (14.8) (467.1)
Impairment of property,
plant and equipment, net (149.1) (100.5) - (0.4) (0.6) (250.6)
Exploration costs written
off (0.8) (452.0) (430.0) (103.9) - (986.7)
=================================== ========== ============= ======== ============ ========== ==========
1. Segment result is a non IFRS measure which includes gross
profit, exploration costs written off, impairment of property,
plant and equipment. See reconciliation below.
2. Unallocated expenditure and net liabilities include amounts
of a corporate nature and not specifically attributable to a
geographic area. The liabilities comprise the Group's external debt
and other non-attributable corporate liabilities.
Reconciliation of segment result 2020 2019
============================================= ======== ==========
Segment result (834.8) (1,276.0)
--------------------------------------------- ----------
Add back:
--------------------------------------------- ----------
Exploration costs written off 986.7 1,253.4
--------------------------------------------- ----------
Impairment of Property, plant and equipment 250.6 781.2
--------------------------------------------- ----------
Gross profit 402.5 758.6
============================================= ======== ==========
4. Segmental reporting continued
$m Ghana Non-Operated Kenya Exploration Corporate Total
=========================================== ========== ============= ======== ============ ========== ==========
2019 restated
-------------------------------------------
Sales revenue by origin 1,262.3 420.3 - - - 1,682.6
-------------------------------------------
Other operating income - lost production
insurance proceeds - - - - 42.7 42.7
=========================================== ========== ============= ======== ============ ========== ==========
Segment result (231.3) (317.6) (535.8) (172.3) (19.0) (1,276.0)
=========================================== ========== ============= ======== ============ ========== ==========
Gain on disposal 6.6
-------------------------------------------
Unallocated corporate expense (115.7)
=========================================== ========== ============= ======== ============ ========== ==========
Operating loss (1,385.1)
-------------------------------------------
Gain on hedging instruments (1.5)
-------------------------------------------
Finance revenue 55.5
-------------------------------------------
Finance costs (322.3)
=========================================== ========== ============= ======== ============ ========== ==========
Loss before tax (1,653.4)
-------------------------------------------
Income tax expense (40.7)
=========================================== ========== ============= ======== ============ ========== ==========
Loss after tax (1,694.1)
=========================================== ========== ============= ======== ============ ========== ==========
Total assets 5,777.8 1,451.0 732.2 183.9 146.3 8,291.2
=========================================== ========== ============= ======== ============ ========== ==========
Total liabilities (3,289.8) (747.2) (75.9) (72.4) (3,122.3) (7,307.6)
=========================================== ========== ============= ======== ============ ========== ==========
Other segment information
-------------------------------------------
Capital expenditure:
-------------------------------------------
Property, plant and equipment 338.3 97.3 12.8 2.4 77.6 528.4
-------------------------------------------
Intangible exploration and evaluation
assets 2.7 53.9 85.5 137.2 - 279.3
-------------------------------------------
Depletion, depreciation and amortization (612.7) (88.6) (1.4) (0.7) (21.2) (724.6)
-------------------------------------------
Impairment of property, plant and
equipment, net (712.8) (24.6) - - (43.8) (781.2)
-------------------------------------------
Exploration costs written off (2.6) (541.5) (535.8) (173.5) - (1,253.4)
=========================================== ========== ============= ======== ============ ========== ==========
5. Other costs
$m 2020 2019
================================================================== ====== ========
Cost of sales
------------------------------------------------------------------ --------
Operating costs 331.7 351.3
------------------------------------------------------------------ --------
Depletion and amortisation of oil and gas assets(1) 446.4 696.1
------------------------------------------------------------------ --------
Underlift, overlift and oil inventory movement 160.5 (137.3)
------------------------------------------------------------------ --------
Share-based payment charge included in cost of sales 0.9 2.6
------------------------------------------------------------------ --------
Other cost of sales 54.1 54.0
================================================================== ====== ========
Total cost of sales 993.6 966.7
------------------------------------------------------------------ ====== --------
Administrative expenses
------------------------------------------------------------------ --------
Share-based payment charge included in administrative expenses 20.0 22.2
------------------------------------------------------------------ --------
Depreciation of other fixed assets 20.7 28.5
Other administrative costs 46.0 60.8
================================================================== ====== ========
Total administrative expenses 86.7 111.5
================================================================== ====== ========
Total restructuring costs and provision for onerous contracts(2) 92.8 4.2
================================================================== ====== ========
1. Depreciation expense on leased assets of $72.4 million as per
note 10 includes a charge of $8.3 million on leased administrative
assets, which is presented within administrative expenses in the
income statement. The remaining balance of $64.1 million relates to
other leased assets and is included within cost of sales.
2. This includes restructuring costs of $4.2 million and
redundancy costs of $63.5 million as well as provisions for onerous
contacts.
6. Net financing costs
$m 2020 2019
======================================================================= ======= =======
Interest on bank overdrafts and borrowings 205.8 216.0
----------------------------------------------------------------------- -------
Interest on obligations for leases 91.0 103.5
======================================================================= ======= =======
Total borrowing costs 296.8 319.5
----------------------------------------------------------------------- -------
Less amounts included in the cost of qualifying assets - (16.3)
======================================================================= ======= =======
296.8 303.2
----------------------------------------------------------------------- -------
Finance and arrangement fees 0.8 0.7
----------------------------------------------------------------------- -------
Other Interest expense 3.6 2.1
----------------------------------------------------------------------- -------
Unwinding of discount on decommissioning provisions 13.1 16.3
======================================================================= ======= =======
Total finance costs 314.3 322.3
Interest income on amounts due from joint venture partners for leases (40.6) (50.0)
Other finance revenue (18.8) (5.5)
======================================================================= ======= =======
Total finance revenue (59.4) (55.5)
======================================================================= ======= =======
Net financing costs 254.9 266.8
======================================================================= ======= =======
7. Insurance proceeds
Insurance proceeds of $24.8 million were recorded in the year
ended 31 December 2020 (2019: $123.8 million). Proceeds related to
lost production under the Business Interruption insurance policy of
$nil (2019: $42.7 million) were recorded as other operating income
- lost production insurance proceeds in the income statement.
Proceeds related to compensation for incremental operating costs
under the Business Interruption and Hull and Machinery insurance
policies of $nil (2019: $4.2 million) were recorded within the
operating costs line of cost of sales (see note 4). Proceeds
related to compensation for capital costs under the Hull and
Machinery insurance policy of $24.8 million (2019: $76.9 million)
were recorded within additions to property, plant and equipment
(see note 11). Coverage related to the Turret Remediation Project
under the Business Interruption insurance policy ended in August
2019 and full and final settlement for the Hull and Machinery claim
was reached in December 2019 with the final proceeds received in
the first quarter of 2020.
8. Taxation on loss on continuing activities
Analysis of tax (credit)/expense for the year
$m 2020 2019
=================================== ======= =========
Current tax
UK corporation tax (24.7) ( 32.3)
Foreign tax 81.2 192.5
Tax in respect of prior periods (25.7) 5.2
=================================== ======= =========
Total corporate tax 30.8 165.4
UK petroleum revenue tax (3.4) -
=================================== ======= =========
Total current tax 27.4 165.4
=================================== ======= =========
Deferred tax
UK corporation tax 19.8 91.7
Foreign tax (85.3) ( 262.9)
Tax in respect of prior periods (11.7) 44.2
=================================== ======= =========
Total deferred corporate tax (77.2) (127.0)
Deferred UK petroleum revenue tax (2.1) 2.3
=================================== ======= =========
Total deferred tax (79.3) (124.7)
=================================== ======= =========
Total income tax (credit)/expense (51.9) 40.7
=================================== ======= =========
8. Taxation on loss on continuing activities contd.
Factors affecting tax (credit)/expense for the year
$m 2020 2019
======================================================================= ========== ==========
Loss from continuing activities before tax (1,273.4) (1,653.4)
======================================================================= ========== ==========
Tax on loss from continuing activities at the standard UK corporation
tax rate of 19% (2019: 19%) (241.9) (314.1)
======================================================================= ========== ==========
Effects of:
Non-deductible exploration expenditure 184.4 208.7
Net tax on fair value movements on derivatives - (1.3)
Other non-deductible expenses 46.5 18.8
Tax impact of change in discount rate on decommissioning provision (2.1) -
Deferred tax asset not recognised 5.5 -
Derecognition of deferred tax previously recognised 0.7 12.4
Utilisation of tax losses not previously recognised (8.4) (0.8)
Current year losses for which deferred tax is not recognised 25.5 73.7
Adjustment relating to prior years (37.4) 49.4
Higher rate of taxation on Norway losses (6.3) -
Other tax rates applicable outside the UK and Norway (37.1) 11.3
PSC expense/ (income) not subject to corporation tax 18.9 (17.2)
Other income not subject to corporation tax (0.2) (0.2)
======================================================================= ========== ==========
Group total tax (credit)/ expense for the year (51.9) 40.7
======================================================================= ========== ==========
Current tax assets
As at 31 December 2020, current tax assets were $36.4 million
(2019: $42.9 million) of which $33.1 million relates to the UK
(2019: $42.9 million).
9. Disposals
During 2020 the Group completed the disposal of its interests in
Uganda for upfront cash consideration of $500 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 as it is expected to be
received in 2021. After deducting transaction costs paid in 2020,
net cash proceeds on disposal were $513.4 million.
The Uganda Sale and Purchase Agreement (SPA) signed in 2017
lapsed in 2019 as a result of the failure to agree all aspects of
the tax treatment with the Government of Uganda which was a
condition to completing the SPA. Following the expiry of the SPA,
the Uganda assets of $840.2 million were reclassified from Assets
Held for Sale to Intangible assets in 2019. Refer to Note 10.
Book Value of Assets disposed in Uganda 2020
============================================== =======
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)
----------------------------------------------
Total assets and liabilities disposed 582.6
============================================== =======
10. Intangible exploration and evaluation assets
$m 2020 2019
============================================= ======== ==========
At 1 January 1,764.4 1,898.6
--------------------------------------------- ----------
Additions 170.7 279.3
--------------------------------------------- ----------
Disposals - (0.4)
--------------------------------------------- ----------
Exploration costs written off (986.7) (1,253.4)
--------------------------------------------- ----------
Net transfer (to)/from assets held for sale (580.4) 840.2
--------------------------------------------- ----------
Currency translation adjustments 0.2 0.1
--------------------------------------------- ======== ----------
At 31 December 368.2 1,764.4
============================================= ======== ==========
Included within 2020 additions is $nil (note 5) of capitalised
interest (2019: $16.3 million). The Group only capitalises interest
in respect of intangible exploration and evaluation assets where it
is considered that development is ongoing.
During 2020, $33.6 million was capitalised and written off in
connection to working capital and indirect taxes associated with
the Uganda disposal.
The below table provides a summary of the exploration costs
written off on a pre and post-tax basis by country.
2020 2020
pre-tax post- 2020 Remaining
Rationale write tax write recoverable
for 2020 off off amount
Country write-off $m $m $m
================= ============ ========= =========== ===============
Kenya e 430.0 430.0 247.0
----------------- ------------
Uganda f 451.4 451.4 -
----------------- ------------
Comoros b 12.4 12.4 -
----------------- ------------
Guyana a 9.2 9.2 42.2
----------------- ------------
Peru b,d 41.2 41.2 -
----------------- ------------
Cote d'Ivoire b 14.3 14.3 -
----------------- ------------
Other a,c 28.2 28.2 -
----------------- ------------
Total write-off 986.7 986.7 289.2
=============================== ========= =========== ===============
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
per cent (2019: 14%)
f. Written down to the value of the transaction consideration.
(Refer to note 9 for further detail)
The Group has received a 15 month licence extension from
September 2020 to December 2021 which is contingent on certain
conditions. As at 31 December 2020, the Group has complied with all
of the conditions which effectively extends the licence extension
period to 31 December 2021. One of the conditions requires the
Group to submit a technically and commercially compliant Field
Development Plan (FDP) with the Government of Kenya by 31 December
2021. If the FDP is not submitted by 31 December 2021, the
extension period will expire on 31 December 2021. The Group along
with its joint venture partners are working towards the preparation
of a technically and commercially compliant FDP in accordance with
the PSCs and expects to submit the FDP by 31 December 2021 to
further extend the licence.
Oil prices stated in note 11 are benchmark prices to which an
individual field price differential is applied. Exploration
write-offs for the Kenya development area assessments are prepared
on a value-in-use basis using discounted future cash flows based on
2C resource profiles. A reduction or increase in the long-term
price assumptions of $5/bbl, based on the range of annualised
average historical prices, are considered to be reasonably possible
changes for the purposes of sensitivity analysis. Decreases to oil
prices would increase the exploration write-off charge by $72.3
million, whilst increases to oil prices specified above would
result in a credit to the exploration write-offs of $65.9 million.
A 1 per cent increase in the pre-tax discount rate would increase
the exploration write-off by $63.7 million. The Group believes a 1
per cent change in the pre-tax discount rate to be a reasonable
possibility based on historical analysis of the Group's and a peer
group of companies' discount rates.
11. Property, plant and equipment
2020 2019
2020 Other 2020 2019 Other 2019
Oil and gas fixed Right of use 2020 Oil and fixed Right of 2019
$m assets assets assets Total gas assets assets(1) use assets Total
=============== ============ =========== ============ ========= =========== ============ =========== =========
Cost
At 1 January 11,279.6 190.6 1,038.5 12,508.7 11,794.0 271.0 - 12,065.0
Adjustment on
adoption of
IFRS 16 - - - - (907.7) - 907.7 -
Additions 203.6 9.6 16.5 229.7 357.1 21.0 150.3 528.4
Disposals (11.0) (125.6) (17.6) (154.2) - (108.4) (20.6) (129.0)
Transfer to
assets held
for sale (1,050.9) - (19.5) (1,070.4) - - - -
Currency
translation
adjustments 38.9 (5.0) 0.7 34.6 36.2 7.0 1.1 44.3
=============== ============ =========== ============ ========= =========== ============ =========== =========
At 31 December 10,460.2 69.6 1,018.6 11,548.4 11,279.6 190.6 1,038.5 12,508.7
=============== ============ =========== ============ ========= =========== ============ =========== =========
Depreciation,
depletion,
amortisation
and impairment
At 1 January (8,194.6) (157.7) (264.7) (8,617.0) (6,951.1) (197.5) - (7,148.6)
Adjustment on
adoption of
IFRS 16 - - - - 151.5 - (151.5) -
Charge for the
year (382.3) (12.4) (72.4) (467.1) (620.1) (18.6) (85.9) (724.6)
Impairment
loss (250.0) (0.6) - (250.6) (737.4) (43.8) - (781.2)
Capitalised
depreciation - - (23.8) (23.8) - - (29.0) (29.0)
Disposal 10.9 122.8 7.1 140.8 - 108.4 1.8 110.2
Transfer to
assets held
for sale 938.2 - 1.6 939.8 - - - -
Currency
translation
adjustments (38.1) 5.6 (0.1) (32.6) (37.5) (6.2) (0.1) (43.8)
=============== ============ =========== ============ ========= =========== ============ =========== =========
At 31 December (7,915.9) (42.3) (352.3) (8,310.5) (8,194.6) (157.7) (264.7) (8,617.0)
=============== ============ =========== ============ ========= =========== ============ =========== =========
Net book value
at 31
December 2,544.3 27.3 666.3 3,237.9 3,085.0 32.9 773.8 3,891.7
--------------- ------------ ----------- ------------ --------- ----------- ------------ ----------- ---------
1. Other fixed assets in 2019 have been restated to include a
derecognition of an asset that was fully impaired during the year
ended 31 December 2019. The amount of disposals included in cost
and accumulated depreciation of other fixed assets has changed from
$0.3 million to $108.4 million.
The currency translation adjustments arose due to the movement
against the Group's presentation currency, USD, of the Group's UK
assets which have functional currencies of GBP.
Trigger for 2020 2020
2020 Impairment/(reversal) Remaining recoverable amount
impairment/(reversal) $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
Mauritania c 30.6 n/a -
Espoir (Cote
d'Ivoire) a.d (2.1) 10% 81.5
TEN (Ghana) a.d 149.2 10% 1,510.6
UK CGU c,e 13.2 n/a -
Other 6.2 n/a -
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 revisions to reserves.
e. The fields in the UK are grouped into one CGU as all fields
within those countries share critical gas infrastructure.
In 1H20 impairments recorded in respect of the TEN and Espoir
assets of $305.8 million and $12.8 million respectively, were as
result of a reduction in short, mid and long-term oil price
assumptions. In 2H20 an impairment reversal was recorded in respect
of TEN and Espoir resulting in a full year impairment/reversal of
$149.2 million and $(2.1) million respectively. This was as a
result of increased booked 2P reserves and in the case of TEN lower
future capex assumptions associated with well costs.
During 2020 and 2019, 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
===== ======== ======== ======== ======== ======== =======================
2020 $45/bbl $50/bbl $55/bbl $60/bbl $60/bbl $60/bbl inflated at 2%
----- ======== ======== ======== ======== ======== =======================
2019 $64/bbl $60/bbl $60/bbl $63/bbl $65/bbl $65/bbl inflated by 2%
===== ======== ======== ======== ======== ======== =======================
Oil prices stated above are benchmark prices to which an
individual field price differential is applied. All impairment
assessments are prepared on a value-in-use basis using discounted
future cash flows based on 2P reserves profiles. A reduction or
increase in the two-year forward curve of $5/bbl, based on the
approximate range of annualized average oil price over recent
history, and a reduction or increase in the medium and long-term
price assumptions of $5/bbl, based on the range of annualised
average historical prices, are considered to be reasonably possible
changes for the purposes of sensitivity analysis. Decreases to oil
prices specified above would increase the impairment charge by
$202.2 million for Ghana and $29.3 million for Non-Operated, whilst
increases to oil prices specified above would result in a credit to
the impairment charge of $203.9 million for Ghana and $48.5 million
for Non-Operated. A 1 per cent increase in the pre-tax discount
rate would increase the impairment by $59.0 million for Ghana and
reduce the impairment charge by $7.5 million for Non-Operated. The
Group believes a 1 per cent change in the pre-tax discount rate to
be a reasonable possibility based on historical analysis of the
Group's and a peer group of companies' impairment discount rates.
The Directors considered that the relevant change in this
assumption would have a consequential effect on other key
assumptions including cessation of production and cash flows.
12. Other assets
$m 2020 2019
========================================= ====== ======
Non-current
----------------------------------------- ------
Amounts due from joint venture partners 547.4 576.6
----------------------------------------- ------
Uganda VAT recoverable - 33.5
----------------------------------------- ------
Other non-current assets - 13.1
========================================= ====== ======
547.4 623.2
========================================= ====== ======
Current
----------------------------------------- ------
Amounts due from joint venture partners 521.9 711.8
----------------------------------------- ------
Underlifts 19.5 97.8
----------------------------------------- ------
Prepayments 60.7 69.5
----------------------------------------- ------
Other current assets(1) 115.0 49.6
----------------------------------------- ------
717.1 928.7
========================================= ====== ======
Other current assets mainly include the deferred consideration
relating to the Uganda disposal ($75 million) as well as the
deferred consideration relating to the Netherlands disposal in 2017
($10 million) and VAT recoverable ($15 million).
Uganda VAT receivable and other non-current assets were written
off in 2020.
13. Assets held for sale
Equatorial Guinea and Dussafu asset in Gabon
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 Exploration and Production Sharing contract in
Gabon, in each case with an effective date of 1 July 2020.
Cash consideration of $89 million is payable at completion of
the Equatorial Guinea transaction and $46 million payable at
completion of the Dussafu Transaction, plus an additional $5
million when both transactions complete.
The major classes of assets and liabilities comprising the
assets classified as held for sale as at 31 December 2020 were as
follows:
$m EG Ruche Total
2020 2020 2020
------------------------------------------------------------------------ ------- ------ -------
Assets
Property, plant and equipment 76.0 54.6 130.6
Inventories 5.6 1.4 7.0
Other current assets 11.3 6.7 18.0
------------------------------------------------------------------------ ------- ------ -------
Assets classified as held for sale 92.9 62.7 155.6
------------------------------------------------------------------------ ------- ------ -------
Liabilities
Trade and other payables (3.5) (27.9) (31.4)
Current tax liabilities (10.0) - (10.0)
Deferred tax liabilities (16.7) - (16.7)
Provisions (124.3) (4.9) (129.2)
------------------------------------------------------------------------ ------- ------ -------
Liabilities directly associated with assets classified as held for sale (154.5) (32.8) (187.3)
------------------------------------------------------------------------ ------- ------ -------
Net (liabilities)/assets directly associated with disposal group (61.6) 29.9 (31.7)
------------------------------------------------------------------------ ------- ------ -------
Equatorial Guinea and the Dussafu asset in Gabon are included
within the Non-operated segment of the Group.
14. Trade and other payables
$m 2020 2019
================================== ======== ========
Current liabilities
---------------------------------- --------
Trade payables 38.3 95.4
---------------------------------- --------
Other payables(1) 49.5 95.7
---------------------------------- --------
Overlifts 3.8 -
---------------------------------- --------
Accruals(2) 409.4 636.1
---------------------------------- --------
VAT and other similar taxes 8.9 16.2
---------------------------------- --------
Current portion of leases 240.8 284.2
================================== ======== ========
750.7 1,127.6
================================== ======== ========
Non-current liabilities
---------------------------------- --------
Other non-current liabilities(3) 89.0 75.0
---------------------------------- --------
Non-current portion of leases 975.7 1,140.9
---------------------------------- ======== --------
1,064.7 1,212.9
================================== ======== ========
1. Other payables include accrued interest of $40.9 million (2019: $43.2 million).
2. Accruals mainly relate to capital expenditure, interest
expense on bonds and loans and staff related expenses.
3. Other non-current liabilities include balances related to joint venture partners.
Payables related to operated Joint Ventures (primarily in Ghana
and Kenya) are recorded gross with the amount representing the
partners' share recognised in amounts due from joint venture
partners (note 12). The change in trade payables and in other
payables predominantly represents timing differences and levels of
work activity. The reduction in accruals is associated with reduced
operational activity in Ghana and the disposal of the Group's
interests in Uganda.
Trade and other payables are non-interest bearing except for
leases
15. Provisions
$m Decommissioning Other provisions Total Decommissioning Other provisions Total
2020 2020 2020 2019 2019 2019
======================== =============== ================ ======= =============== ================ ======
At 1 January 850.1 76.2 926.3 794.0 81.5 875.5
New provisions and
reclassifications 14.9 136.6 151.5 109.0 15.5 124.5
Disposals - - - - (0.3) (0.3)
Transfer to asset and
liabilities held for
sale (129.2) - (129.2) - - -
Payments (57.7) (58.4) (116.1) (75.1) (20.4) (95.5)
Unwinding of discount 13.1 - 13.1 16.3 - 16.3
Currency translation
adjustment 4.9 0.2 5.1 5.9 - 5.9
------------------------ --------------- ---------------- ------- --------------- ---------------- ------
At 31 December 696.1 154.6 850.7 850.1 76.3 926.4
======================== =============== ================ ======= =============== ================ ======
Current provisions 104.4 125.4 229.8 102.6 70.2 172.8
======================== =============== ================ ======= =============== ================ ======
Non-current provisions 591.7 29.2 620.9 747.5 6.1 753.6
------------------------ --------------- ---------------- ------- --------------- ---------------- ------
Other provisions include non-income tax provision, restructuring
provision and disputed cases and claims. Management estimates
non-current other provisions would fall due between two to five
years.
The decommissioning provision represents the present value of
decommissioning costs relating to the European and African oil and
gas interests.
Total Total
Discount rate assumption Cessation of production assumption 2020 Discount rate assumption Cessation of production assumption 2019
Decommissioning provisions Inflation assumption 2020 2020 $m 2019 2019 $m
=========================== ==================== ======================== ================================== ===== ======================== ================================== =====
C ô te d'Ivoire 2% 1% 2031 63.9 2% 2033 55.6
--------------------------- -------------------- ------------------------ ---------------------------------- ----- ------------------------ ---------------------------------- -----
Equatorial Guinea(1) n/a n/a n/a - 2% 2030-2032 116.1
--------------------------- -------------------- ------------------------ ---------------------------------- ----- ------------------------ ---------------------------------- -----
Gabon(1) 2% 1-1.5% 2027-2037 61.8 2-2.5% 2022-2037 56.7
--------------------------- -------------------- ------------------------ ---------------------------------- ----- ------------------------ ---------------------------------- -----
Ghana 2% 1-1.5% 2034-2036 323.5 2-2.5% 2032-2036 365.6
--------------------------- -------------------- ------------------------ ---------------------------------- ----- ------------------------ ---------------------------------- -----
Mauritania n/a n/a 2018 89.0 n/a 2018 82.6
--------------------------- -------------------- ------------------------ ---------------------------------- ----- ------------------------ ---------------------------------- -----
UK n/a n/a 2018 157.9 n/a 2018 173.5
=========================== ==================== ======================== ================================== ===== ======================== ================================== =====
696.1 850.1
=========================== ==================== ======================== ================================== ===== ======================== ================================== =====
1 Decommissioning provision relating to Equatorial Guinea and
Ruche (Gabon) transferred to Assets and Liabilities held for Sale
(note 13) as at 31 Dec 2020 ($124.3 million and $4.9 million,
respectively)
During 2020 the Group lowered its decommissioning discount rate
assumptions from 2-2.5% to 1-1.5% in line with the reduction in US
Treasury rates.
16. Commercial Reserves and Contingent Resources summary working
interest basis
Ghana Non-Operated Kenya Exploration Total
--------------- ----------------- -------------- -------------- ------------------------------
Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Petroleum
mmbbl bcf mmbbl bcf mmbbl mmbbl bcf mmbbl bcf mmboe
bcf
================== ======= ====== ======== ======= ======= ===== ======= ===== ======== ======== ==========
COMMERCIAL
RESERVES(1)
================== ======= ====== ======== ======= ============== ======= ===== ======== ======== ==========
1 January 2020 170.3 136.6 48.3 10.1 - - - - 218.6 146.7 243.0
------------------
Revisions(3) 29.0 42.6 8.0 2.8 - - - - 37.0 45.3 44.6
------------------
Production (19.2) - (7.9) (1.8) - - - - (27.1) (1.8) (27.4)
================== ======= ====== ======== ======= ======= ===== ======= ===== ======== ======== ==========
31 December
2020 180.1 179.2 48.4 11.1 - - - - 228.5 190.2 260.2
================== ======= ====== ======== ======= ======= ===== ======= ===== ======== ======== ==========
CONTINGENT
RESOURCES(2)
================== ======= ====== ======== ======= ============== ======= ===== ======== ======== ==========
1 January 2020 215.7 691.8 529.8 135.4 170.8 - 47.4 - 963.7 827.2 1,101.6
------------------
Revisions(4) 1.3 57.3 (3.2) (2.6) - - 0.3 - 1.7 54.7 7.5
Additions(5) - - - - - - 6.8 - 6.8 6.8
Disposal and
relinquishments - - (467.1) (54.1) 170.8 - - - (467.1) (54.4) (476.2)
================== ======= ====== ======== ======= ======= ===== ======= ===== ======== ======== ==========
31 December
2020 217.0 749.1 59.5 78.4 170.8 - 54.5 - 501.7 827.5 639.7
================== ======= ====== ======== ======= ======= ===== ======= ===== ======== ======== ==========
170.8
TOTAL 397.1 928.3 107.9 89.5 - 54.5 - 730.2 1,017.7 899.9
------------------
31 December
2020
================== ======= ====== ======== ======= ======= ===== ======= ===== ======== ======== ==========
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
reserves.
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.
3. The revision to reserves relates mainly to improved field
performance in both Jubilee and TEN fields, maturation of projects
such as Jubilee South East Phase 1 & 2, New Jubilee
Acceleration projects, partial expansion, additional gas injector
in Ntomme and updated audited volumes in Simba, Ruche and Espoir,
offset by production for the full year 2020.
4. The revision to the contingent resources relates mainly to
increases at the Gabon asset, maturation from Contingent resources
to reserves in both fields in Ghana and the sales of the Uganda
asset.
5. The additional contingent resources relate to oil discoveries in Guyana.
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 248.9 mmboe at 31 December 2020 (31
December 2019: 225.1 mmboe). Contingent Resources relate to
resources in respect of which development plans are in the course
of preparation or further evaluation is under way with a view to
future development.
Alternative performance measures
The Group uses certain measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles. These non-IFRS measures include capital
investment, net debt, gearing, adjusted EBITDAX, underlying cash
operating costs 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, capitalised finance costs,
additions to administrative assets, Norwegian tax refund and
certain other adjustments. The Directors believe that capital
investment is a useful indicator of the Group's organic expenditure
on Exploration and Appraisal assets and oil and gas assets incurred
during a period because it eliminates certain accounting
adjustments such as capitalised finance costs and decommissioning
asset additions.
$m 2020 2019
========================================================== ===== =====
Additions to property, plant and equipment 229.7 528.4
----------------------------------------------------------- ----- -----
Additions to intangible exploration and evaluation assets 170.7 279.3
----------------------------------------------------------- ----- -----
Less
---------------------------------------------------------- ----- -----
Decommissioning asset additions 14.9 109.0
----------------------------------------------------------- ----- -----
Right-of-use asset additions 16.5 150.3
----------------------------------------------------------- ----- -----
Lease payments related to capital activities (4.0) (2.7)
----------------------------------------------------------- ----- -----
Capitalised share-based payment charge - 1.9
----------------------------------------------------------- ----- -----
Capitalised finance costs - 16 .3
----------------------------------------------------------- ----- -----
Additions to administrative assets 9.6 21.0
----------------------------------------------------------- ----- -----
Norwegian tax refund - 0.9
----------------------------------------------------------- ----- -----
Other non-cash capital expenditure 75.3 21.0
=========================================================== ===== =====
Capital investment 288.1 490.0
=========================================================== ===== =====
Movement in working capital 133.2 9.0
----------------------------------------------------------- ----- -----
Additions to administrative assets 9.6 21.0
----------------------------------------------------------- ----- -----
Norwegian tax refund - 0.9
----------------------------------------------------------- ----- -----
Cash capital expenditure per the cash flow statement 430.9 520.9
=========================================================== ===== =====
Net debt
Net debt is a useful indicator of the Group's indebtedness,
financial flexibility and capital structure because it indicates
the level of cash borrowings after taking account of cash and cash
equivalents within the Group's business that could be utilised to
pay down the outstanding cash borrowings. Net debt is defined as
current and non-current borrowings plus non-cash adjustments, less
cash and cash equivalents. Non-cash adjustments include unamortised
arrangement fees, adjustment to convertible bonds, and other
adjustments.
$m 2020 2019
=============================== ======= =======
Borrowings 3,170.5 3,071.7
-------------------------------- ------- -------
Non-cash adjustments 10.5 22.6
-------------------------------- ------- -------
Less cash and cash equivalents (805.4) (288.8)
-------------------------------- ------- -------
Net debt 2,375.6 2,805.5
================================ ======= =======
Gearing and Adjusted EBITDAX
Gearing is a useful indicator of the Group's indebtedness,
financial flexibility and capital structure and can assist
securities analysts, investors and other parties to evaluate the
Group. Gearing is defined as net debt divided by adjusted EBITDAX.
Adjusted EBITDAX is defined as profit/(loss) from continuing
activities adjusted for income tax (expense)/credit, finance costs,
finance revenue, gain/(loss) on hedging instruments, depreciation,
depletion and amortisation, share-based payment charge,
restructuring costs, gain/(loss) on disposal, exploration costs
written off, impairment of property, plant and equipment net, and
provision for onerous service contracts.
$m 2020 2019
================================================= ========= =========
Loss from continuing activities (1,221.5) (1,694.1)
-------------------------------------------------- --------- ---------
Adjusted for
------------------------------------------------- --------- ---------
Income tax (credit)/expense (51.9) 40.7
-------------------------------------------------- --------- ---------
Finance costs 314.3 322.3
-------------------------------------------------- --------- ---------
Finance revenue (59.4) (55.5)
-------------------------------------------------- --------- ---------
Loss on hedging instruments 0.8 1.5
-------------------------------------------------- --------- ---------
Depreciation, depletion and amortisation 467.1 724.6
-------------------------------------------------- --------- ---------
Share-based payment charge 20.9 25.8
-------------------------------------------------- --------- ---------
Provisions 92.8 4.2
-------------------------------------------------- --------- ---------
Loss/(gain) on disposal 3.4 (6.6)
-------------------------------------------------- --------- ---------
Exploration costs written off 986.7 1,253.4
-------------------------------------------------- --------- ---------
Impairment of property, plant and equipment, net 250.6 781.2
-------------------------------------------------- --------- ---------
Adjusted EBITDAX 803.8 1,397.5
================================================== ========= =========
Net debt 2,375.6 2,805.5
================================================== ========= =========
Gearing (times) 3.0 2.0
================================================== ========= =========
Underlying cash operating costs
Underlying cash operating costs is a useful indicator of the
Group's costs incurred to produce oil and gas. Underlying cash
operating costs eliminates certain non-cash accounting adjustments
to the Group's cost of sales to produce oil and gas. Underlying
cash operating costs is defined as cost of sales less operating
lease expense, depletion and amortisation of oil and gas assets,
underlift, overlift and oil stock movements, share-based payment
charge included in cost of sales, and certain other cost of sales.
Underlying cash operating costs are divided by production to
determine underlying cash operating costs per boe.
$m 2020 2019
============================================================ ===== =======
Cost of sales 993.6 966.7
------------------------------------------------------------- ----- -------
Less:
------------------------------------------------------------ ----- -------
Depletion and amortisation of oil and gas and leased assets 446.4 696.1
------------------------------------------------------------- ----- -------
Underlift, overlift and oil stock movements 160.5 (137.3)
------------------------------------------------------------- ----- -------
Share-based payment charge included in cost of sales 0.9 2.6
------------------------------------------------------------- ----- -------
Other cost of sales 54.1 54.0
============================================================= ===== =======
Underlying cash operating costs 331.7 351.3
============================================================= ===== =======
Production (MMboe) 27.4 31.7
============================================================= ===== =======
Underlying cash operating costs per boe ($/boe) 12.1 11.1
------------------------------------------------------------- ----- -------
Free cash flow
Free cash flow is a useful indicator of the Group's ability to
generate cash flow to fund the business and strategic acquisitions,
reduce borrowings and provide returns to shareholders through
dividends. Free cash flow is defined as net cash from operating
activities, and net cash from/(used) in investing activities,
repayment of obligations under leases, finance costs paid and
foreign exchange gain/(loss).
$m 2020 2019
============================================= ======= =======
Net cash from operating activities 698.6 1,258.7
---------------------------------------------- ------- -------
Net cash from/(used) in investing activities 84.3 (512.0)
---------------------------------------------- ------- -------
Repayment of obligations under leases (158.2) (172.1)
---------------------------------------------- ------- -------
Finance costs paid (198.5) (215.4)
---------------------------------------------- ------- -------
Foreign exchange gain/(loss) 5.4 (4.3)
============================================== ======= =======
Free cash flow 431.6 354.9
============================================== ======= =======
At the Capital Markets Day in November 2020, the Group presented
a revised business plan focusing on the maximisation of value from
the Group's producing assets. In order to assess performance
against the revised business plan, the Group set out two new
alternative performance measures in replacement of Free Cash Flow,
Underlying Operating Cash Flow and Pre-financing Cash Flow. These
measures will be used from 2021 onwards but are set out below.
Underlying operating Cash Flow and Pre-financing cashflow
Underlying operating cash flow is a useful indicator of the
Group's assets ability to generate cash flow to fund further
investment in the business, reduce borrowing and provide returns to
shareholders. Underlying operating cash flow is defined as net cash
from operating activities less repayments of obligations under
leases plus decommissioning expenditure.
Pre-financing cash flow is a useful indicator of the Group's
ability to generate cash flow to reduce borrowings and provide
returns to shareholders through dividends. Pre-Financing cash flow
is defined as underlying operating cash flow plus net cash
from/(used) in investing activities, decommissioning expenditure
and payments to/from decommissioning escrow fund.
$m 2020 2019
============================================= ======= =======
Net cash from operating activities 698.6 1,258.7
---------------------------------------------- ------- -------
Plus
--------------------------------------------- ------- -------
Decommissioning expenditure 57.7 75.1
---------------------------------------------- ------- -------
Payments to/from decommissioning escrow fund - 3.8
---------------------------------------------- ------- -------
Less
--------------------------------------------- ------- -------
Repayment of obligations under leases (158.2) (172.1)
============================================== ======= =======
Underlying operating cash flow 598.1 1,165.5
============================================== ======= =======
Net cash from/(used) in investing activities 84.3 (512.0)
---------------------------------------------- ------- -------
Decommissioning expenditure (57.7) (75.1)
---------------------------------------------- ------- -------
Payments to/from decommissioning escrow fund - (3.8)
---------------------------------------------- ======= =======
Pre-financing cash flow 624.7 574.6
============================================== ======= =======
events on the day
In conjunction with these results, Tullow is conducting a
virtual presentation webcast that can be watched live or on
replay.
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 6889987
===================== =====================
WEBCAST
To join the live video webcast or play the on-demand version,
please use this link:
https://edge.media-server.com/mmc/p/kz4hpaav
The replay will be available from noon on 10 March 2021.
CONTACTS
Tullow Oil plc Murrays
(London) (Dublin)
(+44 20 3249 9000) (+353 1 498 0300)
Chris Perry, Matthew Evans (Investors) Pat Walsh
George Cazenove (Media) Joe Heron
======================================== ===================
Notes to editors
Tullow is an independent oil & gas, exploration and
production group, quoted on the London, Irish and Ghanaian stock
exchanges (symbol: TLW). The Group has interests in over 50
exploration and production licences across 11 countries.
For further information, please refer to our website at
www.tullowoil.com.
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END
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